Completion & Workover Training Manual

Drilling Engineering Department

Completions & Workover Training Manual

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006

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TABLE OF CONTENTS 1.

WELL COMPLETION TYPES

2.

COMPLETION DESIGN CRITERIA

3.

WELLHEADS

4.

CASING AND TUBING

5.

PACKERS

6.

SAFETY VALVES

7.

COMPLETION FLUIDS

8.

PERFORATING

9.

STIMULATION

10.

INTRODUCTION TO WORKOVERS

11.

WORKOVER PLANNING

12.

WORKOVER WELL CONTROL

13.

RUNNING AND CEMENTING LINERS

14.

REMEDIAL CEMENTING

15.

SAND CONTROL

16.

COILED TUBING OPERATIONS

17.

WIRELINE OPERATIONS

18.

FISHING OPERATIONS

19.

PLUG AND ABANDON

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TABLE OF CONTENTS INTRODUCTION ...............................................................................................................1 BASIC COMPLETION TYPES..........................................................................................2 I. OPEN HOLE COMPLETIONS ........................................................................2 ADVANTAGES: .........................................................................................2 DISADVANTAGES:...................................................................................2 II. CASED HOLE COMPLETIONS......................................................................3 A. PERFORATED CASING COMPLETIONS:........................................3 Advantages.......................................................................................3 Disadvantages ..................................................................................3 B. PERFORATED LINER COMPLETIONS: ...........................................3 Advantages.......................................................................................4 Disadvantages ..................................................................................4 C. SCREEN/PRE-PERFORATED LINER COMPLETIONS ...................4 Advantages.......................................................................................4 Disadvantages ..................................................................................5 OIL PRODUCER COMPLETIONS....................................................................................6 I. PACKERLESS COMPLETIONS (CASING FLOW).......................................6 II. TUBING & PACKER COMPLETIONS (TUBING FLOW)............................6 A. ONSHORE OIL PRODUCERS.............................................................7 a. Conventional vertical producers. ...............................................7 b. Horizontal producers..................................................................7 c. Dual completion: Producer/observation well ............................8 d. Gas lift producers.......................................................................9 e. Electric submersible pump (ESP) producers. ..........................10 B. OFFSHORE OIL PRODUCERS .........................................................11 a. Conventional vertical producers. .............................................12 b. Deviated producers. .................................................................12 c. Horizontal producers................................................................13 WATER INJECTOR COMPLETIONS............................................................................15 I. PACKERLESS COMPLETIONS (CASING FLOW).....................................15 A. POWER WATER INJECTORS ..........................................................15 a. Vertical power water injectors.................................................15 b. Horizontal power water injectors.............................................15 B. GRAVITY WATER INJECTORS ......................................................17 a. Vertical gravity water injectors................................................17 b. Horizontal gravity water injector.............................................17

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II. TUBING & PACKER COMPLETIONS (TUBING FLOW)..........................18 A. SALT WATER DISPOSAL WELLS ..................................................18 a. Vertical salt water disposal wells.............................................18 b. Horizontal salt water disposal well..........................................18 GAS PRODUCER COMPLETIONS ................................................................................19 I. ABQAIQ GAS PRODUCERS.........................................................................19 II. KHUFF GAS PRODUCERS ...........................................................................19 WATER SUPPLY COMPLETIONS.................................................................................20 I. WASIA WATER SUPPLY WELLS ...............................................................20 A. PUMP DRIVEN WASIA WATER SUPPLY WELLS .......................20 B. GAS LIFT WASIA WATER SUPPLY WELLS.................................21 II. UER WATER SUPPLY WELLS ....................................................................21

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INTRODUCTION Several types of well completions exist in Saudi Aramco oil fields. Completion types can be categorised as to the way the well is completed through the reservoir. This can be either open hole or cased hole. In the cased hole category, several types exist such as cemented casing, cemented liner, slotted (or pre-perforated) liner, screen liner, gravel pack, etc. Completion types can be further categorized as to the well function. This can be oil producers, gas producers, water supply, power water injectors, gravity water injectors, salt water disposal, and observation wells. Some of these can be further broken down into subcategories such as vertical, deviated, or horizontal producers, water injectors, etc. Completion types can also be categorized as to the type of production configuration. This can include single completions, dual (or multiple) completions, single packer, or multiple packer configurations, etc. These completions can range in complexity from a simple packerless completion to a complicated multiple gas lift design with all types of selective and non-selective nipples (and other equipment) above and below the production packer assembly. The above categories can be mixed and matched in several ways to make many different completion combinations. In this chapter many well completion types will be reviewed and the Saudi Aramco completions will be emphasized.

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WELL COMPLETION TYPES

BASIC COMPLETION TYPES Two basic categories of well completions are open hole and cased hole. I. OPEN HOLE COMPLETIONS The open hole completion has the production casing set above the zone of interest. The well is completed with the producing interval open to the well bore (see Figure 1). ADVANTAGES: 1. A low cost completion alternative. 2. Elimination of perforating expense and production restriction caused by the perforations. 3. After setting casing above the producing zone, a new non-damaging mud can be made up to drill the pay zone. The mud weight and chemistry may be controlled to minimize formation damage within the zone of interest. 4. Log interpretation is not critical as the entire pay zone is open to production and no perforations are required. 5. Maximum well bore diameter is opposite pay zone. 6. Deepening of well is easily accomplished. 7. Easily converted to other types of completions (ie. liner completions).

PRODUCTION CASING

CASING SHOE

PAY ZONE

OPEN HOLE

OPEN HOLE COMPLETION

FIGURE 1

DISADVANTAGES: 1. Excessive gas or water production is difficult to control. 2. The production casing is set before the objective horizon is drilled. The extent of the payzone is not known until the next hole section is drilled. 3. The producing interval cannot be selectively stimulated. 4. The open hole section may require frequent cleanout if the formation is unconsolidated.

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II. CASED HOLE COMPLETIONS The basic cased hole completions types can be either cemented/perforated casing, cemented/perforated liner or uncemented/pre-perforated (or screen) liner completions. A. PERFORATED CASING COMPLETIONS: Production casing is cemented through the producing zone and the pay section is selectively perforated (see Fig 2). Advantages 1. Excessive gas or water production is easier to prevent and control. 2. Formation can be selectively stimulated. 3. Well can be easily deepened. 4. Casing will impede sand influx and is additionally adaptable to special sand control techniques. PRODUCTION CASING 5. Full diameter through pay section. 6. Logs can be available to assist decision to set casing. PRODUCTION 7. Adaptable to several completion PERFORATIONS configurations. 8. Minimum rig time required. PAY ZONE

Disadvantages 1. Perforating cost can be significant. CASED HOLE COMPLETION 2. Log interpretation critical for selecting FIGURE 2 perforating interval(s). 3. Greater danger of formation damage in pay section since the mud used to drill from the last casing shoe is usually the same mud used to drill the pay zone. 4. More expensive.

B. PERFORATED LINER COMPLETIONS: Production casing is set above the producing zone, the pay is drilled, and a liner1 is cemented across the pay zone. The liner is then selectively perforated for production (see Fig. 3).

1A

casing string which does not extend to surface is normally referred to as a liner.

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Advantages 1. Formation damage is minimized since a new non-damaging mud can be made up before drilling the pay zone. 2. Excessive gas or water production is easier to prevent and control. 3. Formation can be selectively stimulated. 4. A liner can impede sand influx, and is additionally adaptable to special sand control techniques. 5. Well can be easily deepened. However if the liner size is 4-1/2", then the well will be limited to a 3PRODUCTION 7/8" open hole at the total depth. CASING Liner systems for 3-7/8" hole are not LINER presently available in Saudi Aramco. HANGER PRODUCTION LINER

Disadvantages 1. Recompletion options for deeper PRODUCTION formations are limited if the PAY PERFS production liner size is 4-1/2". ZONE 2. Log interpretation is critical for the CEMENT correct perforating intervals. CEMENTED LINER COMPLETION 3. Additional costs are the liner and FIGURE 3 cementing expense, perforating expense and additional rig time. 4. The production casing is set before the producing zone is drilled. The extent of the payzone is not known until the end of the next hole section.

C. SCREEN/PRE-PERFORATED LINER COMPLETIONS Casing is set above the completion zone and an uncemented screen or preperforated liner assembly is installed across the pay section (see Fig. 4). Advantages 1. Formation damage while drilling the pay is minimized since a new nondamaging mud can be made up before drilling the pay zone. 2. There is no wireline perforating expense, however the cost of the preperforated/screen liner can be high. 3. Log interpretation is not critical since no wireline perforations are required.

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4. Adaptable to special techniques to control sand. A gravel pack or pre-packed liner is an option for this type of completion. 5. Cleanout problems can be avoided if the proper screen/perforation size is used. Disadvantages 1. Excessive water or gas production is difficult to control since there is no isolation (cement) behind the liner. 2. Production casing is set before the producing horizon is drilled. The extent of the pay zone is not known until the next hole section is drilled. 3. Selective stimulation is not possible. 4. Additional rig time is required to run the screen liner assembly when compared to an open hole completion. 5. Diameter across the pay zone is reduced. 6. The well cannot be easily deepened if the liner size is 4-1/2". The hole size for deepening in this case is limited to 3-7/8" (max).

PREPERFORATED LINER

PAY ZONE

PRE-PERFORATED OR SCREEN LINER

FIGURE 4

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OIL PRODUCER COMPLETIONS Saudi Aramco has completed its oil producers in several ways. The main completions are as follows:

I. PACKERLESS COMPLETIONS (CASING FLOW) This is the simplest and most inexpensive completion available (see Fig. 5). Flow is up the tubing/casing annulus which has much less restriction than a tubing/packer configuration. This completion is restricted to wells capable of producing extremely high rates at low to medium flowing and shut in wellhead pressures. This approach however, is not the safest since it is vulnerable to underground blowouts. This could occur if the production casing became corroded and a leak was developed opposite an aquifer above the producing zone.

2-3/8" KILL STRING

CASING SHOE

PAY ZONE

The majority of Saudi Aramco onshore producing wells were completed this way until the early 1980s. CASING FLOW PRODUCER These wells typically had a 2-3/8" or 2-7/8" 'kill string' FIGURE 5 used to kill the well if required (ie. for a workover). The production can be up both the casing and tubing (kill string). During the early 1980s a large workover program to recomplete these wells with packer type completions was undertaken due to rising bottom hole pressures (BHP) and increasing water cuts. As a result, there are almost no casing flow producers today.

II. TUBING & PACKER COMPLETIONS (TUBING FLOW) A tubing/packer installation may be required for: 1. Casing protection from high BHP, high water cut, or corrosion. The tubing/casing annulus (TCA) is usually protected with a corrosion resistant 'packer fluid'. 2. Subsurface well control. This is achieved by installing a subsurface safety valve (SSSV) in the tubing string usually 300' below surface. SSSVs are typically installed in all offshore oil producers and some onshore producers which are near major highways, gas/oil separation plants (GOSP), towns, or other sensitive area.

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Disadvantages of tubing/packer completions include: 1. A restriction in maximum flow potential when compared to casing or casing/tubing flow. 2. Higher completion costs due to the extra equipment and rig time involved.

A. ONSHORE OIL PRODUCERS Saudi Aramco has several types of oil producing tubing and packer configurations. The outline of the most common configurations are as follows. a. Conventional vertical producers. These wells are the basic tubing/packer arrangement and are found in most of the major oil and gas fields (see Fig. 6). The production tubing strings are typically 4-1/2" since the wells normally have either a 7" production liner or 7" production casing. In some cases, the production tubing is as small as 2-3/8" (inside 4-1/2" production casing) or as large as 7" (inside 9-5/8" production casing). Combination strings of 2-3/8" x 4-1/2" or 41/2" x 7" can also be used in wells which have 4-1/2" or 7" production liners respectively.

PRODUCTION TUBING PRODUCTION PACKER

4-1/2" LINER HGR

7" SHOE

PAY ZONE

CASED HOLE COMPLETION

FIGURE 6

The production packers are typically 7" permanent packers, however 4-1/2" and 9-5/8" packers are used in their respective casings. b. Horizontal producers. These hi-tech wells are a recent addition to Saudi Aramco's oil wells. The wellbore enters the payzone at a high angle (about 80 deg inclination) and a horizontal hole is drilled in the reservoir for a distance of about 2000' (see Fig. 7). This type of completion exposes the maximum amount of the reservoir to the wellbore. The wellbore can be located above the oil/water or below the gas/oil contact, thereby reducing the water or gas cut respectively.

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WELL COMPLETION TYPES Saudi Aramco horizontal oil producers are completed in either carbonate or sandstone reservoirs2.

4-1/2" PRODUCTION TUBING 9-5/8" or 7" PERMANENT PACKER 9-5/8" or 7" CASING SHOE 8-1/2" or 6-1/8" OPEN HOLE

Carbonate reservoirs are typically open hole completions. Wells with PAY 9-5/8" casing set at the ZONE top of the payzone HORIZONTAL CARBONATE RESERVOIR PRODUCER usually have an 8-1/2" FIGURE 7 open hole completion. Wells with 7" casing set at the top of the payzone will have a 6-1/8" open hole completion (see Fig 7). The main onshore fields which have horizontal carbonate producers are Ghawar and Abqaiq. The Berri field also has onshore oil producers drilled from pads located on the Berri causeway. Although most of the Safaniya field is offshore, some onshore horizontal sandstone producers have been drilled in there. c. Dual completion: Producer/observation well Dual completions are wells with two reservoirs open to the wellbore. The reservoirs are usually separated by a packer. If more than 2 reservoirs are open to the wellbore, then this is termed a multiple completion.

POLISHED BORE RECEPTACLE 7" LINER HANGER RETRIEVABLE PACKER PORTED 'BV' LANDING NIPPLE ARAB-D PERFS

9-5/8" CASING SHOE PERMANENT PACKER SEAL BORE ASSEMBLY

SDGM-169 is one of the few dual completions in Saudi Aramco. This well is completed as both, an ArabD producer and Hanifa observation well (see Fig. 8). A production packer is set between the Arab-D and Hanifa to isolate the reservoirs.

2

'X' LANDING NIPPLE HANIFA PERFS

HANIFA/ARAB-D DUAL COMPLETION

FIGURE 8

The sandstone horizontal wells are covered in the Offshore Oil Producer section.

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WELL COMPLETION TYPES Another production packer is set above the Arab-D to isolate the tubing/casing annulus from the Arab-D reservoir. The well is normally produced from the Arab-D reservoir. A 'PX' plug is set in the tailpipe below the lower packer to isolate the production tubing from the Hanifa reservoir. The flow of Arab-D oil is through the ported ball valve (BV) nipple into the production tubing. When the Hanifa static bottom hole pressure measurement is required, an isolation sleeve is set in the BV nipple isolating the Arab-D reservoir. The 'PX' plug is removed allowing the Hanifa pressure to access the production tubing.

d. Gas lift producers. One type of artificial lift system used in Saudi Aramco is gas lift. These completions are common in the Khurais, Qirdi, Abu Jifan and Mazalij fields. A gas lift design is also being tested in the Safaniya field. Associated gas is separated, compressed then reused to provide the gas lift mechanism in the wells. As gas is injected into the production stream, the flowing bottom hole pressure is reduced which increases the flow potential of the well. The gas is injected into the tubing/casing annulus and fed into the tubing through gas lift valves located in side pocket mandrels. This is referred to as tubing flow since the production is on the tubing side (see Fig 9). Most of the gas lift completions are tubing flow.

PRODUCTION UP TUBING

INJECTION GAS DOWN TCA

GAS LIFT VALVES IN SIDE POCKET MANDRELS

PRODUCTION PACKER

PAY ZONE

TUBING FLOW GAS LIFT PRODUCER

FIGURE 9

An alternate design is the injection of gas into the tubing and then fed to the tubing/casing annulus through the gas lift valves. This is referred to as annular flow since the production is up the tubing/casing annulus. In this case a perforated joint is required above the packer so the production flow can enter the tubing/casing annulus after passing through the packer (see Fig. 10). This completion is common when the production tubing is 2-3/8" due to a small casing size of 4-1/2". To maximise flow potential, the tubing/casing annulus is therefore used for the production.

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WELL COMPLETION TYPES A recurring problem with the gas lift completions is the formation of hydrates in the gas injection line ahead of the wellhead (downstream of the choke) during cold weather operation. The hydrate is a physical combination of water and small hydrocarbon molecules to produce a solid which has an ice-like appearance. Hydrate formation can only be eliminated by either heating the gas, chemical inhibition, or by dehydrating the gas.

INJECTION GAS DOWN TUBING

PRODUCTION UP TCA

GAS LIFT VALVES IN SIDE POCKET MANDRELS PERFORATED JOINT ABOVE PACKER

PRODUCTION PACKER

PAY ZONE e. Electric submersible pump (ESP) producers. In 1992, three high water cut, low CASING FLOW GAS LIFT PRODUCER flowing wellhead pressure wells in the FIGURE 10 Abqaiq field were selected for a pilot test to install and run electric submersible pumps. The primary objective of the project was to gain experience and knowledge of ESP operation for application in the Hawtah field. The project would also provide data for evaluating the practicality of using the ESPs for lifting high water cut, low flowing wellhead pressure wells in the Abqaiq and Ghawar fields.

The ESP completion consists of a downhole pump and motor assembly. The motors range from 60 HP to 200 HP. Running parallel to this assembly is a tailpipe which can accomodate a blanking plug. The pump/motor assembly is connected with the tailpipe at a 'Y' connection (see Fig. 11). This configuration allows the well to produce through the tailpipe (with the pump shutdown) using the reservoir pressure alone. In the future, when the reservoir pressure declines or during periods of high demand, a blanking plug can be installed in the landing nipple. The motor can be turned on and the oil pumped to surface. Page 10

ELECTRIC CABLE 3-1/2" TUBING

BLANKING PLUG

PUMP

2-7/8" TAILPIPE

MOTOR

PAY ZONE

ESP COMPLETION

FIGURE 11

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WELL COMPLETION TYPES The new Hawtah field in the central area will be almost entirely equipped with ESPs (see Fig. 11). The low bottom hole pressure, low gas/oil ratio, and the lack of a strong natural drive mechanism makes ESPs an attractive completion option in this field.

B. OFFSHORE OIL PRODUCERS Saudi Aramco has a variety of completions offshore. These completions can be categorized as vertical, deviated and horizontal completions. Whereas the onshore oil producers are completed mostly in carbonate reservoirs, the offshore fields are mainly sandstone, except for the Berri and Abu Safa fields. To understand offshore completions, it is helpful to understand the types of offshore production platforms. Saudi Aramco has the following types of platforms: 1. Tripods (three well capacity) 2. Four well platforms 3. Six well platforms These platforms typically have one vertical completion and the rest are either deviated or horizontal completions. Wells offshore can also be completed as a free standing conductor or mud line suspension. These wells usually become future platform locators. Recently, the six well platforms have been redesigned. Whereas the old design was constructed specifically for each field, the new modular design is not field specific and can be used in any field, regardless of water depth. As a bonus, the new design is approximately 1/3 the cost of the old design. Offshore oil producers have a mixture of up hole packer and down hole packer completions. In the early 1980s, most offshore oil producers were equipped with up hole packers (see Fig. 12) to maximise flow potential. Packers were typically located 300' from surface. This allowed both casing and tubing flow below the packer, and tubing flow above the packer. A subsurface safety valve is located above the packer which could shut the well in if a problem occurred on the production platform. Saudi Aramco has the following types of offshore oil producers:

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a. Conventional vertical producers. These wells are the basic uphole or downhole tubing/packer design and are found in all of the major offshore fields. Since the mid 1980s the up hole packer completions are being gradually converted to down hole packers. Besides being a safer mode of production, this also allows the tubing/casing annulus to be filled with a corrosion resistant packer fluid, thereby extending the life of the production casing. The production tubing and packer configurations for the downhole completions are similar to the onshore producers described earlier, except that all offshore producers are equipped with subsurface safety valves.

SSSV UPHOLE PACKER

PORTED NIPPLE

KILL TUBING

PAY ZONE

UPHOLE COMPLETION

FIGURE 12

b. Deviated producers. These wells are commonly referred to as 'directional wells'. They are drilled to intersect the reservoir at a specified distance and direction away from the surface production platform. Their completions are similar to the vertical producers mentioned above, however the degree of wellbore inclination may have a bearing on the type of completion used. The wellbores typically have inclinations that range from about 10 deg. up to a maximum of 60 deg. This 60 deg limit is recognized as an approximate limit for wireline tools. Any inclination above this requires coiled tubing assisted tools. Hydraulic set liner hangers and production packers are normally used in these completions. Mechanical (or rotation) set equipment may have problems due to the drag associated with the high inclination.

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c. Horizontal producers. In 1992, a major horizontal drilling campaign began both onshore and offshore. Most of this activity took place offshore in the Zuluf, Marjan, Safaniya (sandstone) and Berri (carbonate) fields. These wells were drilled using long radius build assemblies which provided 0 - 10 deg/100' build rates. A long radius design allowed conventional (Aramco stock) completion tubulars to be used. The Berri wells are typically open hole completions in either the Hanifa or Hadriya reservoirs. As with the onshore horizontal carbonate wells, the open hole is either 8-1/2" with 9-5/8" casing set at the top of the producing zone or 6-1/8" with 7" casing set above (see Fig 7). Slight variations to the standard open hole completions were made in Berri. Berri #302, for example had a short 7" liner cemented off bottom to cover a highly permeable section near the 4-1/2" TAILPIPE INSIDE 7" LINER TOP top of the Hadriya 9-5/8" CASING SHOE reservoir (see Fig. 7" SHORT LINER 13). This would allow the less 8-1/2" OPEN HOLE permeable lower HI-PERM STREAK part of the reservoir to be HADRIYA produced with the RES option of HORIZONTAL CARBONATE RESERVOIR PRODUCER perforating and FIGURE 13 producing the highly permeable upper section at a later date. Almost all Marjan, Zuluf, and Safaniya horizontal producers are completed with a cemented 7" liner (see Fig 14). These 'horizontal' liners are equipped with special 'solid body aluminum centralizers' which help in providing a positive stand-off of the liner in the horizontal hole. A special liner running tool is used which allows the liner to be rotated, pushed or 'worked' to bottom. Once on bottom, the liner can be rotated and/or reciprocated during the cement job, providing torque and drag limitations are not exceeded.

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WELL COMPLETION TYPES The liners are perforated with drill pipe conveyed perforating guns. More than 1500' of perforations have been made per well in some cases. An alternate completion to the cemented liner has been tested. Maharah #35 is an example of a pre-perforated (non-cemented) horizontal liner completion. Without the drill pipe conveyed perforating expense, the completion cost was reduced. This type of completion however, limits future workover options to shut off gas or water production. This makes it unattractive as a long term completion alternative in areas where these problems exist.

TAILPIPE INSIDE 7" LINER TOP 9-5/8" CASING SHOE 7" PRODUCTION LINER 8-1/2" HORIZONTAL HOLE SELECTIVE PERFS

KHAFJI RES HORIZONTAL SANDSTONE RESERVOIR PRODUCER

FIGURE 14

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WATER INJECTOR COMPLETIONS Reservoir pressure is maintained in most of the Saudi Aramco oil fields through water injection systems. These wells typically line the perimeter of the oil fields. I. PACKERLESS COMPLETIONS (CASING FLOW) The power water injectors (PWI) and gravity water injectors (GWI) are casing flow, packerless completions. These wells can be either open hole, perforated cased hole, or perforated liner completions. A. POWER WATER INJECTORS PWI wells inject water under high pressure (up to 3000 psi well head pressure) through flowlines from nearby water FLOWLINE injection plants (WIPs). They are occasionally stimulated to improve FROM WIP injectivity and reduce the injection well head pressure (IWHP). a. Vertical power water injectors These wells are most common in the Ghawar field (see Fig. 15). These wells are typically open hole, however cemented/perforated liners have been run in wells where selective injection is required.

7" LINER HANGER

9-5/8" SHOE 7" SHOE PAY

ZONE b. Horizontal power water injectors Most of the horizontal PWI wells are POWER WATER INJECTOR located in the Ghawar and Berri fields. FIGURE 15 Whereas vertical PWI wells can be logged with conventional WL, the horizontal wells require coiled tubing conveyed logging tools. Because of this, some horizontal PWI completions differ from their vertical counterparts in that a coil tubing guide string is run to assist coiled tubing operations. These guide strings are normally 4-1/2" or 3-1/2" tubing inside 9-5/8" production casing (see Fig 16). This is typical of the Ghawar - Arab-D high capacity injectors. Computer simulations have shown that the coiled tubing is susceptible to buckling and lock-up inside the 9-5/8" casing and 8-1/2" open hole without the guide string.

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4-1/2" TUBING GUIDE STRING 9-5/8" CASING 9-5/8" CASING SHOE 8-1/2" HOLE

ARAB-D RES TAR ZONE HORIZONTAL POWER WATER INJECTOR

FIGURE 16 Low permeability tar stringers are occasionally encountered in the Ghawar PWI wells. UTMN-1013 is an example of a horizontal PWI completion which was drilled near a tar zone. The well path was steered above the tar zone and into the more permeable part of the reservoir (see Fig 16). This improved the injectivity of well.

7" LINER HANGER @ 3500' 9-5/8" CASING 9-5/8" CASING SHOE HIGH PERM STREAK 7" LINER SHOE 6-1/8" OPEN HOLE

HADRIYA RES BERRI HORIZONTAL POWER WATER INJECTOR

FIGURE 17

Many horizontal PWI wells in the Berri field have a long 7" production liner and a 6-1/8" open hole completion (see Fig. 17). The 7" liner is run from approximately 3500' to below the high permeability streak near the top of the

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WELL COMPLETION TYPES Hadriya reservoir. Computer simulations have shown that with this long 7" liner & 6-1/8" open hole configuration, the well does not require the 4-1/2" guide string necessary as in the 9-5/8" casing completions. This provides a less costly completion option.

B. GRAVITY WATER INJECTORS GWI wells are stand-alone wells (without flowlines) and are located only in the Abqaiq field. These wells are perforated in the Wasia formation which dump water into the lower Arab-D producing formation to help maintain reservoir pressure. The casings in these wells are susceptible to corrosion and erosion from the hot, corrosive Wasia water and have required expensive workovers in the past. As a result, alloy type 13-Chrome casing strings have been run recently in an effort to minimize corrosion and reduce workover cost. a. Vertical gravity water injectors A typical GWI well is shown in Fig 18. These wells are normally completed with 9-5/8" casing opposite the Wasia water aquifer. A 7" liner is run from below the Wasia to the top of the ArabD. When the well is in operation, corrosion occurs from the Wasia perforations to the 7" shoe. Workovers to repair this corrosion involve tying the 7" liner back above the perforations and running a 4-1/2" liner to lap the new 7" liner. In order to minimize corrosion, new wells are completed with 7" 13-chrome liner from the top of the Arab-D reservoir to above the 133/8" casing shoe.

GROUND

WATER ZONE

LEVEL

PERFS 7" LINER HANGER

9-5/8" SHOE 7" SHOE PAY ZONE

OPEN HOLE

GRAVITY WATER INJECTOR

FIGURE 18

b. Horizontal gravity water injector One well, ABQQ-331 has been completed as a horizontal gravity water injector in the Hanifa reservoir. Corrosion resistant 13-Chrome 7" liner and 95/8" casing strings were used. The well was completed with a 6-1/8" open hole.

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II.

TUBING & PACKER COMPLETIONS (TUBING FLOW) A. SALT WATER DISPOSAL WELLS Several salt water disposal wells (SWD) are completed with tubing and packer. The salt water disposal fluids can be both corrosive and pumped at pressures up to 3000 psi. The salt effluent is a by-product of the desalting process or waste water in the gas oil separation plants. An SWD well may have initially been a PWI well which had a low injectivity, high tar saturation, or located down structure, away from the oil/water contact. Many SWD wells have had their tubing and packer removed to maximise their disposal capacity. These wells dispose of salt water that has been treated to minimize corrosion. Wells without this corrosion protection treatment continue to have the tubing and packer completions. a. Vertical salt water disposal wells Fig. 19 shows an SWD well with a tubing and packer completion. SWD wells without tubing and packer are similar to the PWI completions mentioned earlier. b. Horizontal salt water disposal well One well, UTMN-1060 has been completed as a horizontal SWD well. It's completion differs from the vertical SWD wells in that the 9-5/8" casing was run to the top of the Arab-D reservoir and an 8-1/2" open hole drilled to TD. There is no packer in this completion, rather a 4-1/2" guide string was run to assist in coiled tubing unit (CTU) operations similar to the horizontal PWI wells.

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9-5/8" CASING SHOE TUBING & PACKER 7" LINER SHOE

PAY ZONE

OPEN HOLE

SALT WATER DISPOSAL

FIGURE 19

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GAS PRODUCER COMPLETIONS I. ABQAIQ GAS PRODUCERS Abqaiq field has several Arab-D gas cap producers. The wells are a back up source of gas supply whenever the demand exceeds the associated gas and Khuff gas production capabilities. As a result, the wells are shutdown for extended periods of time. These wells have standard tubing/packer configurations. II. KHUFF GAS PRODUCERS The Khuff gas program began in the early 1980s due to a decline in oil production which reduced the supply of associated gas. These non-associated gas wells are as deep as 16000', have bottom hole temperatures up to 320 deg F and high levels of H2S. The high bottom hole and wellhead pressures required that the completions be designed with 10,000 psi rated equipment. Almost all of these wells are located in the Shedgum and Uthmaniyah areas of the Ghawar field. Some of the wells have tubing/packer arrangements, while others have their tubing string stung into a polished bore receptacle (PBR) assembly located above the liner hanger (see Fig. 20). The completion tubing is either 7", 4-1/2" or a combination of 4-1/2" X 7" or 5-1/2" X 7" tubing. A premium tubing connection with a metal to metal seal to contain the high well pressures such as VAM is used. To control H2S embrittlement, an L-80 grade of tubing is used.

7" TUBING

4-1/2" X 7" CROSSOVER 7" HANGER 9-5/8" SHOE 4-1/2" TUBING 4-1/2" PBR 4-1/2" HANGER 7" SHOE

PAY ZONE

4-1/2" SHOE KHUFF GAS PRODUCER

FIGURE 20

Thermal elongation and contraction of the production tubing on these wells can be significant. Several modes of operation such as producing, shut-in hot, shut-in cold and acidize are studied for each well. As part of the completion program, the optimum space out or landing procedure of the tubing string is determined to prevent the tubing from being unstung from the packer or PBR, or buckled beyond the elastic limit while in any of its operating modes. Page 19

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WATER SUPPLY COMPLETIONS I. WASIA WATER SUPPLY WELLS Wasia water is required for wash water supply at the GOSPs and injection water at the WIPs. These wells are either free flowing, equipped with Byron Jackson (BJ) electric submersible pumps (ESPs) or gas lift mandrels. The wells are completed with large diameter casing strings near surface to accommodate the large diameter, high capacity water pumps if required. Many wells are completed initially without pumps, however, they have the provision for future pump installation. The older wells have had their liners tied back to repair corrosion on these large diameter casings. As a result smaller pumps are run whenever the liners are tied back for the pump driven wells. A. PUMP DRIVEN WASIA WATER SUPPLY WELLS Figure 21 shows a new water supply well on the left. The production casing is 185/8" which is required to accomodate the large 16" 600 HP BJ ESP. As the well grows older, the 18-5/8" and 24" casings may corrode requiring a liner tieback to 30" CONDUCTOR CASING LARGE DIAMETER CASING TO ACCOMODATE BIG PUMP

16" MQ 600 HP PUMP 7" MQ 30 HP PUMP 18-5/8" CASING SHOE 24" CASING SHOE @ 600'+-

LINER TIEBACKS RUN DURING WORKOVERS TO REPAIR CSG CORROSION RESTRICT THE DIAMETER AVAILABLE FOR WATER PUMP

13-3/8" INTERMEDIATE LINER

9-5/8" PRODUCTION LINER 8-1/2" OPEN HOLE ACROSS WASIA SAND (APPROX 4000' TD) NEW WELL WITH LARGE PUMP

AFTER LINER TIE-BACKS & SMALL PUMP

TYPICAL WASIA WATER SUPPLY WELLS EQUIPPED WITH ESPs

FIGURE 21

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cover the damaged casing. The first workover will involve tieing the 13-3/8" casing back to surface. The 13-3/8" casing will not accept a 16" pump, therefore an 11" pump will be run. Later, if corrosion damages the 13-3/8" casing, the option exists to tie the 9-5/8" casing back to surface as shown by the well configuration on the right side of Figure 20. In this case the 9-5/8" casing will not accept an 11" pump, therefore the smallest pump, the 7" can be run. Saudi Aramco maintains a wide selection of water pump sizes to accommodate the different casing strings. Pumps as small as 7", 30 HP up to 16", 600 HP are available. The 600 HP pump is capable of 3000 gpm capacity. A list of available pump sizes are shown at the right.

Pump size 7" 10" 11" 15" 16"

Maximum stages 24 15 12 5 6

B. GAS LIFT WASIA WATER SUPPLY WELLS Several Wasia wash water supply CONDUCTOR wells in the Uthmaniyah area are gas lifted rather than pump driven. The advantages of gas lift over a 7 X 9-5/8 PROD TBG pump design are lower installation 7" GAS LIFT VALVE and maintenance costs. The 18-5/8" CSG completion typically includes 7" (or 7" X 9-5/8" combination) production tubing, a 9-5/8" type 'PW' production packer and a 7" gas lift valve at approximately 500' (see 13-3/8" CSG Fig. 22). To reduce sand 9-5/8" PROD PKR production, a 7" screen liner is normally run across the sandstone 9-5/8" PROD CSG reservoir. 7" SCREEN LINER

II. UER WATER SUPPLY WELLS TYPICAL GAS LIFT The UER (Umm Er Radhuma) WASIA WATER SUPPLY WELL reservoir is a large fresh water aquifer FIGURE 22 often used for drinking water supply, drilling rig water supply or other services requiring fresh water. The depth of this formation is relatively shallow, ranging from 700' to 1200'. The Khobar aquifer, another fresh water zone above the UER exists in many areas and can be used for the same purpose. Page 21

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The UER water supply wells are normally completed with an 18-5/8" conductor casing, 13-3/8" production casing and 12-1/4" open hole. Since the static fluid level is usually below ground level, a submersible pump driven by a diesel engine on surface is used. Total dissolved solids (TDS) are monitored for water quality. If for some reason the UER TDS value is high, the option is available to perforate and recomplete the well as a Khobar water supply well. In this case the UER is plugged with cement and the Khobar is perforated.

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TABLE OF CONTENTS INTRODUCTION..........................................................................................................1 COMPLETION OBJECTIVES ...................................................................................1 • Production/Injection: .....................................................................................1 • Safety and Environment:................................................................................1 RESERVOIR COMPLETION INTERVAL ...............................................................2 • Interval Depth ................................................................................................2 • Reservoir Pressure .........................................................................................2 • Reservoir Temperature ..................................................................................2 • Reservoir Fluid ..............................................................................................2 • Reservoir Fluid Chemistry.............................................................................2 COMPLETION TUBING DESIGN CONSIDERATIONS .......................................3 • Tubing Diameter ............................................................................................3 • Tubing Connection Types..............................................................................3 • Tubing Metallurgy .........................................................................................3 COMPLETION PACKER DESIGN CONSIDERATIONS .....................................4 • Permanent Packers .........................................................................................4 • Retrievable Packers........................................................................................4 • Polished Bore Receptacle (PBR) ...................................................................4 WIRELINE COMPLETION DESIGN CONSIDERATIONS ..................................4 COMPLETION FLEXIBILITY CONSIDERATIONS .............................................4 • Production Testing .........................................................................................5 • Through-Tubing Operations ..........................................................................5 • Recompletion Flexibility ...............................................................................5 • Stimulation.....................................................................................................5 • Sand Cleanout ................................................................................................5 • Reservoir Changes .........................................................................................5

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INTRODUCTION The first oil wells were drilled with cable tools and casing was not usually run except near the top of the well. When an oil producing zone was encountered the well would fill with oil. If there was enough pressure, the oil would blow out and be allowed to produce in that manner. Safety and the environment were not considered. Completion decisions were much simpler years ago than they are today. For non-flowing wells the only logging tool available was the bailer. Cuttings were taken and a strip log was prepared from a visual examination of the cuttings. The fluid characteristics were evaluated. If hydrocarbons were present, then a pump would be run. Flowing wells were evaluated, usually some distance away from the rig, by estimating the height of the fluid above the crown after the tools were blown out of the hole. Completion methods have greatly improved since those days. With drilling costs exceeding millions of dollars per well, a good completion design is very important. Operators today are faced with a multitude of completion options and equipment to solve today's problems. This chapter will review the basic well completion criteria and will focus on the 'inner portion' of the completion (inside the production casing). The basic open hole vs cased hole completion criteria is covered in the chapter entitled "Well Completion Types".

COMPLETION OBJECTIVES The basic well completion objectives are summarized as follows: •

Production/Injection: Completion design should enable efficient and cost effective production/injection of the well. Observation wells, which monitor reservoir parameters and do not normally produce, should also be designed with the goal of obtaining the required reservoir data at a minimum cost. Completion design flexibility allows wells completed today the option for recompletion in the future if required.

•

Safety and Environment: Completion design should enable safe production/injection of the well with the least environmental impact as practical. It should be strong enough to withstand all of the forces and movements that occur during the life of the well since the completion string is the primary mechanism for containing the reservoir fluids and pressures.

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RESERVOIR COMPLETION INTERVAL The completion interval is decided by the reservoir engineer and reservoir geologist often in consultation with the drilling/workover completion engineer. The completion engineer will require the following basic information about the completion interval: •

Interval Depth Interval depth will affect the tensile properties of the completion string. Deep wells require long tubing strings with high tensile strengths to support the high axial loads near surface. Special weights and/or grades may be required. Premium tubing connections may be required instead of the standard API threads. Shallow wells can normally be accommodated with relatively light weight - low grade tubulars with standard EUE tubing connections.

•

Reservoir Pressure Reservoir pressure will affect the pressure rating of the completion string. High pressures dictate higher tubing weights and/or grades. Premium connections with metal-to-metal seals may be required. Along with interval pressure, the interval permeability can be used to determine the well producibility. The fluid production rate can be estimated and used to determine the tubing size required.

•

Reservoir Temperature Reservoir temperature may require special elastomers for the tubing and packer seals. Deep, hot wells require tubing movement and stretch calculations to determine seal movement, buckling and tubing to packer forces during the different modes of operations.

•

Reservoir Fluid Reservoir fluid will influence the size of the tubing string. Some oil producers with a high water cut have died due to the low velocity in large tubing strings. A smaller tubing will maintain a higher velocity and carry the water out of the well more effectively. High rate gas wells, such as the Khuff, have required large tubing sizes to stay below the erosional velocity limit.

•

Reservoir Fluid Chemistry Reservoir fluid chemistry may contain corrosive agents or hydrogen sulfide. Completion metallurgy and yield strength may require adjustment for these conditions.

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COMPLETION TUBING DESIGN CONSIDERATIONS The tubing string provides a conduit between the reservoir and wellhead. Since the tubing string is retrievable, it can be recovered and repaired or replaced as necessary. For oil and gas producers, the tubing string is normally accompanied with a production packer. Most water injectors, on the other hand, do not have any tubing at all. The exceptions are the horizontal injectors which have a tubing string which acts as a coiled tubing guide string. Coiled tubing operations are required on the horizontal water injectors to run logs and stimulation work. Calculations have shown that without this guide string, a coiled tubing would buckle and not be able to reach the total depth of the well. When designing a tubing string the following areas are addressed: •

Tubing Diameter Tubing diameter is determined from well deliverability calculations which show the relationship between reservoir pressure, permeability, flowing bottom hole pressure, flowing wellhead pressure, and production rate. The need for large formation fracture treatments may dictate that larger size tubing be set in a well. The maximum tubing size which can be accommodated is dictated by the size of the production casing. New wells with 9-5/8" casing can accommodate 7" tubing sizes, however older wells which have had 4-1/2" liners run, are normally restricted to 2-3/8" completion tubing strings.

•

Tubing Connection Types Tubing connection types can be standard API or a premium type connection. Low pressure, shallow wells typically receive inexpensive 8 Round or EUE (external upset end) connections. Although most of Saudi Aramco completions which have 3-1/2" (or less) tubing sizes have EUE connections, some Khuff gas completions have a 31/2" premium connection to contain the high pressure and axial load. Most oil and gas producers in Saudi Aramco are equipped with 4-1/2" tubing sizes. These wells have standardized on the VAM premium connection due to its superior sealing capability and joint strength.

•

Tubing Metallurgy Tubing metallurgy is important in corrosive or H2S environments. For Saudi Aramco the L-80 grade is a common tubing grade which has good corrosion and H2S resistance for typical oil and gas producers. Page 3

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COMPLETION PACKER DESIGN CONSIDERATIONS Completion packers isolate the producing reservoir from the casing and allow the tubing casing annulus to be filled with a corrosion resistant packer fluid to prolong the life of the production casing. There are three basic types of packers to choose from: •

Permanent Packers Permanent packers can be set either by drill pipe or wireline and are retrieved from the hole by milling operations. These packers are common in corrosive, deep, or high pressure applications.

•

Retrievable Packers Retrievable packers can be set with either the tubing or drill pipe and is retrieved with either the tubing or drill pipe. These packers are common in shallow, non-corrosive, light duty application.

•

Polished Bore Receptacle (PBR) A PBR completion is a specially honed seal nipple which is run as part of a liner or casing string. This type of completion eliminates the need for a production packer. The completion tubing seal assembly is stung into the PBR which is anchored in the wellbore (usually at the top of the liner hanger). Several Khuff gas completions are equipped with a PBR.

WIRELINE COMPLETION DESIGN CONSIDERATIONS Wireline completion items are common in modern wells. Sliding sleeves, which can be opened or closed by wireline tools simplify procedures to circulate a well during workovers. Landing nipples in the tubing and tailpipe permit flow control or accommodate production instruments. Wireline tools can be used to run and land amerada bombs which are often required during well testing operations. Subsurface safety valves are used extensively offshore which will safely shut in the well down hole in the event of mechanical problems at the wellhead or on the production platform.

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COMPLETION FLEXIBILITY CONSIDERATIONS It is important to consider options which may be required in the future. Some of these are: •

Production Testing Will production tests be carried out in the future and will landing nipples and a perforated joint be required to accommodate the amerada pressure bombs?

•

Through-Tubing Operations As the oil/water contact rises will through-tubing bridge plugs (or other tools) be used and will the completion be able to accommodate them. Will additional perforations be made and is the completion packer and tailpipe positioned so as not to obstruct the perforating operation.

•

Recompletion Flexibility In many cases a well completed as a producer today may be used as an observation well in the future when the flood front advances. Will the completion be able to satisfy the requirements later as an observation well? Is the tubing, packer and tailpipe large enough to accommodate the future logging tools? Large diameter logging tools (such as the 3-5/8" Carbon-Oxygen log) are run on many of the observation wells.

•

Stimulation Will the completion accommodate future stimulation pressures and temperature changes? This was a major consideration for Saudi Aramco's Khuff gas completion program.

•

Sand Cleanout Will the completion accommodate possible coiled tubing and sand cleanout operations?

•

Reservoir Changes Will the completion account for possible increases in gas/oil or water/oil ratios?

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SECTION CONTENTS

PAGE i

CONTENTS

PAGE 1

WELLHEAD SYSTEM WELLHEAD FUNCTION TREE FUNCTION TUBULARS TYPICAL WELLHEAD CASING HEAD CASING SPOOL TUBING HEAD TUBING BONNET TREE ASSEMBLY

PAGE 13

TREES MASTER VALVES FLOW TEE WING VALVE CHOKE CROWN VALVE VALVE OPERATION TESTING THE TREE FIRE RESISTANT TREES

PAGE 17

SUSPENSION METHODS CASING SUSPENSION AUTOMATIC TYPE MANUAL TYPE MANDREL TYPE

PAGE 23

OTHER WELLHEAD EQUIPMENT TUBINGLESS WELLHEADS WATER SUPPLY WELLHEADS INJECTION WELLHEADS

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PAGE 27

FLANGES AND SEAL CONNECTIONS FLANGES OVAL AND OCTAGONAL RING GASKETS RX RING GASKET BX RING GASKET RESILIENT SEALS PRESSURE TEMPERATURE RATINGS

PAGE 31

WELLHEAD DESIGN CONSIDERATIONS CASING PROGRAM METALLURGICAL SPECIAL APPLICATIONS API PRESSURE RATINGS PRESSURE REQUIREMENTS DOUBLE STUDDED PACKOFF FLANGES

PAGE 39

EQUIPMENT SPECIFICATIONS INDUSTRY SPECIFICATIONS SAUDI ARAMCO SPECIFICATIONS SERVICE ENVIRONMENTS HYDROGEN SULFIDE

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SECTION:

WELLHEAD SYSTEM

Every type of oil or gas well has some type of wellhead. Conventional wellhead assemblies include the casing head, casing hangers, casing spool sections, tubing bonnet, tubing hanger, valves and fittings. (See Figure 1)

TREE

WELLHEAD

Figure 1: The Wellhead

WELLHEAD FUNCTIONS:

The wellhead performs three important functions: • It provides connection and support for blowout preventers and other well control equipment •

It provides a sealed connection and support for each tubular string

•

It provides a connection and support for the tree. Page 1

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TREE FUNCTIONS:

TUBULARS:

The tree, in turn, performs several important functions: •

It controls the flow of fluids from the wellbore;

•

It provides a means of shutting in the well;

•

It provides a means of entering the well for servicing and workover.

The wellhead is divided into sections. Each section of the wellhead will be used to suspend and/or seal off a separate string of casing or tubing. Therefore, the number of wellhead sections will vary with the number of tubular strings. The tubular strings in a well are the conductor pipe, the surface casing, the protective (intermediate) casing, the production casing and the production tubing (see Figure 2). In some wells, where formation conditions do not place extreme loads on the surface casing, the protective string may not be required. In other wells, usually where abnormally pressured formations are encountered, additional strings of casing may be necessary. In a tubingless well, the production tubing is omitted. A common wellbore configuration, sometimes called a three string well, will make use of each of the above strings. The three strings referred to are the surface casing, protective casing, and the production casing. Each of these strings will be attached to and supported by a section of the wellhead. These connections must be effectively sealed to contain pressures within each string. The conductor pipe, which may be set or driven, maintains the integrity of the walls of the shallow, unconsolidated formations. It is not normally attached to the wellhead because it is exposed to minimal pressure. However, in some cases, a base plate may be welded onto the casing head and placed on top of the conductor pipe in order to distribute the weight of the casing and wellhead (Figure 3). When extreme loading conditions are expected, the plate provides additional support and stability.

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WELLHEAD SYSTEM

CONDUCTOR PIPE

SURFACE CASING

INTERMEDIATE CASING

PRODUCTION CASING

PRODUCTION TUBING

PRODUCING FORMATION

Figure 2: The Tubular Strings

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WELLHEAD SYSTEM

CASING HEAD

WELD

WELD GUSSET

BASE PLATE

SURFACE CASING

WELD

WELD

SURFACE CASING

CONDUCTOR PIPE

Figure 3: The Casing Head with a Base Plate

TYPICAL WELLHEAD:

The typical wellhead for a three string well will consist of (Figure 4): •

The Casinghead (sometimes referred to as the Landing Base or Bradenhead);

•

The Intermediate Casinghead (or Casing Spool);

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WELLHEAD SYSTEM •

The Tubing Head (or Tubing Spool)

•

The Tubing Bonnet and

•

The Tree.

TREE

TUBING BONNET

TUBING SPOOL

INTERMEDIATE CASING HEAD

CASING HEAD

Figure 4: A Three String Wellhead

CASING HEAD:

The casing head is attached to the top of the surface casing (Figure 5). Since the other tubular strings are tied to the casing head, the surface casing must support the weight of all the subsequent casing strings, and the entire wellhead system.

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WELLHEAD

SECTION:

WELLHEAD SYSTEM CASING STUB CASING HANGER

CASING HEAD

BASE PLATE

CONDUCTOR PIPE

SURFACE CASING

CASING - HOLE ANNULUS

CEMENT

INTERMEDIATE CASING

Figure 5: The Casing Head

The casing head is screwed or welded onto the surface casing. The base plate is welded to the conductor pipe and to the casing head. The casing head accepts the next string of casing; either a protective string or the production string depending on the needs of the well. The next string of pipe is hung by means of a casing hanger in the casing head.

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WELLHEAD SYSTEM

The intermediate string is hung in the casing head with a casing hanger and cemented in place. The casing hanger not only holds the intermediate casing but it seals the casing - casing annulus. Hangers are discussed in more detail later in this chapter. The space between any two strings of pipe is called an annulus. The space between the surface casing and the wall of the hole is designated as the "casing - hole annulus" (Figure 5). When the surface casing is set, the casing - hole annulus is filled with cement, which (1) eliminates potential contamination of fresh water zones behind the surface casing, (2) prevents flow between pressured formations behind the surface casing and (3) provides additional stability of the casing string. CASING SPOOL

The casing spool, is bolted onto the casing head (Figure 6). It can be used to suspend either the production casing string, as shown, or an additional string of protective casing. For each additional protective string, an additional casing spool is required. CASING STUB

CASING SPOOL

CASING HEAD

SURFACE CASING

INTERMEDIATE CASING

PRODUCTION CASING

Figure 6: The Casing Spool

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WELLHEAD SYSTEM

The casing spool consists of a lower flange for connection to the casing head and an upper flange for connection to the subsequent wellhead section. A cylindrical bore with shoulders is milled into the upper half to receive the casing hanger. The casing spool contains a primary seal (the casing hanger) inside the top flange and a secondary seal (the packoff bushing) located inside the lower flange (Figure 7). The names primary seal and secondary seal was derived from a pressure change situation. If the casing spool has a 3000 psi bottom flange and a 5000 psi top flange, the casing hanger seal is the first seal to prevent the 5000 psi fluid from getting to the 3000 psi flange face. The packoff bushing is the second preventive seal. The secondary seal performs essentially the same function as the primary seal of the casing head. Aramco has two wellhead manufacturers supplying wellhead material. Each system has its own secondary seals. Cooper (makes Cameron & McEvoy) supplies an X-bushing and Vetco Gray supplies an AK bushing. The AK bushing is redesigned from the original CWC bushing so that regardless of which spool is installed, the casing stub (Figure 6) is cut to the same height for the Vetco Gray spool as for the Cameron or McEvoy spool. RING GASKET

RING GASKET GROOVE CASING HANGER

TEST PORT

INJECTION PORT

RING GASKET GROOVE SECONDARY SEAL

Figure 7: The Casing Spool with Secondary Seal

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WELLHEAD SYSTEM

A ring gasket, made of a special metal alloy, is placed between all flanged connections. The ring gasket fits into specially machined grooves in the upper flange of the casing head and the lower flange of the intermediate casing head. The gasket serves to contain pressures in the wellhead in the event that either or both the primary and secondary seals should fail. Each ring gasket is designed to withstand a maximum pressure that the tubulars will be exposed to during the life of the well. A further explanation of ring gaskets and pressure ratings is discussed later. The side outlets on the casing spool are used to check and relieve pressure inside the casing - casing annulus. TUBING HEAD:

The tubing head suspends the production tubing and seals off the tubing casing annulus (Figure 8). Like the casing spool, the tubing head includes a secondary seal and side outlets. The top flange of the tubing head is used to connect blowout preventers during conventional workover operations; that is, workovers that require pulling the tubing. The lower flange connects to the top flange of the section below it. A ring gasket is also used between the flanged connections. POLISHED NIPPLE

TUBING HEAD TIE DOWN PIN TUBING HANGER

PRODUCTION CASING TUBING

Figure 8: The Tubing Head

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SECTION:

WELLHEAD SYSTEM

The tubing hanger assembly (Figure 8) performs essentially the same function as the casing hanger; i.e., it suspends the tubing and seals off the tubing - casing annulus. Virtually the full weight of the tubing string is supported by the tubing hanger. The tubing hanger is usually equipped with a polish nipple to seal inside the tubing bonnet (Figure 10). However, sometimes the tubing hanger is equipped with an extended neck which is an integral part of the hanger. The polish nipple is a separate item threaded into the tubing hanger. The side outlets of the tubing head can be accessed to (1) inject a fluid into the tubing casing annulus, as in a gas lift operation; (2) monitor annulus pressure; (3) test annulus for leaks; (4) relieve pressure in the tubing - casing annulus; and (5) supply an exit for the sub surface safety valve control line. The tie down pins serve to secure the tubing hanger in the spool. If the tubing is attached to a downhole packer, there is a possibility that the tubing will expand under flowing conditions causing a force large enough to break the seal between the hanger and the spool. For a more detailed view of a tubing hanger refer to figure 17. TUBING BONNET:

The tubing bonnet is the equipment which allows the tree to be attached to the wellhead. It has a sealing mechanism, extended neck or polish nipple, which keeps wellbore fluid from coming in contact with the tubing head or the tubing hanger. The tubing bonnet configuration is usually equipped with studs on top and a flange on the bottom although it can be supplied flange by flange or stud by stud. Ring gaskets are installed on top and on the bottom.

Page 10

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEAD

SECTION:

WELLHEAD SYSTEM

TUBING BONNET

TUBING HEAD TUBING HANGER WITH POLISH NIPPLE

PRODUCTION CASING TUBING

Figure 10: Tubing Bonnet and Polish Nipple

TREE ASSEMBLY:

The tree is a system of gate valves that regulates the flow of fluids from the well, opens or shuts production from the well, and provides entry into the well for servicing. The tree is connected to the uppermost flange of the wellhead which typically is the upper tubing head flange. A typical tree includes several gate valves, a flow tee and a tubing bonnet (Figure 11). This system routes well production into the flow line. The flow line then conducts the fluids from the tree to surface treating facilities. Figure 11 illustrates an Aramco offshore tree and an onshore tree. The only difference is the onshore tree does not have the hydraulic master valve.

Page 11

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEAD

SECTION:

WELLHEAD SYSTEM Page 12

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

TREES

Trees are available as either composite (Figure 11) or block (Figure 12) construction. Composite trees indicate they are a composition of valves and flow tees that are bolted together. On the other hand , a block tree is machined out of a single piece of metal. Aramco Khuff trees are a composite block system (Figure 13).

TREE CAP

WING VALVE

UPPER MASTER VALVE

LOWER MASTER VALVE BLOCK WITH VALVES

Figure 12: Block Tree Assembly

Page 13

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

TREES

TREE CAP

MANUAL CROWN VALVE

HYDRAULIC WING VALVE WYE BLOCK

WING VALVE

BLOCK WITH TWO(2) HYDRAULIC VALVES

BONNET WITH MANUAL LOWER MASTER VALVE Figure 13: The Khuff Tree Assembly

Page 14

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

TREES

MASTER VALVES:

The master valves are used to close in the well to allow servicing the wing valves and crown valve, or to allow connection of treatment lines, lubricators and wireline blowout preventers. Two master valves are installed in high pressure (5000 psi and above), offshore and populated area wells. The lower master valve is a backup for the upper master valve. Valves used on trees and wellheads are subject to special requirements. Master valves and other valves in the vertical flow path of the tree must have full bore, round openings to allow passage of tools. As a result, wellhead master valves are gate valves. Round opening gate valves are specified for this service with API flanged end connections. Various types of valve operating mechanisms are available and individual well requirements will determine this need. Location and safety aspects of well operation should be considered when selecting valve operators (i.e., manual. hydraulic and pneumatic).

FLOW TEE:

The flow tee or flow wye connects immediately above the upper master valve. They are used to connect the upper master valve to the crown and wing valves.

WING VALVE:

The wing valve like the master valve is used to close in the well. Located between the tee and the choke, it is the first valve closed when shutting in the well and the last one opened when production is restarted.

CHOKE:

Connected between the wing valve and the flow line, the choke regulates the flow of fluids from the wellbore. Chokes come in adjustable or fixed. Adjustable chokes can alter the flow rate without shutting in the well. The fixed choke can only be altered after the well has been shut in.

CROWN VALVE:

The crown valve (also a gate valve), connected to the top of the flow tee, is sometimes referred to as the swab or wireline valve. A threaded tree cap is flanged to the top of the crown valve. In wireline or swabbing operations, a wireline lubricator is connected to the top of the tree cap. The lubricator provides an hydraulic seal around the wireline which prevents the escape of pressured

Page 15

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

TREES

liquids while the wireline is in the well. The crown valve is closed while installing the lubricator and then opened to allow wireline entry into the well. Frequently a pressure gauge will be attached to the tree cap (Figure 13). This pressure gauge is used to monitor either the flowing wellhead pressure or the static wellhead pressure with the wing valve closed. VALVE OPERATION:

The tree is operated by opening or closing the valves in a specific order. When shutting in the well the first valve closed is the wing valve. The upper master valve is then closed, followed by the lower master valve. The lower master valve is closed last to ensure that it is not closed against differential pressure; thus saving the valve seats from excessive wear. In a well control situation, this valve may be the last available valve to shut in the well so its integrity should be preserved until the valve is needed.To reopen the flow stream, the procedure is reversed, starting from the lower master valve and ending with the wing valve.

TESTING THE TREE:

The tree is pressure tested for leaks after it has been flanged on the tubing head or the casing head.The tree is normally assembled and pressure tested as a complete unit prior to being flanged onto the wellhead and pressure tested again after installation. Each connection is tested to the specified rating of the tree. In the field, a small hydraulic pump is used to test the connection between the tubing bonnet and the tubing head. A light oil is injected into a port on the upper flange of the tubing head. The pressure is increased until the desired maximum is reached. If the pressure does not hold steady after waiting a few minutes, flange bolts are retightened and the test is repeated.

FIRE RESISTANT TREES:Fire resistant trees are sometimes required and are of the block type. However, they differ from the normal block tree in that clamps are used instead of stud bolts to secure the tree and the seals are metal to metal to prevent deterioration in the event of a fire.

Page 16

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September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

Suspension or hanger assemblies are used to suspend the casing or tubing in a particular casing or tubing head as is shown in figures 6, 8, &10. CASING SUSPENSION: The casing hangers used in Aramco operations are the slip pack type which there are two general categories: (1) those that may be set and sealed without removing blowout preventers (the automatic type), and (2) those that may be set through preventers but require removal of the preventers to establish a seal(manual type). The type chosen depends upon operating conditions. The automatic type need a minimum amount of weight to energize the seals. If that weight is not available a manual hanger must be used. Either of these categories of hangers will permit setting casing at desired depths without the use of space nipples. Examples of the two types are shown in figures 14, 15, and 16. AUTOMATIC TYPE:

The automatic seal wrap around controlled suspension hanger is hinged and may be installed on the casing landing joint by wrapping around the pipe and lowering or dropping through the blowout preventers into the casing head. When the weight of the casing to be suspended is transferred to the hanger slips and to the casing head, the seal is expanded. These hangers are designed for heavy casing loads.

MANUAL TYPE:

With the manual seal with wrap around slips, the slips are lowered through the preventers to suspend the pipe, but the seals are energized only after removing the preventers. The seal is expanded by set screws on the top of the packing. This type, which is generally the lowest cost slip pack hanger, is recommended for short casing strings that do not have enough weight to energize automatic hanger seals.

MANDREL TYPE:

The threaded mandrel hanger is commonly called a "boll weevil" hanger. It can be used on casing but Aramco uses it primarily with tubing. An example is shown in Figure 17. Refer to Figure 10 for the example of an assembled tubing hanger in the tubing spool. The hanger is sent to the field with a pup joint screwed into the bottom. The hanger and pup joint are assembled to the tubing string and then landed with a landing joint. Since the weight of the

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SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

tubing bears down on the hanger seals no other energizing method is necessary. Lock screws or tie-down screws are still tightened to secure the seal. After the tubing is suspended and sealed off, the landing joint is backed off, a back pressure valve(BPV) is installed (the hanger has an internally machined profile designed to accept a back pressure valve) and the blow out preventers are removed. A polish nipple is screwed into the hanger and the bonnet, which will pack off on the polish nipple, is bolted to the tubing spool and then the tree is bolted to the bonnet. The reason for the polish nipple is to keep the well pressure and production fluids away from the ring gasket. Once the tree has been flanged up and pressure tested the BPV is removed. The BPV is used as a well control backup on wells that have been killed prior to workover or completion. The use of the BPV assures that pressure in the tubing is safely contained while nippling up or nippling down the tree and workover BOP's. On Khuff gas wells the tubing hanger does not have a polish nipple screwed into it. The tubing hanger has a metal to metal seal extension referred to as an extended neck. Therefore the whole unit (Figure 18) is called an extended neck hanger. There are other methods of suspending tubulars, in particular tubing, but they are not practiced by Aramco. There is the threaded tubing head adapter, the threaded tubing head adapter with a mandrel sealing element and the double box method.

Page 18

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

GUIDE STRAPS SLIPS ALIGNMENT PINS SLIP BOWL

SLIP RETAINING SCREW SEAL ELEMENTS

COMPRESSION RING

HANDLE

Figure 14: Automatic Casing Slips

CAP SCREW

GUIDE STRAPS

COMPRESSION RING SEAL CAP SCREW SLIP BODY SLIPS

Figure 15: Manual Casing Slips

Page 19

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

PRODUCTS

A

PRODUCTS

EST. WT. 172 LBS `ALL DIMNS REF. ONLY'

Casing Hanger, 12.00-9.5/8" SA

UDI

A RA M

SA

CO

UDI

A RA M

CO

Casing SB-3A

A SECTION B-B 11

ITEM QTY 6 9 ø 13.47" ø 9.72"

7 1 2 3

10.62"

5 8 B

B 4 SECTION ON A-A

DESCRIPTION

1 2

1 1

Casing Hanger Top Casing Hanger Packing

3 4 5 6 7 8 9 10 11

1 1 1 2 12 4 4 4 2 1 1 1

Packing Retainer Ring Slip Bowl Casing Hanger Slips Casting, Casing Hanger Handle Cap Screw, 0.625" UNC-3.25" Steel Csk Screw, 0.312" UNC-1.00" Steel Csk Screw, 0.375" UNC-0.75" Steel Slip Retainer Pin 0.316" O.D.-1.00 Latch, Stain Wrench, 3/16" Hexagon Wrench, 7/32" Hexagon Wrench, 1/2" Hexagon

10

CASING HANGER, TYPE 'SB-3-A', 12" BOWL X 9.5/8" OD CASING,NACE.

ARAMCO STOCK NUMBER: REV. DATE JAN.'92

ARAMCO STOCK NUMBER: API. 6A LATEST EDITION

REV. DATE JAN.'92

API. 6A LATEST EDITION

Figure 16: Automatic/Manual Casing Hanger

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

CAMERON IRON WORKS LTD.

LEEDS, ENGLAND. EST. WT 180 LBS.

ø10.898" SA

UDI

A RA M

CO

4.1/2" API Casing Threads. Body. Part Number 218084-08. (1 Required.)

12.312" Seal. Part Number 641179-01 (2 Required.)

4.3/32" O.D. Left Hand Type `H' B.P.V. Threads. 2.75"

4.1/2" VAM Casing

4.005" Min Bore

Threads. 6.00"

`FBB' TUBING HANGER (PART NUMBER 23486-08.) 11" NOMINAL x 4.1/2" O.D. CASING. WITH 4.1/2"I TUBING THREADS: API TOP & VAM BOTTOM. & 4.3/32" TYPE `H' BACK PRESSURE VALVE THREADS.

ARAMCO STOCK NUMBER:

45-829-148

REV. DATE APR.'90

Figure 17: Mandrel Tubing Hanger

Page 21

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

SUSPENSION METHODS

1 Tubing Bonnet 3-1/16" x 11" 10M 2 Extended Neck Hanger 3-1/2" 3 Tubing Spool 11" 10m x 13-5/8" 10m

1 2

3

Figure 18: Extended Neck Hanger

Page 22

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September 2006 CHAPTER:

WELLHEADS

SECTION:

OTHER WELLHEAD EQUIPMENT

In addition to the onshore tree and the offshore tree (figure 11), there are other configurations that Aramco uses. TUBINGLESS WELLHEADS:

In a tubingless completion, the oil or gas is produced through the production casing without the production tubing being installed. The casing is packed off in the bottom of the bonnet. Unless there is a kill string installed, these type of completions can only be killed by bull heading kill fluid or by stripping through BOP's therefore they should not have very much shut in pressure.

WATER SUPPLY WELLHEADS:

The water supply wells are used to produce water from the Wasia formation to be used in other formations to keep formation pressure constant. The water supply well head consists of a casing head, tubing hanger, bonnet valve combination and an elbow (Figure 19). The elbow has a riser and valve attached to it normally to measure fluid level if the well does not flow. If it does not flow fast enough or does not flow at all there is an electric submersible pump (ESP) installed to help it. These wells will normally deliver 60,000 to 80,000 barrels per day. There a few wells that deliver more than 100,000 barrels per day.

INJECTION WELLHEADS:

Injection wells in Saudi Arabia are used for reservoir pressure maintenance and for the disposal of salt water from water - oil separators. There are two types of injection wellheads used in Aramco. The first is illustrated in Figure 20 and the second is similar to a production wellhead in Figure 1. The injection water line is connected to the wing valve and water is pumped down the casing to the required formation. In wellheads similar to Figure 1 there used to be a tubing string with internal plastic coating (IPC) because this particular type well is used for salt water injection which was thought to be highly corrosive to normal steel. However, time has shown that steel does not corrode to any extent therefore the tubing string has been discontinued in these wells.

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

OTHER WELLHEAD EQUIPMENT

WELLHEAD NO. 8A WASIA WATER SUPPLY 3" 3M UNIBOLT TREE CAP

48" 3" 3M API GATE VALVE 3" RISER W/3M FLANGE

ELBOW 2MSP, 12" X 12" W/3" RISER

18"

B.J. JUNCTION BOX 44" 12" ANSI 600 GATE VALVE 3-1/2" OD JUNCTION BOX CONNECTOR W/BRACKET 20 SW X 21-1/4 CSG HD W/ 20" CASING STUB

41-1/2" 3" ANSI 600 GATE VALVE

WH-8A.DWG SA

18-5/8" CASING

92/10/26.mek UDI

A RA M

CO

Figure 19: Wasia Water Supply Wellhead

Page 24

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

OTHER WELLHEAD EQUIPMENT

WELLHEAD NO. 6 RECOMMENDED WELLHEAD

POWER WATER INJECTOR W/9-5/8" CASING

3" 3M UNIBOLT

10" 3M BALL VALVE TREE

8" 3M BALL VALVE 10" 3M BALL VALVE

86.28"

2" 3M BALL VALVE

13-3/8" X 13-5/8" CASING HEAD 25.25"

2" 3M BALL VALVE

13-3/8" CASING WHNO-6.DWG 92\03\31.RLL

9-5/8" CASING

Figure 20: Power Water Injection Wellhead

Page 25

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

FLANGES AND SEAL CONNECTIONS

The most common end connections used in the oil industry aside from welds and threads are flanges (Figure 21). API has standardized flanges which are covered in API Spec 6A and ASME/ANSI has standardized flanges which are covered by ASME/ANSI Spec 16.5. Because Aramco uses both API and ANSI flanges a knowledge of the similarities and differences is required. Some ANSI ring joint flanges will mate with API flanges but the pressure ratings are different.

FLANGES:

ANSI Class 600 flanges will mate to API 2000 psi, ANSI Class 900 flanges will mate to API 3000 psi and ANSI Class 1500 flanges will mate to API 5000 psi. If an ANSI flange is connected to an API flange, the connection takes the rating of the ANSI flange because of the lower pressure rating.

Temperature °F -20 to 100 200 300 400 500

RATINGS FOR GROUP 1.1 MATERIALS Working Pressure by ANSI Class psig 150 300 400 600 900 1500 285 740 990 1,480 2,220 3,705 260 675 900 1,350 2,025 3,375 230 655 875 1,315 1,970 3,280 200 635 845 1,270 1,900 3,170 170 600 800 1,200 1,795 2,995

2500 6,170 5,625 5,470 5,280 4,990

4500 11,110 10,120 9,845 9,505 8,980

Only API flanges are used on producing wellheads, trees and drilling through equipment such as blowout preventers. ANSI flanges, fittings and valves are used on water wells, pipelines, gas plants and some surface production units. OVAL & OCTAGONAL RING GASKETS:

The oval ring and octagonal ring are both API type R ring gaskets shown in figure 22. Stud bolts used with type R gaskets must perform the double duty of holding pressure while keeping the gasket compressed. When making up the flanges, the curved surface of the relatively soft oval ring is mated with the flat surfaces of the hard flange groove. A small flat is pressed on the curved section of the oval ring. The size of this flat depends on the bolting makeup tightness.

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WELLHEADS

SECTION:

FLANGES AND SEAL CONNECTIONS 24.0000

1.500" X 20 BOLT HOLES

21.000

15.47

3.44

14.53 13.66

RING GROOVE

Figure 21: API13-5/8" 3000 psi Flange

R OVAL

R OCTAGONAL

RX

BX

Figure 22: API Ring Gaskets

Page 28

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September 2006 CHAPTER:

WELLHEADS

SECTION:

FLANGES AND SEAL CONNECTIONS

As normal tightening proceeds, forces accumulate and deform the ring to produce a seal. By the time all bolts around the flange have been tightened, the first bolt is loose again. In most API flanged connections with type R gaskets, it is necessary to tighten bolts around the flange several times to reach a stable condition. The octagonal R does not have to deform as much as the oval R to create a seal. When internal pressure forces become great enough to cause flexing in an API connection using either one of the type R gaskets, the bolting contact force on the seal rings begin to decrease. If flange separation exceeds the limited resilience of the seal, leakage will occur. External shock loads such as drilling vibration add to the compressive loading of the stud bolts, to further deform the gaskets, causing leaks, and make repeated tightening necessary. The two basic faults of both oval and octagonal type R API seal ring designs is that they cannot withstand external loads properly and that internal pressure does not assist their sealing ability. RX RING GASKET:

The RX gasket (Figure 22) is a pressure energized ring which fits the standard API flange ring groove. The RX ring evolved during the development of 15,000 psi working pressure flanges. It was determined that when the ratio of the height of the ring to height of the sealing surfaces was 3 to 1 or greater, the seal was energized by pressure. Specifically , the internal pressure tended to expand the ring against the outer sides to of the ring groove with sufficient force to form a seal. To insure the initial contact is made between the sealing surfaces of the ring and the outer surfaces of the ring groove, the pitch diameter of the ring is made slightly larger than the groove. The advantages of the RX gasket are (1) less bolt load is required since the ring does not have to be crushed to effect a seal and (2) it is pressure energized. Stud bolts need to be tightened only once around to preload the gasket and start the self sealing effect. Vibration during drilling operations does not cause the RX to leak.

Page 29

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September 2006 CHAPTER:

WELLHEADS

SECTION:

FLANGES AND SEAL CONNECTIONS

BX RING GASKET:

The API type BX ring gasket has been adopted for use in 10,000 psi and greater working pressure equipment. This pressure energized ring joint gasket is for use with type BX flanges only and are not interchangeable with type R or RX gaskets. The BX flanges are designed to make up face to face at the raised face portion of the flanges. Figure 22 illustrates the BX flanges at initial contact.

RESILIENT SEALS:

Resilient seals used with wellheads in hangers and auxiliary seals are good to about 300°F. Use of O-ring seals to seal against the OD of casing and tubing is not acceptable because the OD tolerances of tubular goods are too great to obtain a dependable seal. Also, if a leak should develop, no outside means is available for additional makeup. Small clearances and dimensions between tubulars and spools have necessitated the development of lip type resilient seals that can be expanded or re-energized by injecting plastic packing. Metal to Metal seals which are better seals are beginning to be economically better than elastomers.

PRESSURE TEMPERATURE RATINGS: PRESSURE TEMPERATURE RATINGS OF METALLIC PARTS OF API WELLHEADS, VALVES AND FLANGES -20° to 250°

300°

350°

Metal Temperature °F 400° 450° 500°

550°

600°

650°

2000

1995

1905

1860

1810

1735

1635

1540

1430

3000

2930

2860

2785

2715

2605

2455

2310

2145

5000

*4880

5765

4645

4525

4340

4090

3850

3575

* Does not apply to 5000 psi 6BX flanges.

Page 30

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

Selecting the appropriate size, type and pressure rating for each wellhead flange and seal is a critical task performed in planning the well completion. The design specifications for a particular wellhead vary widely from area to area and sometimes from well to well. However Saudi Arabia is blessed with consistent requirements throughout the country. There are two major wellhead considerations. One for the Khuff completion (10,000 psi) and the other (3000 psi) for the remainder of the completions. 2000 psi completions are possible but the 2000 psi equipment costs the same as the 3000 psi equipment therefore Saudi Aramco has standardized on 3000 psi equipment. The weight , size, number and metallurgy of the wellhead components will depend upon the following considerations. CASING PROGRAM:

The number of wellhead sections required is dependent upon the number of casing strings in the well. The casing head accommodates the surface and first protective casing string. Each casing diameter will influence the size of the casing hanger and casing head and casing spools required.

METALLURGICAL:

The conditions in Saudi Arabia require hydrogen sulfide, carbon dioxide and amine inhibitor protection for production wells.

SPECIAL APPLICATIONS:

The installation of artificial lift equipment or the conversion of a producing well into an injection well may require special equipment or connections to be installed in the wellhead. A gas lift system, for example, requires the injection of gas into the tubing casing annulus. For a submersible pump system, the power cable passes through a special conduit in the wellhead to the downhole motor of the pump (Figure 23). Installation of a surface controlled subsurface safety valve (SCSSSV or SSSV) usually requires an hydraulic line that is run from the surface to the downhole valve. Like the submersible pump, the SSSV requires a special hookup to allow passage of the hydraulic line through the wellhead.

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September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

BONNET

SPECIAL CONDUIT

TUBING HANGER

Figure 23: Submersible Pump Tubing Bonnet & Hanger

API PRESSURE RATING: Standard working pressures for flanged wellhead equipment are: 2,000, 3,000, 5,000, 10,000, 15,000 and 20,000 psi. Each flange less than 10,000 psi is tested to twice its working pressure and each flange greater than 5,000 psi is tested to 1.5 times its working pressure (Table 1). Table 1: API Working Pressure Ratings* Working Pressure Rating (psi) 2,000 3,000 5,000 10,000 15,000 20,000

Test Pressure (psi) <16 in. 4,000 6,000 10,000 15,000 22,500 30,000

Test Pressure >14 in. 3,000 4,500 10,000 15,000 -------

*API Spec 6A Table 605.10 - Hydrostatic Body Test Pressure - Sixteenth Edition, October 1 1989 p. 50

Page 32

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September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

PRESSURE REQUIREMENTS:

The pressure rating of each section of the wellhead must be sufficient to control the maximum working pressure that is expected to be encountered (that is, the maximum shut in, injection or treating pressure the equipment will be subjected to). Formation pressures normally increase as drill depth increases and each subsequent casing string is subjected to higher bottom hole pressures. To match these pressure increases the pressure rating of the wellhead components must also increase (Figure 24). The wellhead rating should be higher than the maximum pressure it is expected to see during the life of the well.

10,000 PSI RATING

5,000 PSI RATING

3,000 PSI RATING

Figure 24: Wellhead Working Pressure Ratings

Essentially each wellhead section has its own built in safety factor. In all wells, the pressure rating of the uppermost section of the wellhead is used to categorize the wellhead. Casing head

Page 33

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

sections are normally rated at 3,000 psi because surface strings are normally set to shallow depths and are exposed to minimal pressures. As previously mentioned, a 2,000 psi casing head section used to be the normal starting pressure. Wellhead sections rated at 10,000 psi are found on Khuff wells in Saudi Arabia and 5,000 psi equipment is only found on Khuff trees to transition from 3,000 psi to 10,000 psi. As noted previously, each casing head contains a casing hanger assembly (Figure 25). The casing hanger assembly consists of a set of slips with built in seals. The primary seal is contained in the assembly and seals off the annulus of the string suspended in it. These seals may be automatically compressed by the weight of the string or they may be compressed by tightening lock screws in the top of the slips.

Page 34

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September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

DOUBLE STUDDED PACKOFF SECONDARY SEAL CASING SPOOL PRIMARY SEAL

CASING SPOOL SECONDARY SEAL DOUBLE STUDDED PACKOFF SECONDARY SEAL CASING HEAD PRIMARY SEAL

Figure 25: Primary and Secondary Seals

Page 35

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

SECTION:

WELLHEAD DESIGN CONSIDERATIONS

Secondary seals (Figure 26) contained in the lower flange of casing spools and tubing spools serve as a pack off. They fit around the end of the casing joint suspended in the hanger immediately below. As such, the secondary seal performs essentially the same function as the primary seal located in the flange below. PORT FOR PLASTIC

1

BUSHING METAL

2

ELASTOMER SEAL

4

"O" RING SEALS

5

WIRE SNAP RING

4-1/8" 3

&

11-3/8"

AK Bushing without Elastomers

1

ø11-3/8"

3

4-1/8"

4

2

5

AK Bushing with Elastomers Figure 26: Secondary Seal

Page 36

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

WELLHEADS

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WELLHEAD DESIGN CONSIDERATIONS

As previously mentioned, Cooper supplies the "X" Bushing and Vetco Gray supplies the "AK Bushing". The method of sealing is the same for both of them. The elastomer seal is energized with plastic packing material. The "X" bushing will fit in an "AK" bushing profile and vise versa but the Cooper plastic does not readily flow through the ports of the Gray "AK" bushing which sometimes results in seal failure. A plastic packing gun is attached to the injection port (Figure 7) and the plastic is squeezed in behind the bushing. The O-ring seals stop the plastic from going anywhere except throught the ports in the bushing. The plastic then forces the elastomer against the casing causing a seal. The pressure rating of flanges that are bolted together should be the same. For example, if the top flange of a casing spool is rated at 3,000 psi, the lower flange of the next spool should also be rated at 3,000 psi. However, one pressure jump is allowed. i.e., 3,000 psi to 5,000 psi or 5,000 psi to 10,000 psi. If the upper flange of a spool will be potentially exposed to pressure greater than 5,000 psi, it should be rated to 10,000 psi. If the upper flange of the spool below is rated to 3,000 psi then the two spools should not be connected together because the jump from 3,000 psi to 10,000 psi constitutes a double jump. A double jump is unsafe because the upper flange of the lower spool would be exposed to pressures well in excess of its rated maximum if the secondary seals of the upper spool should fail. Changing pressure ratings at the flanges of two spools can be remedied by means of a double studded packoff flange (Figure 26). The double studded packoff flange is inserted between the upper flange of the lower spool and the lower flange of the upper spool. A 3,000 psi flange cannot be directly bolted to a 5,000 psi flange because the bolt patterns and ring gasket groove are not the same. Double studded packoff flanges can also be used to have another seal between the casing hanger and the bushing if the casing hanger leaks. The ring gasket, however, remains exposed to the leaking fluid.

DOUBLE STUDDED: PACKOFF FLANGES:

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5000 PSI

SEAL ACTUATING

TEST PORTS

INJECTION PORTS

3000 PSI

Figure 26: The Double Studded Packoff Flange

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Five wellhead specifications are often referenced within Aramco in the design of wellhead and tree components. They are API 6A, API 6D, NACE Standard MR-01-75, Saudi Aramco 45-AMSS-005 and the AMS number. INDUSTRY SPECIFICATIONS:

The American Petroleum Institute has published standard specifications for oil industry wellhead equipment. This publication, called API Spec 6A, Specification for Wellhead Equipment, specifies material and physical properties for wellheads. It also specifies test requirements for equipment components. The API Spec 6A is accepted world wide , and is routinely followed by all major wellhead manufacturers. API designates wellhead equipment by the following working pressures: 2,000 psi; 3,000 psi; 5,000 psi; 10,000 psi; 15,000 psi and 20,000 psi (30,000 psi is covered in API Spec 6AB). Generally speaking, the rating of any unit of wellhead equipment is governed by the working pressure of its flanged connections. For hydrogen sulfide environments, the National Association of Corrosion Engineers (NACE) has developed the NACE Standard MR-01-75 specification. It is compatible with API Spec 6A and it is intended to aid oil companies and wellhead manufacturers to select materials resistant to sulfide stress cracking. It specifies the materials, heat treatments, and metal property requirements for components exposed to hydrogen sulfide.

SAUDI ARAMCO SPECIFICATIONS:

Saudi Aramco standards specify that wellheads and trees shall be made in accordance with API Spec 6A. Aramco Standard 45AMSS-005 is a publication that clarifies those points which are not addressed in the API specification. The Aramco Material Supply number includes a complete description of the material required when an order is placed.

SERVICE ENVIRONMENTS:

The worst case environment within a pressure rating is used to specify equipment. For example, the differences in Saudi Arabian wells is not enough to confuse the issue with H2S and non H2S equipment. A great percentage of wells have hydrogen sulfide therefore all wells are equipped for sour service.

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HYDROGEN SULFIDE:

A sour service or H2S well is identified according to NACE MR-0175. In general, if the partial pressure of H2S is greater than or equal to .05 psi, the material is susceptible to sulfide stress cracking. All parts used under these conditions must be heat treated as recommended in NACE Standard MR-01-75 to have not more than a specified maximum material hardness. Material hardness is defined as the resistance of metal to plastic deformation, usually by indentation. In H2S tests, the common unit for material hardness is Rockwell C, which is obtained by applying a cone shaped diamond indentor with a load of 150 Kg to the material and measuring the depth of indention. NACE Standard MR-01-75 specifies that all wellhead and tree components subjected to H2S must have controlled hardness. The hardness maximum depends on the materials used for the components. Rockwell C-22 is the maximum for AISI 410 stainless steel and low alloy steel. (Rockwell hardness numbers may be converted to other units of material hardness by referencing appropriate tables in two other documents - ASTM E140 and Federal Standard N° 151 method 241.1)

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TABLE OF CONTENTS INTRODUCTION..........................................................................................................1 TYPES OF TUBULARS ...............................................................................................1 Casing ..................................................................................................................1 Tubing ..................................................................................................................2 API SPECIFICATIONS................................................................................................2 API Casing & Tubing Weight Designation .........................................................3 API Casing Length Specification ........................................................................3 API Tubing Length Specification ........................................................................4 Hydrostatic Test Pressure ....................................................................................4 PROPERTIES OF TUBULAR MATERIAL ..............................................................5 Yield Strength ......................................................................................................5 Basic Stress-Strain Equations ..................................................................5 Hardness of Steel .................................................................................................6 Heat Treatments ...................................................................................................6 Quenched and Tempered .........................................................................7 Normalizing .............................................................................................7 Normalized and Tempered.......................................................................7 Cold Drawn and Tempered......................................................................7 Hot Rolled................................................................................................7 Chemical Composition.........................................................................................7 Carbon Steels ...........................................................................................7 Alloy Steels..............................................................................................8 High Alloy Steels.........................................................................8 Low-Alloy Steels .........................................................................8 High Alloy Chrome-13 casing for Saudi Aramco GWI Wells ................8 TUBING AND CASING GRADES ..............................................................................9 API Tubing and Casing Grades ...........................................................................9 Non-API Tubing and Casing Grades ...................................................................11 Saudi Aramco Non-API Tubing and Casing Grades ...........................................12 CONNECTIONS............................................................................................................13 API Casing Connections ......................................................................................13 Saudi Aramco API Casing Connections ..............................................................13 API Short/Long Thread and Coupling.....................................................13 API Buttress Thread and Coupling ..........................................................14 API Tubing Connections .....................................................................................14

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API External Upset End (EUE) tubing ....................................................15 Proprietary Connections ......................................................................................15 Saudi Aramco Proprietary Connections ..............................................................16 VAM Connection.....................................................................................16 NS-CC Connection ..................................................................................16 Hydril PH-6 Connection ..........................................................................17 Vetco LS, RL-4S, and Dril-quip S-60 Connections for Large Casing Sizes .............................................................................................17 CORROSION.................................................................................................................19 Corrosion Mitigation............................................................................................19 1. Plastic Coatings..................................................................................19 2. High Alloy Carbon, Stainless Steel or Chromium Tubulars .............19 3. Chemical Inhibition ...........................................................................19 Sulfide Stress Cracking........................................................................................20 1. Steel Properties ..................................................................................20 2. Temperature Susceptibility ................................................................20 3. Other Factors......................................................................................21 4. Design Considerations .......................................................................21 Saudi Aramco Applications in H2S Service............................................21 CARE OF OILFIELD TUBULARS ............................................................................22 CASING DESIGN..........................................................................................................22 TUBING DESIGN .........................................................................................................22 Tubing Size Selection ..........................................................................................23 Anticipated Production Rate:...................................................................23 Nature of Produced Fluids: ......................................................................23 Accommodation of Through Tubing Tools: ............................................23 Economic Considerations: .......................................................................23 Tubular Availability:................................................................................24 TUBING MOVEMENT AND FORCE ANALYSIS...................................................24 Basic Pressure and Temperature Effects .............................................................25 Piston Effect.............................................................................................25 Pressure Buckling Effect .........................................................................25 Ballooning Effect .....................................................................................25 Temperature Effect ..................................................................................25 Tubing Movement Formulas................................................................................25

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1. Piston Effect.......................................................................................26 a) Length change........................................................................26 b) Force change ..........................................................................26 2. Pressure Buckling Effect ...................................................................26 a) Length change........................................................................26 b) Force change ..........................................................................26 3. Ballooning Effect ...............................................................................26 a) Length change........................................................................26 b) Force change ..........................................................................26 4. Temperature Effect ............................................................................27 a) Length change........................................................................27 b) Force change ..........................................................................27 Length and Force Terms ......................................................................................27 Sign Convention ..................................................................................................28 1. Length Changes .................................................................................28 2. Force ..................................................................................................28 3. Pressure Changes ...............................................................................28 4. Temperature Changes ........................................................................28 Appendix A:

SAUDI ARAMCO TUBING & CASING DATA TABLE ..............29

Appendix B: EXAMPLE TUBING MOVEMENT / FORCE PROBLEM ..........31 Landing Condition: ..............................................................................................31 Well Condition Prior to Acid Job: .......................................................................32 Acidizing Condition:............................................................................................32 Assignment of Length and Force Terms:.............................................................33 Substitution of Length and Force Terms into Equations .....................................36 1. Piston Effect.......................................................................................36 2. Pressure Buckling Effect ...................................................................36 3. Ballooning Effect ...............................................................................37 4. Temperature Effect ............................................................................37 Summation of Movements and Forces ................................................................38

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INTRODUCTION Casing and tubing perform important functions during the life of the well. The main functions are: 1. 2. 3. 4. 5. 6.

To prevent wellbore collapse To prevent leaks to subsurface aquifers To isolate the produced fluids To restrict production to the flow string To confine well pressure To facilitate installation of artificial lift equipment

The cost of casing and tubing is often the greatest single item of expense on the well. In addition, an improperly designed casing or tubing program, and/or incorrect handling can result in the loss of equipment, production, and human lives. This chapter will examine the types of tubular goods required in the oil and gas industry, and will focus on the applications in Saudi Aramco. TYPES OF TUBULARS In general, there are four types of thread-connected tubular goods commonly used in the oilfield. These general types are: • • • •

casing tubing drill pipe sucker rods.

Since drill pipe is not part of the completion string, it will not be covered in this chapter. Although sucker rods are a thread-connected tubular used as part of a completion in many parts of the world, they are not used in Saudi Aramco and therefore will not be covered. Casing Casing is a pipe used to protect the wellbore during drilling and production. Each well may have two or more strings of casing cemented in place during the drilling operation. Casing which does not extend to the surface is generally referred to as a liner. The casing protects against wellbore collapse and separates the various aquifers encountered while drilling. American Petroleum Institute (API) casing is available in sizes ranging from 41/2" to 20" (see API section later). Casing sizes above 20" diameter are available, and are Page 1

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defined by the API Line Pipe Specification. Saudi Aramco uses 24", 26", 30" and 36" casings in these larger sizes. Tubing Tubing is a pipe used as a flow string for transmission of fluids from the production zone to the surface. Whereas casing is usually a permanent, cemented fixture in the well, the tubing is usually the working string, and is run or removed from the wellbore to facilitate well servicing operations. API tubing is available in sizes ranging from 1.050" to 4-1/2". API SPECIFICATIONS Prior to 1920, oilfield tubulars had no standard for dimensions, lengths, weights, threads and other properties. Casing and tubing were merely whatever type of pipe might be available from any particular mill in any locality. Threaded connections had varying diameters and tapers. Thread density included 8, 10, 11-1/2, and 14 threads per inch. This caused considerable frustration and required widespread use of crossover joints to get from one thread type to another. High tubing and casing failures were common since there was no control of the tube material or manufacturing procedure. During the 1920s, the American Petroleum Institute (API) achieved standardization for casing sizes and threads. Outside diameter became the standard reference for size, and grading of the material according to strength was introduced. Thread taper was standardized at 3/4 inches per ft with 8 threads per inch. The round thread crests and roots were adopted in 1939. A great many other standards were made over time. Today, the API identifies, assesses, and develops standards for oil and gas industry manufactured products. API specifications which deal with oil country tubular goods are shown in Table 1. TABLE 1 API Spec 5A 5AC

5AX

Description Casing, Tubing & Drill Pipe (ie. Grades H-40, J-55, N-80*) Restricted yield Strength Casing & Tubing (ie. Grades C-75, L-80, C-95*) High Strength Casing, Tubing & Drill Pipe (ie. Grades P-105, P-110*)

* Tubing and casing grades will be covered in a subsequent chapter. Page 2

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Most casing and tubing are manufactured to specifications set out by the API. Tubulars which are manufactured outside of API specifications are known as proprietary designs. Casing and tubing are considered API if they meet certain specifications. Among the properties defined by the API specifications are • • • • • • • • •

weight/ft length ranges outside diameter (OD) wall thickness drift mandrel length and diameter pipe steel grade hydrostatic test pressure methods of steel manufacture physical dimensions of API threaded connections and their related upsets

In addition, the API sets performance ratings for API pipe and API connections such as: • • •

internal yield pressure collapse pressure tensile strengths

API Casing & Tubing Weight Designation Casing and tubing weights are expressed in lb/linear ft and are designated as either plainend weights or nominal weights. • •

Plain-end weight is the weight of non threaded, square-cut pipe. Nominal weight is the weight of the pipe with API connections, including upsets, threads, and couplings.

Nominal weight is usually used for design purposes since most of Saudi Aramco's tubulars are threaded and coupled.

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API Casing Length Specification API specifications for casing and tubing designate the length range of each joint. There are three length ranges for casing: • • •

Range 1 (R-1) includes pipe sections from 16 to 25 ft long. Range 2 (R-2) is the 25 to 34 ft range. Range 3 (R-3) is 34 ft and longer.

Casing is mostly run in R-3 lengths. These longer lengths reduce the total number of threaded connections needed for the casing string. Since casing is usually run in single joints (instead of doubles or triples), the longer R-3 lengths are easier to handle. API Tubing Length Specification Tubing falls into one of two length ranges: • •

Range 1 (R-1) is 20 to 24 ft/joint. Range 2 (R-2) is 28 to 34 ft range.

Tubing is often racked in the derrick during workovers and frequently run in double or triple joint stands. For this reason, most tubing is run in R-2 lengths, which corresponds with the common drill pipe length. The short R-1 tubing is often found in shallow wells. During workover, small inexpensive workover rigs with short derricks are used and the short pipe is more easily handled. The tubing in some cases takes the place of the drill pipe and is used as the work string during workover operations. Hydrostatic Test Pressure API specifies that each length of casing shall be tested to a given hydrostatic pressure at the mill for leakage. The test pressure on casing up to 10-3/4" diameter must be sufficient to produce a stress equal to 80% of the minimum yield strength of the material. For 103/4" and larger pipe, the test pressure is 60% of the minimum yield strength.

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PROPERTIES OF TUBULAR MATERIAL In order to understand strengths of tubular materials, it important to understand the basic terminology and process of manufacture of these materials. Yield Strength The strength of a steel is usually indicated by its minimum yield strength or ultimate tensile strength. Casing and tubing are manufactured mostly from ductile steels. Whereas brittle steels fracture without appreciable deformation, ductile steels can withstand significant plastic deformation prior to fracture. Basic Stress-Strain Equations Stress and strain are common terms used in describing strengths of materials. If a tensile load (or force) is applied to a test sample cross-sectional area, then the tensile (or axial) stress is found by: Stress = Force / Area Axial strain is defined as the ratio of the test sample axial elongation to the original length of the sample: Axial Strain = Axial Elongation / Original Length Hooke's Law defines stress as the product of the elastic constant or Young's modulus of elasticity (YME) and strain: Stress = YME x strain For steels the Young's Modulus is typically 30 x 106 psi.

Figure 1 is a stress-strain diagram for a typical ductile steel. Point 'A' represents the yield strength or elastic limit of the steel. If the steel is stressed below the elastic limit, it will return to its original shape upon unstressing or unloading the test sample. Below the elastic limit, the stress-strain curve is linear. The API specifies that the yield stress is the tensile stress required to produce a total elongation of 0.5% of the tensile test sample length. This is shown by point 'B' in the diagram. Stresses greater than the elastic limit cause permanent deformation of the steel and the steel will not return to its original shape when the load is taken away. If a steel is stressed beyond its yield strength, it will deform plastically until its ultimate strength is reached as shown by point 'C'. The ultimate strength is the maximum stress Page 5

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that the steel can sustain before it begins to fail. Beyond this point the material will continue to deform plastically (with a reducing stress) until complete failure (breakage) occurs as shown by point 'D'.

STRESS (psi)

A - Elastic Limit B - API Specified Minimum Yield

C - Ultimate Strength D - Failure

STRAIN (%) 0.5% STRESS-STRAIN DIAGRAM FOR DUCTILE STEEL FIGURE 1

Hardness of Steel Hardness is the measure of a steel's yield point in compression. When a material is required to resist wear, corrosion, erosion or plastic deformation, it may be necessary to specify a high hardness. Hardness generally increases with increasing material ultimate tensile strength. Very hard materials are brittle and will crack or fracture easily. Hardness is determined by a test where a load is applied with a small ball or pointed object. The hardness of the material is then expressed by the depth of the indentation caused by the pointed object. The "Rockwell C" or "Brinell" hardness scales are used to quantify the degree of hardness of an oilfield tubular material. Heat Treatments Mechanical properties in steel such as yield stress, ultimate tensile strength, ductility, or hardness can be achieved by controlling the heat treating portion of the manufacturing process and chemical composition of the steel. Heat treating affects changes in the microstructure, or grain structure of the steel which directly affects its mechanical properties. Heat treating is an operation involving heating and/or cooling the solid steel tubular to develop the desired steel microstructures. Page 6

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The five basic heat treatments are: Quenched and Tempered The steel is heated to 1500-1600 oF. It is then rapidly quenched (or cooled) in water or oil to produce a desired microstructure. It is then tempered (or re-heated) at 10001300 oF to produce a desired combination of strength and ductility. This is the preferred method of producing high strength casing and tubing. Normalizing The steel is heated to 1600-1700 oF and then cooled in air to produce a uniform microstructure and to alter mechanical properties. Normalized and Tempered The steel is first normalized (as above) and then tempered and air cooled. This tempering process slightly lowers the strength from the normalized condition but improves ductility and helps to relieve residual stresses. Cold Drawn and Tempered The tubing or casing is shaped or rolled to the desired OD at room temperature. This process causes a high residual stresses in the tube and increases the hardness due to plastic deformation. The tubular is then tempered to reform the microstructure from the cold drawn state. Tempering reduces the hardness and relieves the residual stresses. Hot Rolled The tubing or casing is shaped or rolled to the desired OD at a very high temperature. Hot rolling does not cause changes in the microstructure as in the cold rolling process above. Hot rolling produces a steel similar to the normalized condition. Chemical Composition The chemical composition of a steel directly affects all of its mechanical properties and corrosion resistance. Steels can be classified according to chemical composition as follows: Carbon Steels These steels are considered to be a mixture of iron and carbon with up to 2% carbon content. The high carbon steels contain up to 2% carbon while the low carbon steels contain as low as 0.25% carbon. Carbon steels can contain other elements such as manganese or silicon in small quantities.

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Alloy Steels These steels contain significant quantities of alloying elements other than carbon. A steel is considered an alloy steel when the content of either manganese, silicon or copper exceeds 1.65%, 0.6% and 0.6% respectively. A steel is also considered an alloy if there is a minimum content specified for aluminum, boron, cobalt, chromium, niobium, molybdenum, or nickel. High Alloy Steels High-alloy steels contain more than 5% alloy elements, in particular, high concentrations of chromium, molybdenum, and nickel are used for high-alloy tubulars. High-alloy steels which contain greater than 12% chromium are often called "stainless" steels. Low-Alloy Steels Low-alloy steels contain less than 5% metallic alloying elements. High Alloy Chrome-13 casing for Saudi Aramco GWI Wells Gravity Water Injection (GWI) wells are Arab-D reservoir pressure maintenance wells commonly found in the Abqaiq field (see the "Well Completion Types" chapter of this training manual or a detailed description of GWI wells). Hot, corrosive and erosive Wasia water flows through perforations opposite the Wasia formation and is gravity 'dumped' into the Arab-D formation below. This hostile environment caused severe corrosion and erosion on the steel 9-5/8" casing and 7" liner between the Wasia and Arab-D formations. Workover costs were very high and the life expectancy of these wells was low. In 1989 a feasibility study was conducted into the use of a high alloy casing for these wells to replace the standard steel casing. The economics were balanced between the high cost of the alloy casing and the expected increase in useful well life and lower workover costs. As a result of the study Saudi Aramco specified and began using Chrome-13 L-80 steel for its gravity water injector (GWI) casing program in 1990.

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TUBING AND CASING GRADES Steel pipe grades are identified by letters and numbers which indicate various characteristics of the pipe steel. It is a specification according to its yield stress, ultimate tensile strength, chemical composition, heat treatment or other characteristics. There are many grades of steel that make up oilfield tubulars. API Tubing and Casing Grades To understand API tubing and casing grades, it is important to understand the terms minimum yield stress, maximum yield stress, and minimum ultimate strength. To explain these terms, two popular grades of oilfield tubulars will be used as an example: L-80 and N-80. The grade of steel is denoted by a letter of the alphabet followed by the minimum yield stress of the particular steel. For example, the API grade L-80, which is a common grade used by Saudi Aramco, has a minimum yield stress of 80,000 psi as shown by point "A" in Figure 2. In other words, it can support a stress of 80,000 psi with an elongation of 0.5%. The 'L' is a distinguishing prefix to avoid confusion between different steel grades. The letter in conjunction with the number designates such parameters as the maximum yield strength and minimum ultimate yield strength. In L-80 the maximum yield strength is shown by point "B" as 95,000 psi which is 15,000 psi higher than the minimum yield stress. The minimum ultimate strength is shown by point "C" as 95,000 psi. Note that there is no maximum ultimate strength specified.

STRESS (psi) B - API Specified Maximum Yield

95,000 80,000

C - API Minimum Ultimate Strength

A - API Specified Minimum Yield

STRAIN (%) 0.5% STRESS-STRAIN DIAGRAM FOR L-80 STEEL FIGURE 2

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N-80, another API grade (see Figure 3), also has a minimum yield stress of 80,000 psi, but is different from L-80 in that the former has a greater maximum yield stress of 110,000 psi (shown by point "B"). This is 30,000 psi higher than the minimum yield stress and twice the tolerance of L-80. The minimum ultimate strength of 100,000 psi is also higher as shown by point "C". Whereas N-80 has no hardness specification, L-80 has a hardness specification of 23 HRC. The tight tolerance on yield strength and hardness allow the L-80 to be more suitable for H2S service than N-80 grade tubulars.

STRESS (psi)

B - API Specified Maximum Yield

110,000 100,000 80,000

C - API Minimum Ultimate Strength

A - API Specified Minimum Yield

STRAIN (%) 0.5% STRESS-STRAIN DIAGRAM FOR N-80 STEEL FIGURE 3

The following Table 2 lists the API tubing and casing grades and flags the ones common to Saudi Aramco.

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CASING AND TUBING TABLE 2 API TUBING AND CASING GRADES Designation

Min yield psi

Max yield psi

Min ultimate psi

Tubing Grades H-40 J-55 C-75 L-80 N-80 P-105

40,000 55,000 75,000 80,000 80,000 105,000

80,000 80,000 90,000 95,000 110,000 135,000

60,000 75,000 95,000 95,000 100,000 120,000

Casing Grades H-40 J-55 K-55 C-75 L-80 N-80 C-95 P-110

40,000 55,000 55,000 75,000 80,000 80,000 95,000 110,000

80,000 80,000 80,000 90,000 95,000 110,000 110,000 140,000

60,000 75,000 95,000 95,000 95,000 100,000 105,000 125,000

Common to Aramco

Yes Yes

Yes Yes Yes Yes Yes

Casing sizes 24" and larger commonly have grade designations such as X-42, X-56, X60, and B. These are API designations specified under the Line Pipe Specifications. A complete listing of the sizes, grades, weights and connections used by Saudi Aramco is given in the appendix. Non-API Tubing and Casing Grades In addition to API grades, there are many proprietary steel grades which may not conform to the API specifications, but which are used in the industry. These extensively used special grades are often run for various applications requiring such properties as very high tensile strength, high collapse strength, or steels resistant to sulfide stress cracking. This pipe is manufactured to many, but not all of the API specifications with such variations as steel grade, wall thickness, OD, threaded connection, and related upset. As a result of these changes, the ratings of internal yield, collapse, and tension for both the pipe and the connection are non-API.

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The rating of these proprietary products are generally calculated using API formulas or are consistent with API methods. Also, such parameters as drift diameter, wall thickness tolerance, length range, and weight tolerance are kept the same as, or are consistent with API specifications. Saudi Aramco Non-API Tubing and Casing Grades Several non-API tubing and casing grades are used in Saudi Aramco drilling and workover operations. These proprietary grades have different lettering designations than the familiar API standard. The two most common proprietary grades stocked by Saudi Aramco are KO (Kawasaki Steel) and NT (Nippon Steel) and are shown in the Casing and Tubing Data Table in Appendix A.

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CONNECTIONS Oilfield tubulars may be equipped with plain ends (no threads), have API specified threaded connections or proprietary (non-API) threaded connections. API Casing Connections Oilfield casing conforming to API standards may be obtained with plain ends, but ends are usually threaded and furnished with couplings such as: • • • •

short thread and coupling (STC)* long thread and coupling (LTC) * buttress thread and coupling (BTC) Extreme-Line thread (X-line) for casing * with 8 round threads per inch (8 RD)

With the exception of Extreme-Line, male (or pin) threads are machined on plain-end pipe and later made up with a coupling. A reduced OD (special clearance) coupling is offered on some sizes and weights to allow for additional clearance between pipe and hole. While providing this additional clearance, special clearance couplings often reduce the rating of the connection, usually in tension or internal yield and test pressure. Saudi Aramco API Casing Connections Several API connections are used in Saudi Aramco drilling and EXTERNALLY THREADED PIN workover operations. A brief INTERNALLY THREADED COUPLING (BOX) description of the most popular connections used are as follows:

API Short/Long Thread and Coupling The API Short Thread and Coupling (STC) and API Long Thread and Coupling (LTC) are used in several pipe sizes ranging from 4-1/2" through to 13-3/8". Figure 4 shows the LTC

ROUND CRESTS AND ROOTS

60 deg

API LONG THREAD & COUPLING (LTC)

FIGURE 4

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design. The STC design is the same except that the coupling and the threaded pins are shorter. This design is externally threaded on both ends of a non-upset pipe. The single lengths are joined with an internally threaded coupling. The thread profile has rounded threads and roots with a 60° angle between the thread flanks as shown in the figure. The thread density is 8 threads per inch (8 RD) on a 0.0625 inch per inch taper. API Buttress Thread and Coupling The API Buttress Thread and Coupling (BTC) is also a popular thread design used by Saudi Aramco in several casing sizes ranging from 9-5/8" through to 18-5/8". Figure 5 shows the BTC design. This design is externally threaded on both ends of a non-upset pipe (as in the STC and LTC). The single lengths are joined with an internally threaded coupling. The thread profile has flat crests and roots parallel to the taper cone. The thread density is 5 threads per inch on a 0.0625 inch per inch taper for sizes 13-3/8" and smaller, and 0.0833 inch per inch taper for sizes 16" and larger.

EXTERNALLY THREADED PIN INTERNALLY THREADED COUPLING

FLAT CRESTS AND ROOTS

API BUTTRESS THREAD & COUPLING (BTC)

FIGURE 5

The BTC thread has higher joint and bending strengths compared to LTC (or STC). As a result, this thread is used often in deeper wells where higher hook loads are experienced. It is also run in horizontal wells where doglegs can cause high bending loads on the larger size casings. API Tubing Connections API tubing is usually threaded and furnished with the following connections: •

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Non-Upset ends (NU) Integral Joint

API External Upset End (EUE) tubing The API "EUE" connection for tubing is a popular thread design used by Saudi Aramco. It is common in sizes 2-3/8", 2-7/8" and 3-1/2". The tubing is purchased with eightround (8 RND) threads machined on an external upset end (see Figure 6). An upset is the metal gathered at the end of the tube using a hot forging process prior to heat treatment. This method of manufacture helps to maintain both the metallurgical and the mechanical properties in the upset that are present in the pipe body. The upset is used to increase the tensile strength of the connection to a value equal to, or greater than that of the pipe body. In addition, a connection machined on an upset can provide both bending and compression strengths in excess of the pipe body.

PIPE BODY

EXTERNAL UPSET END

ROUND CRESTS AND ROOTS

60 deg

API EXTERNAL UPSET END (EUE) TUBING

FIGURE 6

Proprietary Connections Proprietary connections are available which offer premium features not available on API connections. Among the special features for proprietary connections are: • • • • • • • • •

clearance OD's for slimhole completions metal-to-metal seals for improved high pressure seal integrity high bending strength for deviated holes multiple shoulders for high torque strength a streamlined connection OD for easy running in multiple completions. recess-free bores through the connection ID for improved flow characteristics higher tensile strength for deep holes an integral connection to reduce the number of potential leak paths resilient seal rings for continuous corrosion protection Page 15

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•

high compressive strength for compressive loading situations

Saudi Aramco Proprietary Connections Several proprietary connections are used in Saudi Aramco drilling and workover operations. A brief description of the most popular connections used are as follows: VAM Connection A proprietary connection which is very popular with Saudi Aramco is the VAM connection and is stocked in 4-1/2" and 7" sizes. This connection has a metal to metal seal for superior leak resistance. An internally threaded coupling with internal shoulders provide positive make up torque and a non-turbulent bore (see Figure 7). It has become a standard completion tubing for the Khuff gas wells and most of the oil producers. Also, due to its superior joint and bending strength, it is used as the completion liner for the horizontal wells. NS-CC Connection The NS-CC (Nippon Steel Connection for Casing) is a proprietary connection used by Saudi Aramco in the Khuff Gas wells (see Figure 8). It is stocked in 7", 9-5/8" and 13-3/8" sizes. This

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FLUSH BORE DIAMETER TORQUE SHOULDER METAL TO METAL SEAL FACE

FLAT CRESTS AND ROOTS

PROPRIETARY VAM CONNECTION

FIGURE 7

TWO-STEP PIN NOSE DESIGN

RESERVE SHOULDER METAL TO METAL SEAL

PRIMARY SHOULDER

API BUTTRESS

PROPRIETARY NS-CC CONNECTION

FIGURE 8

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connection is noteworthy for it's gas leak tightness, low hoop stress, high joint strength (equivalent to API buttress thread), high collapse strength and easy stabbing design. It's two step pin nose which incorporate a primary and reserve torque shoulder and metal to metal seal make it a good candidate for the deep, high temperature, high pressure Khuff Gas service. NS-CT (Nippon Steel Connection for Tubing) is similar connection used for tubing applications. It is stocked by Saudi Aramco in the 2-7/8" size. Hydril PH-6 Connection The Hydril PH-6 proprietary connection is an integral connection stocked by Saudi Aramco in the 27/8" and 3-1/2" sizes.

30 DEG. TORQUE SHOULDER & SEAL

THREADS CUT ON TWO DIFFERENT DIAMETERS

Advantages of the PH-6 SECONDARY SHOULDER design are metal to metal seals, high internal and external pressure integrity, and a rugged two step thread design (see Figure PIN TO BOX SEAL 9). The torque shoulders allow make-up to the same point every time (like a PROPRIETARY HYDRIL PH-6 CONNECTION drill pipe tool joint) The FIGURE 9 connection also exceeds API pipe body ratings and can be used as a work string (instead of regular drill pipe) for operations such as drilling, milling, and other workstring applications. Vetco LS, RL-4S, and Dril-quip S-60 Connections for Large Casing Sizes The Vetco LS, RL-4S and Dril-quip S-60 connections are proprietary connections used by Saudi Aramco in the 24" casing size. The Vetco LS connection is a high strength integral design which accommodates high internal operating pressures, bending moments and tensile loads. The pin/box mating shoulder has a 30 degree taper (see Figure 10). This results in the open end of the box being captured by the tapered shoulder of the pin, and prevents the box from ballooning at the pin/box interface during periods of high internal pressure and large bending moments.

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REVERSE SHOULDER "O" RING SEAL ON PIN

COARSE THREE PITCH THREAD DESIGN

ELEVATOR SHOULDER

PROPRIETARY VETCO LS CONNECTION FOR LARGE CASING SIZES

FIGURE 10

The Vetco RL-4S connection features dual stabbing guides and a high stab angle for easy stabbing. Self locking, four start thread forms allow fast quarter-turn makeup. The Dril-quip S-60 connection features easy stabbing, no cross-threading, fast makeup, low torque and high pressure sealing.

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CORROSION The presence of CO2 and H2S accompanied by water, can cause corrosion of the exposed tubulars. In addition, H2S can cause stress corrosion cracking. Corrosion Mitigation When CO2 or H2S are dissolved in water, they will create an acidic solution. These solutions react with the iron in the pipe causing local pitting which can eventually eat a hole in the pipe. Some of the ways of combating this corrosion are as follows: 1. Plastic Coatings Plastic coating on the pipe which is exposed to the produced fluids is one method of corrosion prevention. There are a variety of coating materials and thicknesses for the different chemical components and temperatures of the produced fluid. The application of a coating to the inside of the pipe can reduce its effective drift diameter. This will make it necessary to coordinate the plastic coating thickness with the proposed through tubing work. Plastic coating is difficult to apply to all exposed surfaces. This is particularly true of coupling recesses and accessories such as packers, seating nipples and safety valves. In order to maintain continuity of the plastic coating's corrosion barrier, some connections provide a teflon ring on the ID between the pin end and the box recess. Saudi Aramco carries a stock of internally plastic coated (IPC) tubulars in the 41/2" and 7" sizes. Several salt water disposal wells use these IPC tubulars to prevent corrosion due to the salt water effluent pumped into these wells. 2. High Alloy Carbon, Stainless Steel or Chromium Tubulars Where plastic coating is impractical, corrosion control can be achieved through these alloy steels. This is not a common method since alloy steel tubulars usually cost much more than a conventional steel string. Saudi Aramco maintains a stock of 4-1/2", 7" and 9-5/8" high alloy Chrome-13 tubulars for use in the gravity water injection wells (see section entitled "Properties of Tubular Materials" for more information about CR-13 casing). 3. Chemical Inhibition An inhibitor may periodically be pumped into a well to form a film on the pipe. If there is no means to circulate down the inhibitor while producing the well, it will be necessary to shut in the well and pump down the tubing. In a gas lift installation, the inhibitor may be pumped into the gas system. Where wells are Page 19

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completed with concentric strings, the inhibitor can be continuously pumped down one string, with the produced fluid carrying the inhibitor into the other string.

Sulfide Stress Cracking A type of corrosion caused by H2S can be a severe condition because it can lead to gross failure of steel equipment. Stress corrosion cracking attacks points subjected to a high tension stress. Once the stress crack is initiated, the tensile stress may increase due to the reduced area, thus leading to accelerated stress cracking. This process continues until the stress increases to the ultimate strength of the steel, at which point failure occurs. In order to prevent stress corrosion cracking in tubulars due to the presence of H2S, certain design criteria can be applied. 1. Steel Properties One of the principal factors governing the resistance of tubulars to stress corrosion cracking is the physical properties of the steel. Through extensive testing it has been determined that the higher strength carbon steels are more susceptible to sulfide stress cracking. The API Specification 5AC lists three steel grades, C-75, L-80, and C-95 which have a restricted yield strength range of 15,000 psi. This restricted range has the net effect of holding down the maximum strength of the steel while maintaining an adequate minimum yield strength. In addition to the narrower yield strength range, these grades have additional chemical and heat treatment controls not required on other API steel grades. These three have been widely used in H2S environments. With experimental work on the effect of the heat treatment methods on resistance to sulfide stress cracking, there has been an increased use of the quenched and tempered L-80 grade. In addition to the API grades, there are proprietary grades used in H2S service. Most of these have a minimum yield strength from 80,000 psi to 90,000 psi, with a controlled yield strength range of 15,000 psi. This is the same range as API restricted yield grades. 2. Temperature Susceptibility Another factor in susceptibility of tubulars to sulfide stress cracking is the temperature of the steel when it is exposed. It has been shown that at elevated temperatures, the higher strength steels are not susceptible to sulfide stress Page 20

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cracking. NACE Specification MR-10-75 refers to the use of API grades P-105, P-110 and proprietary grades to a maximum 140,000 psi yield strength in an H2S environment where the temperature during exposure is not less than 175° F. The use of API grades N-80, C-95 and proprietary grades up to a maximum yield strength of 110,000 psi can be used in temperatures above 150° F. 3. Other Factors Other factors effecting sulfide stress cracking are the level of stress in the steel and the time of exposure. Lower stress levels reduce the chance of sulfide cracking. The steel chemical and mechanical properties, in addition to the time and temperature at exposure and the tensile stress level, determine the susceptibility of the steel to sulfide stress cracking. 4. Design Considerations In deep, high pressure gas wells where both internal pressure and tension would normally require high strength steels, design of casing and tubing strings becomes difficult with the restriction of the minimum yield strength to 90,000-95,000 psi in an H2S environment. Application of restricted yield strength steel grades dictates thicker-wall pipe in order to handle the high tension and internal pressure loads. A well with a high bottom hole temperature can use P-110 and/or X-125 casing and P-105 tubing in the lower section of the hole up to a point where the static temperature is no longer high enough. At this crossover temperature, it is then necessary to run the sulfide stress cracking resistant grades to the surface. By using high strength steel on the bottom, the wall thickness can generally be reduced, thus decreasing the total weight of the string. This is particularly important with the upper section of the string requiring lower strength steel, the reduced weight on the bottom sections will further reduce the weight required at the surface. Saudi Aramco Applications in H2S Service Associated gas and non-associated (Khuff) gas can contain high levels of H2S. The L-80 grade has become a standard specification for several Saudi Aramco oil and gas fields which have high levels of H2S. Saudi Aramco stocks several sizes of L-80 tubing and casing such as 4-1/2", 7" and 9-5/8". Proprietary (non-API) grades such as S-95, and NT-90HS are also used in Saudi Aramco high pressure sour Khuff gas applications where a high yield strength is required. Page 21

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CARE OF OILFIELD TUBULARS With the large expense of tubular products to drill and complete an oil or gas well, it is important that the proper shipping, handling, storage, and running practices be followed to ensure that the investment made in tubulars yields its maximum benefit. Leaky joints are one cause of trouble which can be attributed to many forms of improper care. API Recommended Practice for Care and Use of Casing and Tubing (RP 5C1) lists common causes of trouble for casing and tubing. Of these, over half are related to poor shipping, handling, and running practices.

CASING DESIGN Generally, the most economic casing string is the lightest weight, lowest grade string which will accommodate the stresses and environmental conditions to which it is exposed so that it will not: • • • • • • • • •

rupture or burst under internal pressure collapse under external pressure pull apart under axial tensile stress lose pressure or leak fail due to compression effects fail due to bending effects fail due to torsional effects fail prematurely due to wear, fail prematurely due to corrosion or other chemical/metallurgical phenomenon such as sulfide stress cracking

The first four considerations - tension, burst, collapse, and pressure integrity are considered without exception in all casing designs. The latter loads or phenomena are unusual or special conditions that may exist in certain wells and should be considered to develop a perspective of all the stresses and conditions involved.

TUBING DESIGN Tubing, like casing, must fulfill the design requirements dictated by the internal and external pressure loading conditions the tubing will be subjected to. In addition to satisfying the internal yield, collapse and tensile requirements the design must meet additional criteria.

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Tubing Size Selection Since the tubing usually contains the production stream, it must be sized accurately. Several factors are considered when selecting the correct tubing size for a well. Some of the main factors are: Anticipated Production Rate: The tubing must be of sufficient size to accommodate the expected production rate. Small tubing may cause high erosional velocities, a high pressure drop and low production rates. This is an important design considerations in high capacity reservoirs like those in Saudi Aramco. Nature of Produced Fluids: In practice, oil wells produce fluids in either two-phase (oil/water or oil/gas) or three phase (oil/water/gas) flow. Gas wells can also carry liquid in the flow stream. These multi-phase flow regimes complicate the modeling of fluid flow in tubing strings. When wells become water-cut for example, the water may break out and load up in the tubing string if the fluid velocity is too low. A smaller tubing string may be required to maintain a higher fluid velocity to carry the water to surface. Tubing size selection requires several reservoir and production parameters as input to the calculations. Saudi Aramco uses a computer program called "Pipe-Flow" to accurately model these complicated production streams. It is extensively used by Saudi Aramco Production Engineering Departments to determine tubing sizes required for new wells and workover wells. To accurately calculate tubing size, it is recommended to review the "Pipe-Flow" program. Accommodation of Through Tubing Tools: Another consideration is the minimum acceptable through-bore for survey, servicing, production logging and coiled tubing unit (CTU) operations. Slim logging tools are typically 1-11/16" in diameter and can be accommodated with 2-3/8" production tubing. However wells with special logging requirements, such as the 3-5/8" CarbonOxygen log or Induction log, need tubing strings sized large enough to accommodate these logs. Some wells may require landing nipples with no-go profiles which may further restrict through-bore diameter. It is therefore important to communicate with the production engineer to determine the size of tools which will be run in the well after the completion operation.

Economic Considerations: Page 23

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Larger tubing sizes typically cost more. An incentive toward smaller diameter tubing is the savings in tubular costs. Tubing sizes should be as small as practical, yet still fulfill the production requirements of the well. Tubular Availability: Once the accurate tubing size is determined (4" tubing for example), it may be found that the particular tubing size is not available. Saudi Aramco maintains a stock of tubulars of standard sizes and are listed in Appendix A. Some tubulars may have been discontinued (at the time of this printing) and new ones may appear which are not on the list. An up-to-date Aramco Material Supply (AMS) list should be reviewed when checking tubular availability. If the exact size tubing is not available, then either one size smaller or larger must be chosen. Since 4" tubing is not an Aramco stock item, then either 3-1/2" or 4-1/2" must be chosen. The 3-1/2" or 4-1/2" tubing may also be out of stock, further restricting the choice of tubulars available. It is therefore important to determine the size of tubulars required (and what tubulars are available) well in advance of any drilling or workover project. For new wells, once the tubing size is selected, the outer casing sizes may then be determined to accommodate the tubing. For older existing wells, the casing size frequently dictates the maximum tubing size which can be run in the well. Wells completed with 4-1/2" casings are very limited as to the size of tubing which can be run.

TUBING MOVEMENT AND FORCE ANALYSIS The typical Saudi Aramco oil producers have standard tubing landing procedures which accommodate anticipated tubing movement and forces. However, in extraordinary circumstances all possible conditions may need to be reviewed when designing tubing strings. For example, high internal pressure loading may be caused by several different well pressures such as producing, shut-in, stimulation treatments, testing, well killing operations (bull heading), artificial lift operations, etc. In addition to pressure forces, thermal forces may elongate or shrink the tubular beyond acceptable limits. This section will review the basics of tubing movement and force analysis. When the completion tubing is spaced-out and landed, the conditions affecting the tubing and packer are known. These conditions include tubing size and length, casing size, fluid inside and outside the tubing, temperatures, surface pressures and any mechanical forces applied. This point is used as a "reference point" to calculate the changes in forces and length for future conditions.

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In a tubing string, sealed off in a packer, there are four factors that cause length and force changes. These factors are dependent on well conditions, tubing/packer/casing configuration, and tubing restraint. Each factor acts independently and may either add to or cancel the effects of the other factors. Therefore it is important to keep the direction of the length changes and forces correct. Furthermore, mechanically applied tension or compression may be used to negate the combined effect of the pressure and temperature changes. Basic Pressure and Temperature Effects The four pressure and temperature effects which should be investigated for future well operating conditions are: Piston Effect Changes in pressure at the packer act on the inside and outside piston areas to produce length and force changes. These changes may be either up or down depending on the tubing/packer configuration. Pressure Buckling Effect Changes in pressure that cause a higher pressure inside the tubing than outside, at the packer, cause pressure buckling. Pressure buckling is a shortening of the effective length of the tubing string because the tubing bends into a spiral (or helix) within the casing. It can only shorten the tubing and only exerts a negligible force. Although pressure buckling and mechanical buckling appear to have the same mechanics, they must be considered separately as they are produced by completely different factors Ballooning Effect Changes in average pressure cause a radial swelling (ballooning) or contraction (reverse-ballooning) and a corresponding shortening or lengthening of the tubing string. Temperature Effect Changes in the average temperature of the tubing string cause thermal expansion or contraction of the tubing. Thermal forces are prominent in tubing strings in deep hot wells such as the Khuff gas wells.

Tubing Movement Formulas

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The terms and simplified formulas for calculating tubing movement are given below. These formulas give the length and force changes for common wells of one tubing and one casing size. More than one tubing or casing size requires that the calculations be made on each section and combined for a final condition. Length changes are in feet and force changes are in pounds. The terms in each of the equations are defined in the following section "Length and Force Terms". 1. Piston Effect a) Length change The length change due to the piston effect ΔL 1 , is expressed with the following formula: −L ΔL1 = ( A p − A i )ΔPi − ( A p − A o )ΔPo _____________(1) EA S

[

]

b) Force change The force change due to the piston effect is expressed as follows:

F1 = ( A p − A i )ΔPi − (A p − A o )ΔPo

_______________________(2)

2. Pressure Buckling Effect a) Length change The length change due to the pressure buckling effect is expressed with the following formula (only if ΔPi is greater than ΔPo ):

ΔL 2 =

−1.5r 2 A 2p ( ΔPi − ΔPo ) 2 EI( Ws + Wi − Wo )

_________________________(3)

b) Force change The force change is negligible since this effect mainly shortens the tubing. 3. Ballooning Effect a) Length change The length change due to the ballooning effect is expressed as follows: ΔL 3 =

−2 Lγ ⎡ ΔPia − R 2 ΔPoa ⎤ ⎢ ⎥ E ⎢⎣ R2 − 1 ⎥⎦

b) Force change Page 26

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The force change due to the ballooning effect is expressed as follows:

F3 = −0.6( ΔPia A i − ΔPoa A o )

_______________________(5)

4. Temperature Effect a) Length change The length change due to the temperature effect is expressed as follows: ΔL 4 = LβΔT

_______________________(6)

b) Force change The force change due to the temperature effect is expressed as follows:

F4 = 207A s ΔT

_______________________(7)

Since the stresses involved with tubing movement are three dimensional and require complex calculations, the formulas for stress are not included. Length and Force Terms L = Depth, feet E = Modulus of elasticity, psi (30 x 106 psi for steel) Cross-sectional area of the tubing wall, sq. in. As = Ap = Area of packer ID, sq. in. Ai = Ao =

Area of tubing ID, sq. in. Area of tubing OD, sq. in.

ΔPi =

Change in tubing pressure at the packer, psi.

ΔPo =

Change in annulus pressure at the packer, psi

ΔPia =

Change in average tubing pressure, psi

ΔPoa =

Change in average annulus pressure, psi

ΔT = r = l =

Change in average tubing temperature, oF Radial clearance between tubing OD and casing ID, inches Moment of inertia of tubing about its diameter π (D o4 − D i4 ) where D o is outside diameter and D i is inside diameter 64 Weight of tubing, lb/ft Weight of fluid in tubing, lb/ft

= Ws Wi

= =

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Wo =

Weight of displaced fluid, lb/ft

R β γ

Ratio of tubing OD to ID Coefficient of thermal expansion (6.9 x 10-6 in/in/oF for steel) Poisson's ratio (0.3 for steel)

= = =

Sign Convention In tubing movement and force calculations it is important to be consistent with the sign conventions (positive or negative numbers) used in the formulas and calculation results. For example, if a negative length change occurred, does that mean the tubing moved upward or downward? If a positive force change occurred, does that mean the tubing is in tension or compression? The following sign conventions are used by the majority of the industry: 1.

Length Changes Negative length changes refer to the upward tubing movement Positive length changes refer to the downward tubing movement

2.

Force Negative forces refer to tension Positive forces refer to compression

3.

Pressure Changes Negative pressure changes refer to pressure reduction Positive pressure changes refer to pressure increase

P = Pfinal - Pinitial 4.

Temperature Changes Negative temperature changes refer to temperature reduction Positive temperature changes refer to temperature increase

T = Tfinal - Tinitial

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Appendix A: SIZE inches

WEIGHT #/ft

SAUDI ARAMCO TUBING & CASING DATA TABLE GRADE

CONN name

ID inches

DRIFT inches

CON.OD inches

CAPAC cuft/ft

BURST psi

COLLAP psi

JT.STR lbs x 1000

2-3/8 2-3/8

4.70 4.70

J-55 L-80

EUE CS

1.995 1.945*

1.901 1.901

3.063 2.705

0.02171 0.02171

7700 11200

8100 11780

71.7 104.0

2-7/8 2-7/8 2-7/8

6.40 6.50 8.70

J-55 J-55 L-80

NS-CT EUE PH6

2.441 2.200*

2.347 2.165

3.668 3.500

0.03250 0.02783

7260 15000

7680 15300

99.6 199.0

3-1/2 3-1/2

9.30 12.95

J-55 L-80

EUE PH6

2.992 2.687*

2.867 2.625

4.500 4.313

0.04883 0.04125

6980 13007

7400 15310

142.5 295.0

4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2

11.60 11.60 11.60 12.60 13.50 13.50

J-55 J-55 13CR L-80 J-55 L-80 KO-105T1

STC LTC LTC VAM VAM HTS

4.000 4.000 4.000 3.958 3.920 3.920

3.875 3.875 3.875 3.833 3.795 3.795

5.000 5.000 5.000 4.892 4.862

0.08727 0.08727 0.08727 0.08544 0.08381 0.08381

5350 5350

4960 4960

154.0 162.0

5790 8540 10710

5720 9020 11280

198.0 307.0

5 5

15.00 15.00

K-55 13CR L-80

SC BTC SC BTC

5-1/2

20.00

L-80

VAM

4.778

4.653

6.075

0.1245

9190

8840

466.0

7 7 7 7 7 7 7 7 7 7 7

23.00 23.00 26.00 26.00 26.00 29.00 35.00 35.00 35.00 35.00 35.00

J-55 J-55 J-55 J-55 13CR L-80 N-80 L-80 L-80 L-80 L-80 L-80

STC LTC STC LTC LTC LTC LTC VAM SUPER-EU NS-CC IJ-4S

6.366 6.366 6.276 6.276

6.241 6.241 6.151 6.151

7.656 7.656 7.656 7.656

0.2210 0.2210 0.2148 0.2148

4360 4360 4980 4980

3270 3270 4320 4320

284.0 313.0 334.0 367.0

6.184

6.059

7.656

0.2086

8160

7020

597.0

6.004 5.924

5.879 5.879

7.681 7.572

0.1966 0.1966

9960 9960

10190 10180

725.0 957.0

6.004

5.879

0.1966

9960

10180

740.0

9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

36.00 36.00 40.00 40.00 40.00 43.50 47.00 53.50 53.50 53.50 53.50 58.40

J-55 J-55 J-55 J-55 L-80 L-80 L-80 L-80 NT-90HSS2 SM-90 S-95 NT-105HSS2

STC LTC STC LTC 13CR L-80 LTC LTC LTC NS-CC BTC BTC NS-CC

8.921 8.921 8.835 8.835

8.765 8.765 8.679 8.679

10.625 10.625 10.625 10.625

0.4341 0.4341 0.4257 0.4257

3520 3520 3950 3950

2020 2020 2570 2570

394.0 453.0 452.0 520.0

8.535 8.535 8.535 8.535 8.435

8.279 8.379 8.379 8.379 8.400

10.625 10.625 10.625 10.625 10.625

0.3973 0.3973 0.3973 0.3973 0.3881

7930 8920 8920 9410 11360

6620 7110 7110 8840 13420

1062.0 1386.0 1399.0 1477.0 1739.0

13-3/8 13-3/8 13-3/8

61.00 68.00 68.00

J-55 J-55 J-55

STC STC BTC

12.515 12.415

12.359 12.259

14.375 14.375

0.8543 0.8407

3090 3450

1540 1950

595.0 675.0

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Appendix A: SIZE inches

WEIGHT #/ft

SAUDI ARAMCO TUBING & CASING DATA TABLE (continued) GRADE

CONN name

ID inches

DRIFT inches

CON.OD inches

CAPAC cuft/ft

BURST psi

COLLAP psi

JT.STR lbs x 1000

13-3/8 13-3/8 13-3/8 13-3/8 13-3/8

72.00 72.00 72.00 86.00 86.00

L-80 NT-95HS2 S-95 NT-95HS2 S-95

STC NS-CC BTC NS-CC BTC

12.347 12.347 12.347 12.125 12.125

12.191 12.191 12.191 11.969 11.939

14.375 14.375 14.375 14.375 14.375

0.8315 0.8315 0.8315 0.8018 0L8018

5380 6390 6390 7750 7750

2670 3680 3470 6260 6240

1040.0 1935.0 1935.0 2333.0 2333.0

18-5/8 18-5/8 18-5/8 18-5/8 18-5/8

85.50 87.50 87.50 88.70 115.00

J-55 K-55 J-55 H-40 K-55

BTC BTC BTC SJ BTC

17.755

17.567

19.625

17.194

2250

630

1329.0

17.755 17.437

17.249

19.625

17.194 1.6583

3070

1511

1850.0

20 20

94.00 94.00

H-40 J-55

SJ SF

19.124 19.124

18.936 18.936

1.9947 1.9947

1530 520

520 2110

1077.0 1480.0

24 24 24 24

174.00 176.00 176.00 176.00

K-55 X-42 X-42 X-56

BIG-OMEGA VETCO-LS VETCO-RL4 RL-4S

22.624 22.624 22.624

22.327 22.250 22.250

2.7917 2.7917 2.7001

2680 2107 2107

1160 1083 1083

2405.0 2116.0 2060.0

26 26 26

105.00 105.12 136.00

H-40 X-42 H-40

SF SJ SJ

25.250

3.4774

25.000

3.4088

30 30

233.00 233.00

X-42 X-42

SJ VET-RL4FB

28.500 28.120

4.4301 4.3128

1838 1838

768 768

2895.0 2895.0

36 36 36

190.00 282.00 236.00

B B X-60

BW BW BW

35.000 34.500 34.750

6.6813 6.4918 6.5862

851 1458 1822

129 443 254

1952.0 2910.0 4000.0

Notes: 1. KO-105T:

KO (Kawasaki Steel Corporation) 105 (minimum yield strength, psi) T (high collapse resistance)

2. NT-90HSS:

NT (Nippon Steel Special Service) 90, 95, 105 (minimum yield strength, psi) HS (high collapse resistance) S (sour service)

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28.094 36.000 36.000 36.000

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Appendix B: EXAMPLE TUBING MOVEMENT / FORCE PROBLEM The following example takes a typical Saudi Aramco oil producer and calculates the tubing movements and forces which result when the well is acidized. It is provided here to show how the basic tubing movement and force equations are used. It does not cover the three dimensional (or triaxial) stresses since these equations are very complicated12.

Acidization is one of the most stressful operations performed on a well. If not designed properly the well could be damaged to the point that an expensive workover is required to repair it. High surface pumping pressures balloon the tubing, causing it to contract, or shrink. Since the acid is normally pumped at ambient temperature, it is much cooler than the fluid (oil or gas) which was originally in the tubing. This causes the tubing to shrink due to thermal contraction. A combination of these movements, if large enough, may cause the tubing to disengage or "unsting" from the packer allowing the acid, the wellhead injection pressure and subsequent production fluid to be in contact with the tubing/casing annulus. In older wells, it may be possible that the seal assembly is stuck in the packer, not allowing the free movement of the seals in the seal bore extension. Since the tubing cannot move, tensile forces are imparted to the tubing string. These forces, if high enough, may part the tubing. The piston effect at the packer also plays role in tubing movement and forces, depending on the tubing and packer configuration. Three basic well conditions are reviewed: Landing Condition: This condition describes the well when the tubing string was initially installed or landed. For this example the following landing conditions, typical of Saudi Aramco onshore oil producers will be used (refer to Figure 11 for the well cross section): - Production casing is 7" 26# J-55 (6.276" ID from casing tables) - Production tubing is 4-1/2" 12.6# J-55 VAM (3.958" ID from tubing tables) - Packer depth is 7000' - Packer seal bore is 4.00" in diameter and is 12' long - Seal assembly spaced out 3' - Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) - Tubing fluid is diesel (51 pcf) 1

2

Two classic papers have been presented on this subject: - D. J. Hammerlindl (Arco) "Movement, Forces and stress Associated with Combination Tubing Strings Sealed with Packers" published in JPT February, 1977. - Arthur Lubinski (Amoco) et al "Helical Buckling of Tubing Sealed in Packers" JPT June, 1962. Saudi Aramco maintains an in-house computer program called the "Tubing Distortion Program" which can be accessed on the mainframe by selecting ISPF option P.6.25. It calculates tubing movement, forces and triaxial stresses. It was developed by Allen Blanke during the Khuff drilling campaign in 1984 for the Khuff gas completions.

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-

Shut in tubing pressure (SITP) = 0 psi Shut in casing pressure (SICP) = 0 psi Wellhead temperature = 80 oF Bottom hole (stabilized) temperature = 220 oF

Well Condition Prior to Acid Job: This condition describes the well before the acid job. It is provided as background information and is not used in the calculations: - Inhibited diesel packer fluid (51 pcf) - Tubing fluid is oil and gas (~53 pcf) - Shut in tubing pressure (SITP) = 400 psi - Shut in casing pressure (SICP) = 0 psi - Wellhead temperature = 80 oF - Bottom hole temperature = 220 oF Acidizing Condition: This condition describes the well during the acid job. Refer to Figure 11. - Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) - Tubing fluid is 15% HCl acid (67 pcf) - Tubing injection pressure (TIP) = 3000 psi - Shut in casing pressure (SICP) = 500 psi - Wellhead temperature = 80 oF - Bottom hole temperature = 100 oF

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WELLHEAD INJECTION PRESSURE 3000 PSI

FROM PUMPER TRUCKS

CASING PRESSURE 500 PSI

15% HCl ACID (67 PCF)

4-1/2" PRODUCTION TUBING (12.6# J-55 VAM)

INHIBITED DIESEL TUBING-CASING ANNULUS FLUID (51 PCF)

4-1/2" X 3-1/2" CROSSOVER ABOVE PACKER 7" PRODUCTION PACKER @ 7000' with 4.00" SEAL BORE EXTENTION

3-1/2" TAILPIPE 7" PRODUCTION CASING (26# J-55) 6-1/8" OPEN HOLE

TYPICAL SAUDI ARAMCO ONSHORE OIL PRODUCER (TUBING MOVEMENT / FORCES EXAMPLE)

FIGURE 11 Assignment of Length and Force Terms: The length and force change terms (as defined in the previous section) can be defined as follows:

L E As

= = = = =

Depth 7000' 30 x 106 psi (Modulus of elasticity for steel) Cross-sectional area of the tubing wall π 4

( 4.5 2 − 3.958 2 )

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Ap

= = =

Ai

= = =

Ao

= = =

= ΔPi = = =

3.6 sq. in. Area of packer ID π

× 4.00 2

4 12.56 sq. in. Area of tubing ID π

× 3.985 2

4 12.47 sq. in. Area of tubing OD π

× 4.5 2

4 15.90 sq. in. Change in tubing pressure at the packer

change in hydrostatic pressure + change in wellhead pressure ⎡ (67 − 51) ⎤ × 7000 ⎥ + 3000 ⎢ ⎢⎣ 144 ⎥⎦

= ΔPo =

3778 psi Change in annulus pressure at the packer

= = = ΔPia =

change in hydrostatic pressure + change in wellhead pressure 0 + 500 500 psi Change in average tubing pressure

=

Page 34

avg. tubing press while acidizing - avg. initial tubing condition press

=

[ BH press

=

⎤ ⎡⎛ 67 ⎞ × 7000 + 3000⎟ + 3000 ⎥ ⎢⎜ ⎠ ⎥⎦ ⎢⎣⎝ 144

=

3389 psi

( acidizing )

+ surf press ( acidizing )

2

2

] − [ BH press

( initial )

+ surf press ( initial )

2

⎤ ⎡⎛ 51 ⎞ × 7000 + 0⎟ + 0 ⎥ ⎢⎜ ⎠ ⎢⎝ 144 ⎦⎥ −⎣ 2

]

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ΔPoa =

=

= = ΔT = =

r

I

Change in average annulus pressure avg. annulus press while acidizing - avg. initial annulus condition press ⎤ ⎤ ⎡⎛ 51 ⎡⎛ 51 ⎞ ⎞ × 7000 + 0⎟ + 0 ⎥ × 7000 + 500⎟ + 500 ⎥ ⎢⎜ ⎢⎜ ⎠ ⎠ ⎥⎦ ⎥⎦ ⎢⎣⎝ 144 ⎢⎣⎝ 144 − 2 2 500 psi Change in average tubing temperature avg. tubing temp while acidizing - avg. initial tubing condition temp

=

[ BH temp

=

[100 + 80] − [

= = = = = = =

( acidizing )

+ surf temp ( acidizing )

2 220 + 80

]

Ws

8.08 in. Weight of tubing

Wi

= =

12.6 lb/ft Weight of fluid in tubing

= = Wo =

( initial )

+ surf temp ( initial )

]

2

2 2 -60 oF Radial clearance between tubing OD and casing ID (6.276" - 4.5")/2 0.888" Moment of inertia of tubing about its diameter π (D o4 − D i4 ) where D o is outside diameter and D i is inside diameter 64 π ( 4.5 4 − 3.958 4 ) 64

= =

=

] − [ BH temp

Acid Wt × A i 144 67 × 12.47 144 5.8 lb/ft

Weight of displaced fluid Page 35

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= =

β

= = = = =

γ

= =

R

=

Diesel Wt × A o 144 51 × 15.9 144 5.6 lb/ft

Ratio of tubing OD to ID 4.5/3.958 1.14 Coefficient of thermal expansion for steel 6.9 x 10-6 in/in/oF Poisson's ratio for steel 0.3

Substitution of Length and Force Terms into Equations 1. Piston Effect a) Length change −L ΔL 1 = ( A p − A i )ΔPi − ( A p − A o )ΔPo EA S

[

−7000

]

[

(12.56 − 12.47)3778 − (12.56 − 15.90)500 30 × 10 6 × 3.6 = -0.13' (upward since the answer is negative)

=

]

b) Force change F1 = ( A p − A i )ΔPi − ( A p − A o )ΔPo = (12.56-12.47)3778-(12.56-15.90)500 = +340 psi (tubing side) +1670 psi (annular side) = +2010 psi (compression since the answer is positive) 2. Pressure Buckling Effect a) Length change Since ΔPi (3778 psi) is greater than ΔPo (500 psi) the length change due to buckling is

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− r 2 A 2p ( ΔPi − ΔPo ) 2

ΔL 2 =

8EI( Ws + Wi − Wo ) −0.888 2 × 12.56 2 (3778 − 500) 2

=

8 × 30 × 10 6 × 8.08(12.6 + 5.8 − 5.6) = -0.053' (or 0.64" upward since the sign is negative)

b) Force change The force change is negligible since this effect mainly shortens the tubing. 3. Ballooning Effect a) Length change −2 Lγ ⎡ ΔPia − R 2 ΔPoa ⎤ ⎢ ⎥ E ⎢⎣ R2 − 1 ⎥⎦ −2 × 7000 × 0.3 ⎡ 3389 − 114 . 2 × 500 ⎤ = ⎢ ⎥ 30 × 10 6 114 . 2 −1 ⎢⎣ ⎥⎦ = -1.28' (upward since the sign is negative)

ΔL 3 =

b) Force change F3 = - 0.6( ΔPia A i − ΔPoa A o ) = - 0.6(3389 × 12.47 − 500 × 15.90) = -20,586 lb (tension since the sign is negative) 4. Temperature Effect a) Length change ΔL 4 =

LβΔT

= 7000 × 6.9 × 10 −6 × (−60) = -2.90' (upward since the sign is negative) b) Force change F4 = 207A s ΔT = 207 × 3.6 × ( −60) = -44,712 lb (tension since the sign is negative)

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Summation of Movements and Forces

The total movement of the tubing string is summarized by the following table. Since the summation of each effect results in a negative number, the movement is upward. Table 3

Piston Effect Pressure Buckling Effect Ballooning Effect Temperature Effect TOTAL

Movement (ft) - 0.13 - 0.05 - 1.28 - 2.90 - 4.36

If the tubing seal assembly was not allowed to move or if the seals were anchored into the production packer, a tubing to packer force would be exerted. This force would be the sum of all the individual forces as shown by the following table. Since the answer is a negative number, the force is tensile. Table 4

Piston Effect Pressure Buckling Effect (negligible) Ballooning Effect Temperature Effect TOTAL

Page 38

Force (lbs) + 2010 - 20586 - 44712 - 63288

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TABLE OF CONTENTS INTRODUCTION..........................................................................................................1 Packer Definition .................................................................................................1 Types of Packers ..................................................................................................1 Basic Components ...............................................................................................3 PERMANENT PACKERS...........................................................................................4 RETRIEVABLE PACKER..........................................................................................7 PACKER SEAL ASSEMBLY ....................................................................................7 PACKER TAIL PIPE ASSEMBLY..........................................................................9 PACKER SELECTION ...............................................................................................14 POLISHED BORE RECEPTACLES ........................................................................15 LARGE- BORE PERMANENT PACKERS...............................................................16 DUAL PACKERS ..........................................................................................................18

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INTRODUCTION Packer Definition: A production packer can be defined as a subsurface tool used to provide a seal between the tubing and casing to prevent vertical movement of fluids past the sealing point. Packers serve a vital role in well completions and have a marked effect on subsequent operations performed in a well. Major functions of a packer are: •

Protect casing from bursting under conditions of high production or injection pressures

•

Protect casing from corrosive fluids

•

Provide better well control

•

Prevent fluid movement between productive zones

•

Isolate zones or bad casing

•

Keep gas lift pressure off the formation for more efficient gas lift production operation.

Types of Packers: Production packers are generally classified as either retrievable or permanent. By definition, a retrievable packer is one that can be removed from a well by tubing manipulation or some other means not involving destruction of the packer. A permanent packer, on the other hand, must be destroyed for removal. For this reason, permanent packers are often referred to as drillable packers. The primary function of any packer is to provide a seal - the crucial prerequisite to be met in selecting any packer. All other considerations are of secondary importance, and quite rightly so. The functions expected of the packer, the environmental conditions under which it will be used, and its mechanical design must be known before selection is made for a particular application.

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Fig. 1 Otis PERMA-SERIES

Fig. 2 Otis Versa-Trieve Packer

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Basic Components A permanent Otis WB packer is shown in Fig. 1, and in Fig. 2, a retrievable Otis Versa Trieve packer. They all have the following components in common: •

Seal element

•

Slips

•

Cone

•

Setting and releasing mechanism

•

Flow mandrel

Sealing Elements: Sealing elements are normally constructed of nitrile-rubber, except in such special applications as thermal-injection or sour-service operations. Nitrile-rubber seals have proved superior for use in moderate temperatures under normal service conditions. The compound characteristics required for a particular job can be achieved through control of the constituents in the compound and the degree of vulcanization.

Slips: Slips are serrated or "tooth-like" parts of the packer. Once forced outward by the setting action, the slips "bite" into the casing wall preventing the packer from moving when pressure differentials exist across the packer. Some packers have two sets of opposing mechanical slips. The top set of slips prevent the packer from moving uphole while the bottom slips prevent downward motion. Some packers incorporate bi-directional slips, that is, one set of slips which prevent motion in either direction. There are a few packer designs with a set of lower slips and a set of hydraulically activated hold-down button slips.

Cone: The cone is simply that part of the packer which forces the slips to move outward and bite into the casing during the setting of the packer. The cone is known by several other names such as the wedge, expander, or expander cone.

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Mandrel: The flow mandrel (sometimes called the packer mandrel) is the "tube" part of the packer which allows production to enter the tubing and, in turn, on to the surface. It can be generally stated that a packer consists of external components built around the flow mandrel. In many instances, the pressure differential rating of a packer is dependent on the strength of the flow mandrel. Down hole conditions will dictate the type of alloy used to make the flow mandrel.

Setting and Releasing Elements: The setting mechanism on retrievable packers generally consists of a J-latch, a shear pin, or some other clutch arrangement to allow the packer to be engaged. The various mechanisms employed are actuated by a number of different methods, including upward or downward movement, placing weight on the packer, pulling tension in the tubing, or rotating to the right or left. Hydraulically actuated retrievable packers are set with pressure inside the tubing using pump-out plugs, wireline plugs, or flow-out balls. The releasing mechanisms on a retrievable packer involve another wide range of actuation methods - straight pickup, rotating to the right or left, slacking off and then picking up, or picking up to shear pins. Releasing a packer by rotation is difficult to achieve in highly deviated wells. Tubing movement due to changes of pressure and temperature should be evaluated when selecting setting and releasing mechanisms of a retrievable packer. To select a particular type of setting or releasing mechanism, it is necessary to know the conditions existing in the particular wellbore when the packer is set and the operations anticipated during its stay in the hole.

PERMANENT PACKERS Most of the production packers used by Saudi Aramco are of the permanent type. Figure (1) shows an Otis WB permanent packer which is frequently used by Saudi Aramco. The packer can be run and set on wireline or drill pipe. Selection of the setting procedure depends on cost (rig cost and service company charges) and wellbore conditions. When the packer is run on drill pipe a hydraulic setting tool is attached to the top of the packer. Once the packer is on depth, a ball is dropped into the setting tool. Pump pressure activates the setting tool which forces the upper slips, upper cone and lower cone to move downward thus compressing the seal element between the cones against the casing. As the slips slide over the cones they are forced to move outward and "bite" into the casing preventing movement of the packer. When the packer is run on wireline, setting is accomplished by firing an explosive charge to create the necessary pressure required to set the packer.

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Permanent packers cannot be retrieved from the well. A flat bottom mill is used to mill the top slips and part of the sealing element. The packer is then pushed to the bottom and retrieved by using a taper tap or a spear. The packer may also be retrieved by using a milling-retrieving tool. The tool consists of a burn shoe and a collet or a spear. The collet or spear engages the inside of the packer while the top slips are milled by the burn shoe. Once the top slips are milled the packer is pulled to the surface.

Characteristics of Permanent Packers: General characteristics common to permanent packers are: •

Permanently set. Once set, no tubing weight or tension is required to keep it in set position.

•

Economical. Permanent packers have, by design, very few components. As a result, these packers are less costly than other packers of comparable size.

•

Highest pressure rating. Permanent packers due to simple design can be built sturdier than other types of packers. Pressure differential ratings as high as 15,000 psi are possible.

•

High temperature rating. Element packages are available to withstand temperatures in excess of 500 oF.

•

Popularity. Worldwide, permanent packers are the most frequently used of all packer types.

•

Floating seal assembly can be used to accommodate tubing movement.

Disadvantages: The main objection to the permanent packer is the necessity for milling and destroying the packer for removal. A permanent packer can be milled and retrieved in 12 hours by using a milling-retrieving tool or in 24 hours by using a flat bottom mill. Permanent packers can be sub-divided according to the method required to set the packer. Electric wireline, hydraulic and tubing rotation are the three setting methods available. The electric wireline and hydraulic are by far the most common methods used to set permanent packers. Tubing rotation is so rarely used it is beyond the scope of this course.

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Electric Wireline Set Packer The electric wireline set packer is the most commonly used of any type of packer. It can be run and set quickly and accurately at a pre-determined depth. After the packer is set, a production seal assembly and production tubing is then run into the well. Once the seal assembly seals into the packer, tubing length is adjusted at the surface (spaced out) and the well is then completed.

Hydraulic Set Packer There are instances when it is desirable to run a wireline set packer, however, hole conditions may prevent using electric line. To accommodate the running of an electric wireline set packer, a hydraulic setting tool may be used. The hydraulic setting tool takes the place of the electric line setting tool when conditions so dictate. The packer is attached to the hydraulic setting tool and run in the well on pipe. Once on depth, a ball is dropped through the pipe into the setting tool. Hydraulic pump pressure activates the setting tool causing the packer to set. The hydraulic setting tool and workstring are then pulled out of the well and production seals and tubing are run to complete the well. Some conditions which may require using a hydraulic setting tool are: 1. Assembly weight. If the packer and attached equipment weighs more than the electric wireline can support, the assembly may be run and set on pipe using the hydraulic setting tool. 2. Seal assembly on bottom of the packer assembly. If a previously set lower packer is in place, the seals for the lower packer may have to be pushed into that packer using the workstring weight. 3. High angle of deviation. As the angle of deviation becomes greater, a point is reached where the packer will no longer "slide" down the well. This condition requires running the packer on pipe. 4. Heavy mud in the well. A thick, viscous mud may prevent the packer assembly from falling on its own. Again, pipe weight may be required to push the packer assembly down hole.

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RETRIEVABLE PACKER An Otis Versa-Trieve retrievable packer is shown in Fig (2). The packer is designed to be set on wireline or tubing. It has bi-directional slips located below the packer elements to prevent debris from settling on them. During the setting sequence, the packer's guide tube is forced downward while the packer's mandrel is pulled upward. This motion drives the top and bottom wedges under the slips to force them out into the casing wall. Additional setting stroke compresses the packer's elements to form a seal against the casing wall. The packer is maintained in the set position until a shear piston located in the lower end of the packer is moved up to release the packer's mandrel from the packer's shear sleeve. An Otis VRT retrieving tool is used for this operation. Once the packer's mandrel is free to move, a set of shear pins in the Otis VRT tool is sheared, allowing the pulling forces to be transmitted to the packer's mandrel. As the packer's mandrel is moved upward, a snap ring catches the lower end of the element mandrel to release the compression in the packer's elements. Additional upward movement pulls the top wedge from under the slips allowing the slips to move in and release their bite in the casing wall. The main advantage of retrievable packers is that they can be retrieved without destroying the packer. This saves rig time and the cost of replacing the packer. If the old packer is in satisfactory mechanical condition and is not corroded it can be redressed and rerun in the well. Retrievable packers, however, cost more than permanent packers. Sometimes retrievable packers get stuck and cannot be retrieved by conventional retrieving tools. In this case they have to be milled and retrieved by taper tap. Retrievable packers generally take longer time to mill than permanent packers because their slips are made of harder metal.

PACKER SEAL ASSEMBLY: Since permanent packers cannot be pulled out of the well, the tubing cannot be attached directly to a permanent packer. Occasionally, the tubing may have to be retrieved and repaired or replaced. A pressure tight seal must exist between the tubing and the packer bore forcing the production into the tubing. This is accomplished by using a seal assembly which attaches to the tubing and seals in the packer. The seal assembly is designed such that it can move in the packer to accommodate tubing elongation or contraction which can result from changes in temperatures and pressures in the tubing and tubing-casing annulus. The basic seal assembly used in Saudi Aramco wells consists of a locator, a spacer bar, a seal unit and a mule shoe guide.

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Fig. 3 Straight-Slot Locator, J-Slot Locator, Molded Seal Unit & Muleshoe Guide

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Locator: The locator is attached at the top of the seal assembly and at the bottom of the tubing. It is designed to prevent any further downward travel of the seal assembly once the locator encounters the top of the packer. An Otis straight slot locator used by Saudi Aramco is shown in Fig. (3). It is used when free-to-move seal assembly is required. The jay-slot locator shown in Fig. (3) is used when small tubing movement or forces are expected. The jay slots of the locator latch onto the lugs in the packer's head preventing tubing movement. Spacer Bar: A spacer bar is a length of pipe without seals attached to the bottom of the locator and above the seals. It is used as an extension to space out the locator above the packer and at the same time keep the seals inside the bore of the packer and sealbore extension. Seals: The seal unit forms a seal in the bores of the packer and sealbore extension. An Otis standard moulded seal unit used in Saudi Aramco's completions is shown in Fig. (3). The seal is made of nitrile rubber and is used in wells where the pressure is less than 10,000 psi and temperatures are less than 275 oF. Each seal unit is 1 foot long and longer seal assemblies can be made by simply attaching the seal units together. Premium seals are used for harsh conditions of high temperatures, high pressures and in severe environments such as hydrogen sulfide, carbon dioxide and amine inhibitors. Mule Shoe: An Otis mule shoe is shown in Fig. (3). It is installed at the bottom of the seal assembly to facilitate entry into the packer bore. The shape of the mule shoe is designed such that if the seal assembly hangs up at the top of the packer or liner hanger a simple rotation of the assembly will allow it to pass through.

PACKER TAIL PIPE ASSEMBLY: The tailpipe assembly is the part of the tubing that is connected to the bottom of the packer. It serves the following functions: •

Provides a seal bore for the seal assembly.

•

Contains landing nipples for setting wireline plugs used for well control and pressure testing tubing.

•

Contains no-go landing nipples used for hanging bottom hole pressure gauges.

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Facilitates re-entry of wireline tools.

The standard tailpipe assembly used in Saudi Aramco oil producers consists of the following components: • • • • •

Sealbore extension Millout extension Selective landing nipples No-go landing nipples Re-entry guide

Sealbore Extension: A sealbore extension is a length of pipe with polished bore that is connected at the bottom of the packer. It is designed to extend the polished surface of the packer bore to permit use of longer sealing units to compensate for the contraction and elongation of the tubing. An Otis sealbore extension used by Saudi Aramco is shown in Fig (4). It is 12'± long and has the same bore ID as the packer.

Millout Extension: A millout extension is a length of pipe 5'± long which is connected to the bottom of the sealbore extension. The purpose of the millout extension is to facilitate the retrieval of the packer and tailpipe assembly after the packer is milled. It has a larger inside diameter than that of the sealbore extension. The difference in the diameters provides a shoulder where a special plucking tool can engage and retrieve the packer and tailpipe assembly. The use of a millout extension is optional. When not used the packer can be milled out and then retrieved by taper tap or spear.

Fig. 4 Otis Sealbore Extension

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Fig. 5

Landing Nipples used in Saudi Aramco's Well Completions

Landing Nipples: A landing nipple is a device connected to the tubing or tailpipe assembly used for setting wireline plugs or flow control devices. Otis selective nipples are used in Saudi Aramco's well completions. Type 'X' nipple shown in Fig (5) is used for standard weight tubing, type 'R' nipple is used for heavy weight tubing. The bore size of the nipple should be compatible with the size and weight of the tubing. The first 'X' nipple in the tailpipe assembly is installed at the bottom of a tubing pup joint which is connected to the sealbore extension or millout extension. The nipple is used for setting wireline tubing plugs to stop the flow into the tubing. This is normally done during workovers before the tree is removed or when Well Services replace a damaged tubing master valve. In Southern Area well completions two 10' perforated tubing pup joints are connected below the 'X' nipple. During flow tests pressure gauges are hung inside the tailpipe below the 'X' nipples which partially block the flow into the tailpipe. The purpose of the

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Fig. 6

Otis Re-entry Guide

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perforated pup joint is to allow the fluids to enter into the tubing during the flow test. A second 'X' nipple is installed at the bottom of the perforated joints. This nipple is used by S. A. Wireline Services for hanging bottom hole pressure gauges (Normally 'X' nipples are not designed for hanging pressure gauges).

No-Go Landing Nipples: The no-go or 'XN' landing nipple is installed on a 10' tubing pup joint below the bottom 'X' nipple. Like the 'X' nipple it has a polished bore for setting wireline tubing 'PXN' plugs. In addition, the 'XN' nipple has a no-go ID at the bottom to prevent pressure gauge hangers from dropping to the bottom of the well. The nipple is used for hanging pressure gauges and other flow control devices.

Re-entry Guide: The re-entry guide is installed at the bottom of the tailpipe assembly. Its bell shaped design facilitates re-entry of wireline tools into the tailpipe. An Otis re-entry guide is shown in Fig (6).

Fig. 7

Packer Seal and Tailpipe Assemblies Page: 13

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A schematic diagram of the seal and tailpipe assemblies is shown in Fig (7).

PACKER SELECTION The best approach for selecting a packer is to first examine well conditions and desired operational capabilities and then determine which packer features meet those well conditions and best fulfill those operational requirements. Some of the factors that should be considered in selecting a packer are: A. Cost: The packer of minimum cost that will accomplish the objective should be selected. Initial packer price should not be used as the only criterion. Rig time cost for running and retrieving the packer should also be taken into consideration. B. Well Conditions: 1. Packer should be selected to withstand the pressure differentials between the tubing-casing annulus and wellbore below packer during producing and acidizing. 2. Packer should be made of alloys that will withstand the corrossitivity of well fluids. C. Running and Setting Considerations: Packer setting mechanisms are tubing-set, electric-line-set or hydraulic-set. Tubingset packers should not be used in deep wells because of increased possibility of tubing manipulation problems with increased depth. Electric-line-set packers should not be used in highly deviated holes (greater than 50-55o) because it is not possible to run the packer to the required depth. D. Retrieving Considerations: Retrievable packers can be retrieved by a rotational release mechanism or straight pickup release mechanism. A rotation release packer should be avoided in deviated wells because of difficulty in transmitting rotation downhole. E. Production & Treating Considerations: Packers must be able to accommodate tubing movements (elongation and contraction) as a result of changes in temperatures and pressures. Packers set in tension allow for tubing movement due to expansion whereas packers set in compression accommodate tubing contraction. Tubing movement due to both expansion and contraction can be accommodated using a floating seal assembly with sealbore extension.

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F. Compatibility with other Downhole Equipment: If wireline equipment or perforating guns are to be run in the tubing, it is desirable to use packers that do not require weight to keep them set. Wireline operations can be more successfully completed if tubing is kept straight by landing it in tension or neutral. Furthermore, the bore of the packer or the seal assembly should be large enough to allow for running through-tubing, perforating guns, production logs and tubing plugs.

POLISHED BORE RECEPTACLES A polished bore receptacle (PBR) is another type of packer system that can be used in place of a permanent packer. The PBR accepts an inner seal assembly that seals off between the tubing and the PBR Fig (8) and (9). The PBR is commonly used in a liner completion, where it is installed as an integral part of the liner hanger. When the completion string is run, the seal assembly, similar to that used on a permanent packer, is run on the end of the tubing string. The seal assembly is either latched onto the PBR, or left floating to allow tubing movement. The bore of the seal assembly is equal to the ID of liner below which will provide free passage of wireline tools. Normally, the PBR diameter is larger than the diameter of the liner below it. Most workover tools and procedures can be run through the PBR with ease. In a completion, the sealing characteristics and capabilities between the tubing and PBR are the same as between the tubing and packer body of a permanent packer completion.

Fig. 8

PBR installed in Liner Completion Page: 15

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PACKERS The PBR has a disadvantage that the permanent packer does not. The position of the PBR is fixed in the hole, generally in the liner hanger, which may be several hundred feet above the zone of interest. As stated previously, one of the functions of the packer system is to protect the casing string from the corrosiveness of wellbore fluids by sealing off the tubing annulus. Since the PBR is set at the top of the liner, the entire length of the liner is exposed to potentially corrosive fluids when the well is produced. For example, in a well with a 500 ft. liner and a producing interval 50 ft in length, the entire liner is exposed to the effect of the production fluids, as opposed to a typical installation in which the packer would be located just above the pay. LARGE-BORE PERMANENT PACKERS Large-bore packers provide full bore packer ID to facilitate running large OD logging tools. A schematic diagram of an Otis HC packer is shown in Fig. (10). The large bore is achieved by placing the overshot seal unit above the packer bore. The seal unit provides a seal around the polished rod which is latched into the top of the packer. The packer is run on tubing or drill pipe with overshot seal unit attached to the polished rod with shear pins. The packer is set hydraulically and the tubing is picked up to shear the pins and release the overshot from the polished rod. The tubing is then spaced out to allow for tubing movement.

Fig. 9

PBR and Seal Assembly

The HC packer is retrieved by pulling out the tubing and the overshot seal unit. The polished rod is unlatched from the packer and retrieved by using a special 'J' latch retrieving tool. The packer is then milled and retrieved by using a taper or spear.

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Fig. 10

Otis HC Packer

Fig. 11

A Conventional Dual Completion

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DUAL PACKERS A conventional dual completion is shown in Fig (11). This type of completion system allows producing from two zones through separate tubing strings. The bottom packer is run with the tailpipe assembly and set above the bottom producing zone. The top dual retrievable packer is made up on the long tubing string with the lower seal assembly and tail pipe assembly attached to the bottom. The packer is run and the seal assembly stung into the bottom packer as shown in Fig (11). The packer is then set and pressure tested. The long tubing string is permanently attached to the top packer. A travelling joint is normally run on the tubing to allow for tubing movement. The short tubing string is run with a travelling joint and latched into the second outlet of the top packer. The tubing strings are hung on a special dual tubing hanger. A dual production tree is installed on top of the tubing spool which allows producing the two zones separately.

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SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SECTION CONTENTS

PAGE i

CONTENTS

PAGE 1

INTRODUCTION SUBSURFACE SAFETY VALVE SURFACE SAFETY VALVE SAFETY VALVE STATUS SPECIFICATIONS

PAGE 3

SUBSURFACE CONTROLLED SUBSURFACE SAFETY VALVE VELOCITY TYPE ADVANTAGES DISADVANTAGES APPLICATIONS

PAGE 5

SURFACE CONTROLLED SUBSURFACE SAFETY VALVE CONTROL LINE OPERATION ADVANTAGES DISADVANTAGES CLOSURES EQUALIZING BALANCED VALVES RETRIEVAL METHODS WIRELINE ADVANTAGES WIRELINE DISADVANTAGES TUBING ADVANTAGES TUBING DISADVANTAGES CONTROL PRESSURE

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SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SECTION CONTENTS

PAGE 15

SURFACE SAFETY VALVE GATE VALVE AND ACTUATOR INTENDED FUNCTION CONTROL LINE OPERATION OTHER ACTUATORS

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SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

INTRODUCTION

SUBSURFACE SAFETY A subsurface safety valve is a device installed in the tubing of a VALVE: well below the wellhead that can be actuated to prevent uncontrolled well flow. This device can be installed and retrieved by wireline (wireline retrievable) or it can be an integral part of the tubing string (tubing retrievable). They can be subsurface controlled or surface controlled. SURFACE SAFETY VALVE

The surface safety valve, an automatic valve, is an integral part of the wellhead which prevents uncontrolled well flow. The valve consists of two parts; the surface valve and an actuator.

SAFETY VALVE STATUS

The safety valves can be installed alone or together in a well. They are designed to shut when a production facility malfunction or well condition is sensed that indicates a wellhead problem. Table 1 depicts a possible status of either valve under various conditions. Table 1 Safety Valve Status

Alarm

High Flow Line Pressure Low Flow Line Pressure High Separator Level Low Separator Level Fire Wellhead Damage Emergency Shutdown

SPECIFICATIONS

Surface Safety Valve

Subsurface Safety Valve

Closed Closed Closed Closed Closed Inoperable Closed

Open Open Open Open Closed Closed Closed

Specifications which control the manufacture and usage of subsurface safety valves are issued by the American Petroleum Institute. They include: Spec 14A Specification for Subsurface Safety Valve Equipment RP 14B Recommended Practice for Design, Installation and Operation of Subsurface Safety Valve Systems RP T2 Recommended Practice for Qualifications Programs for Personnel who work with anti pollution devices

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SUBSURFACE CONTROLLED SUBSURFACE SAFETY VALVE

Subsurface controlled subsurface safety valves (SSCSSV) are closed by the flow characteristics of the well. They are usually closed by differential pressure through the valve (velocity type) or by tubing pressure at the valve (ambient pressure type). Wireline retrievable SSCSSV's were the first subsurface safety valves developed and provided a means of shutting in a well without operator assistance. VELOCITY TYPE

Velocity type valves utilize a choke or "bean" to create a differential pressure across the choke. A velocity type valve is held open by a selected spring and spacer combination. When the flowing pressure below the valve is equal to or less than the flowing pressure above the valve plus the spring pressure, the valve stays open. Should the pressure above the valve drop to value when added to the spring pressure, lower than the pressure below the valve, the valve will close.

ADVANTAGES

1. 2. 3. 4. 5. 6. 7.

DISADVANTAGES

1. 2. 3.

Does not require a surface control panel or control line. Vandalism is less likely because surface equipment is not needed. Generally less expensive than surface controlled installations. SSCSSV can be set below a packer. The valve can act as a down hole choke in gas wells. It may be used as a secondary valve inside a permanently locked out tubing retrievable safety valve. Provides protection on platforms that produce while drilling additional wells. It has no surface controlled emergency shutdown capabilities. The choke in the valve provides a restriction to flow. The SSCSSV may prematurely close due to: a) wells producing slugs of liquid b) Paraffin build up in the valve. c) Surface chokes being opened. d) Sand production causing high friction through the choke. e) Chamber leakage.

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SUBSURFACE CONTROLLED SUBSURFACE SAFETY VALVE

4.

5.

6.

APPLICATIONS

The valve may fail to close due to: a) Paraffin or scale buildup above the valve. b) Changing well conditions. c) Paraffin buildup in the valve, plugging the flow tube. d) The choke size increases because of erosion from solid laden fluids. e) Improper setup. Choke size, spring rate and number of spacers are chosen by an extensive calculation involving well flowing characteristics. When the valve is installed, it may not function as desired. If the valve does not function as desired, it has to be retrieved and redesigned. Small polluting dangerous but not catastrophic leaks in the tubing, wellhead or flow line will not cause the valve to close.

Subsurface controlled subsurface safety valves can be used in producing wells or in injection wells. The safety valve is attached to a lock selected to be landed in the nipple located in the tubing string (Figure 4). An equalizing sub should be installed between the lock and the valve. The equalizing sub will allow a pressure differential across the closed valve to be equalized by wireline methods. Those direct controlled subsurface safety valves installed in water injection wells are normally closed. They are opened through the force created by the injection pressure from above.

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY VALVE

Surface controlled subsurface safety valves (SCSSV's) are designed to operate independent of well conditions. These valves are connected to the surface with a control line that provides external opening energy, usually hydraulic or electric. These surface safety valves actuate on loss of the external energy. CONTROL LINE

The control line is generally a stainless steel tube spooled, filled with hydraulic fluid, pressure tested and delivered to the location on reels. For installations in hostile environments, monel tubing is used. The line is fastened to the tubing with stainless steel bands. The line is run directly to a tubing retrievable valve or to a lug on a hydraulic landing nipple required for a wireline retrievable valve. The line connects the landing nipple or tubing retrievable valve to a special exit bushing at the tubing spool in the wellhead. In older Aramco wells the control line exited from the tubing bonnet.

OPERATION

SCSSV's are normally closed valves(Figure 1). A spring holds a flow tube(Figures 2 & 3) in an upward position allowing the closure mechanism to form a seal on the valve seat. When hydraulic fluid pressure enters the hydraulic chamber area of the valve the flow tube is forced down compressing the power spring and opening the valve. When hydraulic pressure is released, the spring forces the flow tube up and allows the valve to close. A hydraulic surface control panel is usually used to open the valve and maintain it in the open position. The control panel also connects to an emergency shut down loop, which usually contains all of the emergency control devices. The valves used by Aramco are controlled by the system on the actuator of the surface safety valve.

ADVANTAGES

1. Always controllable by the operator regardless of changes in well conditions. 2. The valves can be tubing retrievable to provide virtually unrestricted flow. 3. They are more reliable than subsurface controlled valves. 4. Unique calculations based on well characteristics are not necessary to calibrate the valve for a particular flow rate.

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

5. High flow rates are not required for periodic tests. (formations may be rate sensitive) 6. They have no severe restrictions to be eroded by flow. 7. Changing well characteristics have no effect on valve operation. 8. the valve can be closed easily in threatening situations. 9. If part of the system fails the valve is designed to close (fail safe).

DISADVANTAGES

1. Requires a control system on the surface. 2. An actuating line must be run to the valve with the tubing. 3. Hydraulic controlled valves have depth limitations.

CLOSURES

The two popular types of closures mechanisms for subsurface safety valves are the ball(Figure 1) and the flapper(Figures 2 & 3). ARAMCO uses the ball valve however flapper valve closures are being tested with favorable results. There are advantages to utilizing the flapper. 1.

Ball closures are a linkage type mechanism and historically have a poor performance in a solids type environment. Flappers are not directly attached to the flow tube , but are free to move and pivot around a single point (hinge pin).

2.

The linkage on the sides of the balls are subject to shearing when being forced open against a differential. The flapper has had some problems when being forced open against differentials in that there were random shearing of the hinges. This problem has been primarily eliminated by reducing the size of the hydraulic chamber so that the hydraulic forces are less than the yield strength of the hinge pin.

3.

Flapper valves are easier to pump through than ball valves.

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

OTIS WIRELINE RETRIEVABLE SUBSURFACE SAFETY VALVE NOMINAL 4" BALL TYPE

SPRING

FLOW TUBE UPPER SEAL

HYDRAULIC PORT PISTON

LOWER SEAL

BALL

VALVE CLOSED

VALVE OPEN

Figure 1: Wireline Retrievable Subsurface Safety Valve

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

DIMENSIONAL DATA (INCHES)

Adapter To Suit Otis Lock 710-YX-012

A

3.812

B

3.802

C

2.122

D

41 (APP.)

O-Ring Material: For H2S/Mild CO2 Service 9 Cr 1 Mo Flow path

Packing Sub

See Detail "A" See Detail "B" Back-Up Ring A

Chevron Packing Unit

T-Seal

Set Screw

Back-Up Ring

O-Ring DETAIL "A" DYNAMIC SEAL ASSEMBLY

Spring Washer D

Spring Housing B Back-Up Ring

Power Spring T-Seal C

Back-Up Ring

Flow Tube

Spring Stop

DETAIL "B"

C-Ring

DYNAMIC SEAL ASSEMBLY

O-Ring Set Screw Intermediate Sub Set Screw

Set Screw Flapper Pin Torsion Spring

Equalizing Plunger Flapper Plunger Spring DETAIL "C" EQUALIZING FLAPPER ASSEMBLY

See Detail "C" Flapper Housing To Fit In Otis Nipples 711 MXO 38141 11 XES 38101 11 XES 38105

Figure 2: Wireline Retrievable Subsurface Safety Valve - Flapper (Baker)

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

C DIMENSIONAL DATA (INCHES)

4-1/2" O.D. 12.6 lb/ft Vam Box Nipple Adapter w/ "B" Nipple Profile Set Screw D

B

Top Sub O-Ring & Back-Up Rings Jam Nut Sub-assembly (See Detail "A") O-Ring & Back-Up Rings Lock Open Ring Set Screw

E

A

7.750

B

6.870

C

4.862

D

3.812

E

3.870

F

126

MATERIAL: For Standard & H S Service 2

Control Line Jam Nut

Back Ferrule Front Ferrule

O-Ring & Back-Up Rings DETAIL "A" JAM NUT SUB-ASSEMBLY Brass Shear Screw See Detail "B" Upper Housing

Wide Back-Up Ring Dynamic T-Seal Wide Back-Up Ring

Locking Mandrel

DETAIL "B" DYNAMIC SEAL ASSEMBLY

Wide Back-Up Ring

F

Piston O-Ring & Back-Up Rings See Detail "C" Set Screw Intermediate Sub

E

Dynamic T-Seal Wide Back-Up Ring

DETAIL "C" DYNAMIC SEAL ASSEMBLY

Set Screw O-Ring & Back-Up Rings Set Screw Piston Coupling Split Ring Flow Tube Power Spring Spring Housing

E

A

D

Spring Stop O-Ring & Back-Up Ring Set Screw O-Ring & Back-Up Ring Flapper Seat Flapper Base Resilient Seal Flapper Pin Torsion Spring

Flapper Equalizing Plunger

Equalizing Plunger Spring

See Detail "D" Flapper Housing DETAIL "D" Flapper Hinge Support EQUALIZING FLAPPER ASSEMBLY O-Ring & Back-Up Rings Set Screw Bottom Sub 4-1/2" O.D. 12.6 lb/ft Vam Pin

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE Figure 3: Tubing Retrievable Subsurface Safety Valve (Baker)

EQUALIZING:

Many surface controlled valves have an equalizing feature in which the shut in well pressure is equalized across the valve by the application of control line pressure to the piston. This pressure causes an equalizing seat to open so that the pressure above and below the valve are equalized before the primary valve mechanism is opened fully. Low pressure wells, extremely high pressure wells and wells with sanding problems are not usually equipped with an equalizing feature. In all cases, the pressure differential across a closed valve should be equalized to prevent damage to the closure mechanism during opening. API does not recommend any type of equalizing features in a valve.

BALANCED VALVES:

In a balanced valve, a second control line is run to the valve and filled with the same control line fluid. The hydrostatic pressure applied to the underside of the piston balances the pressure on top of the piston regardless of the valve setting depth. Theoretically, a balanced valve has an unlimited setting depth; however, the closing time required to displace the control line fluid to the surface limits the depth.

RETRIEVAL METHODS: The first subsurface safety valves designed were wireline retrievable(Figures 4). Then the tubing retrievable subsurface safety valve was designed(Figure 4) to remove the flow restriction of the wireline retrievable valve. Aramco uses wireline retrievable subsurface safety valves but tubing retrievable valves are being evaluated. WIRELINE: ADVANTAGES:

1. Accessibility: wireline retrievable valves can be installed in hydraulic landing nipples, communication nipples or locked out tubing retrievable subsurface safety valves. 2. Wireline valves are easily installed and removed for repair or replacement. 3. Situations requiring a valve with internal equalizing capabilities can utilize a sacrificial wireline retrievable valve

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

with confidence. If the equalizing area is flow cut the valve may be easily and inexpensively retrieved and repaired. 4. Wireline valves can be removed during severe workover operations such as acidizing or fracturing. DISADVANTAGES:

1. During wireline operations, the valve must be removed. Hence, a downhole safety valve is not available. 2. Flow rates can be restricted because of the ID that is smaller than the tubing ID. 3. Installation errors or faulty locks can cause the valve to come loose when it is closed. 4. Before the valve is landed in the nipple the control line fluid is exposed to contaminating fluids in the tubing.

TUBING: ADVANTAGES:

1. Flow rates through valve are the same as for the tubing because the two ID's are the same. 2. Wireline operations can carried out through the tubing valve. 3. The tubing retrievable SCSSV is made up in the tubing string. 4. If the tubing valve should malfunction a wireline SCSSV can be located inside of it. 5. The valve is always in the well. It is not removed for any wireline work. 6. Control line fluid is not exposed to well fluids during installation or retrieval. 7. The valve can usually be bridged during severe workover operations, such as acidizing or fracturing.

DISADVANTAGES:

1. Accessibility: to retrieve a tubing retrievable SCSSV the tubing must be pulled. Page 11

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

TUBING RETRIEVABLE

FLAPPER

BALL

WIRELINE RETRIEVABLE

FLAPPER

BALL

Figure 4: Retrievable Subsurface Safety Valves

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

CONTROL PRESSURE: Safety valve problems vary with each individual application and valve. Since these valves are linked to the surface by the control line, the operation and condition of the valve can be determined by observing the control line pressure characteristics(Figure 5). To determine if the valve piston is moving down, hand pump the control manifold at a constant rate. by observing the control line pressure, an increase in opening pressure (A) should be notice as illustrated in Figure 5. The pressure should increase slower than before time A, indicating the piston is travelling, until time B is reached; then the pressure should increase sharply, indicating the valve is fully open.

100%

TEMPORARY PRESSURE INCREASE DUE TO STATIC FRICTION

B CONTROL LINE PRESSURE

VALVE FULL OPEN

A PISTON TRAVEL

0%

TIME---WITH CONTROL LINE FLUID PUMPED AT A CONSTANT RATE

100%

Figure 5: Control pressure characteristics - opening cycle

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September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE CONTROLLED SUBSURFACE SAFETY

VALVE

To determine if the valve is closing (the valve piston is moving up), exhaust the control line fluid at a constant rate and observe the pressure. It should decrease to pressure A (Figure 6), after which the rate of pressure decrease is much less than before time A. At this point the valve spring pressure exceeds the control line hydraulic pressure and initiates upward piston motion. The lower rate of pressure decline in control line pressure will continue until the piston bottoms out or ceases motion (pressure B on Figure 6). The pressure decrease should continue at the same rate as when the fluid was first bled to the atmosphere.

100%

PISTON TRAVEL VALVE FULL CLOSED

A CONTROL LINE PRESSURE

B TEMPORARY PRESSURE DECREASE DUE TO STATIC FRICTION

0%

TIME---WITH CONTROL LINE FLUID EXHAUSTED AT A CONSTANT RATE

100%

Figure 6: Control pressure characteristics - closing cycle

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WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE

GATE VALVE AND ACTUATOR:

The SSV comprises the gate valve and an actuator assembly. The actuator may be installed by the manufacturer on almost any reverse acting gate valve or may be installed in the field on existing gate valves. Figure 12 is a schematic with parts list to install on a Cameron 6-1/8" FL valve which Aramco uses. Figure 8 shows a valve with a hydraulic actuator in the closed position. Figure 9 is the same valve in the open position. The position of the stem indicates the status of the valve. The valve may be mechanically locked open by a screw on lockout cap shown in Figure 10 Item 21. Fusible caps are available that will melt in the event of a fire and will the valve to close if the valve is inadvertently left locked open. This is a fail close valve since in the absence of control line pressure the spring (Figure 10) is the closing force. Figure 11 is the parts list that is referenced to Figure 10 by the item numbers. Figures 10, 11, and 12 are the drawings and parts lists of the Baker equipment that Aramco uses.

INTENDED FUNCTION:

The surface safety valve is an integral part of the tree and it is designed to shut in the well when a problem occurs downstream of the wellhead. This design eliminates the repeated use of the SCSSV valve by subjecting it to differential pressures and improves the SCSSV reliability should an emergency occur at the wellhead.

CONTROL LINE:

The automatic surface safety valve closes upon loss of control pressure. In a simple application (Figure 7) the control lines are connected from the control panel to the flow line monitor, from the control panel to the hydraulic actuator and from the control panel to the subsurface safety valve. The control fluid in the monitor line is nitrogen(100-150 psi) and the other two control lines have hydraulic fluid(2000-3000 psi).

OPERATION:

There is a pilot monitor on the flow line to which the monitor line is connected. The pilot monitor has a high setting, to guard against the line being closed, and a low setting to guard against line breaks. If either condition happens, the pilot monitor vents

Page 15

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE

FLOW LINE

SURFACE SAFETY VALVE FUSIBLE PLUG

TO CONTROL PANEL TO HYDRAULIC ACTUATOR TO SUBSURFACE SAFETY VALVE

SUBSURFACE SAFETY VALVE

Figure 7: Safety valve control lines

Page 16

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE

the nitrogen which reduces the pressure in the monitor line causing the control panel to take the hydraulic control pressure away from the surface safety valve. The surface safety valve closes. Once the surface safety valve control pressure is released a timing mechanism is set in motion which will release the pressure on the subsuface safety valve allowing it to close. There are two emergency shut down capabilities usually incorporated into the system. One is a remote location manually operated switch and the other is a fusible plug that will melt if fire is present. The surface safety valve can be closed without the subsurface safety valve closing if the control panel and pilot monitors are designed to have separate closings. An example of this situation might be that on high pressure the surface safety valve closes to protect the flow line but the subsurface safety valve does not need to close therefore it is not activated. OTHER ACTUATORS:

There are other types surface safety valves actuators. There is the pneumatic actuator that works on low pressure (100 psi) and the non external control that uses flow line pressure to hold the valve open. The pneumatic actuator works the same as the hydraulic actuator other than control pressure.

GATE VALVE

VALVE BONNET CLOSED

HYDRAULIC ACTUATOR

Figure 8: Hydraulic actuated valve in the closed position

Page 17

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE

GATE VALVE

VALVE BONNET OPEN

HYDRAULIC ACTUATOR

Figure 9: Hydraulic actuated valve in the open position

Page 18

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE

25

4

7

8

9

10 11

1

5

13

27 14 27

15

12

16

17

8

7

19

25 18 26

2.75 O.D.-8N THRD. SEE NOTE 7

2.00

.50 O.D.-20N THRD. 23 24 2

1.75

E

20 THRD. PROTECTOR IS PART OF CYLINDER SUB-ASSY. OR HEAD WELDMENT.

FIGURE 1

F

C 3

22

28

6

D

28 B A

21

UP

OFF

FIGURE 2

FIGURE 3

REMOVE PLASTIC THRD. PROTECTOR AND INSTALL METAL LOCK-OUT CAP AFTER PRODUCTION TESTING. PLASTIC THRD. PROTECTOR ALSO TO BE SHIPPED W/ACTUATOR.

DRAWN BY

7-8-91

Richard Sjodin

PLOT SCALE: 1/2

CHECKED BY

APPROVED BY 8/ /12/ /91 DATE

RS BY

6945 CK.

REVISIONS

-

D

NO.

LTR.

Q.A. APPROVAL

APP.

TITLE MATERIAL

CHARTED

COMMODITY NUMBER

CHARTED

PRODUCT NUMBER

885-11

MODEL-C HYDRAULIC ACTUATOR ASSEMBLY F/H2S-CO2 SERVICE (CLASS-1-2-3S-4)

804 1 400 6

Figure 10: Hydraulic Actuator (Baker)

Page 19

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE ITEM NO.

DESCRIPTION

QTY.

1 2 3 4

SHAFT

+

WIPER RING HEAD PIPE PLUG

+

5 6 7

HOUSING T-SEAL O-RING

+ + +

8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28

08-00260-00 WY-P594-919 08-00262-00 WV-S10D-03P

1 1 2

08-00259-00 WK-R025-ADX WW-B429-V30

2 1 1 1

08-00264-00 WO-RRTS-300 08-00267-00 08-00257-00

1

08-00469-00 WA-H118-OM1 WK-P034-ADX 08-00263-01 08-00258-00

*

LOCK RING RETAINING RING LOCK RING

* * *

UPPER SPRING RETAINER SPRING HEX HEAD BOLT T-SEAL PISTON PISTON CYLINDER LOWER SPRING RETAINER O-RING BASE

+ + + +

THREAD PROTECTOR LOCK-OUT CAP SAFETY HEAD I.D. TAG DRIVE SCREW O-RING BACK UP O-RING BACK UP WIDE T-SEAL BACK UP

+ + + +

WIDE T-SEAL BACK UP

*1 *1 1 1 1

+ +

COMM. NO.

1 1 1 1

*1 1

08-06937-00 WH-S775-B1M 08-00406-01 WA-U004-OD1

*2 *1 *2 *2

WW-A429-12H WW-A345-12H 08-06094-00 08-05932-00

HEAT TREAT

316 S.S.

Rc 22 MAX. N/A Rc 18-22 N/A

FLOUROMYTE AISI 4140/4142 POLYETHYLENE AISI 4140/4142 VITON VITON

AISI 4140/4142 INCONEL X-750

AISI 4140/4142

1.)FOR GENERAL PART LUBRICATION USE BAKER SSS GREASE COMMODITY No. 08-00414-00. 2.) ALIGN ARROWS ON SHAFT WITH CONTROL PORTS AS SHOWN ON FIG. 3. 3.) STAMP I.D. TAG AND ACTUATOR PER SSS-79-2102-40.1-6.13. 4.) TEST ACTUATOR PER SSS-79-2329-00 AND ASSEMBLE PER SSS-80-2330-00. 5.) AFTER TEST COAT PER SSS-79-2102-60.4. 6.)TECH UNIT MUST BE SHIPPED WITH EACH ACTUATOR. 7.) STAMP ACTUATOR SERIAL No. AND "BOT SSS" 2.0" FROM TOP OF CYLINDER AS SHOWN WHEN REQUIRED.

Rc 18-22 N/A Rc 18-22 N/A

AISI 4140/4142 VITON

8.) (+) INDICATES THAT THESE PARTS ARE CRITICAL PER SSS-80-2107-03.

*

9.) REPAIR KIT CONSISTS OF ITEMS & GREASE 08-00414-00.

N/A COMMERCIAL COLD WORKED COLD WORKED

NITRILE NITRILE

10.) CAN SUBSTITUTE SAFETY HEAD 08-03539-80 W/REDUCER WV-BRBO-641.

N/A N/A N/A N/A

NYLATRON NYLATRON

885-11-0304 885-11-0304D

NOTES:

Rc 50 MAX. SOL. ANLD. N/A Rc 29-33 Rc 18-22

304,316 S.S. VITON 17-4 PH S.S.

302,304,316 S.S. 302,304,316 S.S.

ACTUATOR PRODUCT COMMODITY NO. REFERENCE TECHNICAL UNIT NO.

Rc 22 MAX. COMMERCIAL Rc 22 MAX. Rc 18-22

316 S.S.

AISI 4140/4142 POLYETHYLENE CARBON STEEL S.S. AND MONEL

ENG. FILE NO. 6J1105

Rc 18-22 N/A N/A

316 S.S. 302 S.S.

08-00265-00 WW-B345-V30 08-00261-00 08-06969-00

1 1 1 4

MATERIAL

I.D. TAG INFORMATION

INDICATES ITEM 20 IS PART OF HEAD DRWG. 08-00262-00 885-11-0304

PRODUCT COMM. NO.

08-00318-00

REPAIR KIT

* ITEMS

3"

NOMINAL PISTON DIA. TEST PRESSURE

ACTUATOR DIMENSIONS

11625

32.68±.42

7500

A-2 (SHAFT UP VALVE CLOSED)

A-3 + VALVE STROKE

A-3 (SHAFT DOWN VALVE OPEN)

26.43±.43

A-4 (SHAFT DOWN DISCONNECT POS.)

PRODUCT WEIGHT:

TEMP. RANGE

-20 °F TO

PSI X VALVE PRESSURE +

TEMP. RANGE +150

SAFETY HEAD SET AT MAX. WORKING PRESSURE

140

) PSI

°F. SAFETY HEAD SET POINT ESTABLISHED AT 75 °F. 7750

PSI.

26.11±.28 B

VOLUME DISPLACEMENT A-1 TO A-4

.827

CONTROL PRESSURE=(

, H2S-CO2

4"

PSI , API CLASS 1-2-3S-4

MAX. OPERATING PRESSURE A-1 (SHAFT UP REMOVED FROM VALVE)

, SERVICE

, VALVE NOM. SIZE

23.54±.15

C

.99±.076

D

1.255±.005

E

6.05±.020

F

6.75±.031 38.5 IN

DRAWN BY

7-8-91

Richard Sjodin

3

CHECKED BY

APPROVED BY

158 LBS. 8/ /12/ /91

RS

6945

-

G

Q.A. APPROVAL

TITLE MATERIAL

CHARTED

COMMODITY NUMBER DATE

BY

CK.

REVISIONS

NO.

LTR.

APP.

CHARTED

PRODUCT NUMBER

885-11

ASSEMBLY F/0304 MODEL 'C' HYD. ACTUATOR F/H2S-CO2 SERVICE CLASS 1-2-3S-4

804 3 400 6

Figure 11: Hydraulic Actuator Parts List (Baker)

Page 20

SAUDI ARAMCO

WELL COMPLETIONS & WORKOVERS

September 2006 CHAPTER:

SURFACE AND SUBSURFACE SAFETY VALVES

SECTION:

SURFACE SAFETY VALVE ITEM NO. +

DESCRIPTION

QTY.

COMM. NO.

MATERIAL

1

COLLAR

1

08-04630-00

PLASTIC

2

STEM

1

08-08137-03

718 INCONEL

3

WEAR RING

1

WU-NW22-755

O-RING

1

WW-B333-V30

HEX HD. CAPSCREW

6

08-00184-00

+6

BONNET RING

1

08-04896-00

AISI 4140-4142

+7

PACKING CARTRIDGE

1

08-08107-00

17-4 PH S/S

1

08-08150-00

4

*

5

+ 8 * VARIPAK SEAL 9

SPACER

+ 10

1

2

3

4

6

5

7

8

9

10

MOLYGARD

12.62 O.D.

VITON ALLOY STEEL

TURCITE CARBON STEEL

CHTD. 08-00178-00

BONNET

1

08-08136-00

AISI 4140-42

11

GREASE FITTING

1

WU-0410-103

AISI 4130

12

DRIVE SCREW

2

WA-U004-091

S/S

13

I.D. PLATE

1

08-03193-01

S/S

NOTES: 1)

ASSEMBLY PROCEDURE PER SSS-80-2315-00.

2)

ASSEMBLE BONNET WITH NOMINAL No. OF SPACERS, PUSH STEM TO DOWN POSITION, ADJUST GATE TO `A' DIMENSION, PIN GATE IF APPLICABLE, ADJUST DRIFT WITH SPACERS , ATTACH EXTRA SPACERS TO ITEM 5. HAND TIGHTEN BONNET RING , ITEM 6 , AT ASSEMBLY , UPON INSTALLATION OF BONNET ASSEMBLY ON VALVE , TORQUE BONNET RING , ITEM 6 , TO 300 FT. LBS. AFTER ADJUSTING DRIFT. STAMP PER SSS-79-2102-40.1-6.4, 6.5, 6.6 WHEN REQUIRED. STAMP I.D. TAG PER SSS-79-2102-40.1-6.14.

3) 4)

NOM. No. 0F SPACERS

5) 6)

TECHNICAL UNITS MUST BE INCLUDED WITH EACH SHIPMENT.

7)

TEST PER SSS-79-2305-00.

8)

REPAIR KIT

(+) THESE PARTS ARE CRITICAL PER SSS-80-2107-01.

ADJ. + or FROM NOM.

3

3

08-08151-00

TOTAL No. OF SPACERS

6

13 12

14D 6A

TEMP.: U

11

CLASS : 1-2-3S MAT'L. EE

BONNET PRODUCT COMMODITY NO.

879-27-8080

CONSISTS OF (*) ITEMS AND GREASE 08-00414-00.

STROKE REF.

`A' DIM.

6.750

ENGR. FILE No.

6F - 1115 -VI

CUST. VENDOR DWG. No.

X-48500-01 REV. C1

TEST RING & FLG. No.

TF-82

TEMPERATURE

-20°F. TO +250-20F.

TECH. UNIT NO.

879-27-8080

DRAWN BY

6/11/91 Keith Adams

TITLE MATERIAL

COMMODITY NUMBER

CHARTED PRODUCT NUMBER

BONNET ASSEMBLY F/ CAMERON MODEL `FL' 6-1/8" - 3K W.P. SPEC. SERV. W/ 718 STEM & VARIPAK SEAL

808

1

080

1

Figure 12: Hydraulic Actuator Bonnet Assembly (Baker)

Page 21

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006 SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

TABLE OF CONTENTS

INTRODUCTION

1

Definitions, selection of fluids and fluid functions.

TYPES OF FLUIDS

5

Oil, water and oil / water emulsions CHARACTERISTICS OF FLUID ADDITIVES Calcium carbonate and polymers Viscosity and suspension

11

SELECTING A COMPLETION FLUID Solids-free high density fluids: NaCl, KCl, CaCl2 and NaCl / CaCl2 Brine compatibility.

17

SPECIALLY DESIGNED BRINE / POLYMER SYSTEMS

27

Calcium carbonate fluids. Low density (oil-in-water or brine) emulsions Oil -based fluids or invert emulsions

PACKER FLUIDS

36

Functions, characteristics and important points to remember Corrosion inhibitors and guidelines for selecting packer fluid.

HANDLING COMPLETION FLUIDS

41

Rig preparation and fluid maintenance. Displacement techniques and recommended procedure. Spacers, chemical washes and water flushes.

SAFETY Safety apparel and rig safety equipment

63

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

INTRODUCTION Completion or workover fluids are those that are placed against the producing formation while well killing, cleaning out, stimulating, or perforating. A workover fluid is used during remedial work on a well which has been producing for some time. Any contact of a well servicing fluid with an oil or gas reservoir rock will be a prime source of wellbore damage. Poor performance of water source wells, injection wells, or oil and gas production wells can almost always be traced to undesirable characteristics of drill-in and completion fluids used. We should think of completion fluids as tools that aid in performing a downhole operation after the well has been drilled. As tools, these fluids are introduced in the wellbore for a particular function and should be removed after the job. Therefore, we must try to prevent the loss of damaging fluids into the producing zones. Completion and workover fluids technology evolved in an effort to minimize this damage through the use of specialized fluids. These fluids differ from drilling muds in that they are clean, solids-free or degradable and tailored to be nondamaging to the producing formation. Two primary objectives must be accomplished regardless of the well servicing operation undertaken: • •

Control the well during the operations Protect the producing formation from damage

Definitions Completion fluidsare used for downhole applications such as : • Perforating • Wellbore cleanout • Displacement of treating chemicals ( surfactants, acids, and solvents ) • Underreaming, gravel packing, and fracturing • Cement and sand consolidation • Packer fluids Workover fluids are the general purpose fluids such as : • Kill fluids to control the well while it is open • Milling and fishing downhole equipment or sidetracking • Displacement of cement for zone isolation or plugging old perforations • Suspending wells

Page 1

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

Selection of fluids Many factors must be considered before a decision is made on which well servicing fluid is to be used. Selection of fluid should be a logical solution based on operational necessities and formation characteristics. The workover engineer should communicate between the different departments ( geological, petrophysical, reservoir, drilling and workover operations and the laboratories ) to gather information, conduct the necessary studies and laboratory tests. The proper fluid system can be selected based on the data obtained. In most cases, this selection process requires compromises be made. Usually, formation damage cannot be totally prevented, but certainly it can be minimized by optimizing the favorable aspects of the fluids to be used. Applying the technology available today, we can remove most of the "guess work" in designing the best fluid. Procedure • • • • • • •

Define the operational objectives. Identify the environment under which the fluid must perform ( bottomhole pressure and temperature, location, rig equipment, water supply and surface temperature ) . Evaluate performance of fluids used before and problems encountered in the field. Study the reservoir rock and reservoir fluid chemical characteristics. Examine possible reactions between candidate fluids, rock minerals & fluid. Analyze field results and assess the fluid performance after the job. Recommend changes or modifications for future work.

Understanding of the physical and chemical reservoir characteristics by all personnel involved will ensure good planning, help in identifying problems and improve field practices. A reservoir rock sensitivity study may be required along with measurements of the residual damage caused by different fluids. Such a study will determine the degree of damage caused and the effectiveness of the remedial measures. SENSITIVITY STUDY RESERVOIR FLUID

RESERVOIR ROCK

Water analysis & Fluids compatibility Scaling tendencies Emulsion tendencies

Mineral analysis & clay fraction Grain & pore size distribution Porosity & permeability

_____________________________________________________________________________________ Page 2

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

Fluids functions Well control is a primary function. The fluid must be heavy enough to create the required hydrostatic pressure to stop the well from flowing. The fluid density determines the hydrostatic head and it should be no higher than necessary to minimize the fluid invasion into the subsurface formation. Fluid density is the mass per unit volume and may be measured as pounds mass per cubic foot or pounds mass per gallon. Density may also be expressed in terms of specific gravity or pressure gradient. Specific gravity is the mass of fluid at a given temperature relative to the mass of an equal volume of water at the same temperature. The pressure gradient is the hydrostatic pressure created by the fluid per unit of vertical depth. Fluid densities decrease with increasing temperature. The amount of decrease depends on the fluid composition. By way of example, an 86.77 pcf ( 11.6 lb/gal ) CaCl2 brine at 70 °F decreases to 83 pcf ( 11.1 lb/gal ) at 230°F. The measurement of fluid density will be affected by entrapped gases. If gas entrapment is a problem, one can use a pressurized mud balance or deaerator to measure the fluid density. Two instruments are in general use in the field: mud balance and hydrometer ( API 13J ). Three different types of materials are commonly used in the oil field to increase the fluid density, water soluble salts, acid soluble minerals and insoluble minerals. The nature and applications of each type will be discussed in this presentation. Saudi Aramco's recommended practice is not to use insoluble minerals in well servicing fluid formulations. Wellbore cleanout is another major function. Drilled cuttings, produced sand, drilling mud residue, rust, scale, paint chips, iron shavings and debris must be removed from the well. Solids left in the wellbore can enter the perforation restricting the flow capacity of the well. After the well is completed, these solids can fall on the downhole dynamic seal assembly causing leaks and the potential need for an expensive workover. The effectiveness of any fluid used in the well cleanout operations depends on its carrying capacity, which is largely a function of fluid viscosity. Rotating the workstring ( 3-10 rpm ) will improve the removal of solids from the well while circulating. Chemical washes ( water wetting surfactant, mutual solvent in acidic water ) will remove organic and inorganic residue when circulated downhole followed by high viscosity sweeping pill. Examination of tubing recovered from wells shows that corrosion in the annulus could be avoided had solids been effectively removed through proper displacement.

Page 3

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

Corrosion protection is an important function of all well servicing fluids which will remain in the well for an extended period of time. Corrosion inhibitors are added to reduce the fluid corrosion rate to acceptable level. Oxygen scavengers, film forming amines, high temperature inorganic inhibitors and pH buffers are effective chemicals at low concentrations. The simplest and most common method of corrosion control is to use a highly alkaline fluid. Static testing in the lab for thirty days at the desired temperature and pressure, is sufficient to determine the long term corrosivity of the fluid Formation protection is a function of any fluid that may become in contact with a producing formation. The fluid allowed to leak off to the formation should not contain damaging solids, such as clays, silt, barite, paraffin, asphalt, rust, pipe dope etc.,. The fluid or fluid filtrate should be chemically compatible with the formation fluids and should not allow the clay minerals to hydrate, swell or move. Surfactants, such as the oil wetting corrosion inhibitors, oil-based mud emulsifiers, and lubricants will cause emulsion blockage when introduced into a producing formation. If excessive fluid losses are expected, water-wetting surfactant should be included in the fluid formulation to prevent or remove water blocking. Treating chemicals displacement is a very important function of the well servicing fluids. To pump acid, mutual solvent, clay stabilizer, injection water, etc into the reservoir rock a workover fluid is usually employed. It must be clean and compatible with the treating chemicals and the formation fluids. The wellbore must be also cleaned with properly designed spacers and chemical washes. Electrical logging is greatly affected by the wellbore fluid. Materials and chemicals which adversely affect the quality of the logs should be avoided. Reservoir Engineering should be involved in the selection of the type of workover fluid to be used. Some logs require low chlorides content and others will produce erroneous data in the presence of small amount of barite. Saudi Aramco's recommended practice is to maintain the chlorides below 50,000 mg/l and not to use any barite in the fluids while drilling and completing the payzone section.

_____________________________________________________________________________________ Page 4

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

TYPES OF FLUIDS Completion fluids are used in well operations during the process of establishing final contact between the productive formation and the wellbore. They may be water-based mud, nitrogen, an invert emulsion, a solids-free brine, or an acid soluble system. The most significant requirement is that the fluid is not damaging to the producing formation. Packer fluids are used in the annulus between the production tubing and casing. They must provide the required pressure, must be non-toxic and non-corrosive, must not develop high gel strength or allow solids to settle out of suspension over long periods of time, and must cause minimal formation damage. Various types of fluids may be utilized for completion and workover operations. Current literature relating to completion and workover fluids reveals different approaches to classifying such fluids. Allen and Roberts used the following categories in their discussion of completion and workover fluids. 1 - Oil fluids: • Crude oil • Diesel oil

2 - Clear water fluids: • Formation salt water • Seawater or bay water • Prepared salt water

3. Solid Laden fluids 4. Conventional water-base muds 5. Oil-based or invert emulsion muds According to Gray, completion and workover fluids may be categorized as follows: 1. Water-base fluids: • Fluids with water-soluble solids • Fluids containing oil-soluble organic particles • Fluids with acid degradable polymers and solids 2. Oil-in-water emulsions ( low density ) 3. Oil-based or invert emulsion ( water-in-oil emulsions )

Page 5

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

Following Allen's classification, a description of the different types of completion and workover fluids follows: Oil fluids As the name indicates, oils of different origin are sometimes used to complete the well. Depending on availability, crude or diesel oil may be used as the completion fluid. Crude oil is a logical choice where its density is sufficient to control formation pressure. The fluid has very low viscosity, limited carrying capacity and no gel strength. The loss of fluid to the formation is not harmful from the point of view of clay hydration and migration. Since it has no fluid loss control, fine solids may enter the formation. Crude oil always has to be checked for presence of asphaltenes and paraffins that can damage the formation. The possibility of emulsion forming with the formation water should be checked before it is used. The technique described in the API RP 24 is suitable for field use. If forming of emulsion is possible, a surfactant should be added to prevent it. Diesel oil is used when a clean and low density fluid is necessary for a completion and workover operation. Always check the diesel for a possible solid contamination in order to avoid formation damage. Emulsion and wettability problems will be avoided if the diesel is obtained form the refinery before fuel additives are added. Diesel oil will offer a non-corrosive environment, which makes it attractive as packer fluid. Clear water fluids This group includes waters of diverse origin with different salts in solution. These waters may contain solids, although the concentration is usually very low. Based on the origin of the water, the clear water fluids may be divided as follows: Formation water is the produced reservoir water. It is a common workover fluid, since its cost is low. Clean formation water is ideal from the point of view of compatibility with the reservoir fluids and minerals. Before using produced formation water as a completion and workover fluid, a compatibility study with the reservoir rock exposed in the wellbore should be run. Also, the calcium content and the scaling tendencies should be determined. Although formation water is taken into consideration as a clean, ready to use fluid, it many times will contains fine solids, treating chemicals, paraffins, asphalt or scale.

_____________________________________________________________________________________ Page 6

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

All these compounds, if not controlled, may cause serious formation damage. The water should be cleaned or filtered before use and a field check should be run using API RP 42 procedures to avoid emulsion problems. Abqaiq pit brine is a natural brine available in Abqiaq field with density of about 77.5 pcf. This brine has high concentrations of sulfate and bicarbonate ions. It can be used as a kill fluid to plug and abandon a well and must not be used for preparing any other salt solutions such as KCl or CaCl2 . Any additions of calcium chloride will precipitate sodium chloride, calcium sulfate, and carbonates which will cause plugging downhole. NOTE ABQAIQ PIT BRINE SHOULD NOT BE USED FOR WELL COMPLETION OR ACID STIMULATION OPERATIONS . IT IS NOT CHEMICALLY COMPATIBLE WITH OTHER FLUIDS. IF USED, CALCIUM SULFATE SCALE WILL PRECIPITATE, THE PRODUCING ZONES AROUND THE WELLBORE WILL BE PERMANENTLY DAMAGED AND THE WELL MAY THEN HAVE TO BE PLUGGED AND ABANDONED.

Abqaiq pit brine analysis ( + 77.5 pcf ) Na Ca Mg Sp.gr

69,409 mg/l 480 mg/l 32,000 mg/l 1.242 gm / cc

Cl SO4 HCO3 pH

154,425 mg/l 62,790 mg/l 683 mg/l 7.2

Seawater is frequently used in coastal areas due to its availability. Depending on salinity, it may be necessary to add NaCl or KCl to avoid formation clays or shale swelling. Calcium chloride brines should not be prepared with seawater. Calcium sulfate and carbonate will precipitate downhole and cause plugging.

A good well servicing fluid will not damage a formation.

Page 7

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

COMPLETION & WORKOVER FLUIDS

Such so-called clear and clean fluids can be most damaging if proper steps are not taken because: 1. They do not contain sized, well-balanced bridging particles, or fluid-loss additives that will bridge and seal the formation to assure minimal fluid losses.

Properly sized bridging particles minimizes fluid invasion into permeable formation.

2. They usually contain both dissolved and undissolved solids which can be carried deep within the formation and can damage it beyond economical repair. 3. Sea and bay water contains living microorganisms like bacteria and plankton, which also acts as plugging material.

_____________________________________________________________________________________ Page 8

SAUDI ARAMCO

COMPLETIONS & WORKOVER MANUAL

September 2006

SEGMENT

COMPLETIONS

CHAPTER

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SEM photo for material ( diatoms ) filtered out of seawater.

4. Seawater usually has a high sulfate concentration ( 2,600 ppm ) which can, in the presence of calcium or barium, plug the well with solid calcium and / or barium sulfate for which there is no economically feasible treatment. 5. Many crude oils, when produced, drop out heavy hydrocarbons like asphaltenes and waxes in myriad of small particles which are easily injected into the formation and cause severe plugging. 6. Freshwater is quite damaging to many formations containing appreciable clay content such as the Unayzah reservoir. Oil and water emulsions Oil and water are incompatible fluids but can be mechanically mixed under high shear to form emulsions where one phase exists as small droplets ( dispersed phase ) in the other phase ( continuous phase ). Invert emulsions consist of water droplets in a continuous oil phase ( water-in-oil ) and normally contain higher volumes of oil. Direct emulsions or true emulsions consist of oil droplets in a continuous water phase ( oil-in-water ) and normally contain higher volumes of water. The stability of the emulsion can be drastically improved by the addition of chemicals called surfactants ( emulsifiers ). They have the special ability to concentrate between the oil and water phases and so stabilize the emulsion.

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Surfactant molecule Water loving group

Oil loving group

Oil-in-water emulsion

Whether an oil-in-water or water-in-oil emulsion is formed depends on the relative solubility of the emulsifier in the two phases. A preferentially water soluble surfactant, such as sodium oleate, will form an oil-in-water emulsion because it lowers the surface tension on the water side of the oil-water interface, and the interface curves towards the side with the greater surface tension, thereby forming an oil droplet enclosed by water. On the other hand, calcium and magnesium oleate are soluble in oil, but not in water, and thus form water-in-oil emulsion. The advantages, composition and applications of oil-based fluids will be discussed in this presentation.

Stabilization of invert emulsion with surfactant emulsifier

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CHARACTERISTICS OF COMPLETION / WORKOVER FLUIDS ADDITIVES Acid soluble ( CaCO3 ), weighting material Conventional Water base muds ( composed of bentonite, barite, caustic soda, soda ash and lignosulfonates..etc. ) should never be used except in zones to be abandoned. These muds contain high concentrations of dispersed fine solids and clays that can cause irreversible formation damage. Also, the filtrate of these muds can cause dispersion, movement and swelling of the formation clay minerals. It may also precipitate fine solids in the formation causing further damage. Fluid densities up to 105 pcf can be achieved with finely ground marble ( 5 - 10 microns ).

Typical Physical and chemical constants for sized marble Hardness (Moh's Scale) Specific Gravity Bulk density, lb/ft3 Total carbonates (Ca, Mg) Total impurities ( A12O3, Fe2O3, SiO2, Mn )

3.0 2.7 168.3 98.0% (Min.) 2.0 % (Max.)

Also, it is possible to prepare fluids with a maximum density of 120 pcf using iron carbonate. To minimize the high viscosities associated with large solids content, the calcium carbonate should be ground in such a way that 93% will go through a 325 mesh screen. Both calcium carbonate and iron carbonate are soluble in hydrochloric acid ( HCl 15 % ). Calcium carbonate used has a specific gravity of 2.7 g/cc and should be at least 97 % acid soluble ( iron carbonate is only 87 % ). One gallon of HCl 15% dissolves 1.84 lb of calcium carbonate. Iron carbonate will leave residue of 13% solids in the formation after acidizing. These solids may be left to plug the formation or may be flushed out depending on the size and distribution of the formation pore channels. A combination of hydrochloric acid and hydrofluoric acids ( HF or mud acid ) should not be used with calcium or iron carbonate. The hydrofluoric acid reacts with the calcium and iron to precipitate insoluble salts. Calcium Carbonate ( ground marble )is locally produced and commonly used in drilling fluid. Ground Limestone is not suitable for this application, it breaks and become paste like which causes settling, etc.

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Chacteristics of polymers The most suitable viscosifiers for non-damaging completion and workover fluids are the XC-polymer ( xanthan gum ) and the HEC ( hydroxy ethyl cellulose ). These polymers are effective in salt brines and the thickening action can be stabilized at temperatures as high as 275°F. Other viscosifiers such as bentonite, polyacrylamide and guar gum are not degradable and should not be used. When choosing a viscosifier, one must be careful to determine the product generic name or chemical composition and whether it is degradable or not. Some polymers should not come in contact with reservoir rocks. In most applications of these systems, it is necessary to add polymers to control filtration and to provide carrying capacity and suspension. After examining the characteristics of all available polymers, the industry chosen polymers to used are HEC, XC-Polymer and Modified Starch . In applications where a high carrying capacity is required, suspending properties ( gel strength ) can be only achieved with XC-Polymer ( xanthan gum ). Also, it should be kept in mind that for stabilizing the suspension and minimize settling at high temperature, MgO ( magnesium oxide ) should be used. It will also provide the proper pH up to 10.

Polymer HEC HEMC CMC XC-Polymer Drispac Starch Guar gum Polyacrylate

Type

Viscosity Development

Filtration Control

Suspension Properties

Acid Solubility

Brine Tolerance

NI NI A A A NI NI A

Excellent Excellent Good Fair Poor Poor Excellent Poor

Poor Poor Good Poor Good Good Poor Good

Poor Poor Fair Excellent Poor Poor Poor poor

Excellent Good Poor Good Poor Poor Fair Insoluble

Excellent Excellent Poor Fair Poor Good Good Poor

NI Non lonic A-Anionic

Characteristics of water soluble polymers used for viscosity, suspension and filtration control

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Viscosity and suspension It is necessary to assure that solids are suspended in the fluid. Suspended solids should not rapidly separate from the fluid when circulation is stopped. Or, we may desire that suspended solids remain suspended in surface tankage for some period of time. Calcium carbonate "fine" should have particles in the range of 0.1 - 10 microns which is fine enough to remain in suspension by imparting gel strength to the well fluid. In drilling fluids, gel strength is derived from the interaction of clay particles. In workover fluids gel strength is usually provided by XC-polymer ( NOT HEC ). A gel strength of only 2 to 4 lb/100 ft² is sufficient to suspend the barite used in drilling muds. More gel strength is required to suspend larger particles or denser particles. If the suspending fluid has no gel strength and suspended particles are above colloid dimensions, then the particles will settle out with time. Particle settling can be drastically slowed, but not eliminated by providing the fluid with increased viscosity. This is usually accomplished in well fluids by adding XC-polymer to the fluid. When gel strength is used to give particle suspending properties to a fluid, one must be concerned not only with the ability of the resulting gel to suspend solids, but also with the pressures required to reinitiate fluid flow. Depending on the location of gelled fluid within the tubulars, undesirable pressure may develop at the surface or bottomhole before the gel breaks and flow is reinitiated. The gel strength determines the pressure required to break circulation. For example, consider the removal of a gelled packer fluid from an annulus. A concern in this case might be whether or not exposed formation will be fractured before circulation is broken and packer fluid removal begun. In this case, if a 0.57 psi/ft packer fluid with a gel strength of 50 lb/100ft² were to be circulated from a 31/2" x 7" annulus with a 0.54 psi/ft workover fluid in a 10,000 ft well, the pressure required to break circulation would be 840 psi. The 840 psi increase in the surface pressure will be reflected by a similar increase in the overbalance at the perforations. Such an increase may not be tolerable. Circulating fluids are those working fluids used to move things around within a well. These fluids may be required to transport solids into or, more typically, out of the well. They may be required to suspend solids for various lengths of time when circulation ceases. They may also be required to displace treating fluids to the formation and in some cases to over displace the treatment fluids out into the formation. Excessive loss of the circulating fluid to the formation often can not be tolerated. In a workover involving solids transport or washing operations, the workover fluid should be able to carry solids to the surface. In this application, viscosity is the most important

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fluid property. As the viscosity of the fluid increases, the carrying capacity increases. Brines with viscosifiers added, muds, foam, and gas are the most common fluids used for these clean-up operations. Foam or gas may be used to provide lifting capability for workover or completion fluids, sand, and small cuttings. There are three main factors which determine the magnitude of effective viscosity required for solids transport in washing operations. These factors are well temperature, the size and weight of solids to be transported, and the shear conditions (flow rates and tubular dimensions) in the tubing or annulus in which the solids are to be transported. The viscosity decreases more-or-less exponentially as temperature increases. To be conservative it is appropriate to design using the maximum expected circulating temperature thereby providing more than sufficient viscosity for transport at all other temperatures. The fluid temperature profile in a well depends upon wellbore geometry, flow rate. flow direction, elapsed time and geothermal gradient. Accurate estimation of the flowing temperature profile requires a computer simulator. On the basis of such simulations we can generalize as follows: During circulation the maximum temperature occurs is somewhere between 213°F and 250°F. The maximum temperature is lower at high flow rates and higher at low flow rates approaching the geothermal profile as flow ceases. The maximum temperature is always less than the static bottomhole temperature and always greater than the return fluid temperature. The second factor affecting the desired viscosity of a fluid is the nature of the solids to be transported. As a rule, a higher viscosity is required to transport larger and heavier particles. For example, removing cuttings from milling out a packer will require a viscosity greater than that required to wash sand from the well. The third factor effecting the desired viscosity is the shear conditions to which the fluid is exposed. The shear rate is determined by the fluid flow rate and wellbore geometry at the point of interest. Shear conditions have an effect similar to the effect of temperature on the fluid viscosity. Most polymer viscosifiers, which are added to brines to increase viscosity, are shear thinning (i.e., their viscosity drops as shear increases). The shear rate through the tubing is significantly greater than shear rate through the tubing casing annulus. Depending on the type of operation, method of fluid circulation, and other well conditions, the shear rate may be lesser or greater.

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Typical shear rate ranges are :

Tanks, Pits

0

-

5

sec–1

Annulus

10

-

500

sec–1

Tubing, Workstring

100

-

3000

sec–1

The relationship between these three factors will determine the range of viscosities that may be achieved with a particular fluid, and the desired concentration of polymer required to achieve a particular viscosity. The effect of particle size on required viscosity is illustrated in the following table:

Particle size ———— 40 mesh 40 mesh 20 mesh 20 mesh 10 mesh 10 mesh 1 cm 1 cm

Circul. rate ( BPM) ———— 5 5 5 5 5 5 5 5

Fluid density ( pcf ) ———— 67.3 67.3 67.3 67.3 67.3 67.3 67.3 67.3

Tubing

Casing

( inch ) ———— 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5

( inch ) ———— Tubing 7" annul. Tubing 7" annul Tubing 7" annul Tubing 7" annul

Required viscosity (cp) ————— 0.25 0.7 1.0 2.8 5.8 16 150 400

Forty mesh sand may be circulated or reverse circulated using a fluid with a viscosity of 0.7 cp or 0.2 cp respectively. This viscosity is less than or equal to the viscosity of water at well temperatures. On the other hand, viscosity somewhat greater than the viscosity of water at well temperatures is required to wash twenty mesh sand.

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Typically, in this case the viscosity would be raised to 10 cp as a safety margin to compensate for temperature effects and possible shut downs. Ten mesh sand requires still greater viscosity and large cuttings require a substantial increase in viscosity. The effect of flow rate on the required viscosity is illustrated in the following table:

Particle size ———— 10 mesh

Circul. rate ( BPM) ———— 1

Fluid density ( pcf ) ———— 67.3

Tubing

Casing

( inch ) ———— 3.5

( inch ) ———— Tubing

Required viscosity ( cp ) ———— 29

1

67.3

3.5

7" annul.

80

1 1 5 5 10 10

67.3 67.3 67.3 67.3 67.3 67.3

3.5 3.5 3.5 3.5 3.5 3.5

Tubing 7" annul Tubing 7" annul Tubing 7" annul

750 2000 150 400 75 200

( 2 mm )

10 mesh ( 2 mm )

1 cm 1 cm 1 cm 1 cm 1 cm 1 cm

Larger sand particles (10 mesh = 2 mm) may be reverse circulated from the well at 1 BPM with a 20 cp fluid and circulated from the well with an 80 cp fluid. At the same flow rate particles of 5 times the diameter require 750 cp and 2000 cp viscosity fluids to be removed by reverse and direct circulation respectively. increasing the circulation rate decreases the required viscosity proportionately.

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SELECTING A COMPLETION FLUID Some conditions must be satisfied when making a completion fluid selection from all available systems. The fluid must have the necessary density required to control the subsurface pressure. This may narrow the choice considerably. If a non-solids or solidsfree fluid is to be used, density limitations before precipitation of the solute will dictate limitation of a particular fluid. For example, if sodium chloride is the solids-free system of choice, then 75 pcf would be the density limit. If a higher density is needed, then calcium chloride can be used to a limit of 86 pcf. After inspecting what fluid would fit the hydrostatic head requirement, a cost comparison should be made. Overall cost, however, should be included at this point, not just the cost per bbl. Solids -free high density fluids Solids-free brines can have densities ranging from 62.4 to 143.6 pcf .

Saturated brine NaCl KCl NaBr NaCl / NaBr2 NaCl / CaCl2 CaCl2 CaBr2 CaCl2 / CaBr2 CaCl2 / CaBr2 / ZnBr2 CaBr2 / ZnBr2

Density pcf 75 72 95 95 83 87 106 113 144 151

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Comparative Densities of Solids-Free Completion & Workover brines in Pounds Per ft³

Brines used in completion and workover applications may be a single-salt brine, twosalts brine, or a brine blend containing three different salt compounds. Single Salt Brines are those made with clean fresh water and one water soluble salt such as potassium chloride, sodium chloride and calcium chloride. They are the simplest brines used in completion and workover fluids. Because they contain only one salt, their initial composition is easily understood. Their density is adjusted by adding either salt or water. Two salts brines are made with combination of two salts in fresh water. They required accurate measurement of the starting volume of water and the quantities of salts required for the specific density. Excess salt will precipitate the less soluble salt. Three salts blends are made with a combination of three salts in fresh water. They require a specialist to blend in the field due to the complex nature of the blends and several tests required during the preparation of these blends. CaCl2 / CaBr2 / ZnBr2 are example of these blends . These blends are not used in Saudi Aramco wells and will not be discussed in this presentation.

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Sodium chloride brines The most commonly used brine in the oil field is sodium chloride (NaC1). The maximum density of a sodium chloride brine is 74.5 pcf at 60°F. The preparation of brines up to 73 pcf is fairly easy. From 73 pcf to 74.5 pcf , additional sodium chloride dissolves very slowly. Corrosion rates are fairly low for the saturated brine ( 74.5 pcf ) and high for the lower density brines. Corrosion inhibitor is required for NaCl saturated packer fluids. Material requirements for NaCl brines are provided in the formulation charts. Brine Density at 70 ºF pcf 62.8

To Make 1 bbl ( 42 gal ) Water 100% NaCl bbl lb 0.998 4

63.6

0.993

9

64.3

0.986

16

65.1

0.981

22

65.8

0.976

28

66.6

0.969

35

67.3

0.962

41

68.1

0.955

47

68.8

0.948

54

69.6

0.94

61

70.3

0.933

68

71.1

0.926

74

71.8

0.919

81

72.6

0.91

88

73.3

0.902

98.7

74

0.895

102

74.8

0.888

109

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The effects of temperature change on NaCl density

lb / ft2 = 7.48 X lb / gal

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Potassium chloride brines Potassium chloride (KCl) brines are excellent completion fluids for water-sensitive formations where densities over 72.5 pcf are not required. Corrosion rates are reasonably low and can be reduced even more by keeping the pH of the system between 8 and 10 using KOH. Material requirements for preparing KCl brines are given in the formulation charts. Brine Density at 70 ºF pcf 62.8

To Make 1 bbl ( 42 gal ) Water 100% KCl bbl lb 0.995 4

63.6

0.986

11.6

64.3

0.976

18.9

65.1

0.969

26.1

65.8

0.96

33.4

66.6

0.95

40.7

67.3

0.943

47.9

68.1

0.933

55.2

68.8

0.924

62.4

69.6

0.917

69.7

70.3

0.907

76.9

71.1

0.898

84.2

71.8

0.89

91.5

72.6

0.881

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Calcium chloride brines Calcium chloride (CaC12) brines are easily mixed at densities up to 86 pcf. Generally, dry CaCl2 is available in two grade: 94-97% and 77-80% pure. A considerable amount of heat is generated when dry CaC12 is mixed with water. Corrosion rates for CaC12 brines are approximately the same as for KCl and NaCl brines; i.e., reasonably low in the pH range between 7 and 10. Material requirements for preparing CaCl2 brines are given in the formulation charts. To Make 1 bbl ( 42 gal ) % by Wt. 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

pcf 62.4 63 63.5 64 64.5 65 65.5 66 66.6 67.2 67.7 68.3 68.8 69.4 70 70.6 71.2 71.8 72.4 73 73.7 74.3 74.9 75.5

95% CaCl2 lb 0 3.72 7.5 11.35 15.26 19.23 23.27 27.36 31.52 35.74 40.03 44.4 48.83 53.36 57.95 62.62 67.35 72.16 77.03 82.01 87.07 92.2 97.4 102.7

Water bbl 1 0.998 0.995 0.933 0.99 0.988 0.985 0.981 0.978 0.975 0.97 0.967 0.964 0.96 0.957 0.953 0.949 0.945 0.94 0.936 0.932 0.927 0.922 0.917

Chloride mg/l 0 6454 13,018 19,690 26,470 33,360 40,358 47,466 54,682 62,006 69,440 77,018 84,710 92,560 100,531 108,624 116,838 125,174 133,632 142,272 151,040 159,936 168,960 178,112

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24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

76.1 76.8 77.5 78.1 78.8 79.4 80 80.9 81.5 82.2 82.9 83.6 84.3 85 85.8 86.5 87.3

108 113.5 119 124.7 130.4 136.2 142.1 148.1 154.2 160.3 166.6 173 179.4 186.1 192.8 199.5 206.3

0.912 0.907 0.901 0.896 0.89 0.884 0.879 0.872 0.866 0.86 0.853 0.846 0.839 0.832 0.825 0.817 0.809

187,392 196,880 206,502 216,259 226,150 236,269 246,528 256,928 267,469 278,150 288,973 300,048 311,270 322,758 334,400 346,070 357,888

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The effects of temperature change on CaCl2 density

lb / ft³ =

7.48 X lb / gal

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Sodium chloride / calcium chloride brines For densities between 75.5 and 83 pcf, a combination of sodium chloride and calcium chloride brine is often satisfactory. The advantage of a combination of the two salts is a lower cost compared to that of a calcium chloride brine of the same weight. The disadvantage is that at each density, the fluid is saturated, and in order to increase the density, the fluid must be diluted with fresh water before additional calcium chloride is added. Any excess salt ( NaCl ) will precipitate and plug the perforations , the pipe etc.... Brine Density at 70 ºF pcf 75.5

To Make 1 bbl ( 42 gal ) 100% NaCl 95% CaCl2 lb lb 88 29

Water bbl 0.887

76.3

0.875

70

52

77

0.875

54

72

77.8

0.876

41

89

78.5

0.871

32

104

79.3

0.868

25

116

80

0.866

20

126

80.8

0.864

16

135

81.5

0.862

13

144

82.3

0.859

10

151

83

0.854

8

159

NOTE: 1 - It is crucial to accurately measure the starting volume of water needed and the quantities of salt required for each specific density to avoid precipitating NaCl. 2 - Pilot testing with the make up water at the rig site is necessary to adjust the above concentration or change fluid densities.

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Field operations utilizing brine Spot-checks of field operations have revealed that most of the so-called clean fluids used in well killing, completion are dirty enough to cause severe, and often irreparable, formation damage. All fluids used in well servicing operations must be analyzed. Preserved samples should be tested in the laboratory for clarity and compatibility with produced formation fluid samples. A clarity test for purity and compatibility should be carried out and repeated at the wellhead. Such a field test consists of observing the fluids in a clear glass. If the sampled fluid is not crystal clear and solid-free, it should be either filtered or discarded. It is advisable to spot-check the visual test with a Milliporefiltration test for presence of micron-sized particles. The Malvern particle size analyser is available in the Laboratory Research and Development Center for determining the particle size distribution up to 600 microns. Solids particles capable of plugging the formation are picked up from most types of equipment used in the field. Vacuum trucks, dirty tanks, pump tanks, check valves, swivel joints, and tubular goods are the main sources of contamination. Major contamination comes from iron, mud, cement, pipe dope, oxidized crude, sludge, bacteria, chemical additives, and other materials pumped or produced previously through the system. Tanks used for drilling and cementing will have dried mud, sand, silt, crude oil, and partially set cement deposited in suction lines and mixing boxes, on walls,.. etc. Such sediments and rust do not adversely affect the drilling mud, but when clean fluids are placed in the tanks and agitated, these sediments are entrained. Injected dissolved iron is converted in most formations with oxygen into iron hydroxide, a voluminous floc which helps consolidate the bridged solids (clay and silts) within the pores. Often less than a teaspoon of such " dirt " can plug a perforation

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SPECIALLY DESIGNED BRINE / POLYMER SYSTEMS Another category of water-based fluids is specially designed brine / polymer systems. These systems use polymers as a replacement for bentonite for viscosity, solids suspension, and fluid loss control. These systems are formulated in brine for inhibition using sized particles as bridging material to help control loss of filtrate to the formation. Brine / polymer system can be divided into three major types: • • •

Acid soluble systems Water soluble systems Oil soluble systems.

The basic formulation and technology associated with each of these systems is identical. The major difference between these systems lies in nature of the material used as the bridging agents and/or weighting agents. As the name implies, the bridging material is either acid soluble, water soluble, or oil soluble. The systems are composed primarily of various types of polymers, some type of brine water, and special type solids for bridging and weighting material. The most common brine water used is either KCl, NaCl, or CaC12. Should higher densities be required, special type solids are added to increase the density. This is somewhat of an opposite approach from the use of clear brines, but it should be kept in mind that not all solids are damaging. Good useable solids are either acid soluble, water soluble, or oil soluble, and incompressible. Special fluids can be designed with solids of known particle size distribution and solubility. Special brine / polymer systems can be separated into two types: nonthixotropic and thixotropic. This categorization is governed by the type of polymer used. Non-thixotropic polymer systems are viscous, but have no gel-building ability. The use of these systems is limited to operations where viscous carrier fluid is needed while circulating. They will not suspend solids when circulation is stopped ( lost circulation pills ) . Thixotropic polymer systems have both viscosity and gel-building ability, offering the advantage of suspending solids when circulation is stopped. Weighted brine / polymer systems must be thixotropic. There are a multitude of polymers available and currently being used in the drilling industry. However, for well servicing fluids, the preferred non-damaging polymers used for viscosity and/or suspension are confined to two types: Hydroxy Ethyl Cellulose ( HEC ) and Xanthan gums ( XC-Polymer).

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HEC polymers are nonionic derivatives of the cellulose polymer modified to impart water solubility to the cellulose molecule. The nonionic substitution in HEC polymers makes them very tolerant to high salt environments, including divalent calcium and magnesium. Because of this, HEC is ideal for viscosifying most completion brines. HEC polymers do not develop gel strengths to suspend solids. Systems made up with HEC polymers alone are considered nonthixotropic. XC polymer is a slightly anionic, high molecular weight polymer produced by bacterial action on carbohydrates. XC-polymer is an excellent viscosifier and suspending agent for KCl and NaCl brines. It functions quite well in CaC12 brines as long as the polymer is properly sheared in the initial mix. CaC12 brine / polymer system should be vigorously agitated in the tanks all the time to prevent the polymer chain from coiling. Solids settling will occur if the CaC12 brine / polymer slurry remains static for a period of time. XC-polymer is one of a very few polymers which will build gel structure. This, therefore, makes XC- polymer the key ingredient when solids suspension is required. Systems containing XC- polymer are considered thixotropic. HEC and XC-polymer are soluble in 15% hydrochloric acid and normally, the two polymers are used together for optimum performance. The temperature stability of both polymers is limited to the 250-275ºF range. Special additives are available to extend the temperature range to 300ºF.

Calcium carbonate fluids Fluid Formulations ( Example ) Formulation & order of addition ( one barrel ) Fresh, clean water, Defoamer, XC-Polymer, Modified starch, MgO, CaCO3 (fine), Salt ( NaCl ),

bbl : 0.92 gal : 0.01 lb : 1.00 lb : 3.00 lb : 0.50 lb : 10.00 lb : 75.00

Average fluid properties Density, Plastic viscosity, Yield point, Gels, Filtrate, pH, Cl¯,

lb/ft³ cp lb/100 ft² lb/100 ft² ml/30 min mg/

: 71 : 12 : 15 : 2/6 : 8 : 9 : 130,000

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If low chlorides is preferred ( Example ) Formulation & order of addition ( one barrel ) Fresh, clean water, Defoamer, XC-Polymer Modified starch, MgO, CaCO3 (fine),

bbl : 0.93 gal : 0.01 lb : 1.00 lb : 3.00 lb : 0.50 lb : 75.00

Average fluid properties Density, lb/ft³ : 71 Plastic viscosity, cp : 25 Yield point, lb/100 ft² : 15 Gels, lb/100 ft² : 2/6 Filtrate, ml/30 min : 6 pH, : 9 mg/l < 10000 Cl¯,

Acid soluble bridging material Fluid loss control for these special brine / polymer systems is achieved by solids and polymers. The key to sealing off a production zone is a proper mixture of bridging solids, colloidal solids, and subcolloidal particles. This combination creates an impermeable bridge across the face of the production zone ( or as close as possible to the wellbore ) for minimizing the fluid or fluid filtrate invasion into the formation. Coarser particles bridge on the pore spaces around the wellbore. This reduces the porosity and permeability at the wellbore surface. This bridge is then sealed by smaller particles, which plug the fine inter-particle spaces of the bridging solids. The bridge or wall cake allows only a very small amount of liquid to filter into the formation. The colloidal and subcolloidal particles are normally a combination of polymers, modified starches, and calcium carbonate. The formation of tight, impermeable bridges requires some knowledge of the particle size distribution of the bridging solid and the average size of the formation pore opening. Particles which are one-third of the average pore size of the formation will get trapped in the pore and initiate a bridge. Smaller particles will pass through the formation, while larger ones will pack on the surface and not seal properly. The average pore size can be calculated by taking the square root of the permeability (in millidarcies) of the formation. This number is the average pore size in microns. For example, if the formation has a permeability of 100 millidarcies, the average pore size is 10 microns. To seal this formation, the bridging material must then contain a percentage of particles in the 3.5 micron range. Designing a bridging material is a delicate process. Care must be taken to see that this material contains enough different size particles to seal production zones.

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Should a production zone have an extremely high or extremely low permeability, the bridging material may have to be altered to compensate for the abnormal pore sizes. Do not use just any available material for bridging and expect to get a tight seal on the formation. The most commonly used bridging materials is calcium carbonate ( ground marble ). It is the primary bridging agent in the acid soluble brine / polymer systems. This material is totally soluble in 15% hydrochloric acid. Calcium carbonate is used as a weighting agent in the drilling fluids for all the carbonate reservoirs development wells ( Arab"D", Hanifa, Hadriyah etc..... In most cases, the fine grind ( average particle size is 10 microns ) which is used as weight material will not work as a bridging agent in zones with more than 100 md permeability. AMS / stock ( 3300 lbs super bags and 50 lbs bags ) • • • •

Ground marble ( fine - 10 microns ) Ground marble ( medium - 150 microns ) Ground marble ( coarse - 600 microns ) Ground marble ( chips - 2000 microns )

Typical lost circulation pill formulations Formulation & order of addition ( one barrel ) Fresh, clean water, Defoamer, HEC, XC-Polymer, Modified starch, Lime, Ground marble M , Ground marble C ,

bbl gal lb lb lb lb lb lb

: : : : : : : :

0.90 0.01 1.5 0.5 1.00 1.00 80.0 40.0

Average fluid properties Density, Plastic viscosity, Yield point, Gels, Filtrate, pH,

lb/ft³ cp lb/100ft² lb/100 ft² ml/30 min

: : : : : :

71 25 20 5/15 10 11

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In brine / polymer systems, it is possible to use sized sodium chloride (NaCl) as bridging particles. However, this can only work in a fluid which is near or already saturated with respect to sodium chloride. Therefore, the minimum mud weight is above 75 pcf. Sizing sodium chloride to the small sizes needed is fairly difficult and should be done in a zero humidity environment. The NaCl bridge will dissolve in undersaturated solutions ( or fresh water ) usually associated with production. This system is relatively expensive and can be justified for dry gas wells. Oil soluble bridging material Oil soluble resins are usually paraffin or waxlike particles used as bridging agents in the brine / polymer systems. Since these resins are oil soluble, they are removed when the well is brought back on oil production. Care should be taken when choosing these resins. It is necessary for the melting point of the resin to be approximately the same as the bottom hole temperature. If the melting point is too low, the resin will dissolve before the bridge is set. If the melting point is too high, the resin will not dissolve in the produced oil and the bridge may not be removed. Strong water wetting surfactant should be included in the formulation to disperse the resin and prevent it from floating. The carrier fluid should be a high viscosity water or brine. Any trace of oil or oil contamination of the pill will create a big lump of wax and plug the pipe. Weighting agents The HEC and especially the XC-polymer perform best in lower density brines e.g., saturated NaCl (75 pcf) or CaCl2 (85 pcf ). Higher densities for these brine / polymer systems can only be accomplished with the addition of solid weighting agents. This weighting agent must be either water or acid soluble. This eliminates the use of barite, since it is neither. The weighting agent should be ground to specifications which allows easy dispersion and suspension. This grind, however, is not nearly as critical as for bridging agents. Extremely finely ground weighting agents cannot be used because of the high surface area, causing viscosity problems. Sodium chloride is water soluble and calcium carbonate is soluble in 15% hydrochloric acid, if the acid can reach the calcium carbonate dowhole. Systems weighted with sodium chloride or calcium carbonate are workable up to 103 pcf, while systems containing the iron compounds can go as high as 142 pcf .

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To summarize, lab and field results strongly suggest that the use of specially designed brine/polymer systems, with properly sized bridging particles, are among the best well servicing fluids. These systems form external bridges on the surface of the borehole and seal off production zones with minimum invasion of fluid. The bridge can be removed by mechanical action or it can be solubilized. These systems are inhibitive, and offer a wide range of densities, lifting capacity, and suspension qualities. Compared to clear brines, polymer systems are economical at higher densities. The formation of a good, tight, external bridge is the key to the success of these fluids. This bridge is especially effective in depleted zones which cannot hold the pressure gradient of water or oil. Specially designed brine / polymer systems can effectively control fluid loss at overbalance pressure. Removal of the external bridge is usually accomplished by flushing or bringing the well back on production. If further clean up is necessary, an acid soluble bridge can be removed with a 15% hydrochloric acid wash, a sodium chloride bridge can be removed with a low salinity water wash, and an oil soluble resin bridge with a diesel, crude oil or xylene wash. When mixing brine / polymer fluids remember: •

High shear mixing is very important to allow the polymers to perform and to eliminate fisheyes and polymer lumps which may reach the perforations downhole and cause plugging problems.

•

Foaming is almost always a problem while mixing brine-based fluids. Defoamers should be available on location. Follow the recommended order of addition in the initial mix, and mix defoamer with any salt or water required for system maintenance. Avoid injecting air into the slurry with mixing hopper, guns and pumps.

•

Corrosion could be excessive, but maintaining the pH with lime or magnesium oxide, using oxygen scavengers ( sodium sulfite ) and corrosion inhibitors can control this. Be sure the corrosion inhibitor used is not going to be injected into the payzone. All corrosion inhibitors are damaging to the reservoir.

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For low pressure reservoirs requiring drill-in, completion and workover fluids lighter than water ( 62.4 pcf ), two alternatives are available: Direct emulsions, oil-in-water ( using Atlasol-S as the emulsifier ) Invert emulsions, water-in-oil ( using Invermul and / or Ezmul as the emulsifiers)

Direct emulsions Low density direct emulsions are made with water as the continuous phase and dispersed oil ( as fine drops ) which is the internal phase. This emulsion is recommended when formation wettability change to oil-wet is undesirable. The emulsifier used is a water wetting surfactant for maintaining the drilled cuttings and solids water wet allowing easy hole cleaning. Viscosity and suspension are developed with small concentrations of water soluble polymers such as XC-polymer and HEC. It is much cheaper than the invert emulsion and has electrical properties similar to water-based fluids. The water phase can contain KCl for inhibiting sensitive clays in the reservoir rock. This emulsion is not chemically stable and require mechanical shear ( good agitation ) to prevent oil separation. Under static conditions and downhole temperature, the emulsion will break after sometime. With a high viscosity external phase ( water ) the emulsion can stay stable for longer periods in the hole. Fine solids such as CaCO3 ( 10 microns ) will stabilize the emulsion and makes a suitable drill-in fluid. Emulsions should never be injected into the reservoir even if they are solids-free. Forcing a thick emulsion into the reservoir will create blockage which will require treatment with mutual solvents, surfactants and / or acids to remove. Formulation and order of addition (one barrel ) Average fluid properties Make-up water, XC-Polymer, Dextrid, MgO, Oil, Atlosol-S, CaCO3 fine,

bbl lb lb lb bbl gal lb

: : : : : : :

0.50 1.00 6.00 1.00 0.50 0.10 5.00

Density, lb/ft3 Plastic viscosity, cp Yield point, lb/100 ft2 10 sec.gel, lb/100 ft2 10 min.gel, lb/100 ft2 Filtrate, cc/30 min pH,

: 57 : 18 : 25 : 4 : 6 : 4 : 9

Note

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•

Fine mesh shaker screens ( 150 - 200 mesh ) will help to maintain the fluid clean

•

No other chemicals should be used . The pH should be maintained with magnesium oxide or lime and the viscosity with XC-polymer. Dextrid along with the fine CaCO3 will control the filtrate and filter cake. The oil must be added to water through the mixing hopper to form the oil-in-water emulsion followed by Atlosol-S. Additions of more oil will cause thickening and additions of more water will cause thinning.

Oil-based fluids Oil-based well servicing fluids are generally a form of invert emulsion, with some type of oil as the external or continuous phase. Crude oils are used occasionally, but their application usually is limited to depleted formations. The use of oil-based fluids offers several advantages. These include: 1. 2. 3. 5. 6.

High temperature stability for deep high pressure wells. Wide density range up to 157 pcf Maximum inhibition for clays. Non-corrosive to the tubular and downhole equipment. Stable in most subsurface environments

Formulation & order of addition ( one barrel ) Oil, Invermul, Lime, Duratone, Water, GeltoneII, EZ-Mul, CaCl2(78%), CaCO3 fine,

bbl lb lb lb bbl lb lb lb lb

: : : : : : : : :

0.5 6.0 4.0 6.0 0.2 2.0 2.0 61.0 113.0

Average fluid properties

Density, Viscosity Plastic viscosity, Yield point, Gels, Filtrate(200 ºF/500psi) Electrical stability, Oil/Water ratio

lb/ft3 sec/qt cp lb/100ft2 lb/100ft2 ml volts

: : : : : : : :

85 45 25 20 4/8 2 all oil 800 70/30

Invert emulsions originally were developed as drilling fluids, specifically for use in deep, hot holes. The oil-based fluids can be designed for working temperatures in excess of 500°F and densities from 56 to 157 pcf.

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Since oil is the external phase, the fluid invading the formation will be all oil which should have no effect on the clays in the formation. This minimizes the concern for clay migration or clay swelling. These fluids are non-corrosive and resistant to most contaminants which affect waterbase fluids. Formation damage studies with various oil-base fluids consistently show minimal damaging characteristics. Oil-base fluids approach being the ideal well servicing fluid. They do, however, have some disadvantages including that they may: • • •

be restricted in environmentally sensitive areas. contain high solids and damage dry gas sand payzones. will change the formation wettability and cause emulsion blocks.

Stricter environmental regulations are making it difficult to use oil-base fluids without the use of expensive handling equipment and high disposal costs. This is especially true offshore. Higher density oil muds contain a high percentage of solids. The majority of these solids are incompressible, but the fluid could contain a certain percentage of compressible solids, such as organophilic clays or drilled solids. Oil-base fluids contain oil wetting surfactants designed to make the solids dispersed in them preferentially oil wet. These wetting agents could cause the formation to become preferentially oil wet, lowering the relative permeability to oil. Should this occur, the condition is usually temporary. The emulsifiers in the oil-base fluids could form emulsions in the formation, causing emulsion blocks. Mutual solvents and water wetting surfactants will remove the damage and restore productivity. ( Zuluf, Marjan and Safaniyah horizontal wells is a good example ). Exposure of a formation containing only gas and water to an oil-base fluid can result in a reduction of the relative permeability to gas by the introduction of a third immiscible fluid. Oil filtrate invasion will occur. When gas production begins, some of the oil filtrate will back flow and clean up, but some of the filtrate will remain as irreducible or immobile, hence lowering the gas productivity of the well. Air / Mist / Foam The use of dry air, mist, stiff foam, or aerated mud as the circulating fluid is rarely used. Dry air or dust drilling is used when the formation is completely dry or when there is only a slight water influx. Air is ideal to reduce formation damage. Since there is no liquid phase, there is no fluid loss and no invasion of particles. The use of foam as a well servicing fluid should be considered with low bottom hole pressure wells.

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PACKER FLUIDS Functions: The primary function of a packer is to seal off the tubing-casing annulus, and allow production from below the packer, through the tubing. Packer fluids are placed in the casing-tubing annulus to provide a hydrostatic head necessary to control the well in case of packer failure or leaks. Also, to reduce the pressure differential between the inside of tubing and the annulus, the outside of the casing and the annulus, and the perforated interval below the packer and the annulus. The packer fluid performs these functions mainly by protecting the steel in the tubing-casing annulus from corrosion. Since the packer may remain in the annulus for an extended period of time, it is necessary to properly inhibit the fluid to prevent or minimize annular corrosion and enhance retrievability of tubing and packers. A worldwide review of workover operations indicated extremely high costs associated with recovery of tubing stuck in settled mud solids. High density water-base or oil-base muds are not stable suspensions when left static in a well for a long time. High temperatures and/or contamination of these muds with the produced gas and oil destroys the initial suspension properties and allow mud solids and weighting materials to settle on top of the packer and around the tubing. Expensive washover and fishing operations are then performed. During the washover, more costly complications such as twist off, stuck washover pipes, casing leaks, blowouts and formation damage could develop. When such complications occur many wells have to be plugged and abandoned. Most of these problems could be eliminated by utilizing solids-free packer fluids. Required characteristics of packer fluid: •

• • • • •

Must be chemically and mechanically stable under downhole conditions, i.e. no settling of suspended solids and no chemical precipitates if mixed with produced fluids or gases. Must not degrade by time or temperature. Must not deteriorate packer elastomers. Must remain pumpable during the life of the well, i.e. no high gelation or solidification to be developed by time. Must not cause corrosion (inside casing, outside tubing). Must not damage the producing formation because they may contact these producing zones during completion or workover operations.

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Necessary fluid properties: •

The usual practice is to use a packer fluid with kill density. The packer fluid must contribute to well control during the seating and unseating of the packer.

•

A packer fluid should ideally be solids-free. If a packer fluid must be weighted with solid materials, they should not settle out over the period of fluid use. Solidsweighted packer fluids must have gel strength to prevent the solids from settling.

•

The gel strength should not be so great as to prevent initiation of circulation or tubing movement should a workover become necessary. If solids do segregate out and fall to the bottom, a retrievable packer or the tubing may get stuck, resulting in a long and expensive fishing job.

Drilling muds are not desirable packer fluid Water base drilling mud organic additives degrade upon prolonged exposure to high temperatures and sometimes generate corrosive gases such as CO2 and H2S. Bacterial activity could also breakdown organic materials and/or produce corrosive elements. Lignosulfonate solutions can react electrochemically at metal surfaces to form sulfides even at moderate temperatures. Properly formulated oil-base muds are non-conductive and should not cause corrosion. However, in case of packer failure or leaks, produced oil or gas dissolves in the oil mud, destroys their suspension properties, allowing the weighting material (barite) to settle on top of the packer, and results in stuck packers and tubing. Solids - free oil as a packer fluid Clean oil with proper corrosion inhibitor ( oil soluble film forming amine ) is an ideal packer fluid. Clean oil is non-conductive, stable and in case of casing leaks and water influx, the inhibitor will provide protection for some time. Solids - free packer fluids The obvious advantages of utilizing solids-free heavy brines for packer fluid applications triggered extensive investigation into combating their corrositivity via the addition of suitable inhibitors. Increasing the pH, removing the oxygen and selecting the compatible

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brine or brine blends along with the effective inhibitor for the anticipated invironment are very important steps in formulating the proper brine packer fluid. NaCl brines In the presence of entrained oxygen, sodium chloride can be major contributor to corrosion. The activity of the electrolyte is accelerated by the dissolved salt. When the salt concentration excesseds 12%, the corrosion rate decreases below that of water. CaCl2 brines In laboratory tests, it was demonstrated that the corrosion rate increases dramatically with an increase in temperature. CaC12 at 250ºF has a rate of 5 mpy but at 400ºF increases to 55 mpy. However, these high rates will decrease with longer exposure time. This phenomenon indicates the consumption of the active corroding elements in the brine. Important points to remember •

Based on the laboratory observations, the thirty days static test is a sufficient test period to determine the long term corrosivity of the inhibited brines.

•

Commonly used film forming amine corrosion inhibitors degrade between 250ºF and 300ºF and therefore are ineffective for high temperature wells. Also many film forming amines are insoluble in heavy brines.

•

Calcium brines should not be treated with oxygen scavengers containing sulfites. These types of chemicals could precipitate calcium scale and have caused stuck packers on several occasions.

•

In the field, drilling mud should be properly displaced from the wellbore with the clean brine. Residual mud materials in the annulus must be cleaned out mechanically and chemically (scraper, surfactants...etc.). Mud residue adhering to the metal surfaces can be sites for under deposit corrosion. The brine should be filtered, solids content less than 100 mg/l achieved in the field.

•

If CO2 ingress into the annulus is expected, low calcium or a calcium free brine should be considered to minimize chances of precipitating calcium scale. As a rule in CO2 environment, use KC1, NaCl, and NaBr for brine densities up to 92 pcf .

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•

Fluids of low inherent corrosivity are generally hydrocarbon based. The low electrical conductivity of these fluids suppresses corrosion currents. In low pressure wells the hydrocarbon may be diesel or lease crude. Oil-base or invert-emulsion mud may be used in higher pressure wells. The clay dispersants and emulsifiers in oil muds keep water emulsified and metal surfaces oil wetted, thus, further minimizing conductivity and corrosivity. Both oil soluble and brine dispersible corrosion inhibitors are sometimes added to hydrocarbons to insure corrosion protection when inefficient displacement of water-base mud or brine is anticipated.

•

Corrosion inhibitors may be added to electrically conductive fluids to reduce the corrosion rate. Typically, corrosion inhibiting agents function by scavenging oxygen, electrostatically passivating the metal surface, or, more commonly by forming a hydrophobic film on the metal surface that prevents the entrance of corrosion currents into the surface. Corrosion inhibitors function well in brines. Film forming corrosion inhibitors do not provide much protection in water-base muds since they tend to adsorb strongly on the mud solids. Bactericides act as corrosion inhibitors by killing bacteria that generate corrosive by-products.

•

Control of pH is the primary method of reducing corrosion in water-base muds. When a brine can tolerate a high pH, elevated pH can also control corrosion in brines. High pH controls sweet and sour corrosion by preventing the oxidation of iron by hydrogen ions and by preventing the growth of sulfate reducing bacteria. A pH greater than 9.5 significantly reduces corrosion of iron. Water-base mud pH should be adjusted to a stable value between 10.5 and 11.5 prior to installation of the mud as a packer fluid. The pH of the mud should remain unchanged following circulation for 48 hours before it is considered stabilized. This is necessary because mud components tend to reduce the mud pH with time.

Corrosion inhibitors A water soluble corrosion inhibitor, such as Coat B1400 (or equivalent film forming amin) for solids - free brines provides excellent protection under subsurface conditions. A concentration of 1 % by volume is generally recommended when saltwater is used as a packer fluid or will be left in the wellbore for extended periods of time. Corrosion inhibitor is not usually necessary for salt waters that will be circulated out of the well after completion or workover operations are finished. Most corrosion failures attributable to packer fluids are observed to occur below circulating valves and between packers in

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multiple completions and in other areas from which mud and fluids are not removed by normal circulating methods. When such possibilities exist, only inhibited fluids should be used. For clean oil packer fluid, Coat 415, an oil-solubles film forming amine is recommended to provide corrosion protection in Arab"D' wells. In case of casing leaks across the Wasia, the inhibitor should give some protection. Lab tests are currently being conducted to determine the optimum concentration required. The use of 3% by volume should continue until the lab study is completed. Contamination of the clear packer fluid to be used or left in a well can be lessened by displacing the drilling fluid with clear untreated fluid, discarding the returned interface between the fluids, and then circulating the clear fluid again after the addition of required corrosion inhibitor and biocide additives. Wastage of corrosion inhibiting chemicals is avoided by delaying their addition until after the first purge of the well with clear fluid. Packer fluids which contain water can support the growth of bacteria. Bacterial life processes often generate corrosive by-products and bacterial bodies can plug and damage formation rock. A bactericide should be added to packer fluids to prevent the growth of bacteria. Increasing the fluid salinity to saturation and the pH to 10.5 - 11 will prevent growth of bacteria. The common bactericides used for packer fluid systems contain paraformaldehyde. Bacteria can cause sulfide corrosion in the absence of oxygen (anaerobic conditions). Anaerobic bacteria are able to use hydrogen formed by electrochemical corrosion to reduce sulfate ions, forming hydrogen sulfide. This anaerobic process accelerates the electrochemical corrosion, and the resulting hydrogen sulfide also attacks the steel, forming black iron sulfide scale and pitting corrosion. lron sulfide scale has caused plugging in injection wells. The hydrogen sulfide formed can cause tubular goods to fail through sulfide-stress-cracking/hydrogen-embrittlement under certain conditions. If untreated packer fluids come in contact with the formation, the bacteria may damage the formation ( Biofouling ). This can occur following a period of bacterial colony growth if the packer fluid is subsequently used as a workover fluid, or if the packer fails and the fluid leaks into the producing tone.

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HANDLING COMPLETION FLUIDS The proper handling of well servicing fluids is important to the overall success of the operation and the safety of the rig personnel. The objective is to safely handle all fluids while maintaining the volume, density, and clarity or cleanliness of the fluid to control formation damage Transportation ( Trucks and boat hold tanks ) The key to all successful completion fluid applications is that the fluids are maintained clean and contain no particulate matter considered damaging to the formation. If handling and mixing equipment are not clean, then the expense and effort used to secure clean, uncontaminated fluid or brine are wasted. Visually inspect each tank before any fluid is mixed. Tanks that are not clean or have any water or other liquid in the bottom must be cleaned and dried. lnspect the hoses on the water truck to make sure that they are clean. Boat hold tanks must be visually inspected before any fluid or brine is pumped on board. If the tanks are dirty, they must be scrubbed clean and dried. If this cannot be done, they must be rejected. Tank hatches must be resealed and the hatch-to-tank gasket area should be caulked to help prevent fluid contamination should the deck become awash. Be sure that the boat crew knows not to pump into or out of the fluid tanks when the boat is underway. Other tanks must be used to even the keel. Rig preparation One of the most important, but least acknowledged, aspects of using clean completion fluids or brines is the preparation of the rig before taking or mixing the fluid into the pits. Most muds are not compatible with brines. Every piece of equipment that will come into contact with the clean completion fluid must be meticulously cleaned of muds and other additives. Pits, lines, and valves that have leaks must be repaired to eliminate loss of expensive brines. Small pinhole leaks that are plugged by a drilling mud will not be plugged with the brine. The following recommendations are guidelines for preparing a rig to use clean fluids: •

Isolate all tanks, pumps, and equipment that will be used to carry or transport the clean fluid or the solids-free brine.

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•

• •

Scrub all tanks, circulate detergents and/or surfactants through the entire system to remove contaminants. Rinse the system with water and dump the water until it is clean. While the water is circulating, check for leaks.- remove any additives or other materials in the mixing areas and store them at some other location. Cover all the open pits if rain is expected and keep sack materials dry. Store brine in closed tanks to help prevent moisture from being drawn into the brine and lowering the density.

Clear brines The high cost of brines makes it imperative that inspections be accomplished in order to ensure the fluid being mixed is the correct volume, density, clarity. The initial inspection should be performed at the mixing tanks. Subsequent inspections should be performed whenever brines are transferred from tanks or vessels. Check the Volume, this can be done by a flow meter when transferring or by simply checking the tank. Although this may seem simple, costly errors may be made. Check the Density, the density must be checked with hydrometer . Check the Clarity, the clarity of the brine should always be checked when the brine is transferred or mixed to ensure that it did not pick up any contaminants. Samples can be sent to the lab for atomic absorption test to determine the quantity of cations. Anion chromatography will determine the quantity of anions. Total suspended solids and particle size distribution can be also measured. Testing on site can be arranged specially if fluid filtration is required for water injection tests or gravel packing etc... Fluid maintenance •

• • •

A solids-free system appears to result in less formation damage and higher productivity. The continued care and maintenance of the fluid in the system is critical during well servicing operations. The following steps should be followed: Mixing and storage tanks should be thoroughly cleaned and visually inspected before each use. All lines and pumps should be cleaned and inspected. The drilling mud in the casing should always be displaced with a clean, preferably filtered well servicing fluid. The wellbore should be cleaned to remove as much of the drill solids from casing walls and fluid system as possible. Over-displacement with water is the

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• • • • •

recommended practice. A spacer of at least 500 feet weighted to the necessary density should be used when displacing mud. All tanks should have bottom baffles in order to contain settlings. Tank agitators should never be used if clear ,solids free fluid is being used.. Tanks should be checked often for settlings and should be cleaned when needed. A mud cleaner with a 325 mesh screen can be used to remove solids larger than 44 microns. The brine can then be filtered through 2 micron filters. Tubular goods should be free of rust, scale, and pipe dope. An oxygen scavenger or corrosion inhibitor should be added if necessary to help prevent the formation of iron oxide particles.

Displacement techniques The proper displacement technique has a dramatic impact on the operation. However, the basic displacement format remains the same, regardless of all other conditions. It is a simple two-step formula: 1. Condition the mud before displacing it. 2. Displace the mud. Conditioning mud The actual conditioning of the mud must be done before the mud is removed from the well. This phase is the key factor that determines how clean the well will be after displacement. The purpose of mud conditioning is to disperse and evenly distribute all of the solids from the casing inner walls, the wellbore, tanks, pipes, etc., into the mud. The rheology of the mud is then adjusted to make it flow more easily during displacement. The mud is conditioned using both mechanical and chemical methods. The first step to distribute the solids in the well is, obviously, to circulate the mud in the hole. If the mud has remained in fairly good condition, it will circulate easily and evenly distribute the solids. If the solids have packed at the bottom of the well or annulus, they will have to be washed over or drilled to be dispersed into the mud. The second step is to remove the wall cake. Once the mud can be circulated and the bottom of the hole or the required depth is reached, the mud cake must be removed from the walls. Mechanical scrapers have proven to be the most effective tools to remove these solids from the casing wall. A scraper run should be made for each casing diameter. Circulate the mud through all available solids removal equipment to remove as many solids contaminants as possible.

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Rotating the workstring will improve the removal of solids from the wellbore while circulating the mud. Most wells are not true vertical holes and some corkscrewing of the hole is assured as the well is drilled. The workstring will lie against the low side of the casing / liner wall at various points. Fluid flow is restricted or virtually nonexistent at these points and solids will collect unless the workstring is rotated. Rotation of the workstring distributes the fluid flow path across the entire hole section. Once the solids are evenly dispersed throughout the mud system, the mud rheology can be adjusted. Thin the mud as much as possible while it still retains its ability to hold the solids in suspension. Usually, adding water to a water-base mud or oil to an oil-base mud is all that is required. Do not use packaged thinners or build density unless well conditions require this. Displacing mud After the mud is conditioned a displacement pad to separate the mud from the brine can be as simple as single viscous spacer or as complex as several different pills, each designed to perform one specific function. Let's briefly look at the intended functions of these pills. Displacement pads spacers. Spacers may be solids free or solids-laden. Their sole function is to separate two incompatible fluids. To do this, the spacer must be more viscous than either of the fluids it separates. The greater viscosity helps to retain the integrity of the spacer by enabling the spacer to stay in plug or laminar flow at higher pump rates than the other fluids. However, some intermingling with the other fluids is probable. Therefore, the spacer must also provide enough distance between the two other incompatible fluids to keep them from contact each other. Each spacer should cover at least 500 feet of the annulus at its largest diameter. Chemical washes Chemical washes provide a polishing action to remove those solids that remain in the well. These washes usually have a combination of surfactants that remove organic contaminants as well as inorganic contaminants. Coarse materials such as 60/80 frac sand or coarse CaCO3 can be added as scouring agents.

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Special techniques Water Flushes: When well conditions permit, the mud can be displaced and the well cleaned by circulating water downhole. This technique has certain restrictions. You must be able to answer "yes" to all of the following questions to successfully use a water flush. · Is water readily available and inexpensive ? · Is the wellbore isolated from the casing? · Will the casing, tubing, and cement bonds withstand the difference in pressure between the formation pressure and the hydrostatic head of the water? · Can the water and some of the mud be easily, inexpensively, and safely disposed of ? If the answer to all of these questions is yes, the well can be flushed with water. A water flush cleans the well better than any other method. Rig time is the greatest cost factor. The chemical cost is essentially nothing. A viscous pill such as 50 barrels of HECseawater with a viscosity of 150-200 sec/qt should separate the water and the mud if the mud is to be saved. Another viscous pill should separate the water and the brine when the water is displaced. Reverse Circulation: The density of the brine and the density of the fluid that it is displacing will determine the flow path of the fluid during displacement. The fluid should be pumped down the annulus and up the tubing or wash pipe when the brine is lighter than the fluid that is being displaced. The reason for this flow direction follows. Under static conditions, heavier fluids will sink through lighter fluids due to the force of gravity. Even though a spacer may separate the two fluids, commingling of the fluids can occur. When the fluids are pumped down the annulus, the heavier fluid must be below the lighter weight fluid to help prevent commingling. Commingling may occur in the tubing, but this poses little problem to keeping the annulus clean. Conversely, the flow direction should be down the tubing and up the annulus when the brine is heavier than the fluid it is replacing. Pressure drop values should be calculated and compared to tubing burst strengths before a final decision is made. Staging spacer densities: The densities of each spacer should be gradually adjusted. If more than one spacer is used in line between two fluids of dissimilar weight, use the spacer with the recommended highest density for the spacer that is next to the heaviest fluid, and adjust to the lowest

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density for the spacer that is next to the lightest fluid. For example, when three spacers are used in line to displace a 100 pcf mud with an 80 pcf brine, each spacer should be adjusted to a different density. The spacer next to the 100 pcf mud should weight slightly less than 100 pcf. The middle spacer should be in the neighborhood of 90 pcf and the spacer next to the 80 pcf brine should be between 80 and 90 pcf. The reasoning is the same as that used on determining the best flow direction. A lighter weight fluid should be above the heavier fluid in the annulus to help prevent or retard commingling. General displacement procedures A general procedure to displace the drilling mud with a well servicing fluid is usually performed when a bit and scrapper, properly sized for the casing, is run in the hole on a workstring to PBTD. Four displacement procedures are listed below as a general guideline for a displacement system. The specific displacement procedure must be adjusted to fit individual well requirements. Displacement of a water - based mud using a seawater flush This general procedure for the displacement of an water base mud using a seawater flush is intended to highlight relevant points and state some recommended practices. 1. Circulate and condition the mud to obtain the minimum acceptable yield point before the displacement. 2. Displace the water base mud with a viscous HEC/seawater spacer between the mud and the seawater. This spacer should have a funnel viscosity of 150-200 sec/qt. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. Circulate the seawater until contaminants are less than 50 Nephelometer. Turbidity Units (NTU) . 3. Add a chemical wash and circulate two workstring volumes. 4. Add another viscous HEC/seawater spacer between the seawater and the brine. The funnel viscosity should be 150-200 sec/qt and the spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. 5. Follow with clean filtered brine. 6. Filter the brine to a turbidity of 50 NTU. _____________________________________________________________________________________ Page 46

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Displacement of an oil - based mud using a seawater flush This general procedure for the displacement of an oil base mud using a seawater flush is intended to highlight relevant points and state some recommended practices. Notice that oil-base systems using highly aromatic oils will leave an oil sheen on the seawater. 1. Condition the mud before the displacement. 2. Displace the oil-base mud with an oil pad. The volume should be +500 feet of the annulus at its widest diameter. 3. Follow the pad with a viscous HEC/seawater spacer between the oil pad and the seawater. The spacer should have a funnel viscosity of 200-250 sec/qt. The spacer volume is usually equal to about 500 feet of workstring annulus at its widest diameter. 4. Circulate the seawater until the seawater has less than 50 NTU of solids. Circulate continuously or once through, depending upon pollution control requirements. 5. Add a chemical wash for oil mud and circulate two full workstring volumes. 6. Add a viscous HEC/brine spacer between the seawater and the brine. The funnel viscosity should be 150-200 sec/qt and the spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. 7. Displace with a clean filtered brine. 8. Filter the brine to a turbidity of 50 NTU. Balanced displacement of water-based muds This general procedure for the balanced displacement of a water base mud without using a water flush is intended to highlight relevant points and state some recommended practices. 1. Condition the mud before displacement. 2. Displace the water base mud with a single pass down hole of the following spacers :

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Spacer 1 This spacer must be compatible with the drilling mud and must have a yield point greater than that of the drilling mud. The spacer should be pumped at a high enough rate so it remains in turbulent flow. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. This spacer should be displaced with weighted brine at least equal to the volume of the spacer. Note the brine following the spacer will be very dirty and a significant portion will probably be lost. Spacer 2 - This spacer is a cleaning spacer. This fluid should contain caustic, surfactant or a cleaning compound that will remove the drilling fluid from the casing. This spacer should be weighted if necessary to help prevent an influx of formation fluid, or the returns should be choked. Sand can be placed in this spacer as an abrasive to clean the casing walls. More than one cleaning spacer can be pumped, if desirable. This spacer should be displaced with weighted brine. Spacer 3 - This last spacer is intended to separate the clean filtered well servicing fluid from the cleaning spacer. It is usually a viscosified pill of the well servicing brine similar to Spacer 1. 3. Circulate the clean filtered brine into the well to displace the spacers. 4. Circulate and filter until the brine's turbidity is less than 50 NTU. Balance displacement of an oil-based mud. This general procedure for the displacement of an oil-base mud without using a water flush is intended to highlight relevant points and state some recommended practices. 1. Condition the mud before displacement. 2. Displace the oil-base mud with a single pass downhole with the well on choke to control pressure of the following spacers: Spacer 1 - This spacer must be compatible with the drilling mud and must have a yield point greater than that of the drilling mud. The spacer should be pumped at a high enough rate so it remains in turbulent flow. The spacer volume is usually equal to about 500 feet of workstring annulus at its largest diameter. This spacer should be displaced with weighted brine at least equal to the volume of the spacer. Note the brine following the spacer will be very dirty and a significant portion will probably be lost.

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Spacer 2 - This spacer is a cleaning spacer. This fluid should contain caustic, surfactant or a cleaning compound that will remove the drilling fluid from the casing. This spacer should be weighted if necessary to help prevent an influx of formation fluid, or the returns should be choked. Sand can be placed in this spacer as an abrasive to clean the casing walls. More than one cleaning spacer can be pumped, if desirable. This spacer should be displaced with weighted brine. 3. Circulate the clean filtered brine into the well to displace the spacers. 4. Circulate and filter until the brine's turbidity is less than 50 NTU. Spacers A spacer is a neutral fluid designed to separate two other fluids without contaminating either. Spacers are used when changing from one fluid system to another and are usually used in a cased hole situation. The selection of a spacer depends upon the fluid in the hole and the fluid that will be used for displacement. The selected spacer(s) must be compatible with adjacent fluids. To select a spacer first, determine what type of fluid will be placed in the hole. Next, decide how the fluid in the hole will be conditioned. Then select a spacer that will not contaminate the fluid in the hole. The second spacer should not contaminate the first spacer. The second, or third spacer should not contaminate the fluid used for displacement. When a spacer is used to help scour the casing, it should not contaminate either of the adjacent spacers. Some of the most commonly used spacers are viscous spacers, water, weighted spacers, diesel spacers, and frac-sand spacers. General information about each of these spacers is provided on the following pages. This chapter is intended to provide guidelines for the use of spacers, but does not include all available alternatives. Flexibility and judgment will be necessary when using this information. Viscous spacers The spacer is formulated with HEC and the brine to be used. The general guidelines to formulate and use the spacer are: 1. Use 1 - 3 ppb HEC, depending upon the type of salt in the fluid. 2. The viscosity will range form 35 to 500+ sec/qt depending on concentrations and type of make-up fluid. The viscosity is determined by the types of fluids separated by the spacer. The spacer should have greater viscosity than the preceding fluid.

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3. The volume is determined by rig and hole conditions, and the method of pumping, i.e., long way or short way. (The long way is through the tubing or drill pipe and up the casing. The short way is down the casing or annular space and up the tubing or drill pipe.) The purposes of the spacer are: 1. 2. 3. 4.

To separate two fluids, thereby preventing contamination. To completely displace the fluid in the hole. To clean the casing and not allow debris to collect on the walls. To serve as a marker fluid to distinguish between two fluids.

The spacer is pumped following one fluid and preceding another, and then dumped at the surface. Viscous spacers are compatible with other fluids in use, are less expensive than other spacers, and perform effectively. They also contain a minimum of solids. Water spacers As the name indicates, water spacers are composed of water in an amount sufficient to separate the two fluids. The main purposes of the spacer are: 1. 2. 3.

To separate two fluids. To move fluid out of the wells. To serve as a marker fluid.

The spacer is pumped following one fluid and preceding another, and then dumped at the surface. The rationale for its selection and use: 1. Cheap and quick. 2. Usually used with lightweight completion fluids. 3. Convenient, since seawater may already be in the hole. 4. Water spacers are used as a buffer in conjunction with more elaborate spacers. Weighted spacers Based on the type of mud that will be displaced, there are two types of weighted spacers . 1) A filtered, fresh water, weighted spacer may be used when there is fresh water mud in the hole. Its contents are as follows: _____________________________________________________________________________________ Page 50

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a. Fresh filtered water. b. Lime to adjust pH. 0.2-0.5 ppb. c. Xanthan gum to provide suspension, 0.5 - 1.5 ppb. d. Calcium carbonate, to a maximum density of 105 pcf. If greater densities are required, use iron carbonate. For additional density, use barite. 2) A seawater weighted spacer contains the following ingredients. a. Seawater treated with soda ash to remove calcium. b. Sodium chloride, 10.0 ppb. c. Xanthan gum, 0.5 -1.5 ppb. d. Calcium carbonate, to a maximum density of 105 pcf. Greater densities ( up to 127 pcf ) require iron carbonate. For additional density, use barite. The main purposes of the spacer are: 1. To maintain the hydrostatic pressure, thereby keeping the casing from collapsing. 2. To separate two fluids. 3. To serve as a marker fluid. The spacer is pumped following one fluid and preceding another. Weighted spacers are used when formation pressure requires that a high hydrostatic head is maintained and/or when water cannot be used to flush out the casing because of differential pressure. Diesel spacers Diesel spacers are emulsified oil spacers. The purposes of these spacers are: 1. To wash or clean the pipe. 2. To separate water from an oil fluid. Usually diesel spacers are used in conjunction with other weighted spacers The spacer is pumped following one fluid and preceding another. Then, it is placed in a holding tank to avoid pollution. Diesel spacers are used when changing from water-base to an oil-base systems or the reverse. The diesel spacer has a tendency to channel when used alone.

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Emulsified Spacers Contents and Concentrations 1. 2. 3. 4.

Emulsified oil. Water, to control viscosity. (The more water, the higher the viscosity.) Calcium carbonate and/or iron carbonate, to reach desired density. Diesel.

The purposes of these spacers are: 1. To separate oil muds from brines during displacement. 2 To serve as a marker fluid. The spacer is pumped following one fluid and preceding another. Spacer is held in a special tank upon return to avoid pollution. The emulsified oil spacer prevents oil mud from becoming thick. Once pumping is started, make sure to continue pumping until all spacers are out of the well. Frac-Sand Spacers Frac-sand spacers are always used in conjunction with other spacers. The basic formulation of the spacer should include the following: 1. Fresh water, approximately 5 barrels. 2. HEC, to viscosity of 200 sec/qt. 3. Frac-sand, 40-50 ppb. The main purposes of the spacers are: 1. To scour the casing and pipe before displacement. 2. To reduce filtering time by achieving a cleaner displacement, and therefore, preventing the brine from being contaminated by drilling fluid solids. 3. To separate two fluids. For a more effective application: 1. Follow with water. 2. Then follow with approximately 2 barrels of viscous brine fluid. 3. Finally, follow with brine. The frac-sand spacer is selected for its ability to scour the hole. It is usually used in a hole that has contained fluid over a long period, or a hole where excessive filter cake has formed. Pills _____________________________________________________________________________________ Page 52

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A pill is a mixture, that is different from the fluid that is in the hole. Pills are used to provide viscosity, to carry debris out of the hole, to prevent lost circulation, or during perforation. They are usually used in an open-hole situation. Some of the most commonly used pills are viscous pills and carbonate pills. While this presentation material provides some guidance in the use of pills, it does not represent all available alternatives. Therefore, flexibility and judgment will be necessary when using these recommendations. Viscous pills Formulation: The viscosity of the pill can range form 35 to 400+ sec/qt depending upon the concentration of HEC (0.5 to 5.0- ppb). The viscosity required depends upon the type and severity of the problem. (Most pumps will not pump fluids with funnel viscosities greater than 500 seconds.). When a pill is used to carry sand and cuttings out of the hole, a small amount of xanthan gum (0.1 to 1.0 ppb) may be added to the HEC for additional carrying capacity. Xanthan gum can be used in fresh water and sodium chloride fluids. The purposes of these pills are: 1. 2.

To prevent seepage loss to the formation. To carry sand and cuttings out of the well.

Applications When used to prevent seepage loss, the viscous pill is spotted and sometimes squeezed into the formation. When used to carry sand and cuttings out of the well, the viscous pill is circulated and dumped at the surface. Rationale for Selection and Use HEC is less damaging to the formation than carbonate pills. The viscous pill can be produced out of the well instead of having to be acidized. Carbonate pill

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Contents: Calcium carbonate ( medium and coarse ), make-up fluid, HEC and, possibly xanthan gum. Concentration 1. For seepage, use 5-10 ppb CaC03 plus 0.5 - 1.0 ppb HEC. 2 For medium loss, use 20-30 ppb CaC03 plus 0.5-1.5 ppb HEC. 3. For severe loss, use 50-150 ppb CaC03 plus 1.0-2.0 ppb HEC. 4. Xanthan gum can be used for suspension in brine. It require high shear and good mixing to allow the polymer to yield and suspend the sized CaC03. If you plan to use 50-150 ppb of bridging agent in the fluid and spot across perforations for two hours or more, or if the fluid is to be left in the well over an extended period of time, xanthan gum is required to prevent the settling of CaC03 particles. Clear brine completion fluid displacement The most important step in preparation for brine displacement is cleaning the wellbore. Proper procedures should be applied to remove solids and "dirt" from the well and rig equipment. The casing must be cleaned with a bit and scraper or hydraulic jets to free mud solids, scale deposits...etc. Tubing must be scraped and cleaned, inside and out, before being run into the well. If the wellbore is in communication with producing zones, care must be taken to avoid losing into the formation the solids and "dirt" freed during well cleanup. This means a minimum overbalance and the use of sweeping pills. Thick spacers should be used to separate the clean brine from dirty fluid while pumping i.e., avoid contaminating the clean brine with drilling mud or packer fluid already in the hole. In some cases, the hole could be displaced with clean water, mechanically scraped and circulated until all solids are removed from the wellbore. The following spacers are recommended: Scrubber Pill (Volume 10-30 bbl) Composed of: ( Displacing water base mud ) · Fresh water · Caustic soda, 1-1.5 lb/bbl · 20-40 mesh fracturing sand, 20-30 lb/bbl or ( Displacing oil base mud ) · Fresh water · Metaphosphoric acid, 2-4 lb/bbl · Non-ionic surfactant, 25% by volume · Degreaser, 2-3% by volume · 20-40 mesh fracturing sand, 20-30 lb/bbl

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The frac-sand will serve as scouring agent to remove mud cake and scale from the casing and tubing. In the case of displacing oil base mud, it is advisable to pump an emulsified oil pill first (10-30 bbls) having a density of 0.2 pcf higher than the displaced oil mud density. This pill will be followed by diesel oil (10-30 bbls) with frac-sand (20-30 lb/bbl) then the scrubber water base pill described above. High viscosity brine pill volume (10-30 bbls) composed of: · The clean completion brine · HEC, 1 - 2 lb/bbl This pill is to be followed by the clean, filtered brine to complete the displacement. Once displacement is completed, continue circulating the brine and start filtering if required. Lost circulation pill (viscous brine pill with the suitable degradable bridging material) should be prepared and kept on hand before displacement starts. This pill should be spotted at the perforated interval to minimize fluid losses into the zone. Proper displacement procedures should always be followed by the removal of solids and "dirt" from the wellbore and rig equipment. Avoid contaminating the clean filtered brines with drilling or packer fluids previously in the hole by using proper spacers. The following are the common contaminants to be separated from completion brines: •

Iron (iron oxide, iron carbonate, iron hydroxide and iron shavings) Iron is the most serious contaminant for heavy brines. Some iron can give a dark green gelatinous precipitate and can cause filtering problems. The Fe++ sometimes changes to Fe+++ (dark reddish brown precipitate) which is easier to filter because of its loose crystal nature. Some filtration service companies use HC1 to keep the iron in solution and avoid plugging the filter media. This way they filter the brine easier and faster. Using HC1 will increase the brine acidity and aggravate the situation. In many cases, leaving the filtered brine in storage tanks a few days will allow the iron to precipitate out. Adding HC1 or any other acid to the brine or to the filter media should not be allowed.

•

Pipe Dope: Analysis of downhole plugging materials indicated that iron compounds and pipe dope were the major constituents.

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•

Mud Additives: Bentonite, barite, illmenite, iron carbonate, iron-oxide, polymers (CMC, starch, lignosulfonate ...etc.) calcium carbonate, asphalt, waxes ... etc.

•

Mica, cane fiber, cotton seed hulls, walnut

•

Other Lost Circulation Materials ( LCM): shells, cellophane, shredded rubber, etc.

•

Drilled Solids: Sand, shale, clay, limestone, dolomite, anhydrite, gypsum, salt, lignite, plant remains, iron oxide, iron carbonate, mica, pyrite, etc.

•

Crude Oil: Asphaltenes and waxes.

•

Plankton and Bacteria: From seawater or bay water.

•

Downhole Tools: From seawater or bay water.

There are two different displacement procedures used today. They are indirect displacement and direct displacement. The choice of procedure depends on casing-tubing strengths and cement bond log results. If the bond logs and casing strength data indicate that the casing will withstand a calculated pressure differential. the indirect displacement procedure should be used. (Pressure differential = bottom hole pressure - hydrostatic head due to salt water.) This procedure uses large volumes of seawater to flush the well, resulting in a clean, solidsfree displacement, reduced spacer costs and lower filtration costs. When applying the indirect method (reverse circulation) we have to be sure that the pumping pressure will not exceed the collapse or burst strength of the casing. If the bond logs indicate that the casing will not withstand the differential pressure, the direct displacement procedure should be used. This method does not obtain a clean displacement and expensive filtering will be necessary. However, undesirable pressure situations are eliminated because this procedure maintains a constant hydrostatic head. Both direct and indirect displacement procedures make use of pills and spacers for effective hole cleaning and spacers for effective hole cleaning and separation of fluids.

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The primary purpose of a spacer is to provide a complete separation of two incompatible fluids. The spacer must be compatible with both the displaced fluid (fluid coming out) and the displacing fluid (fluid going in). Cleaning pills are used to sweep debris out of the hole. Two types of cleaning pills may be used. A basic cleaning pill is composed of brine viscosified with HEC. A scouring pill, used to remove mud cake from the inside of the casing, consists of water, and coarse sand. The scouring pill must be preceded and followed by a viscous spacer to prevent mixing with other fluids. Indirect displacement procedure 1.

Run bit and scraper.

2.

Condition and thin the mud as much as possible while maintaining correct rheological properties. Circulate the mud and reciprocate the tubing during this process.

3.

Pump seawater down the annulus and up the tubing no faster than 2 bbl/min. Spot the displaced mud into the desired reserve tank. The reverse circulation reduces intermingling of the mud and seawater. Pumping fluid faster than 2 bbl/min creates turbulent flow and increases intermingling of the mud and seawater.

4.

Prepare a 50 barrel pill of fresh water and caustic soda with a pH of 12 to 13. Circulate this pill slowly through the entire system for two circulations rotate and reciprocate the pipe while circulating. The high pH helps dissolve the wall cake from the casing.

5.

Chase the pill with clean saltwater and flush until the seawater is clear.

6.

Prepare a 20 barrel spacer of filtered seawater and HEC with a funnel viscosity of 150 to 200 sec/qt. Reverse circulate the spacer, pumping at 1 to 2 bbl/min. Follow with the completion fluid. 7. Pump until the density pumped in equals the density in the flow line. Dump the spacer. 8.

Place the filtration unit on line. Direct displacement

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( Heavy brine in / light oil mud out )

B R I N E MUD

Light oil mud

( 68 pcf )

High viscosity oil mud with additional Geltone

( 69 pcf )

Spacer - 2 500 ft

XC- Polymer / mutual solvent detergent / barite

( 69 pcf )

Spacer - 3 500 ft

Brine / water wetting surfactant caustic / frac sand

( 68 pcf )

Spacer - 4 500 ft

High viscosity clear brine

( 70 pcf )

MUD

Spacer - 1 500 ft

BRINE

B R I N E

BRINE

Heavy brine

( 70 pcf )

Indirect displacement ( or reverse circulation ) _____________________________________________________________________________________ Page 58

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( Light brine in / heavy water-based mud out )

BRINE

MUD

M U D

M U D

Clear brine

( 70 pcf )

Spacer - 4 500 ft

High viscosity clear brine

( 70 pcf )

Spacer - 3 500 ft

Brine / caustic / frac sand

( 70 pcf )

Spacer - 2 500 ft

XC- Polymer / detergent / barite

( 73 pcf )

Spacer - 1 500 ft

High viscosity mud

( 74 pcf )

Heavy mud

( 75 pcf )

BRINE

MUD

Indirect displacement ( or reverse circulation )

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( Light brine in / heavy oil-based mud out )

BRINE

M U D

Clear brine

( 70 pcf )

Spacer - 4 500 ft

High viscosity clear brine

( 70 pcf )

Spacer - 3 500 ft

Brine / water wetting surfactant caustic / frac sand

( 70 pcf )

XC- Polymer / mutual solvent detergent / barite

( 73 pcf )

High viscosity oil mud with additional Geltone

( 74 pcf )

Heavy oil mud

( 75 pcf )

BRINE

Spacer - 2 500 ft Spacer - 1 500 ft

MUD

M U D

MUD

Direct displacement _____________________________________________________________________________________ Page 60

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( Heavy brine in / light water-based mud out )

Spacer - 1 500 ft

Light mud

( 68 pcf )

High viscosity mud

( 69 pcf )

Spacer - 2 500 ft

XC- Polymer / detergent / barite ( 69 pcf )

Spacer - 3 500 ft

Brine / caustic / frac sand

( 68 pcf )

Spacer - 4 500 ft

High viscosity clear brine

( 70 pcf )

Heavy brine

( 70 pcf )

Direct displacement

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Direct displacement is a somewhat tedious procedure which involves using five spacers in line. Each spacer has a specific use. Spacer No. 1 is 20 bbl viscosified mud used as a plug to displace the mud. Spacer No. 2 and 4 separate the spacer with degreaser from organic additives in the mud and from the brine. Spacer No. 3 is a combination scouring-dissolving spacer. The frac-sand is used to scrape mud off casing walls while the degreaser caustic dissolves the mud. Spacer No. 5 is used to separate the solids laden fluids from the solids free. 1. 2.

Pump 20 bbl of mud into slugging pit and increase funnel viscosity to 80 sec/qt, Run a bit and scraper on the drill string assembly. Circulate the mud and reciprocate the pipe. 3. Condition and thin mud as much as possible while maintaining the proper rheological properties. Note: Reverse circulate during steps 4-9. 4.

Pump the 20 bbl pill. into the annulus. (Spacer No. 1)

Special application of completion and workover

5.

Follow with a 20 bbl pill of fresh water, xanthan gum(l/2 lb/bbl) and barite to desired density. (Spacer No. 2)

6.

Follow with a 10 bbl pill of fresh water, 1 drum of degreaser 500 lb coarse fracsand and caustic soda to a pH of 12.5. (Spacer No. 5)

7.

Follow with 10 bbl pill of fresh water, xantham gum (12 lb/bbl) and barite to desired density. (Spacer No. 4)

8.

Follow with a 10 bbl pill of the completion fluid viscosified to 150- 200 sec/qt. (Spacer No. 5)

9.

Follow with clean brine.

10 · Discard all pills. Filter for at least one full circulation after displacement.

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COMPLETION & WORKOVER FLUIDS

SAFETY

High density brines have unique chemical properties. Consequently, they should be handled in a different manner than conventional muds, especially for safety reasons. Personnel safety when handling these brine systems involves two aspects: 1) Education of all personnel

2) proper safety apparel.

A brine is simply a salt (or a blend of salts) plus water. Low concentrations of these salts cause little or no problem. Commercially available salts currently used in Saudi Aramco's fields are: - sodium chloride ( NaCl ) - potassium chloride (KCl) - calcium chloride (CaC12) Safety apparel

This is a list of the minimum safety apparel which should be worn when working with or in the vicinity of brines: Hard hats Chemical splash goggles Rubber gloves Rubber boots Aprons/slicker suits Disposable dust/mist respirators Rig safety equipment

Following is a list of the minimum safety equipment that should be available when working on a rig with brines: Eye wash fountains and drench showers Pipe wipers Floor mats

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TABLE OF CONTENTS INTRODUCTION ...............................................................................................................1 SHAPED CHARGE FUNDAMENTALS ...........................................................................2 I. Basic Components .............................................................................................2 II. Detonation Mechanics .......................................................................................3 GUN TYPES AND THEIR APPLICATIONS....................................................................5 I. Retrievable .........................................................................................................5 A. Hollow Carrier Guns..............................................................................5 II. Expendable.........................................................................................................7 A. Fully Expendable Guns..........................................................................8 B. Semi-Expendable Guns..........................................................................9 C. Tubing Conveyed Guns .......................................................................10 PERFORATION PRODUCTIVITY..................................................................................13 I. Factors Affecting Perforation Productivity......................................................13 A. Charge Geometry .................................................................................13 B. Perforation Flow Characteristics .........................................................14 C. Depth Of Perforated Zone....................................................................15 D. Gun Clearance......................................................................................15 E. Casing Damage ....................................................................................16 F. Formation Damage...............................................................................16 II. Increasing Perforation Productivity .................................................................17 A. Ways To Avoid Casing Damage..........................................................17 B. Ways To Avoid Plugging Perforations ................................................17 C. Ways To Avoid Formation Damage ....................................................17 PERFORATING JOB DESIGN AND OPERATIONS.....................................................18 I. Design Considerations .....................................................................................18 A. Natural Completions ............................................................................18 B. Diversion..............................................................................................18 C. Matrix Acidizing..................................................................................18 D. Gravel Packing.....................................................................................19 E. Hydraulic Fracturing............................................................................19 II. Perforating Operations .....................................................................................20 A. Selective Firing ....................................................................................20 B. Gun Positioning ...................................................................................20 C. Depth Correlation ................................................................................21 D. Perforating For Injection......................................................................22

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PERFORATING SERVICES AVAILABLE IN SAUDI ARAMCO ..............................23 I. Schlumberger ...................................................................................................23 II. Western Atlas...................................................................................................24

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INTRODUCTION Perforating is often a primary goal of a completion and is one of the most important completion and workover operations performed. In cased hole completions, perforations provide the means of communication between the reservoir and the wellbore. Achieving good communication (productivity or injectivity) requires: 1.

Selecting the appropriate equipment for the type of completion.

2.

Providing wellbore conditions (e.g., wellbore fluid and differential pressure) to safely optimize the performance of the equipment selected.

To perforate successfully requires planning. The fact that perforating is essentially irreversible is the best argument for good planning. Without proper planning, you run the risk of casing deformation, formation damage or worse. In any event, productivity could be seriously affected. The basic tool used in modern perforating is the shaped charge. The shaped charge is an outstanding example of the transfer of military technology to the private sector. Replacing the old bullet guns, shaped charges account for 90% of all the perforating done in the world today and 100% of the perforating done in Saudi Aramco. Shaped charges, due to their mechanical simplicity and their use of high-order explosives, offer flexibility in application, high reliability and a high energy to size ratio. Our discussion of perforating will start by briefly describing the fundamentals of shaped charges. Next, we will discuss gun types and their applications, perforation productivity then job design and operations. We will conclude with sections on the tools available and the recommended guidelines for perforating in Saudi Aramco.

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SHAPED CHARGE FUNDAMENTALS I. BASIC COMPONENTS The shaped charge is composed of only four basic components; the liner, main charge, primer and case as shown in Figure 1. Despite its simple design, the shaped charge is a highly refined piece of engineering. Figure 2 illustrates the effect of charge shape on penetration. Part (a) shows the small indentation resulting from a flat ended charge. In Part (b), a conical void in the charge helps to direct the force of the explosion outward more efficiently. The resulting indentation has increased to about one-half of the diameter of the conical void. Part (c) places a thin metallic liner into this conical void. The penetration has now increased to four or five times the diameter of the liner. It is the liner that is responsible for the great penetrations produced with shaped charges.

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MAIN EXPLOSIVE CHARGE CASE PRIMER CHARGE

LINER

DETONATING CORD GROOVE (POINT OF IGNITION) TYPICAL SHAPED CHARGE

Figure 1

FLAT-END EFFECT (A)

UNLINED EFFECT

LINED EFFECT

(B)

(C)

SHAPED CHARGE EFFECTS

Figure 2

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II. DETONATION MECHANICS Most shaped charges use RDX or HDX. These are explosives similar to TNT or nitroglycerin. The reaction is so fast that the time required to perforate is only 100 to 300 microseconds. Figure 3 illustrates the detonation process. MAIN EXPLOSIVE CHARGE (INTACT) DETONATION WAVE

AFTER THE PRIMER IGNITES THE MAIN EXPLOSIVE, THE DETONATION WAVE MOVES AT ±30,000 FT/SEC.

(A) PRIMER IGNITES EXPLOSIVE

MAIN EXPLOSIVE CHARGE (SPENT)

DETONATION WAVE JET BEGINS TO FORM

THE METALLIC CONE BEGINS TO COLLAPSE, FORMING THE JE AND THE SLUG.

SLUG BEGINS TO FORM (B) ±50% OF EXPLOSIVE IS SPENT SLUG MOVES OUT BUT SLOWER THAN THE JET

DETONATION WAVE

TIP OF JET, TRAVELS AT ±20,000 FT/SEC.

THE JET AND SLUG TRAVEL OUTWARD AT DIFFERENT SPEEDS ALONG THE METALLIC CONE'S AXIS.

(C) DETONATION COMPLETE PHASES OF DETONATION

Figure 3 Page 3

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As the explosive detonates, a wave sweeps through the charge collapsing the liner. As it reaches the axis, the inner portion of the liner material is forced forward forming the perforating jet. While the outer portion, that was in contact with the explosive, slides back forming the slower moving slug. This all takes place in less than 20 microseconds. Since the jet moves faster than the slug, the slug can follow the jet into the newly created perforation plugging it. To mitigate this problem, considerable efforts have been made to reduce the size of the slug or eliminate it entirely. These efforts will not be discussed here but they include bimetallic liners and particulate metal liners. Contrary to popular belief, the penetrating mechanism of the shaped charge is one of crushing, not of burning. The casing, cement and formation plastically yield under the extreme jet impingement pressures. There is considerable crushing and compression, as might be expected, but no fusing of the perforated material occurs.

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GUN TYPES AND THEIR APPLICATIONS Modern perforating guns can be grouped into three classes: the retrievable hollow carrier, the expendable guns and the tubing conveyed guns. A fourth class of gun would be the bullet guns. Bullet guns see limited use in North America since they provide a very uniform hole size ideal for the ball sealers used in fracturing. Outside this application, they are virtually obsolete and not used at all in Saudi Aramco. I. RETRIEVABLE A. Hollow Carrier Guns Hollow carrier guns can be re-used and are commonly available in sizes ranging from 3-1/8" up to 5" for general casing operations. There are also slim hole guns that can be used in small casing sizes or through tubing. The carriers are available with a normal shot density of four shots-per-foot at 90° or 120° phasing. They are typically used when a well is to be perforated before the production string has been run. Figure 4 shows a 120° phased hollow carrier gun. A variation of the hollow carrier gun is the high shot density (HSD) gun. HSD guns are not reusable but they can be recovered from the well.

PHASE ANGLE (120°)

CHARGE OR BLANK AS REQUIRED

POSITION ON BACKSIDE OF GUN

HOLLOW CARRIER GUN WITH 120° PHASING

Figure 4

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Advantages of the hollow carrier gun include: 1. High reliability since the blasting caps, detonating cord and charges are all contained within the gun. 2. Rugged design. The weight of the steel carrier plus the fact that all fragile parts are protected within often makes it easier to get to perforating depth and minimizes rig time by allowing higher running speeds. 3. The operator has the advantage of perforating at any desired shot density, one or two shots-per-foot being the most common alternatives to four shots-perfoot. High density carriers typically have shot densities up to 12 shots-perfoot. 4. The gun is retrieved, leaving essentially no debris in the hole. 5. The carrier provides protection for the charges from high wellbore temperature and pressure. Standard guns are rated to 340°F at 15 to 20,000 psi. High-temperature guns are rated for 25,000 psi at 470°F with some decrease in performance. 6. Since the carrier absorbs the reactive forces produced during detonation, the gun produces no casing deformation. Disadvantages of the hollow carrier gun include: 1. The weight of the carrier limits the length of gun that can be run in one trip. 2. The rigidity of the carrier may prevent the slim-hole hollow carrier guns from passing through crooked production tubing. 3. Difficulties perforating under balanced. The first interval to be perforated may be done under balanced but this presents well control problems. Applications of hollow carrier guns include: 1. In Saudi Aramco, the 3-1/8", 3-3/8" and 4" guns are the most commonly used hollow carrier sizes. 2. HSD guns have been used to test an exploration well.

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3. HSD guns are used for perforating highly productive sandstone reservoirs where sand control is an issue and high shot densities are desired. Hawtah wells are a good example of this application.

II. EXPENDABLE When more flexibility than a ported hollow carrier can provide is required or it is desired to perforate very long intervals in one trip, one of the expendable designs can be used. There are two basic classes of expendable guns: wireline and tubing conveyed. Wireline conveyed expendable guns consist of individual pressure sealed aluminum, glass, ceramic, or cast iron cases wired together with the detonating cord. These can be further divided into two groups, the fully expendable and the semiexpendable guns. The fully expendable gun is designed to shatter when fired. The debris falls to bottom and is left in the well. Only the perforator casings of a semiexpendable gun are destroyed when the gun is fired. The carrier remains intact and is removed from the wellbore. Figure 5 shows both types of wireline conveyed expendable guns.

(A) FULLY EXPENDABLE

(B) SEMI-EXPENDABLE (WIRE AND STRIP)

WIRELINE CONVEYED EXPENDABLE GUN TYPES

Figure 5

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A. Fully Expendable Guns Aluminum has emerged as the most economical case material for fully expendable guns because it is light and can be cast into integral casings, simplifying the assembly of these guns. These cases have been strung together in sections as long as 200'. Advantages of fully expendable guns include: 1. High flexibility permits handling long lengths. 2. Comparing size, these guns are likely to penetrate 10 to 25 percent deeper than slim (through tubing) hollow carrier guns. Disadvantages of fully expendable guns include: 1. They leave debris in the well. The concern here is that the debris can bridge off in the casing or, if perforating under balanced, the gun can be blown up the hole causing a fishing job. 2. The aluminum cases are not resistant to HCl acid and it is not recommended to use them in acid. HCl is sometimes used to dissolve debris left in the hole. 3. Because the aluminum cases are softer than steel, they can experience excessive wear if run in the hole too fast. Running speeds for aluminum cases should be limited to 10,000 ft/hour as opposed to 30,000 ft/hour for steel. 4. There is no way of verifying if all the charges fired. 5. Pressure and temperature ratings are lower for expendable guns than for hollow carrier guns. Most are good for 5000 psi at 200°F but some can have ratings as high as 15,000 psi at 300°F. 6. Expendable guns are not as sturdy as hollow carrier guns. If a bridge is encountered, expendable guns can not be pushed or even spudded lightly as they may ball up or brake causing a fishing job. 7. Expendable guns can damage or deform the casing when fired and their use is not recommended in old wells or where the casing has been corroded. Application of fully expendable guns: Page 8

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1. Fully expendable guns are rarely used in Saudi Aramco. Only when two strings (e.g., 4-1/2" and 7") of casing are to be perforated through 2-3/8" tubing would fully expendable guns be used. Schlumberger's pivot gun is currently available for this application. B. Semi-Expendable Guns Semi-expendable charges are either attached to a carrier strip or wire carrier which makes using glass or ceramic cases more practical. Wire type carriers are seldom used, the tougher strips being preferred. An angled variation on the strip gun has been developed and is now available in Saudi Aramco. This enables consecutive charges to be fired 90° apart. This phasing places the perforations at ±45° on either side of the magnetic positioning tool's central axis. By providing some phasing, the angled strip gun is believed to limit a well's tendency to produce sand by reducing the DP across the perforations. Semi-expendable guns offer the following advantages over fully expendable guns: 1. The amount of the debris left in the hole is greatly reduced as the strips and wiring are recovered. 2. In the case of glass or ceramic cases, the type of debris left is more like sand and less apt to cause problems. 3. The ability to use ceramic cases allows improvements in wear resistance, chemical resistance, durability, gas and pressure integrity. 4. Semi-expendable guns are usually magnetically positioned, maximizing penetration in through tubing applications. 5. Strip type semi-expendables are less apt to cause casing damage than their fully expendable counterparts. 6. The modular nature of the strip carriers facilitates spacing out the charges in the field. This is of particular use in Saudi Aramco where logistics often

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PERFORATING require guns to be transported offshore or to remote locations long before the actual intervals to be perforated are known.

Disadvantages of semi-expendable guns include: 1. Verification of charges fired may be a problem. 2. Pressure and temperature ratings are lower than hollow carrier guns. Most are good for 5000 psi at 200°F but some can have ratings as high as 15,000 psi at 300°F. 3. Strip guns while sturdier than fully expendable guns, still cannot be pushed or spudded as they may ball up or break causing a fishing job. 4. In old wells or where the casing has been corroded, strip guns may damage or deform the casing when fired and their use is not recommended under these conditions. Application of semi-expendable guns: 1. Semi-expendable guns are used extensively in Saudi Aramco, the most common being the 2-1/8" and the 1-11/16" guns that are run through tubing to perforate a liner or casing. C. Tubing Conveyed Guns A recent innovation in perforating is the tubing conveyed gun. Tubing conveyed perforating (TCP) is the placement of a hollow carrier gun on the end of a string of tubing or drill pipe. TCP carriers are recovered from the well but they are not ported and can only be used once. Hence their classification as expendable guns. TCP guns can be run on a work string, test string, production tubing, etc., but most of the TCP work today uses the production tubing. Advantages of TCP guns include: 1. Differential pressure (formation to wellbore) can be used to surge debris from the perforations without the fear of getting blown up hole. 2. Very long intervals can be perforated in a single trip. 3. Pressure and temperature ratings are the same as the hollow carrier guns. Page 10

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DRILL PIPE TO SURFACE RADIOACTIVE MARKER SUB ±500' OF DRILLPIPE RADIOACTIVE PIP TAG

DRILL PIPE OR TUBING TO SURFACE RADIOACTIVE MARKER SUB

DRILLPIPE OR TUBING

±500' OF DRILLPIPE

PACKER W/ BYPASS

CIRCULATING SUB DIFFERENTIAL PRESSURE FIRING HEAD

DIFFERENTIAL PRESSURE AND/OR DR BAR FIRING HEAD SAFETY SPACER

SAFETY SPACER 4-1/2" O.D. HIGH SHOT DENSITY GUNS AT 5 SHOTS-PER-FOOT & SPACERS AS REQUIRED

4-1/2" O.D. HIGH SHOT DENSITY GUNS AT 5 SHOTS-PER-FOOT & SPACERS AS REQUIRE

BOTTOM NOSE

BOTTOM NOSE

(A) Typical Horizontal TCP String

(B) Typical TCP String

TUBING CONVEYED PERFORATING

Figure 6

Disadvantages of TCP guns include: 1. If the guns are to be left in the well, they may hinder future workover operations. 2. The cost of tubing conveyed perforating may exceed the cost of other through tubing methods by as much as 40%.

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3. The only way of verifying that all the charges have fired is to trip out of the hole with the guns. Applications of TCP guns include: 1. In Saudi Aramco, horizontal wells are perforated using TCP guns on drill pipe without a packer. After logging, the well is circulated to clean kill weight brine. The guns are made up, run in the hole and radioactive markers in the string are used to place the string on depth. The guns are then fired hydraulically. The guns are pulled out and the completion is run. Close to 2400' of have been perforated in one trip using this technique. See Figure 6 (A). 2. Exploration wells in Saudi Aramco are tested using TCP strings made up with a retrievable packer. The guns are run on the tailpipe assembly, and landed opposite the production zone. The production packer is set, coil tubing is used to displace the string to a lighter fluid and the guns are fired. After being fired, if the completion does not have a permanent tailpipe, the well can be killed and the guns pulled. Otherwise, the guns can be left or dropped into the rathole. See Figure 6 (B).

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PERFORATION PRODUCTIVITY Several factors affect the performance of a perforated zone's productivity. Increases in entrance hole size and depth of the perforations tend to enhance productivity while casing and formation damage can restrict it. I. FACTORS AFFECTING PERFORATION PRODUCTIVITY A. Charge Geometry Figure 7 shows many of the factors affecting penetration and lists the results of changes made to each. CHARGE DENSITY AND DISTRIBUTION, D v

ENTRANCE HOLE DIA.

PERFORATION VOLUME

CHARGE / CASE SIZE, S

α

d

t

a LINER MATERIAL AND PHYSICAL PROPERTIES

STAND-OFF b

PENETRATION

TYPICAL SHAPED CHARGE

Figure 7 To increase: PENETRATION ENTRANCE HOLE DIA. HOLE VOLUME

INCREASE

REDUCE

a, S, d, t & Dv α&d α, d & t

α b, t & Dv @ apex b and adjusts Dv

Theoretically, the optimum stand-off would be where the tip of the jet touches the target material when the liner has just finished collapsing. At this point the jet has Page 13

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reached its maximum potential energy. If the jet is required to travel further before encountering the target material, it will have lost some of its effectiveness. An extreme example of this scenario is seen in multi-phase perforating with eccentric gun placement. The charges adjacent to the casing produce much deeper penetrations than their counterparts on the opposite side of the gun. Gun positioning is discussed in more detail in the Perforating Operations section. The manufacturers of shaped charges have done considerable research into the effects of changing the parameters shown above. Perforating service companies take much of the guesswork out of planning a perforating job by publishing catalogs containing technical data such as maximum shots-per-foot, phasing possibilities, explosive characteristics, pressure and temperature limitations. These tables also include the API RP-43 Certification Data of their charges (e.g., length of perforation, entrance hole diameter and others). Some are able to provide information on perforation performance with regard to phasing, gun clearance and centralization. Charge size affects only the length of the penetration. The materials used and the geometry of the shaped charge are the controlling factors for penetration. Assuming the perforation reaches beyond filtration damage done during drilling, the length and the entrance hole size of the perforation has little effect on the flow characteristics. B. Perforation Flow Characteristics The flow characteristics of a single perforation are more dependent on our ability to provide a clean perforation tunnel than any other factor. For this reason, perforation clean up is very important. The type and quality of the charge used will have a significant effect on clean up. High quality charges provide a jet that is more uniform, has better velocity distribution and will tend not to plug the perforation with slug material. Indications are that it is the quality of the charges that produce perforations that are easier to clean up. The only other way to increase flow is to add more perforations. High shot densities increase the flow by increasing the surface area on the reservoir exposed to the wellbore. Increasing the number of perforations also reduces the pressure drop across the perforations, providing added benefits that will be discussed later. High shot densities can make stimulation and workover operations more difficult

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Therefore, good flow characteristics are a result of using high quality charges and high shot densities rather than the size of the charges used. The amount of explosive used remains important to us when we consider casing deformation produced in conjunction with expendable guns. C. Depth Of Perforated Zone Earlier in this chapter, we learned that impingement pressures are the actual mechanism responsible for crushing the target rock, giving the penetration its volume. If, the pressure within the target were to increase, it would follow that the net force, available to crush the rock, would decrease. This would manifest itself as a reduction in the volume of the perforation. Since the impingement pressure is related to the velocity of the jet, we would expect the jet velocity to decrease as the hydrostatic pressure, or depth of the perforation, increased. Laboratory testing has actually confirmed this phenomenon. The reverse is also true. Lower hydrostatic pressure will improve perforation efficiency. As an added benefit, we will see that lower pressure also helps to clean out the perforations. Furthermore, the strength of the target rock will affect perforation efficiency with a general trend toward lower penetrations with increased rock strength. Strength variations within the target material (reservoir rock) will have little effect. Although the depth of the zone being perforated should be considered, it is minor when compared to gun clearance. D. Gun Clearance Gun clearance is defined as the distance along the axis of the jet from the outside diameter of the gun to the inside wall of the casing. For most designs, optimum stand-off occurs when the perforator is at or near the casing wall. Therefore, it is desirable to keep gun clearance to a minimum. As with most of our real-world experiences, this ideal is difficult to obtain. There are a large number of factors that increase gun clearance but very little that we can do to minimize it. Variable clearance is common since most perforating is done with phase angles other than 0° and the guns tend to lie on the low side of the hole due to wellbore deviation. As gun clearance varies, so does entrance hole diameter and penetration. The problem is compounded when through-tubing guns are used. These guns are very small in diameter relative to the casing. Centralizing the gun under these circumstances will not provide satisfactory results as the clearance will be high on all sides of the gun. For through-tubing applications, the only

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thing that we can realistically do to improve gun performance is to intentionally decentralize. This practice, known as positioning, and will be discussed in detail later. E. Casing Damage Casing damage can prevent effective stimulation, eliminate zone isolation and allow the production of excess amounts of sand and water. This damage is usually characterized by bulging, splitting or complete rupture of the casing. As mentioned in the discussion of 'Gun Types and Their Applications', hollow carrier guns do not cause casing damage. This is due to the fact that the explosion's reactive force is contained within the carrier. This is not the case with expendable guns. Causes of casing damage include: 1. Hollow carrier guns produce no casing damage, expendable guns do. 2. Semi-expendable strip guns produce less casing damage than fully expendable guns. 3. Damage increases as explosive load increases. 4. Casing damage decreases as hydrostatic pressure increases. 5. Casing wall thickness, grade and support (cement sheath thickness) all contribute to minimizing casing damage. 6. Cement strength has little effect on casing damage. 7. Shot density (up to 8 shots-per-foot) has little effect on casing collapse resistance. F. Formation Damage Formation damage is the most significant factor limiting perforation productivity. Causes of formation damage include: 1. Debris left in the perforation tunnel; explosion by-products and liner residue. 2. Compaction of the reservoir rock in the vicinity of the perforation. 3. Solids deposited in the perforation by the filtration of borehole fluids.

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II. INCREASING PERFORATION PRODUCTIVITY Anything that restricts production, by definition, limits productivity. Damaged casing can cause sanding, water intrusion or collapse entirely. Formation damage can keep all fluids from entering the well. By selecting the proper guns, by providing proper wellbore conditions and by using clean completion fluids, we can significantly reduce casing and formation damage. A. Ways To Avoid Casing Damage 1. Use hollow carrier guns whenever possible. 2. When perforating with expendable guns, use the minimum charge size that will provide reliable results. 3. Avoid the use of fully expendable guns in older wells, where corrosion may have weakened the casing. B. Ways To Avoid Plugging Perforations 1. Using high quality charges (high-order explosives such as RDX or HMX with properly designed liners) will reduce the amount of explosion by-products and liner residue. 2. Using hollow carrier guns will eliminate the debris associated with expendable cases that could find its way into the perforation tunnels. 3. Perforating with negative differential pressure will surge the perforation tunnels. This acts to clean much of the debris before it has a chance to plug the perforations and to restore some of the permeability in the compacted zone around the perforations. C. Ways To Avoid Formation Damage 1. Perforating with a clean completion fluid is essential. Fluids high in particulates such as unfiltered brines or drilling mud shouldn't be used. 2. Clean brine is the preferred fluid for perforating. Fresh water can cause hydratable clays to swell, reducing the effective permeability. 3. Avoid perforating with positive differential pressure. This is more critical in sandstone reservoirs where there may be hydratable clays present.

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PERFORATING JOB DESIGN AND OPERATIONS I. DESIGN CONSIDERATIONS Perforations are a method of conducting reservoir fluids into the wellbore. When planning a perforation job, we immediately think of ways that we can improve perforation productivity (ie. reducing formation damage or improving clean up characteristics). Additionally, attention must be given to the other functions that we may ask the perforations to perform. Some of these are: A. Natural Completions The term natural completion is used to refer to the case where perforations are made and the well placed into service without any stimulation. There are three prerequisites for the natural completion to be effective: 1. The completion and reservoir fluids must be compatible. 2. The completion fluid must be clean. 3. The reservoir must have a high permeability. If all three components are not present, then the natural completion will have to be supplemented with some form of stimulation. This is especially true when perforating over-balanced (ie. kill weight fluid is in the hole). B. Diversion For ball sealers to be effective, the entrance hole size of the perforations should be between 0.2 and 0.4 inches. Also, the benefits of re-perforation must be carefully considered. Ball sealers will fail to divert fluids away from an interval where overlapping runs have created irregular shaped perforations. C. Matrix Acidizing For matrix acid jobs, the shot density is limited to 2-4 shots-per-foot to facilitate diversion with ball sealers. This does not apply to acid washes and soaking.

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D. Gravel Packing Although not routinely used in Saudi Aramco, gravel pack completions require large holes (0.5") and high shot densities (8-12 shots-per-foot). A high number of large holes should minimize DP across the perforations and help to maintain the pack's stability. There should be sections left unperforated to facilitate the setting of packers or bridge plugs for squeezing, etc., at some later date.

E. Hydraulic Fracturing Although not routinely performed in Saudi Aramco, fracturing requires diversion. The considerations from item 'B' apply. Also, to maintain zone integrity across multiple zones, each should be less than 250' separated by 100-200'. This should insure that communication is not established between zones.

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II. PERFORATING OPERATIONS A number of operational considerations are as follows: A. Selective Firing Most selective firing is done using retrievable guns on a carrier-by-carrier basis from the bottom up. This is achieved by assembling perforation gun segments and spacer elements, on the surface in accordance with perforation criteria obtained from open hole logs. The guns are then run in the hole and the first segment to be shot is placed on depth opposite the first interval to be perforated. Once the first segment is fired, the second segment is placed on depth and the process is repeated until all the segments are fired. B. Gun Positioning INNEFFECTIVE PERFORATION

MARGINAL PERFORATION

CEMENT

BORE HOLE CASING

GUN

GUN FORMATION ROCK

EFFECTIVE PERFORATIONS RANDOM MULTI-DIRECTIONAL Variable Clearance (PHASE ANGLE = 90°)

POSITIONED Minimum Clearance (PHASE ANGLE = 0°)

ECCENTRIC PERFORATING

Figure 8

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Positioning is defined as the intentional de-centralization of the perforating gun to a specific orientation. This is achieved by using a magnetic or mechanical decentralizing device to hold the gun against the wall of the casing. The result, for tools with a 0° phase angle, is that all the charges are fired in or close to the direction of minimum clearance. In deviated wells, this is usually the low side of the hole, where cement thickness is typically at a minimum due to the casing's tendency to eccenter. This combination will provide the deepest possible penetration into the formation. Figure 8 shows two examples of eccentric perforating, one random and one intentional. In Saudi Aramco, magnetic positioning is the preferred method as it avoids the possibility of jamming the mechanical type kick-out tools in the packer-tailpipe assembly. C. Depth Correlation There are two methods used to convey perforating guns. They are either run on wireline or on tubulars. To perforate at the correct depth, both conveyance methods rely on a Gamma Ray - Collar Locator log. It is the way in which this log is used that is different for each method. To insure that the perforating guns are on depth before firing, a Gamma Ray (or Neutron) log is run in conjunction with a Collar Locator (CCL) to establish a relationship between the casing collars and the formation, as seen via the open hole logs. When the perforating guns are run in the hole, a collar locator is placed on top of the guns and the distance from the CCL to the top perforating charge is measured. Next, with the gun in the hole, the casing collar locations are logged and the two logs placed side by side. With the collar depths and the distance from the top charge to the CCL sensor known, the charges can be placed on depth with confidence. Figure 9 shows an example of the two logs and the perforating gun schematic in the on depth position. With tubing conveyed guns, the correlation process is slightly different than the wireline case. Referring back to Figure 6, you will notice that there are one or two radioactive markers placed in the string above the guns. When the TCP guns are run in the hole, a Gamma Ray - Collar Locator log (GR-CCL) is run inside the tubing or drill pipe to tie the radioactive markers to the formation's Gamma Ray trace obtained from open hole logs. Next, the string is positioned so that the

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marker(s) are at the same distance above the top of the zone to be perforated. Now the charges are on depth and the well can be perforated. GAMMA RAY COLLAR LOCATOR

COLLAR LOCATOR (from first pass) (on gun assembly)

CASING COLLARS (ON DEPTH)

PERFORATING GUN

(A) FIRST PASS GR-CCL Correlation Run

(B) PERFORATING RUN Perforating Gun Assembly

PERFORATING DEPTH CORRELATION

Figure 9 D. Perforating For Injection Before attempting to inject into new perforations, it is a good practice to flow them first to remove debris from the perforation tunnels. Otherwise, the injectivity may be impaired.

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PERFORATING SERVICES AVAILABLE IN SAUDI ARAMCO There are two contractors providing perforating services in Saudi Aramco. They are Schlumberger and Western Atlas. The tables below list their guns and types of jobs most commonly performed. I. SCHLUMBERGER Gun

Size

HyperDome Retrievable Hollow Carrier HyperDome Retrievable Hollow Carrier Port Plug Gun (Casing Gun) Retrievable Hollow Carrier

1-11/16"

Shot Density 4 spf

Phase Angle 0°

Conveyance Method Wireline

2-1/8"

4 spf

0°

Wireline

3-3/8"

4 spf

90°

Wireline

Port Plug Gun (Casing Gun) Retrievable Hollow Carrier Enerjet Semi-Expendable Strip Gun

4"

4 spf

90°

Wireline

1-11/16"

0°

Wireline

0°

Wireline

±45°

Wireline

varies

Wireline

Enerjet Semi-Expendable Strip Gun

2-1/8"

Phased Enerjet Semi-Expendable Strip Gun

2-1/8"

High Shot Density Gun Expendable Hollow Carrier (retrieved but not re-used) High Shot Density Gun Expendable Hollow Carrier (retrieved but not re-used) High Shot Density Gun Expendable Hollow Carrier (retrieved but not re-used) High Shot Density Gun Expendable Hollow Carrier (retrieved but not re-used)

2-7/8"

4 spf & 6 spf 4 spf & 6 spf 4 spf & 6 spf 1-6 spf

4-1/2"

1-12 spf

varies

Wireline

2-7/8"

1-6 spf

varies

TCP Drill Pipe

4-1/2"

1-12 spf

varies

TCP Drill Pipe

1-11/16"

4 spf

180°

Wireline

Pivot Gun Fully Expendable Laser Cut Carrier

Most Common Use In Saudi Aramco Used to punch 2-3/8" to 4-1/2" tubing. Used to punch 4-1/2" tubing. Used to perforate 4-1/2" to 7" casing or liners. Used to perforate 7" and larger casing or liners. Used to perforate 4-1/2" and 5" liners through tubing. Used to perforate 7" or 41/2" casing or liners through tubing. Used to perforate 4-1/2" to 7" liners through tubing. Is available but not in use. 8 spf used in sandstone reservoirs for sand control. offshore. Used @ 6 spf to perforate horizontal wells. Used @ 4 spf to perf horizontal wells before the completion is run and @ higher shot densities in Central Area well tests. New tool. Is available but not in use.

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II. WESTERN ATLAS Gun Slim Kone Retrievable Hollow Carrier Slim Kone Retrievable Hollow Carrier

1-11/16"

Shot Density 4 spf

2-1/8"

4 spf

0°

Wireline

Alpha Jet Retrievable Hollow Carrier Alpha Jet Retrievable Hollow Carrier

3-1/8"

4 spf

90°

Wireline

4"

4 spf

90°

Wireline

Silver Jet Semi-Expendable Strip Gun

1-11/16"

0°

Wireline

Silver Jet Semi-Expendable Strip Gun

2-1/8"

0°

Wireline

Used to perforate through tubing.

Alpha Jet (deep penetrator) Expendable Hollow Carrier (retrieved but not re-used) Alpha Jet (deep penetrator) Expendable Hollow Carrier (retrieved but not re-used) Alpha Jet (HSD charges) Expendable Hollow Carrier (retrieved but not re-used) Jumbo Jet BH Expendable Hollow Carrier (retrieved but not re-used) Jumbo Jet BH Expendable Hollow Carrier (retrieved but not re-used)

4"

4 spf & 6 spf 4 spf & 6 spf 4 spf

varies

Wireline

Used in Central Area sandstone reservoirs.

4-1/2"

5 spf

varies

Wireline

Used in Central Area sandstone reservoirs.

4-1/2"

1-12 spf

varies

TCP

4-1/2"

1-12 spf

varies

Wireline

4-1/2"

4 spf

180°

TCP

5"

5 spf

90°

TCP or wireline

Alpha Jet (deep penetrator) Expendable Hollow Carrier

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Size

Phase Angle 0°

Conveyance Method Wireline

Most Common Use In Saudi Aramco Used to punch 2-3/8" through 4-1/2" tubing. New tool. Is available but has not been used to perforate. Used to perforate 4-1/2" casing or liners. Used to perforate 5" and larger casing or liners (Prod. & GWI). Used to perforate through tubing.

Used at 8 & 12 spf in Central Area sandstone reservoirs. New tool. Is available but not in use. New tool, but not in use. To be used in sandstone reservoirs for sand control. in Northern Area horiz. wells. Available on request. To be used to perforate 95/8" and larger csg.

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FORMATION DAMAGE

TABLE OF CONTENTS INTRODUCTION..........................................................................................................1 EFFECT OF DAMAGE ..............................................................................................1 Darcy's Law .........................................................................................................1 Productivity Index................................................................................................2 Effect of Damage on Productivity Index .............................................................3 Matrix Treating Benefits......................................................................................4 INDICATORS OF DAMAGE ....................................................................................5 Offset Production .................................................................................................5 Production History ...............................................................................................5 Well Testing.........................................................................................................5 CAUSES OF FORMATION DAMAGE...................................................................8 Clay Disturbance..................................................................................................8 Clay Swelling.......................................................................................................8 Clay Dispersion and Migration............................................................................9 Low Salinity Clay Dispersion..............................................................................9 Flow Induced Fines Migration ............................................................................10 Effect of Mobile Water ........................................................................................11 Scale Deposition .................................................................................................12 Water Blocking ....................................................................................................12 DAMAGE REMOVAL ................................................................................................14 Acid Washing.......................................................................................................14 Matrix Acidizing..................................................................................................14 Solvents & Surfactants.........................................................................................14 Hydraulic Fracturing............................................................................................14

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MATRIX ACIDIZING OF CARBONATES

TABLE OF CONTENTS CARBONATE MINERALS ........................................................................................15 Calcite ..................................................................................................................15 Dolomite ..............................................................................................................15 Occurrence in Nature ...........................................................................................15 Natural Fractures..................................................................................................15 Vugs .....................................................................................................................15 ACID TYPES ................................................................................................................17 Mineral Acids ......................................................................................................17 Hydrochloric Acid ...................................................................................17 Hydrochloric-Hydrofluoric Acid .............................................................18 Organic Acids ......................................................................................................18 Acetic Acid ..............................................................................................18 Formic Acid .............................................................................................18 Retarded Acid Systems ........................................................................................19 Gelled Acids ............................................................................................19 Chemically Retarded Acids .....................................................................19 Emulsified Acids......................................................................................19 ACID REACTIONS WITH CARBONATES...........................................................20 ACID TYPES AND THE CHEMISTRY OF THEIR REACTIONS.................20 Dissolving Power .................................................................................................21 ACID STRENGTH .......................................................................................................24 Organic Acid Limitation ......................................................................................24 ACID ATTACK ON CARBONATES.......................................................................26 Reaction Time......................................................................................................26 Temperature and Pressure Effects .......................................................................26 Carbonate Mineral Type Effect ...........................................................................26 Wormhole Formation...........................................................................................26 Wormhole Properties ...........................................................................................27 Fluid Loss Control ...............................................................................................28 Effect of HCL on Cement ....................................................................................28

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ACID ADDITIVES .......................................................................................................29 Corrosion Inhibitors.............................................................................................29 Surfactants ...........................................................................................................30 Antisludge Agents................................................................................................31 Mutual Solvents ...................................................................................................31 Friction Reducers .................................................................................................31 Sequestering Agents ............................................................................................31 TREATMENT DESIGN ..............................................................................................33 Preflush ................................................................................................................33 Type of Acid and Volume....................................................................................33 Acid Displacement...............................................................................................33 Maximum Injection Pressure ...............................................................................33 Injection Rate .......................................................................................................34 Safety Considerations ..........................................................................................34 Acid Quality Control ...........................................................................................35 Bullheading ..........................................................................................................35 Concentric Tubing ...............................................................................................35 Establishing Injectivity ........................................................................................35 Monitoring Treating Pressures.............................................................................36 Spent Acid Recovery ...........................................................................................36

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MATRIX ACIDIZING OF SANDSTONES

TABLE OF CONTENTS DESCRIPTION OF TREATMENT ..........................................................................37 SANDSTONE COMPOSITION..................................................................................39 Silica ....................................................................................................................39 Feldspars ..............................................................................................................39 Clays ....................................................................................................................39 Carbonates ...........................................................................................................40 ACID SANDSTONE REACTIONS ...........................................................................41 HF Acid................................................................................................................41 Dissolution Reactions ..........................................................................................41 Silica (quartz)...........................................................................................41 Feldspar (albite) .......................................................................................42 Clay (kaolinite) ........................................................................................42 Precipitation Reactions ........................................................................................42 Fluosilicates .............................................................................................42 Hydrated Silica ........................................................................................43 Calcium Fluoride .....................................................................................44 MECHANISM OF ACID ATTACK ............................................................................45 Damage Induced by Acid.....................................................................................45 Effect of HF Concentration..................................................................................46 Effect of Acid Injection Rate ...............................................................................46 Effect of Matrix Composition..............................................................................47 Effect of HF-HCL Reaction on Core Mechanical Properties ..............................47 Prediction of Radius of Acid Reaction ................................................................48 TREATMENT DESIGN ..............................................................................................50 Required Data ......................................................................................................50 Completion Data ......................................................................................50 Formation Data ........................................................................................50 Types of Fluids ........................................................................................51 Preflush ........................................................................................51 HF/HCL .......................................................................................51 Afterflush .....................................................................................52 Injection Pressure.....................................................................................52 Example Design Calculations ..............................................................................53

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FIELD IMPLEMENTATION .....................................................................................57 Well Condition.....................................................................................................57 Safety ...................................................................................................................57 Establishing Injectivity ........................................................................................57 Placement of Fluid ...............................................................................................58 Bullheading ..............................................................................................58 Circulating with Workstring ....................................................................58 Coiled Tubing Injection ...........................................................................58 Returning the well to production .........................................................................59

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TABLE OF CONTENTS WHEN TO DIVERT....................................................................................................60 HOW TO DIVERT ......................................................................................................60 PACKERS ......................................................................................................................60 PARTICULATE DIVERTING AGENTS .................................................................61 TREATMENT DESIGN ..............................................................................................62 Sandstone Matrix Acidizing ................................................................................62 Carbonate Matrix Acidizing ................................................................................62 FIELD APPLICATION ...............................................................................................64 VISCOUS FLUID DIVERTING AGENTS..............................................................65 Foam ....................................................................................................................65 Gel Diverters........................................................................................................67 PERFORATION BALL SEALERS ...........................................................................67 Description...........................................................................................................67 Performance Factors ............................................................................................68 Perforation Flow Rate ..............................................................................68 Wellbore Flow Rate .................................................................................68 Fluid Viscosity .........................................................................................68 Ball-Fluid Density Contrast .....................................................................68 Ball Sealer Seating Mechanisms..........................................................................70 Applicability ........................................................................................................71 Size and Composition ..........................................................................................71 Selection Guidelines ............................................................................................73 BALL SEALER TREATMENT DESIGN................................................................73 Ball Injection........................................................................................................73 Ball Removal or Control......................................................................................73

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INTRODUCTION Flow restriction in the reservoir rock which cause poor well productivity is called formation damage. Formation damage is usually caused by disturbances to the formation during drilling, workover and producing operations. It is generally limited to the reservoir rock within 2 feet of radial distance from the well bore. Formation damage can be removed by small stimulation treatments designed to penetrate a limited distance into the formation. EFFECT OF DAMAGE Fluid flow in a porous reservoir rock proceeds via a radial geometry in which fluids traverse progressively smaller volumes of rock as they approach the wellbore. Consequently, the greatest pressure drop occurs in the formation adjacent the wellbore, making overall production very sensitive to permeability reductions there. Darcy's Law The radial flow of a single liquid in the laminar region in a porous formation is represented by Darcy's equation: (1)

Comment [LS1]: Page: 1

where Q = flow rate, stock tank barrels / day k = average permeability, millidarcy h = interval thickness, feet Pe = formation pressure at external drainage radius (static pressure), psi Pw = flowing wellbore pressure at perforations, psi µ = oil viscosity, cp bo = reservoir fluid volume factor, reservoir bbl stock tank bbl re = drainage radius, feet rw = wellbore radius, feet Darcy's equation can be used to estimate an oil well's flowing potential if the reservoir and wellbore factors are known.

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Productivity Index The productivity index is a well property that is usually used to detect formation damage. It is defined as the ratio of the rate of production to the pressure drawdown at midpoint of the producing interval, (2)

The productivity index is a measure of the well's potential or ability to produce, and is a commonly measured well property. A subsurface pressure gauge is used to measure the static pressure Pe after a sufficient shut-in period. Also the flowing bottom-hole pressure Pw is measured after the well has flowed at a stabilized rate for sufficient period of time. The difference (Pe - Pw) is called pressure drawdown. The well is usually flowed to a separator where the gas is separated from the oil and the oil production rate Q is measured by a positive displacement meter. The productivity index is used to compare well performance within a given formation, where the formation properties are constant. The Specific Productivity Index, J per foot of interval, is a way of accounting for differences in formation thickness from one well to another.

Figure 1. Typical Inflow Performance Relationship for Solution Gas Drive Reservoirs

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In some wells the productivity index will remain constant, as long as the formation properties k, h and µ do not change, such that the flow rate is directly proportional to the pressure drawdown, ie. linear relationship. In other wells, at higher rates the linearity fails and the productivity index declines as shown in Figure (1). The cause of this decline may be due to (a) turbulence at increased rates of flow, (b) decrease in the value of k due to presence of free gas caused by the drop of pressure below the bubble point, (c) increase in oil viscosity with pressure drop below bubble point or (d) reduction in permeability due to formation compressibility. Therefore, when the productivity index (or specific productivity index) of a well drops below the original productivity index or is less than the productivity index of an offset well, it may not be damaged but simply producing below the bubble point. Effect of Damage on Productivity Index As a consequence of radial flow, formation damage that is closest to the wellbore results in the greatest reduction in the production rate. Of course, the deeper the damage zone is, the greater the reduction of productivity. However, once damage near the wellbore region occurs, deepening the damage adds progressively smaller contribution to the production production loss. This is mathematically shown by Darcy's equation by including a damaged permeability, kd of thickness rd. The resulting equation relates the productivity index of the damaged formation to the non-damaged native formation (J /Jo) and depth and magnitude of damage,

a a

(3)

where a is the ratio of damage zone permeability to virgin permeability. These dimensions are illustrated in Figure (2) for an idealized damage zone. Plotting the above equation for various amounts of damage, a, as a function of depth of damage radius shows that the greatest effect of damage is within the first two inches of the wellbore (Figure 2), with diminishing influence as depth of damage invasion increases.

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Figure 2. Productivity Loss Due to Damage in Two-Zone Permeability Model Matrix Treating Benefits Removing damage with solvents can result in productivity many times the damaged productivity, depending on the extent of initial damage. For example, Figure (2) indicates that a well which contains a 90% reduction in permeability in the first foot around the wellbore has a flow efficiency near 35%. Therefore, a properly designed damage-removal treatment has the potential to increase the production rate by a factor of three. Such damage removal benefits are estimated on the assumption of uniform, radial removal of damage from within the matrix of the rock, hence such treatments are often referred to as matrix treatments. Hydraulic fracturing can also yield these benefits, by a mechanism which causes the damage to be bypassed. However, a fracture treatment must be intentionally designed in order to be effective. Fracturing treatment intended for matrix injection will generally yield disappointing results. Matrix treating only offers the potentail for significant productivity improvement in damaged wells. Little benefit can be expected if no damage is present. The negligible benefits of undamaged well treating can be shown with the aid of Equation 3. For example, if the permeability within 1 ft of the wellbore of a well whose rw is 6 inch and re is 660 ft is increased two-fold by matrix treatment, the increase in productivity will be about 5%.

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INDICATORS OF DAMAGE There is a large incentive for being able to identify the presence of treatable formation damage, since the economic return of a field often depends on maintaining maximum productivity from each well. Treatments performed on undamaged wells are wasted at best, and may actually lead to increased damage. We can avoid many problems associated with incorrect diagnosis by exploiting the evaluation tools available, including productivity comparisons, calculated production estimates, and well testing. Offset Production A common indicator of well damage is low productivity relative to offset wells in the same formation. The specific productivity index, J/ft of interval, provides a means for quantifying this comparison. A substantially lower specific productivity index relative to other wells in the field suggests that damage is present. However, although this is a useful approach for initial screening, this concept is limited by the heterogeneous makeup of many formations. Therefore, additional diagnostics and data should be gathered prior to deciding a course of remedial action. Production History Comparison of present production with past production history is a good indicator of problem wells, providing that normal reservoir decline is accounted for. Productivity index, J, is especially useful for comparing production from the same well at different times, since formation factors are likely to remain constant. After an abnormally high production decline has been verified, the well's history can give important clues as to the type of damage present. Low productivity may be traceable to a specific completion, workover or production practice. For example, formation damage is often common after well killing operations, especially if drilling mud is used as a workover fluid. Injection of unfiltered brines into disposal or injection wells is a common cause of reduced injectivity. Instances such as these should be looked for in well files when damage is suspected. Well Testing Well testing is generally understood to encompass flow testing and pressure buildup testing. Flow testing can provide productivity index, fluid ratios, and a measure of average permeability. Changes in flow rate or relative fluid production from one test period to another are often signs that the well is damaged.

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Pressure buildup testing is a relatively sophisticated approach to measuring reservoir permeability and obtaining an indication of formation damage. A buildup test involves flowing the well at constant rate for an established period known as Horner time, th, after which flow is shut in and the buildup of pressure in the formation is monitored. The rate at which this pressure re-establishes itself after being drawn down is a measure of the native formation permeability, and the presence of a damage zone. The ideal system is a single well in an infinite, homogeneous reservoir containing a fluid with constant properties but with no altered zone around the well. If this well is shut in at the sand face after producing at a rate q for Horner time, th, the sandface pressure at time Dt after shut-in is given by: (4) This equation suggests that a plot of Pw vs. log((th + Δt)/Δt) will be a straight line for circumstances adequately described by the ideal reservoir model. Bulk formation permeability can be obtained from the slope, m, of this straight line by: (5)

Figure 3. Ideal Buildup

Figure 4. Actual Buildup

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Original reservoir pressure, Pi, is obtained by extrapolating the straight line to infinite shut-in time; ie., where (th + Δt)/Δt = 1. (See Figure 3) In an actual buildup or falloff test, it is rare for a straight line to be observed over all shut-in times. Instead, field curves have various shapes, which can be explained with the depth-of-investigation concept. Field curves can logically be divided into three regions, as shown in Figure 4. At early times, the depth of investigation is near the wellbore. Accordingly, conditions in the altered zone (such as formation damage) determine the character of the curve. In addition, continued production into the well (afterflow) because of surface shut-in influences the curve in this region. "After flow" occurs because the compressibility of fluid in the wellbore will permit residual feed in, even after shut in. This effect, which interferes with early time data analysis, can be eliminated or reduced by using bottomhole shut-in equipment. Formation damage is often indicated by the shape of the curve in the region 1. A steeply rising slope suggests a high pressure drop caused by formation damage. A numerical estimate of damage, called the skin factor, "s", is obtainable from this region. Although its calculation is beyond the scope of this text, it is worthwile to gain an appreciation of typical skin factor magnitude. A skin factor of 0 indicates that no damage is present, while positive skin factors are typical of damaged formations. Typically, a skin factor of 5-10 may indicate moderate levels of damage, while factors above 10 indicate severe damage. Very high skin factors, say 30 and above, may sometimes be attributable to ineffective perforation penetration or incomplete perforation of an entire interval. These possibilities should be investigated in cases of high skin factors. Negative skin factors often are indicative of stimulated wells.

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CAUSES OF FORMATION DAMAGE Formation damage implies that hydrocarbon flow through reservoir rock has been impaired. Solids plugging probably is the major cause of damage problems. As a category, solids include native clays & fines, materials precipitated from reservoir fluids (mineral scale, asphalt, paraffin) and solids introduced by drilling mud (barite, bentonite, drilled rock). They can range in size from sub-micron clay particles to perforation- and wellbore-filling scale deposits. Other established causes of damage are emulsion blocking, water blocking, and wettability changes. These conditions adversely affect production through different mechanisms but nevertheless the end result can be as harmful as solids damage. A more recently recognized form of damage occurs as a result of reprecipitation of dissolved material during sandstone acidizing. Clay Disturbance Clays are the fine particles that are probably most often responsible for damage. They can impair permeability in several ways. First, all clays are prone to dispersion and migration when disturbed. Foreign fluid invasion and fluid flow forces are common disturbances which are often blamed for causing clay migration and subsequent plugging of formation pore space. The second widey accepted damage mechanism involves swelling. There is a variety of clay known as smectite (montmorillonite) which can expand to several times its size upon water absorption. This expansion is believed capable of causing blocking of pore spaces, especially if the clays are located at critical pore throats. These clays are also more prone to disperse and migrate when they expand. Consequently, they can restrict pores by a dual mechanism of expansion & migration if disturbed. Clay Swelling Swelling is believed to occur because of an osmotic pressure difference between the bulk fluid and the interlayer region of the clay particle. This theory explains the sensitivity of clays towards brines with salinity sharply lower than connate brine. Water molecules from a less-saline brine will enter a clay structure containing higher salinity brine. This occurs because osmotic forces tend to equilibrate the lower bulk salinity with the higher salinity in the vicinity of the clay layers.

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Figure 5. Osmotic Swelling of Clays Divalent cations such as Ca++ and Mg++ limit clay swelling by holding the clay layers together more tightly. This is also true of K+ and NH4+, monovalent cations which are effective at reducing swelling because they fit well into the clay structure. Regardless of which cation is responsible for stabilizing clays, the effect is reversible. Stabilizing cations can be replaced by re-exposure of clays to sodium, after which the clays are prone to low salinity damage. Clay Dispersion and Migration Clays also reduce permeability by dispersing and migrating. In this case, they can lodge in pore throats, causing blockage. Although this pore blockage occurs on a microscopic scale, the result is a reduction of the bulk rock permeability. Migration can be caused by salinity incompatibility with introduced brine and mechanical forceson particles during fluid flow. Either or both of these causes may be operative at the same time.

Low Salinity Clay Dispersion Abrupt salinity reductions of the clay environment will often cause clay particles to detach from each other and the sand grain surfaces, as shown in Figure 6. Clays in this detached state are free to migrate until they bridge at pore constrictions and reduce fluid flow.

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Figure 6. Low Salinity Causes Clay Dispersion The charge characteristics of clays explain their tendency to disperse upon exposure to low salinity brines. Clays are characterized by a negative surface charge which attracts a diffuse layer of cations such as Na+ and Ca++. This layer of cations experiences two opposing forces which counteract each other. A diffusional force away from the clay surface is counteracted by attractive forces which pull the cations toward the clay surface. The tendency for diffusion increases if the salinity is reduced, causing the layer of ions to expand and exert repulsive forces on nearby particles, as shown in Figure 6. This mechanism is believed to be responsible for dispersing clays, especially if salinity reduction is abrupt. However, evidence has shown that reduction in salinity sometimes will be completely non-damaging if introduced gradually. This suggests that the repulsive forces causing dispersion can be rendered less damaging if they are taken in a stepwise fashion. This observation has important practical implications for workover fluids. If low salinity brine must be used, severe damage can be avoided by exposing the formation to progressively lower brine until the desired strength is attained. Flow Induced Fines Migration The foregoing discussion suggests that dispersion damage can be avoided by the proper choice of fluids introduced to the formation. This is true, up to a point. Clays, as well as other fine particles, can be mobilized by fluid forces exerted by fluid flow, and this problem is more difficult to avoid. As shown in Figure 7, fluid flow velocities increase dramatically towards the near wellbore region, and it is possible to entrain particles from a few feet into the reservoir, particularly in a high rate well.

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Figure 7. High Fluid Velocity near Wellbore Can Cause Fines Migration Effect of Mobile Water Entrainment of fines by fluid flow has been shown to be related to the mobility of the water phase. Clays and silica fines, being generally water-wet, will experience greater fluid forces if the water phase flows. This concept is illustrated in Figure 8, which potrays physical laboratory observations made under a microscope.

Figure 8. Field observations tend to support this concept, since it is generally true that the onset of water production marks the onset of sand production in poorly consolidated fields. Coning, flood breakthrough, and workover fluid leakoff are a few mechanisms by which an irreducible water phase, and hence fines may become mobilized. Page: 11

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Scale Deposition Scale deposition occurs because produced fluids seek to regain equilibrium with the new environment in the wellbore. As a result, solid mineral material, called scale, is often deposited if solubility limits are exceeded under well conditions. Common scales include CaCO3 (calcite), CaSO4 . 2H2O (gypsum), and BaSO4 (barite). Calcite scales are generally deposited as a result of pressure drop and CO2 gas evolution from produced brine, according to the equation: Ca++ + 2HCO3 ⇒ CO2 (gas) + CaCO3 + H2O Deposition may occur in the perforations or tubing, depending on flow conditions. The above equation also implies that calcite scale can form if a natural brine rich in HCO3 is exposed to a Ca++ brine. This is also an established damage mechanism. Calcite scales are very soluble in ordinary acids, so their removal is generally straightforward. Scales such as CaSO4 and BaSO4 are deposited as a result of temperature and pressure drops which the produced fluids experience. Although these scales can be deposited in the perforations or tubing, they usually occur in the tubing. Both of these scales are insoluble in acids . Water Blocking

Figure 9. Relative Permeability Curves Page: 12

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Water blocking refers to the condition in which a higher water saturation impedes the flow of hydrocarbons within pore spaces. Water blocking is a relative permeability effect, and can be explained with the aid of Figure 9, which describes the effect of the presence of two immiscible fluids on each other's permeability. On each vertical axis is the permeability of each phase in the absence of the other. For fluids which don't interact with the formation, these permeabilities are the same for both phases. The relative permeability curve also shows how the presence of a second phase will reduce the permeability of the first. Increasing water saturation has the effect of progressively reducing oil permeability. Water blocks may occur as a result of coning or fingering of water from another zone, or temporary loss of workover fluid. Acid jobs tend to leave small temporary water blocks, which explains why restoring production often involves a short cleanup period during which the spent acid is recovered.

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DAMAGE REMOVAL Damage removal is a general term given to treatment designed to remove the effects of damage. Some treatments remove the damage while others overcome its effects without actually removing it. There are many techniques available for removing wellbore damage, depending upon the type of formation and the type of damage. Most treatments fall into the general categories of wellbore treatments, matrix treatments and hydraulic fracturing. Acid Washing Acid washing is an operation designed to remove acid soluble scales present in the wellbore or to open perforations. It involves the spotting of a small quantity of acid at the desired position in the wellbore and allowing it to react, without external agitation, with scale deposits on the formation. Alternatively, the acid may be circulated back and forth across the perforations or formation face. Circulation may accelerate the dissolution process by increasing the transfer rate of unspent acid to the rock surface. Matrix Acidizing Matrix acidizing is defined as the injection of acid into the formation porosity (intergrannular, vugulor, or fracture) at a pressure below the fracturing pressure. The goal of the treatment is to achieve radial acid penetration into the formation. Stimulation is usually accomplished by removing the effect of formation damage by enlarging the pore spaces, dissolving the particles plugging these spaces or bypassing the damage. Solvents & Surfactants Damage attributable to emulsions, water blocks, wettability changes, and organic deposits is usually treated with surfactants and organic solvents. Surfactants are surfaceactive molecules which can break emulsions, reduce water blocks and restore wettability if properly chosen and applied. Organic solvents are used to dissolve asphalt and paraffin deposits. Hydraulic Fracturing Hydraulic fracturing involves generating a fracture within hydrocarbon formations and rendering the crack conductive, either by propping it open with sand or by etching it with acid, if it is in a carbonate. These treatments usually are done to effect reservoir stimulation by partially overcoming naturally low permeability. However, fracturing is occasionally used to bypass formation damage. Hydraulic fracturing is covered in detail in Reference (2). Page: 14

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TABLE OF CONTENTS CARBONATE MINERALS ........................................................................................15 Calcite ..................................................................................................................15 Dolomite ..............................................................................................................15 Occurrence in Nature ...........................................................................................15 Natural Fractures..................................................................................................15 Vugs .....................................................................................................................15 ACID TYPES ................................................................................................................17 Mineral Acids ......................................................................................................17 Hydrochloric Acid ...................................................................................17 Hydrochloric-Hydrofluoric Acid .............................................................18 Organic Acids ......................................................................................................18 Acetic Acid ..............................................................................................18 Formic Acid .............................................................................................18 Retarded Acid Systems ........................................................................................19 Gelled Acids ............................................................................................19 Chemically Retarded Acids .....................................................................19 Emulsified Acids......................................................................................19 ACID REACTIONS WITH CARBONATES...........................................................20 ACID TYPES AND THE CHEMISTRY OF THEIR REACTIONS.................20 Dissolving Power .................................................................................................21 ACID STRENGTH .......................................................................................................24 Organic Acid Limitation ......................................................................................24 ACID ATTACK ON CARBONATES.......................................................................26 Reaction Time......................................................................................................26 Temperature and Pressure Effects .......................................................................26 Carbonate Mineral Type Effect ...........................................................................26 Wormhole Formation...........................................................................................26 Wormhole Properties ...........................................................................................27 Fluid Loss Control ...............................................................................................28 Effect of HCL on Cement ....................................................................................28

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ACID ADDITIVES .......................................................................................................29 Corrosion Inhibitors.............................................................................................29 Surfactants ...........................................................................................................30 Antisludge Agents................................................................................................31 Mutual Solvents ...................................................................................................31 Friction Reducers .................................................................................................31 Sequestering Agents ............................................................................................31 TREATMENT DESIGN ..............................................................................................33 Preflush ................................................................................................................33 Type of Acid and Volume....................................................................................33 Acid Displacement...............................................................................................33 Maximum Injection Pressure ...............................................................................33 Injection Rate .......................................................................................................34 Safety Considerations ..........................................................................................34 Acid Quality Control ...........................................................................................35 Bullheading ..........................................................................................................35 Concentric Tubing ...............................................................................................35 Establishing Injectivity ........................................................................................35 Monitoring Treating Pressures.............................................................................36 Spent Acid Recovery ...........................................................................................36

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CARBONATE MINERALS: Calcite: Calcite is the most common carbonate mineral in nature. The chemical composition of pure calcite is calcium carbonate, CaCO3, which has a hexagonal crystal structure. A reservoir containing primarily crystalline CaCO3 is called a limestone reservoir. If the CaCO3 is fine-grained and powdery, it is called a chalk. Calcite is also found as a component of sandstone and marl. Marl is a poorly consolidated mixture of carbonates, clays, and shell remnants. Dolomite: The chemical composition of pure dolomite is calcium magnesium carbonate, CaMg(CO3)2. The crystal structure of dolomite is hexagonal. Dolomite is generally believed to be formed from calcite by replacement of some of the Ca ions by Mg. However, dolomite can also form directly from water solution. As was the case with calcite, dolomite is also found as a component of sandstone and marl. But as a reservoir rock, dolomite is not as common as calcite. Occurrence in Nature: In nature, a pure calcite or dolomite reservoir is uncommon. This is a consequence of the origin of the reservoir and the changes that can occur over geologic time. A carbonate reservoir can be created by chemical and biochemical precipitation in a water environment or by transportation of clastic grains. Over time, some calcite can be converted to dolomite in a process referred to as dolomitization. Thus, the two carbonate minerals are often intermingled and interbedded with one another. Siliceous components, for example quartz, chert, and shales may also be found in a carbonate reservoir. However, in most cases, the siliceous components are a minor component of the rock. Natural Fractures: Natural fractures are microcracks in carbonate minerals that occur naturally due to earth stresses. These fractures can have a pronounced influence on the response to acid by directing the flow down the fracture. for example, if a natural fracture intercepts the wellbore, it will probably accept most of the acid. It is also possible that a more reactive mineral is formed as a secondary deposit in the natural fracture. In this case, the mineral in the fracture will be preferentially dissolved. Vugs: A vug is a cavity in a carbonate mineral that is usually created by a dissolution process during the burial history. This leaves a void in the carbonate mineral that is visible to the

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unaided eye. In comparison with natural fractures, vugs are generally larger in diameter and much shorter in length. The vugs in a carbonate mineral direct the initial flow of acid in a manner similar to fractures. Thus, the presence of vugs can also affect the response to an acid treatment.

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ACID TYPES: Acid systems in current use can be classified as mineral acids, organic acids and retarded acids systems. The most common members of each category are as follows: - Mineral Acids Hydrochloric acid Hydrochloric-hydrofluoric acid - Organic Acids Acetic acid Formic acid - Retarded Acids Gelled acids Chemically retarded acids Emulsified acids All these acids except hydrochloric-hydrofluoric acid, are used to stimulate carbonate formations. Mineral Acids Hydrochloric Acid: Most acid treatments in carbonate formations use hydrochloric acid. Usually it is used as a 15% (by weight) solution of hydrogen chloride gas in water. With the development of improved inhibitors, higher concentrations (up to 31%) have became practical and, in some cases, more effective. Acid concentrations lower than 15% are also available and are used where the acid dissolving power is not the only consideration. An example of such an application is found in sandstone acidizing where 5 to 7.5% HCl is used to displace salt water ahead of HCl-HF acid to prevent the formation sodium and potassium fluosilicates which are capable of plugging the formation. The main advantages of HCl is its moderate cost, complete spending at reservoir conditions and its soluble reaction products (calcium chloride and carbon dioxide). The principal disadvantage of HCl acid is its high corrosivity on wellbore tubular goods. This high corrosivity is high to control at temperatures above 250 oF. Also aluminium or chromium plated metals, often found in pumps are easily damaged.

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Hydrochloric-Hydrofluoric Acid: This acid mixture is used almost exclusively for sandstone stimulation. Within the chemical industry, hydrofluoric acid (HF) is available commercially as a relatively pure material in anhydrous form or as a concentrated (40 to 70 percent) aqueous solution. As it is used in the petroleum industry for well stimulation, HF is most often a dilute solution in hydrochloric acid (HCl). It may be formed from dilution of concentrated solutions of hydrogen fluoride or, more frequently, from the reaction of ammonium bifluoride with hydrochloric acid. Often, 15-percent HCl is used, and enough ammonium bifluoride is added to create a solution containing 3-percent HF. Consumption of hydrogen chloride by this reaction leaves 12-percent HCl remaining in solution. Similarly, 6-percent HF is often generated from 15-percent HCl solutions and the final hydrochloric acid concentration is approximately 9 percent. The corrosion characteristics of the HF-HCl mixture are comparable with those of HCl alone, and similar corrosion inhibitors are required. Organic Acids The principal virtues of the organic acids are their lower corrosivity and easier inhibition at high temperatures. They have been used primarily in operations requiring a long acidpipe contact time, such as a perforating fluid, or where aluminium or chrome-plated parts unavoidable will be contacted. Although many organic acids are readily available, only two, acetic and formic, are used to any great extent in well stimulation. Acetic Acid: Acetic acid was the first of the organic acids to be used in appreciable volumes in well stimulation. It is commonly available as a 10-weight-percent solution of acetic acid in water. At this concentration, the products of reaction (calcium and magnesium acetates) are generally soluble in spent acid. The main disadvantage of acetic acid is its increased cost and low dissolving power due to equilibrium limitations. Formic Acid: Of the organic acids used in acidization, formic acid has the lowest molecular weight and, correspondingly, the lowest cost per volume of rock dissolved. It is substantially stronger than acetic acid, though appreciably weaker than hydrochloric acid. Like acetic acid, it reacts to an equilibrium concentration in the presence of its reaction products.

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The principal advantage of formic over acetic acid is cost, although this is partially offset by the greater difficulty of inhibiting corrosion with this acid. Although more corrosive that acetic acid, formic acid corrodes uniformly and with less pitting than hydrochloric acid, and effective inhibitors are available for its use at temperatures as high as 400 oF. Retarded Acid Systems The acid reaction rate theoretically can be retarded by gelling the acid, oil-wetting the formation solids, or emulsifying the acid with an oil. Gelled Acids: Gelled acids are used to retard acid reaction rate in fracturing treatments. Retardation results because the increased fluid viscosity reduces the rate of acid transfer to the fracture wall. Use of the gelling agents (normally water-soluble polymers) is limited to low-temperature formations because most of the available agents degrade rapidly in acid solution at temperatures exceeding about 130 oF. When more stable polymers are developed, they should find application in acid fracturing. Gelling agents are seldom used in matrix acidization because the increased acid viscosity reduces injectivity of the acid and often prolongs the treatment needlessly. Chemically Retarded Acids: These acids are often prepared by adding an oil-wetting surfactant to acid in an effort to create a physical barrier to acid transfer to the rock surface. To function, the additive must adsorb on the rock surface and form a coherent film. Use of these acids often requires continuous injection of oil during the treatment. At high flow rates and high formation temperatures, adsorption is diminished and most of these materials become ineffective. Emulsified Acids: Emulsified acids may contain the acid as either the internal of the external phase. The former, which is more common, normally contains 10 to 30 percent hydrocarbon as the external phase and regular hydrochloric acid as the internal phase. When acid is the external phase, the ratio of oil to acid is often about 2:1. Both the higher viscosity created by emulsification and the presence of the oil can retard the rate of acid transfer to the rock. This reduction in transfer rate, and its corresponding reduction in acid reaction rate, often can increase the depth of acid penetration. Use of oil-external emulsified acids is occasionally limited by the increased frictional resistance to flow of these fluids down well tubulars.

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ACID REACTIONS WITH CARBONATES: The acids commonly used to treat carbonate formations are HCl, formic and acetic acids. These acids all react with carbonates to form carbon dioxide (CO2), water, and a calcium or magnesium salt. Typical reaction are ⎯ ⎯→ 2HCl + CaCO 3 ← ⎯⎯ CaCl 2 + H 2 O + CO 2

(1)

and

⎯ ⎯→ 4HCl + CaMg(CO 3) 2 ← (2) ⎯⎯ CaCl 2 + MgCl 2 + 2H 2 O + 2CO 2 These equations indicate the stoichiometry of the reaction. For example, equation 1 indicates that 2 moles of hydrochloric acid (HCl) react with 1 mole of limestone (calcium carbonate, CaCO3) to create 1 mole of calcium chloride (CaCl2), 1 mole of water (H2O), and 1 mole of carbon dioxide (CO2). ACID TYPES AND THE CHEMISTRY OF THEIR REACTIONS: The numbers multiplying the moles of the component required in the reaction (for example, ''2''HCl) are known as stoichiometric coefficients. Combining Eq. 1 with molecular weight data for each component (given in Table 1) allows calculation of the amount of acid required to dissolve a given quantity of a carbonate, the quantity of reaction products produced by the reaction, or other stochiometric data. Table 1 - Molecular weight of components in HCl reaction with Carbonates Compound Hydrochloric acid Calcium carbonate (limestone) Calcium magnesium carbonate (dolomite) Calcium chloride Magnesium chloride Carbon dioxide Water

Chemical Formula

Molecular Weight

HCl CaCO3

36.47 100.09

CaMg(CO3)2

184.30

CaCl2 MgCl2 CO2 H2O

110.99 95.30 44.01 18.02

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Dissolving Power: The concept of acid dissolving power (expressed as volume of rock dissolved per unit volume of acid reacted) is a useful quantity because it allows a direct comparison of acid costs. Dissolving power is easily calculated for any reaction of interest: First, define β to be the mass of rock dissolved per unit mass of acid reacted. Therefore, β =

molecular weight of mineral (rock) × its stoichiometric coefficient molecular weight of acid × its stoichiometric coefficient

(3)

For the reaction of 100-percent hydrochloric acid with pure limestone, defined by Eq. 1, the dissolving power is β100 =

100.09 × 1 gm limestone dissolved = 1.372 36.47 × 2 gm 100 - percent HCl reacted

(4)

If the acid concentration is 15 percent by weight rather than 100 percent, then β15 = β100 × 0.15 = 0.206

gm limestone dissolved gm 15 - percent HCL reacted

(5)

The dissolving power, which is the volume of rock dissolved per volume of acid reacted (defined as X) can be obtained from Eq. 5 by multiplying the mass ratio by the appropriate density ratio. Note that the porosity of the rock is not included in this calculation. For 15-weight-percent HCl, this calculation gives X15 =

ρ15 - percent HCl β15 - percent HCL ρCaCO 3

(6)

where ρ15 − percent HCl HCl is the density of a 15-percent-HCl solution (1.07 gm/cc) and ρCaCO 3 is the density of calcium carbonate (2.71 gm/cc). The specific gravity data for HCl solutions are given in Table 2. Substituting into Eq. 6 gives

X15 =

cc limestone dissolved 1.07(0.206) = 0.082 cc 15 - percent HCl reacted 2.71

(7)

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Table 2 - Specific gravity of aqueous hydrochloric acid solutions (at 20 oC) Percent HCl 1 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40

Specific Gravity 1.0032 1.0082 1.0181 1.0279 1.0376 1.0474 1.0574 1.0675 1.0776 1.0878 1.0980 1.1083 1.1187 1.1290 1.1392 1.1493 1.1593 1.1691 1.1789 1.1885 1.1980

Gradient, psi/ft 0.434 0.436 0.441 0.445 0.449 0.453 0.458 0.462 0.466 0.471 0.475 0.480 0.484 0.488 0.493 0.498 0.502 0.506 0.510 0.515 0.519

Although the volume units shown in Eq. 7 are cubic centimeters, this volumetric ratio is independent of units, and any consistent set of volumetric units may be used. Values for the dissolving power are given in Table 3 for hydrochloric acid and the commonly used organic acids. Data are included for several acid concentrations and for both limestone and dolomite formations. Table 3 is useful when comparing one acid with another. In general, HCl has the largest dissolving power, followed by formic acid and then acetic acid. The numbers presented in this table do not take into account limitations that may be imposed by chemical equilibrium. Typically, in field treatments, organic acids do not react completely, so a given volume of the acid will dissolve less rock than is indicated in Table 3. To correct the dissolving power, it must be multiplied by the fraction of acid that reacts before equilibrium at reaction condition is reached.

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X⊗ 10 Percent

15 Percent

30 Percent

Limestone (CaCO3, calcite: ρCaCO 3 = 2.71 gm/cc) Hydrochloric acid (HCl) 1.37 0.026 Formic (HCOOH) 1.09 0.020 Acetic (CH3COOH) 0.83 0.016

0.053 0.041 0.031

0.082 0.062 0.047

0.175 0.129 0.096

Dolomite [CaMg(CO3)2: ρCaMg ( CO 3 ) 2 = 2.87 gm/cc Hydrochloric 1.27 0.023 Formic 1.00 0.018 Acetic 0.77 0.014

0.046 0.036 0.027

0.071 0.054 0.041

0.152 0.112 0.083

β100 **

5 Percent

* Data for organic acids have not been corrected for equilibrium. mass rock dissolved ** β100 = mass pure acid reacted volume rock dissolved ⊗ X = volume acid solution reacted

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ACID STRENGTH When an acid is placed in water, it dissociates (ionizes) by the generalized reaction: ⎯ ⎯→ + HA ← ⎯⎯ H + A

(8)

In equation 1, the acid is denoted HA and the ionized species in the water are H+ and A-. For example, HCl acid ionizes to produce hydrogen ions (H+) and chloride ions (Cl-). Equilibrium is rapidly attained when an acid is added to water. At equilibrium, there is no net change in the concentration of HA, H+, or A-. it is convenient to define an equilibrium constant that can be used to determine the concentration of HA, H+, and Aat a given temperature. The equilibrium constant for an acid dissociation is called a dissociation constant (KD) and given by: [H + ] [A - ] (9) KD = [HA ] If KD is large, the acid is strong and will dissociate completely; if KD is small, the acid is weak and will only partially dissociate. A weak acid is not as effective for dissolving carbonates. The dissociation constants for three common acids used for carbonate acidizing are given in Table 4. Note that the values of KD are a function of temperature and that HCl is much stronger than acetic and formic acid, making it more effective for reaction with carbonates. Table 4. Dissociation Constants of Acids

Acid

77 oF

150 oF

250 oF

HCl Formic (HCO2H) Acetic (CH3CO2H)

~ 103 1.8 X 10-4 1.8 X 10-5

~ 103 1.5 X 10-4 1.5 X 10-5

~ 103 7.7 X 10-5 8.2 X 10-6

Organic Acid Limitation: Since HCl is a strong acid, it reacts essentially to completion with carbonates, until it is spent. In comparison, the weaker organic acids (formic and acetic) that have smaller

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dissociation constants do not react to completion at reservoir conditions because a state of equilibrium develops. Equilibrium occurs because CO2 (one reaction product) is held in solution by the reservoir pressure and not allowed to escape from solution. At low pressure, the CO2 can escape and even the weak acids will react to completion. Results of tests relating the fraction of acid reacted to the temperature and acid composition at 1500 psi are given in Figures 1 and 2. The values expressing the fraction reacting can be used to approximate the reduction in dissolving power of formic and acetic acid. For example, Figure 1 shows that at 150 oF and 1500 psi, only about 50% of a 10 wt% acetic acid solution will react. Thus, the dissolving power of the acid must be reduced by 50%.

Fig. 1. Fraction of acetic acid reacted vs. temperature at 1500 psi.

Fig. 2. Fraction of formic acid reacted vs. temperature at 1500 psi.

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ACID ATTACK ON CARBONATES: Reaction Time: The reaction of a carbonate mineral with acid is very rapid, occurring as soon as live acid contacts the mineral surface. We can conceptually divide the reaction into reaction into three steps:

(1) Live acid transport to the carbonate mineral surface. (2) Acid dissolution of the carbonate mineral. (3) Reaction product transport away from the surface. The slowest step in the reaction is the first step. This step controls the overall reaction time or rate. A heterogeneous reaction of this type is called mass-transfer limited and is controlled by live acid diffusing to the carbonate mineral surface. However, at reservoir conditions, the acid diffusion is rapid, so the reaction is essentially instantaneous. Temperature and Pressure Effects: An increase in temperature results in more rapid diffusion and an overall faster reaction time. However, this effect is only of secondary importance since the reaction is already very fast. The effect of pressure on the reaction time is minimal and can be neglected. Keep in mind that pressure does limit complete spending of the weaker organic acids. Carbonate Mineral Type Effect: The effect of mineral type on the acid attack of carbonates is also of secondary importance. At low temperature (77 oF), it has been shown in the laboratory that calcite reacts faster with HCl acid than dolomite. However, at typical formation temperatures (200 oF), the rate of reaction of both carbonates is controlled by the diffusion of live acid (step number 1) from the bulk solution to the carbonate mineral surface. Wormhole Formation: When an acid is pumped into a carbonate reservoir at pressures below the fracture pressure (matrix rates), acid flows preferentially into the highest permeability regions, which may include natural fractures and vugs. The fast acid reaction in the higher permeability regions favours the formation of flow channels called wormholes. Representative wormhole patterns in carbonate minerals are schematically shown in figures 3 and 4.

Wormhole Properties:

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The rate of fluid loss from the wormhole to the formation will control the length, diameter, and number of wormholes. A high fluid loss acid tends to generate a few wormholes that are short and larger in diameter. This is illustrated in Figure 3. A lower fluid loss acid tends to generate more wormholes that are longer with a smaller diameter. This case is illustrated in Figure 4.

Fig. 3. Representative wormholes for a fast reaction time - high fluid loss case.

Fig. 4. Representative wormholes for a slow reaction time - lower fluid loss case.

Acids normally used in field treatments are highly reactive and tend to form only a limited number of wormholes. This assertion is substantiated by both laboratory tests with HCl acid and theoretical models. In laboratory tests with HCl acid, reaction is usually characterized by the formation of a single wormhole. Although several large pores will form initially at the acid injection face, continued pumping results in enlargement of fewer pores, until ultimately only one channel is accepting most of the acid. Theory also predicts that only a few wormholes will form due to the rapid reaction and fluid loss rate of HCl acid. In the zero fluid loss limit (a hypothetical case), wormholes up to about 100 feet are possible. In reality, wormholes of a few inches to a few feet are formed. The shorter wormholes would be more likely in a higher permeability carbonate (100 md) and the longer wormholes are more likely in lower permeability carbonate (1 md).

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Fluid Loss Control: To control wormhole properties, several methods of fluid loss control have been attempted. These include: • • • • •

particulate fluid loss agents acid viscosifiers emulsified acids foamed acids retarded acids

Of these five techniques, only acid viscosifiers and emulsified acids have proven somewhat effective. Particulates are not generally effective, because rapid carbonate dissolution prevents the formation of an impermeable filter cake. Foamed acids provide some fluid loss control, but suffer from a reduced dissolving power. The so-called retarded acids are not retarded at reservoir conditions and provide no benefit for fluid loss control. Because of the practical difficulties and questionable benefit of acid fluid loss control for matrix stimulation, fluid loss agents are seldom used in routine jobs. Fluid loss additives are not used in matrix treatments in Saudi Aramco. Effect of HCl on Cement: Tests were conducted at EPR under simulated downhole conditions to determine the effect of HCl acid on the wellbore integrity. The following conclusions were reached: •

Cement is not severely attacked by HCl acid in normal acidizing conditions.

•

The cement-casing bond is not weakened by HCl acid.

•

Mud channels may be broken down by HCl acid. This is a mechanical failure of the mud channel, not a dissolution of bypassed mud solids.

•

The cement-formation bond in a carbonate formation can be weakened due to the rapid dissolution of carbonates in acid.

The breakdown of a mud channel or the attack of the cement-formation bond may result in an increased water cut of a higher GOR after carbonate acidizing if these zones are nearby. However, before concluding that the problem was caused by the acid job, the engineer should confirm that the job was pumped at matrix rates to ensure that a fracture was not generated.

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ACID ADDITIVES: Corrosion Inhibitors Corrosion inhibitors are chemicals that adhere to metal surfaces and form a protective barrier between metal and acid. The barrier slows down the metal corrosion rather than stops it .

There are many factors that influence the corrosion rate. The major factors are: 1. Amount of Agitation - An increase in agitation increases corrosion rate. Static tests make the performance of the inhibitor appear more favourable than it is likely to be when acid is pumped through tubular goods. 2. Metal Type - The effect of metal is significant. It is essential when testing inhibitors that coupons tested be from a representative sample of the tubular goods to be protected. 3. Exposure Time - Corrosion rate increases with exposure time. Graphs showing effect of exposure time on corrosion can be obtained from service companies. 4. Temperature - Increasing the temperature increases the acid corrosion rate. This is a consequence of inhibitor desorption and more rapid diffusion of the acid through the inhibitor film. In addition, some organic inhibitors decompose at temperatures higher than 250 oF thereby losing their ability to protect the metal. 5. Acid Type and Concentration - Concentrated (30%) HCl is more corrosive than 15% HCl. Organic acids (acetic and formic acids) are less corrosive than HCl. Inhibitor concentrations needed to provide protection against corrosion can be obtained from service companies.

The selection of inhibitor type and concentration can be done only after specification of the following treating and well conditions: 1. 2. 3. 4.

type and concentration of acid, type of tubular goods to be exposed, maximum pipe temperature and duration of acid-pipe contact.

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Generally, with these factors specified, service company information can be used to determine the inhibitor requirements needed to provide the required level of protection. Most service company information is based on the assumption that a metal loss of 0.02 lb/sq ft. of area can be tolerated during a treatment if no pitting occurs. Sometimes a figure as high as 0.05 lb/sq ft is assumed allowable. Corrosion inhibitors that are used by Saudi Aramco are shown in table 5.

Table 5.

Corrosion Inhibitors used by Saudi Aramco

Inhibitor

Service Company

Recommended Use

HAI-85

Halliburton

Organic inhibitor used with 15% - 28% HCl and HF-HCl mud acid to 250 oF. Will give adequate protection to 400 oF when mixed with HII-124 intensifier.

MSA

Halliburton

Effective upto 400 oF in acetic and formic acids.

A-260

Dowell

Organic inhibitor used with HCl and mud acid upto 300 oF. Gives adequate protection to 350 oF when mixed with inhibitor aid A-201.

A-166

Dowell

Nitrogeneous and acetylenic organic compounds. Used in gelled acid and to remove scale in tubing, wellhead and surface facilities upto 250 oF.

Surfactants Surface active agents are used in acid treating to demulsify acid and oil, to reduce interfacial tension, to alter formation wettability, to speed cleanup, and to prevent sludge formation. Caution should be exercised when adding surfactants to be sure that they are compatible with the corrosion inhibitor and other additives.

A demulsifying agent often is used in carbonate limestone acidizing treatments to prevent emulsion formation between the acid and formation crude oil. Surfactants should be compatible with the formation fluids and should not adversely wet the reservoir rock.

Antisludge Agents

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Antisludge agents appear to be required for effective acid treatment in fields containing heavy asphaltic oils. The sludges formed when these oils contact acid can plug the formation and restrict production after treatment. This problem can sometimes, but not always, be reduced by adding surface active chemicals such as alkyl phenols, fatty acids and certain oil-soluble surfactants to the acid. The need for, and the specific antisludge agent to be used, generally must be determined in laboratory tests with the crude oil and acid system to be employed. An alternative to the use of antisludging agent is a diesel spacer ahead of the acid. Also a demulsifier or surfactant may function as an antisludging agent. Mutual Solvents Mutual solvents are materials that have appreciable solubility in both oil and water. Many chemicals, including alcohols, aldehydes, ketones, ethers and others have this property. In oilfield applications, the term "mutual solvent" is normally used to describe a glycol ether. The glycol ether most frequently used in sandstone acidizing is ehthylene glycol monobutyl ether (EGMBE). EGMBE, in addition to its mutual solubility, reduces interfacial tension between oil and water, acts as a solvent for solubilizing oil in water, acts as a detergent capable of removing oil-wetting materials from surfaces that otherwise would be water-wet, and finally, improves the action of surfactants and emulsifiers in contact with formation materials. If a mutual solvent is used in carbonate acidizing, it is recommended that EGMBE (Corexit 7610) be added at 10% by volume to the acid. Friction Reducers Friction reducers are chemicals that when dissolved in fluids reduce the fluid's frictional drop through well tubing. Friction reducers are used to minimize the horsepower required to pump at a specified rate or maximize the pumping rate at a given horsepower. Friction reducers are organic polymers that convert the fluid from a Newtonain fluid to a nonNewtonian fluid (viscosity varies with shear rate). The friction reducer that is available in Saudi Aramco is FR-20. The addition of 4 lbs of FR-20 per 1000 gals of acid will give about threefold reduction in pressure drop in 2-3/8" or 2-7/8" tubings. Sequestering Agents Sequestering or complexing agents are chemicals that prevent precipitation by binding up metal ions, which keeps them soluble even in spent acid. The metal that is believed to be the major problem is iron (Fe). Possible sources of iron are: • •

Corrosion of tubulars with acid Dissolution of iron and mill scales

•

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The precipitation of iron depends on the iron concentration, pH, and oxidation state of the iron. The oxidation state of iron can be Fe(II) (ferrous) or Fe(III) (ferric). The Fe(II) is not a problem since it precipitates around pH ~ 6 and the acid only spends to pH ~ 4. The Fe(III) precipitates as iron hydroxide around pH ~ 2. Precipitation of ferric iron during carbonate acidizing is by no means a common problem. In the presence of iron pipe, most Fe(III) is converted to Fe(II). In addition, the majority of corrosion scales are Fe(II) and in carbonate formation there is little if any Fe(III). For these reasons, an iron sequestering agent should only be considered for water injection wells where corrosion control has been inadequate. Some of the common iron sequestrants on the market include citric, lactic, acetic and gluconic acid. Derivatives of these basic acids include ethylene-diamine-tetraacetic acid (EDTA) and nitrilo-triacetic acid (NTA). Each of these sequesterants has certain advantages and limitations. The primary limitations are low solubility, precipitation of reaction products, or high temperature instability. Both cost and performance vary widely.

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TREATMENT DESIGN

The objective of matrix acid treatment in a carbonate formation is to remove the effect of damage and restore flow. This can be accomplished by dissolving the particulate material plugging the formation (if it is soluble in acid) and by creating wormholes that bypass the damage. For a successful treatment, the engineer should assess the well condition and make sure the well is damaged. Then he should specify the type and volume of acid, acid additives, spacers and diverters. Calculations should be made to determine the maximum surface pumping pressure to avoid fracturing the formation Preflush A tubing volume of diesel spacer is normally injected ahead of the acid to prevent any known adverse interactions between the acid and the crude in the formation. Diesel should not be used in gas and water wells to avoid the introduction of a second phase. Type of Acid and Volume HCl acid is normally used for acidizing carbonate formations. A corrosion inhibitor must be mixed with the acid. The acid concentrations most frequently used are 15% and 28% HCl. Acid volumes depend on the type of formation and severity of the damage. Typical volumes range from 50 to 150 gals per foot of formation or perforated interval. Acid Displacement All the acid must be displaced into the formation. The displacing fluid can be clean (nondamaging) water, brine or diesel. In gas and water wells only water and brine should be used. Maximum Injection Pressure The maximum surface pumping pressure should be lower than the formation fracture pressure. The fracture gradient can be estimated from the equation P G ≅ α + (1 - α ) (10) D α P D G

= = = =

constant (0.3 to 0.5) reservoir pressure, psi depth, ft fracture gradient, psi/ft

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The fracture pressure is calculated from the equation P max = (G - ρ × 0.43)D

(11)

where ρ is the specific gravity of the acid. During the treatment the acid should be pumped at maximum rate while maintaining the injection pressure below the fracture pressure. Injection Rate The maximum injection rate without fracturing the formation can be estimated from Darcy's equation, 4.917X10 -6 kave h( P max − P) qmax = (12) ⎛ re ⎞ μ ln ⎜ ⎟ ⎝ rw ⎠

where, qmax = kave = h = μ = re = rw = P max = P =

rate in BPM average permeability of damaged formation, md perforated interval, ft viscosity of the acid, cp drainage radius, ft wellbore radius, ft maximum injection pressure at perforations, psi static reservoir pressure, psi

The injection rate to avoid fracturing the formation should be less than qmax or the maximum rate at an injection pressure less than P max .

Safety Considerations Safety should be a primary concern when pumping acid at high pressure. Many operators require that a safety meeting be held before beginning a job. At this time, the design of the job can be reviewed so that all personnel know the job procedure. When pressure testing lines, personnel should be located in a safe place. Those that have to be near the wellhead or high pressure lines during pumping should wear proper head, eye and body protection equipment.

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Acid quality control In most cases, acid is mixed in the service company yard and is not a responsibility of the Production or Workover engineer. For premixed acid, the engineer witnessing the acid job can check the specific gravity of the acid on-site with a hydrometer to ensure that the correct strength acid is delivered. Knowledge of the specific gravity is especially important if buoyant ball sealers are being used for diversion. Before measuring the specific gravity, it is good practice to circulate the acid in the tanks two or three times. This ensures that all additives, especially dispersible corrosion inhibitors, are uniformly distributed in the acid. Often times, the inhibitors can float to top of the tank, resulting in inaccurate specific gravity readings or corrosion problems. The engineer should collect a sample of the acid and forward it to the laboratory for acid strength measurement. Bullheading Pumping the treatment directly down the tubing, or bullheading, is one of the least expensive methods of treatment implementation. The primary disadvantage of bullheading is that all wellbore fluids and any debris will be injected into the formation ahead of the acid. Since acid cannot be spotted across the carbonate interval, establishing injectivity may also be more difficult. Spent acid recovery may also be more difficult with a bullheaded job since nitrogen cannot be injected downhole to reduce the fluid hydrostatic head. Concentric Tubing The use of concentric tubing, including coiled tubing or a workstring, is generally more expensive, but has advantages over bullheading the treatment. The advantages include: • • • •

wellbore fluids and debris are not injected acid can be spotted across entire interval better fluid control is attained acid recovery is facilitated

If the location, depth and economics of the job are not restrictive, the use of either coiled tubing or a workstring is recommended over bullheading. Establishing Injectivity Establishing injectivity can be a problem in severely damaged wells. In cases where there is no injectivity, fracture pressure can be temporarily exceeded and then reduced when acid hits the formation. In carbonate formations, acid should break down the formation soon after the acid reaches bottom hole. Thereafter, the treatment should be performed at matrix rates.

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Monitoring Treating Pressures To ensure that fracture pressure is not exceeded, the engineer should monitor treating pressure throughout the job. Most service companies have a permanent record of the surface pressure on a chart recorder. Significant events to note are the breakdown of the formation due to acid attack, the "ball action" if ball sealers are used for diversion, or the pressure response to other diverting agents. A large drop in surface pressure that suddenly occurs may indicate that the formation was inadvertently fractured.

Spent Acid Recovery In carbonate acidizing, the acid should return spent provided that it was properly displaced into the formation. No shut-in time is required for spending since the reaction is very fast. A shut-in time will not result in precipitation damage, but corrosion may continue to occur if the acid was not displaced.

The return of live acid to the surface is an indication that part of the acid was not properly injected. Live acid can also remain in the rathole and result in corrosion problems. It is good practice to record the volume of recovered fluid and compare this volume to the fluid pumped. If formation water is not being produced back with the spent acid, the volume will give an indication of the well clean-up time. If a production well will not unload, some form of temporary artificial lift must be used. If nitrogen is on-site with a concentric tubing, the N2 can be used to jet-out the wellbore. Acid should not be recovered from an injection well. In this case, the displacement fluid can be the injection water. The well can be returned to injection immediately following the job.

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TABLE OF CONTENTS DESCRIPTION OF TREATMENT ..........................................................................37 SANDSTONE COMPOSITION..................................................................................39 Silica ....................................................................................................................39 Feldspars ..............................................................................................................39 Clays ....................................................................................................................39 Carbonates ...........................................................................................................40 ACID SANDSTONE REACTIONS ...........................................................................41 HF Acid................................................................................................................41 Dissolution Reactions ..........................................................................................41 Silica (quartz)...........................................................................................41 Feldspar (albite) .......................................................................................42 Clay (kaolinite) ........................................................................................42 Precipitation Reactions ........................................................................................42 Fluosilicates .............................................................................................42 Hydrated Silica ........................................................................................43 Calcium Fluoride .....................................................................................44 MECHANISM OF ACID ATTACK ............................................................................45 Damage Induced by Acid.....................................................................................45 Effect of HF Concentration..................................................................................46 Effect of Acid Injection Rate ...............................................................................46 Effect of Matrix Composition..............................................................................47 Effect of HF-HCL Reaction on Core Mechanical Properties ..............................47 Prediction of Radius of Acid Reaction ................................................................48 TREATMENT DESIGN ..............................................................................................50 Required Data ......................................................................................................50 Completion Data ......................................................................................50 Formation Data ........................................................................................50 Types of Fluids ........................................................................................51 Preflush ........................................................................................51 HF/HCL .......................................................................................51 Afterflush .....................................................................................52 Injection Pressure.....................................................................................52 Example Design Calculations ..............................................................................53

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FIELD IMPLEMENTATION .....................................................................................57 Well Condition.....................................................................................................57 Safety ...................................................................................................................57 Establishing Injectivity ........................................................................................57 Placement of Fluid ...............................................................................................58 Bullheading ..............................................................................................58 Circulating with Workstring ....................................................................58 Coiled Tubing Injection ...........................................................................58 Returning the well to production .........................................................................59

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Sandstone formations are stimulated by using hydrofluoric acid to dissolve clay and siliceous minerals that are causing damage in the formation. The acid is injected at a pressure less than the formation fracture pressure. Stimulation by acidizing is limited to the removal of damage near the wellbore because acid penetrates less than two feet from the wellbore. The use of hydrochloric-hydrofluoric acid mixture in sandstone acidizing was first developed by Jesee Wilson in 1933. The first commercial use of the acid mixture was begun by Dowell in 1940. The product called Mud Acid, was used to dissolve drilling mud filter cake. Although many modifications and improvements have been introduced since 1940, the basic sandstone acidizing treatment continues to be used to the present. Description of Treatment An acidizing treatment for a sandstone formation normally will consist of sequentially injecting three fluids - a preflush, the hydrofluoric acid - hydrochloric acid mixture and an afterflush. These fluids serve definite purposes. •

The Preflush is usually hydrochloric acid, ranging in concentration from 5 to 15 percent and containing a corrosion inhibitor and other additives as required. The preflush displaces water from the wellbore and connate water from the near wellbore region, thereby minimizing direct contact between sodium and potassium ions in the formation brine and fluosilicate reaction products. Normally, this will eliminate redamaging the formation by precipitation of insoluble sodium or potassium fluosilicates. The acid also reacts with calcite (calcium carbonate) or other calcareous material in the formation, thereby reducing, or eliminating, reaction between the hydrofluoric acid and calcite. The preflush avoids waste of the more expensive hydrofluoric acid and prevents the formation of calcium fluoride, which can precipitate from a spent HF-HCl mixture.

•

The Mud Acid which is a mixture of HCl and HF acids (usually 3% HF and 12% HCl). The hydrofluoric acid is the only acid that dissolves siliceous and clay minerals and creates the porosity and permeability increase required for productivity improvement. The purpose of the HCl and is to provide a highly acidic environment which enhances the dissolving power of HF and also tends to maintain the HF-silica reaction products in the solution.

•

The Afterflush is used to displace the acid reaction products away from the nearwellbore region. In oil wells, the afterflush is usually diesel mixed with a mutual solvent. In gas or water wells, an afterflush of nitrogen, HCl or NH4Cl water and a

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mutual solvent is used. The mutual solvent is used to keep the reservoir rock water wet and thus increase the relative permeability to oil. It also water wets material loosened by acid reaction and prevents emulsion stabilization by these materials and expedites spent acid cleanup.

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SANDSTONE COMPOSITION Sandstone is commonly composed of four different minerals: silica, feldspars, clays and carbonates. Hydrofluoric acid, which is the only substance capable of dissolving silicates, will dissolve all these minerals. Silica: The main constituent in a sandstone reservoir is silica (SiO2). The quartz sand grains that are the primary constituent of a sandstone are essentially pure silica. Frequently, the cementing material holding the sand-grain matrix together is composed of silica. The silica structure is very stable making the rate at which this mineral dissolves in HF very slow. Feldspars: Another group of minerals commonly found in sandstones are feldspars. Feldspars have a three-dimensional network structure with SiO4-4 and AlO4-4 tetrahedra as the building blocks. The negative charge of this network is balanced by the presence of cations such as Na+, K+ and Ca++ in the interstices. The feldspar aluminosilicate structure is similar to the pure silica structure found in quartz, except that aluminium has been substituted for some of the silicon. This makes feldspars more susceptible to attack by HF; hence, the rate of dissolution of feldspars is somewhat greater than silica. There are three basic chemical compositions for feldspars: Potassium feldspar Sodium feldspar Calcium feldspar

KAlSi3O8 NaAlSi3O8 CaAl2Si2O8

(orthoclase) (albite) (anorthite)

Unlike silica, which is deposited as a pure substance, feldspars are rarely formed with the compostions listed above, but occur with various proportions of K, Na and Ca. As a practical matter, the precise composition of the feldspar component has negligible impact on sandstone acidizing, relative to other factors, and hence does not affect design. Clays: Clays are siliceous materials like silica and feldspar, but their structure is quite different. Instead of being three-dimensional, clays have a sheet-like structure. Silica sheets composed of SiO2 alternate with alumina sheets of composition Al2O3. Frequently other atoms such as Fe++, Ca++, Mg++ or Al++ become substituted for one of the Si or Al atoms. This substitution results in a charge imbalance within the sheets that is balanced by the incorporation of Na+ or K+ atoms on the sheet surfaces. This highly substituted sheet-like

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structure is highly susceptible to rapid attack and dissolution by HF. Even plain HCl is capable of attacking the structure by leaching out the aluminium and iron constituents of some clays. There are many different types of clays, the most familiar being kaolinite, montmorillonite (smectite), illite and chlorite. These clays all dissolve similarly in HF, although there are differences in the relative amounts of Si, Al and other components which are solubilized from one clay to the next. Carbonates: Carbonate minerals are also present in many sandstones. There are three carbonate minerals common to sandstone reservoirs: Calcite Dolomite Siderite

CaCO3 Ca0.5Mg0.5CO3 FeCO3

These minerals often occur as cementing material between the quartz grains. The carbonates react very rapidly with HF, but they are also reactive toward HCl and other strong acids.

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ACID SANDSTONE REACTIONS Successful application of sandstone acidizing technology requires some basic understanding of the chemical reactions that occur when the hydrofluoric acid is injected into a sandstone. There are, first, the dissolution reactions whereby HF dissolves rock and enhances permeability. However, there are also precipitation reactions that deposit material in the pore spaces and thereby reduce permeability. To acidize a sandstone successfully, conditions must be adjusted so that dissolution reactions are promoted and precipitation reactions are minimized. HF Acid: Hydrofluoric acid (HF) is the only commonly available solvent which will dissolve silica formation damage in a reasonable period of time. Although HF can be obtained in concentrations up to 49%, it is used at no greater than 3% in the field. Hydrofluoric acid is a weak acid that is only partially ionized in solution: HF → H + + F This means that HF is not very effective at providing H+, the acid component. Therefore, HCl is added to the HF to maintain an acid medium to prevent precipitation of some of the reaction products. Adding HCl also increases the dissolving power of HF and the rate of dissolution. Dissolution Reactions: The object of sandstone acidizing is to dissolve silicate damage and produce soluble products. Most components of sandstone will dissolve in HF. The reactivities of the three types of minerals with HF are shown in the Table 1 below Table 1. Reactivities of Siliceous minerals with HF Clays Feldspar Silica •

Very reactive Reactive Slowly reactive

Silica (quartz) The simplest of these reactions involves silica dissolution, which produces fluosilicic acid, H2SiF6 :

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SiF4 + 2HF → H2SiF6 •

Feldspar (albite) Feldspars also react with HF to produce fluosilicic acid as the final product. However, because feldspars are aluminosilicates, aluminium fluoride is also a reaction product. NaAlSi3O8 + 22HF → 3H2SiF6 + AlF3 + NaF + 8H2O

•

Clay (kaolinite) Clays also react with HF to yield soluble fluosilicic acid and aluminium fluoride. Although the ratio of Si to Al will vary with different clay types, the reaction product species will essentially be the same. Al2Si2O5(OH)4 + 18HF → 2H2SiF6 + 2AlF3 + 9H2O

Precipitation Reactions Competing with the dissolution reactions are a series of precipitation reactions. Dissolving a feldspar or clay mineral with HF does not mean that it will always remain in solution. Indeed, there are many conditions under which the dissolved ions can precipitate from solution. These precipitates can be damaging to the permeability of the near-wellbore region. Because many of these precipitates are gelatinous, they occupy more space than does the mineral that was originally dissolved. Therefore, a net decrease in formation permeability can result when reaction product precipitation occurs. The major precipitation reactions are related to the dissolved silicon, which can reprecipitate as fluosilicate salts or silica gel. Dissolved aluminium ions are too soluble in conventional low pH mud acid to reprecipitate. Under some circumstances a precipitate of calcium fluoride can form. Fluosilicates: The sodium and potassium salts of fluosilicic acid are very insoluble. The introduction of Na+ or K+ ions into a spent hydrofluoric acid solution containing fluosilicic acid will cause immediate precipitation of the salt: H2SiF6 + 2Na+ → Na2SiF6(ppt) + 2H+

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These solubilities of some fluosilicates in water are given Table 2. Only the salts of sodium and potassium present any significant hazard of fluosilicate precipitation. Table 2. Solubilities of Fluosilicates Salt K2SiF6 Na2SiF6 CaSiF6 (NH4)2SiF6 MgSiF6

Solubility at Room Temperature g/100g soln. 0.18 0.74 10.60 15.60 23.00

There are generally two sources of Na+ and K+ in sandstone formations. First, feldspars and most clay minerals contain some Na+ and K+ in their crystal lattices. As these minerals dissolve, some Na+ and K+ ions are put into solution. However, the amount is relatively small and experimental evidence suggests that this source of Na+ and K+ is not significant. The second source of Na+ and K+ is formation brine. Mixtures of formation brine and spent HF acid will invariably result in precipitation. In designing a sandstone acidizing treatment, it is important to avoid contacting the HF - either before or after spending on the sand - with formation brine. The HCl preflush is specifically designed to isolate the HF from formation brine. Hydrated Silica: The fluosilicic acid produced from the reaction of silica and clay with HF can be hydrolysed to silicic acid as follows: H2SiF6 + 4H2O → Si(OH)4(ppt) + 6HF Silicic acid is a hydrated form of silica and exists as a gelatinous precipitate in the pore space. Since the precipitation of silicic acid does not begin to occur until after the HF is spent on the sandstone, formation damage from this precipitate can be avoided by: (1) employing an afterflush (2) returning the well to production immediately after acidizing

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The use of an afterflush will displace the partially spent HF near the wellbore to a location deeper in the reservoir. If precipitation does occur, it will be far enough away from the wellbore so that the effect on well productivity will be minimal. Even when an afterflush is used, it is recommended that the well be put on production (or injection) immediately following the acid treatment. This step will permanently remove spent HF from the near-wellbore region, eliminating silicic acid precipitation problems entirely. Calcium Fluoride: Contacting HF with a high concentration of calcium ions may lead to precipitation of insoluble calcium fluoride (CaF2) : HF + Ca++ → CaF2(ppt) + 2H+

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MECHANISM OF ACID ATTACK During the injection of the HCl preflush, the carbonates in the pore spaces are dissolved and the formation brine which contain the Na and K ions is displaced away from the wellbore. These processes ensure that calcium fluoride and sodium and potassium fluosilicate precipitation will not occur when the HF acid is injected into the formation. Damage Induced by Acid Laboratory core studies were made by Smith in 1964 to investigate the nature of HCl-HF reaction with sandstone. These studies showed that core permeability declines on initial contact with the acid. As the acid injection continues the permeability increases as shown in Fig 1. The initial permeability reduction is believed to be caused by the partial disintegration of the sandstone matrix by acid and the downstream migration of fines which plug the pore channels. Continued exposure of the fines to the unspent acid eventually result in their dissolution. Therefore, the subsequent permeability increase was thought to come from clearing the pore channels plugged by fines and the enlargement of other pore channels by the acid. Other investigators have proposed that the decrease in permeability could be caused by the precipitation of orthosilicic acid (Si(OH)4) or other reaction products.

Fig. 1

Effect of HF concentration on core response to HF-HCl mixtures

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Effect of HF Concentration Fig. 1 illustrates the effect of hydrofluoric acid concentration on the response of Berea sandstone to HF-HCl mixtures. This figure shows that higher HF concentrations give a greater initial permeability decrease, but that a smaller volume of acid will achieve a given permeability increase. The Berea sandstone used in these tests is a relatively homogeneous sandstone that contains less clay (the most reactive component) than many sandstone formations; therefore, the response may be different in formation sands. Increasing the concentration of HF acid will increase the amount of reaction products. This condition may force some species to their solubility limit, thereby causing precipitation of reaction products. Investigators have found that 3% HF by weight is about the maximum desirable concentration. The data in Fig 1 indicate that 50 to 100 pore volumes of 3% HF - 12% HCl mixture have to be injected to achieve a significant permeability increase. This is equivalent to an acid volume of 220 to 440 gal of acid per foot to treat a zone of 1 ft radius around a 6" wellbore. This volume may destroy the consolidating materials of the rock and allow the permeability to decrease because of compaction. Effect of Acid Injection Rate Fig. 2 shows that as the acid flow rate through the Berea core is increased (pressure gradient is increased), the initial permeability decline increases. Also, greater quantities of acid are required to achieve a given permeability increase.

Fig. 2

Effect of acid flow rate on Berea core response to HF-HCl

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The increased permeability decline may be caused by an increase in the quantity of fines released because of the increased drag forces at high flow rates. Larger volumes of acid are probably required to achieve a given permeability increase because all the HF was not reacted while the acid resided in the core when injected at the higher flow rates. Effect of Matrix Composition The mineralogical composition of the sandstone matrix has a substantial effect on formation's response to HF acid. Although sandstones generally contain only a few percent of carbonate some sandstones may have upto 10% carbonate. In this case larger quantities of HCl preflush may be required to prevent HF acid reacting with the carbonate. The greater the amount of clay in the rock the faster the HF acid spends and the shorter the penetration distance. At present there is no effective way to design for clay content. It must be remembered, however, that the goal is to dissolve the damaging clays. If damage is not deep, it will not matter if penetration distance is short. Effect of HF-HCl Reaction on Core Mechanical Properties In an effort to remove damage completely, one may decide to try a larger acid volume. There is a physical limitation on the quantity of acid the formation can tolerate without becoming unconsolidated. Recall that the acid is dissolving the cementing material; therefore, as acid is injected, the formation progressively becomes weaker until it finally disintegrates.

Fig. 3

Effect of acid throughput on formation compressive strength

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Fig. 3, taken from this study, illustrates what happens to the compressive strength of a core as increased volumes of acid are injected. These data show that as the volume of acid injected is increased, the uniaxial compressive strength decreases until the sandstone is finally unconsolidated. Note that the compressive strength decrease correlates closely with the total dissolving power of acid injected. For example, a compressive strength of 500 to 600 psi was obtained after injection of an equivalent of about 18 gal/ft of 8% HF, 30 gal/ft of 5% HF and 75 gal/ft of 2.5% HF. Prediction of Radius of Acid Reaction One approach used in designing sandstone acid treatment was developed by Williams and Whiteley. This technique couples a mathematical description of acid reaction with data taken on formation core material. The resulting design curves are shown in Figs. 4 through 7. These figures are for temperatures ranging from 100 to 250 oF and injection rates of 0.001 to 0.2 bbl/min/ft of formation to be treated. The curves were developed for 3% HF / 12% HCl, but the effect of other acid concentrations can be estimated by converting to the equivalent volume of 3% HF on a dissolving power basis. These curves can be used to obtain a reasonable estimate of the required acid volume without detailed experimental core data.

Fig. 4. Depth of permeability increase for 100 oF formation temperature and 3" wellbore radius.

Fig. 5. Depth of permeability increase for 150 oF formation temperature and 3" wellbore radius.

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Fig. 6. Depth of permeability increase for 200 oF formation temperature and 3" wellbore radius.

Fig. 7. Depth of permeability increase for 250 oF formation temperature and 3" wellbore radius.

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TREATMENT DESIGN A well candidate for sandstone acidizing must be damaged before the acid treatment will yield significant improvement in productivity. Even after ascertaining that a well is damaged, there is no assurance that sandstone acidizing will increase productivity. Causes of damage such as water blocking emulsions and scale deposition cannot be removed by acidizing and is best treated by other methods. Therefore, it is important to determine the cause of the low productivity before deciding whether or not to acidize the well. Hydrofluoric acid can remove near-wellbore damage caused by: •

Drilling Mud Solids During the drilling operations mud solids are forced into the formation matrix. With well formulated mud and good drilling practices, this solids invasion can be limited to few inches.

•

Clay Damage The introduction of low salinity water can cause clays to swell or disperse. Clays like bentonite increase in size by imbibtion of fresh water. Clays like kaolinite and illite can be removed from the pore walls and transported until they become lodged in the matrix pores. Sources of low salinity water can be workover fluids, injection water and drilling mud filtrate.

•

Workover Fluid Solids During workover operations solid additives added to workover fluids such as fluid loss agents or weighting materials can plug the perforations.

Required Data Before designing an acid job the following data should be gathered: •

Completion Data Casing, tubing, downhole packers and tailpipe assemblies. Pressure ratings and dimensions.

•

Formation Data Reservoir pressure and temperature, fracture gradient, permeability or porosity from open hole logs, state of consolidation, depth and thickness of sandstone interval.

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•

Types of Fluids Three types of fluids must be specified: the preflush, the HF-HCl acid and the afterflush. Preflush Hydrochloric acid at a concentration of 15% is normally used as a preflush. The purpose of the preflush is to: 1. Prevent contact between HF acid and formation brines so that insoluble fluosilicates are not precipitated. 2. Dissolve any calcium carbonate in the formation and prevent the precipitation of CaF2 from the HF acid. In cases where there is incompatibility between the oil and the acid, a diesel spacer is pumped ahead of the preflush to prevent the formation of emulsions. The volume of the preflush should be enough to prevent HCl and formation brine from mixing and dissolve all the calcite (CaCO3). The minimum volume is 50 gal/ft. In cases where the amount of calcite in sandstone is high, it may be necessary to increase the volume to 100 gal/ft. HF/HCl The mixed hydrofluoric/hydrochloric acid stage is the silicate-dissolving portion of the sandstone treatment. In practice, hydrofluoric acid is never used by itself. It is always used with hydrochloric acid for two reasons. First, the dissolving power of HF is enhanced by HCl, and second, the HCl prevents the appearance of precipitates such as metal hydroxides and calcium fluoride (CaF2). A common formulation, known as "12-3 mud acid", consists of a 12% hydrochloric acid and 3% hydrofluoric acid mixture. This is prepared either in the field or in the service company yards by adding solid ammonium bifluoride salt to 15% HCl. The resulting mixture contains 12% hydrochloric acid, 3% HF and about 3% ammonium chloride (a byproduct). Under high temperatures (greater than 200 oF), the use of half strength mud acid has been found to be beneficial because it reduces the rate at which silica will reprecipitate from spent acid. This half strength acid consists of 6% hydrochloric acid and 1.5% hydrofluoric acid. HF/HCl Volume - The volume of acid ranges from 25 to more than 150 gals/ft. A typical volume is 125 gals/ft. A volume of 25 gals/ft is used when the formation

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damage is only a few inches deep. Volumes larger than 150 gals/ft may cause unconsolidation of the rock and lead to sand production. The volume of HF/HCl acid can also be estimated by using the charts in Fig 4 through Fig 7 as follows: 1. Estimate the maximum injection rate in Bbl/min and divide by the perforated interval to obtain the specific injection rate, Bbl/min/ft. 2. Estimate the radius of the damage zone. In the absence of well test data, it is suggested that low permeability (less than 5 md) formations have a damage zone thickness estimated at 3"; more permeable formations may be regarded as having a damage zone of 6" or more. 3. Determine formation temperature (in oF). 4. Choose the chart from Figs 5 through 8 nearest the formation temperature of concern and, using the assumed damage zone thickness and specific injection rate, read the volume of mud acid (3% HF, 12% HCl) required to obtain a permeability increase to the desired radius. If the mud acid to be used contains more than 3% HF, reduce the volume read from Figs. 4 through 7 by multiplying by the ratio 3/(HF concentration). Afterflush The afterflush isolates spent acid from the fluids used to displace the treating fluids into the formation. It also helps water-wetting the formation rock thereby preventing the formation of oil/acid emulsions. For oil wells, diesel is usually used as the afterflush fluid. Diesel establishes high oil saturation in the near-wellbore region. This saturation and lower fluid gradient allows the well to flow with the least amount of nitrogen lifting or swabbing. It is recommended that 10% by volume ethylene glycol monobutyl ether (EGMBE) be added to the diesel. The diesel-EGMBE mixture improves relative permeability to oil and leaves the formation water wet. In gas and water injection wells, the afterflush is normally 15% HCl. Addition of 10% by volume EGMBE is again recommended. Diesel oil is not to be used in either gas or water injection wells because of its adverse effect on the relative permeability to either fluid. •

Injection Pressure Injection pressure during sandstone acidizing treatment should be limited to a value that will not fracture the formation. The formation fracturing pressure Pf is,

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where

(1)

FG = fracture gradient, psi/ft D = vertical depth, ft

The best source of the fracture gradient is from a recent fracturing treatment of the formation to be treated. If no treatment has been done the fracture gradient can be estimated from the following formula, P FG = αB + (1 - α ) (2) D where, B = a constant related to over-burden gradient = 1.0 P = formation pressure, psi D = vertical depth, ft α = constant Using Equation 2, the value of α can be computed from the fracture gradient, formation pressure and depth on the day the well was fractured. If no previous fracturing data is available then a value α = 0.5 may be assumed and the above equation is used to estimate the fracture gradient. The maximum allowable injection pressure to avoid fracturing the formation is, Pmax = (FG - Fluid Gradient) × D + Friction Pressure

(3)

The fluid gradient is calculated from the fluid density in the tubing. Fluid gradients of HCl acid are listed in Table 2 of the previous chapter. The gradients of HF/HCl mixtures may be found by using the combined weight percentages of the HF and HCl concentrations (eg. 3% HF / 12% HCl is equivalent to 15% HCl). When treating fluids are injected through conventional tubing the friction pressure is not significant. However, when coil tubing is used the friction pressure is large and should be included in equation 3. Friction pressure charts for coil tubing are available from service companies. Example Design Calculations To illustrate the design procedure, we will consider the design of an acid mutual solvent treatment for an oil well with the following characteristics:

(1)

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(2) (3)

perforated interval = 10 ft, kav = 50 md average permeability of the formation, including the damaged zone, before acid treatment), (4) temperature = 150 oF, (5) μo = 1 cp at reservoir conditions, (6) μ = 0.78 cp (viscosity of 15% HCl at 150 oF from Fig 8), (7) fracture gradient = 0.7 psi/ft (at initial pressure of 2,000 psi), (8) current reservoir pressure = 1,000 psi, (9) overburden gradient = 1.0 psi/ft, (10) wellbore radius = 3", (11) drainage radius = 660 ft.

Fig. 8

Acid viscosity versus temperature

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Step 1. Fracture gradient is not known for current reservoir pressure, so this must be estimated using Eq. 2, the overburden gradient, and the initial reservoir pressure and fracture gradient. 2,000 psi 0.7 = α + (1 - α ) 5,000 ft solving for α, we find α = 0.5 and the current fracture gradient is estimated to be FG = 0.5 + 0.5 ×

1,000 psi 5, 000 ft

= 0.6 psi/ft Step 2. The maximum injection rate can now be estimated from Darcy's equation, i max =

4.917 × 10 -6 (50 md) (10 ft) (5,000 ft × 0.6 psi / ft - 1,000 psi) (0.78 cp) ln (660 / 0.25)

imax = 0.80 bbl/min i/h = 0.080 bbl/min/ft Step 3.

Maximum surface pressure should not exceed that given by Eq. 3

pmax = (0.6 - 0.47) psi/ft × 5,000 ft where 0.47 psi/ft is the hydrostatic gradient of 15% HCl. pmax = 650 psi Step 4. Acid volume required to give 6" depth of permeability change (obtained from Fig. 5) is Vol = 220 gal/ft of perforated interval

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500 gal of 15% HCl 2,200 gal of 3% HF - 12% HCl 2,200 gal of 90% diesel oil - 10% EGMBE

Displace all fluids into the formation at a surface pressure less than 650 psi in the sequence shown above. Stop the displacement when the displacing fluid reaches the top perforation. Corrosion inhibitors that are effective in the presence of EGMBE should be selected to provide the required protection, taking into consideration type of tubular goods, temperature and maximum acid-pipe contact time.

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FIELD IMPLEMENTATION Well Condition Before any acidizing treatment is done on a well, the engineer should have investigated the history of the well condition and the pressure rating of the wellhead. For instance, the tubing design and types of wellbore equipment present should be known so that precautions may be taken to remove or protect acid-sensitive components such as downhole pumps. Acidizing treatments should never be done on wells with known tubing or casing leaks until leaks are repaired. The pressure ratings of the wellhead should be known so that injection pressures do not exceed the rated working pressure. The burst rating of the downhole tubulars must also be known so that back pressure may be applied to the annulus in cases where injection pressures may be very high. If the well has a downhole packer, the engineer should calculate the amount of tubing contraction that would result from pumping cold acid down the tubing. These calculations can be made using Saudi Aramco's Tubing Distortion Program. If the tubing contraction is large enough to cause the seal assembly to come out of the packer, then pressure may have to applied to the tubing-casing annulus while pumping the acid and/or the acid may have to be preheated before pumping to ensure that the seal assembly remains below the packer during the treatment. Safety Acidizing demands some special safety attention because of the corrosiveness of the fluids and the high pressures sometimes encountered. Hydrochloric acid (HCl) is more hazardous than HCl because of the types of burns it inflicts. These burns do not appear immediately, but may take a while to develop. However, they are slow to heal. Suitable neutralizing agents should be on site to treat exposure to either HCl or HF. Eye protection is also necessary for those working in the vicinity. In general, acid is not pumped during hours of darkness because of the extra hazards of undetected leaks. Establishing Injectivity Diesel or brine should be injected into the formation to establish injectivity before the acid job. Establishing injectivity is important especially when a rig or coil tubing is not available to circulate out the acid. If the injectivity of a well is zero or very low, flowing back the well before the acid treatment may increase the injectivity of the formation. If this fails a workover rig or coiled tubing unit can be used to spot acid across the perforated interval.

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Placement of Fluid Acid treatments can be performed by three methods: (a) Bullheading (b) Circulating with workstring (c) Coiled tubing injection Bullheading: The bullheading technique refers to the injection of acid directly into the production tubing or casing. This technique is the least expensive method of injecting the acid into the formation. The primary disadvantage of this technique is poor treatment control. With the bullhead technique acid cannot be spotted across the zone of interest or circulated in and out of the well. Injectivity must be established before performing the acid job. If injectivity cannot be established it will be very difficult to remove the acid from the tubing. Circulating with Workstring: Acidizing through a concentric workstring such as tubing or drill pipe and a retrievable packer (RTTS) provides better treatment control than bullheading acid down the tubing. A workstring with retrievable packer can be used at greater depths and higher treating pressures than coiled tubing. This method provides the ability to circulate and spot live acid directly across the perforations in order to effect initial breakdown. It also facilitates livening the well with nitrogen or diesel whenever required after the acid job. The disadvantage of the concentric workstring method is its high cost, since it requires the use of a workover rig and the killing of the well before the acid treatment. Coiled Tubing Injection: Coiled tubing workover techniques employ either a 1" or 1.5" O.D. continuous tubing to place the acid across the perforations and to inject the acid. The advantage of this technique is that more control over the acid can be achieved in that it can be circulated and placed exactly where desired. Also, the acid may be distributed more evenly over longer intervals by simple tubing reciprocation up and down across the interval during the acidizing treatment. While this is not true diversion, advantages are gained by contacting the entire interval to be acidized with live acid.

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The major disadvantages of the coiled-tubing unit are higher friction pressures and relatively low burst ratings of the coiled tubing. Also, coiled tubing is not routinely used at depths below 15,000' due to its limited tensile strength. Because coiled tubing exists on a continuous reel which can be used upto 20,000 ft long, all fluids must be pumped through the entire length of tubing, which results in relatively high friction pressures compared to the other treatment placement techniques. Friction pressure drop in coiled tubing is available from service companies. Friction pressure reducing additives such as FR-20 may be mixed with the acid to reduce the pressure drop in coiled tubing. Returning the Well to Production To minimize the occurrence of damage from reaction products precipitating from mud acid, the well should be returned to production or injection immediately after the acid treatment is completed. To define the acid term "immediately" a little more precisely, producing the well one hour after the job is completed is acceptable whereas waiting 12 to 24 hours is not. Achieving this goal requires good cooperation between production and workover personnel. Field results have demonstrated that it is well worth the effort.

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TABLE OF CONTENTS WHEN TO DIVERT....................................................................................................60 HOW TO DIVERT ......................................................................................................60 PACKERS ......................................................................................................................60 PARTICULATE DIVERTING AGENTS .................................................................61 TREATMENT DESIGN ..............................................................................................62 Sandstone Matrix Acidizing ................................................................................62 Carbonate Matrix Acidizing ................................................................................62 FIELD APPLICATION ...............................................................................................64 VISCOUS FLUID DIVERTING AGENTS..............................................................65 Foam ....................................................................................................................65 Gel Diverters........................................................................................................67 PERFORATION BALL SEALERS ...........................................................................67 Description...........................................................................................................67 Performance Factors ............................................................................................68 Perforation Flow Rate ..............................................................................68 Wellbore Flow Rate .................................................................................68 Fluid Viscosity .........................................................................................68 Ball-Fluid Density Contrast .....................................................................68 Ball Sealer Seating Mechanisms..........................................................................70 Applicability ........................................................................................................71 Size and Composition ..........................................................................................71 Selection Guidelines ............................................................................................73 BALL SEALER TREATMENT DESIGN................................................................73 Ball Injection........................................................................................................73 Ball Removal or Control......................................................................................73

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During stimulation operations, it is usually necessary to treat a massive section or several intervals which are open to the wellbore. Such multiple-zone stimulation is accomplished using some means of distributing or diverting the treating fluids to the different zones. Mechanical tools, particulate materials or ball sealers are commonly used diversion techniques. Treating fluid follow the path of least resistance which is usually determined by the permeability of the formation. The major portion of any matrix treatment will be injected into the zone with greatest permeability. Diverting agents are usually used in stimulation operations to distribute the treating fluid more uniformly across the damaged intervals. When to Divert - Diversion is usually used during: • •

Matrix acidizing when interval lengths are greater than about 20 - 50 ft. Matrix acidizing of isolated sands separated by distances greater than about 20 ft.

How to Divert agents: • • • •

there are basically four classes of diversion techniques or diverting

Packers Particulate diverting agents Viscous fluid diverters Perforation ball sealers

Packers Packers, straddle packers and similar mechanical equipment offer the most reliable method of obtaining fluid diversion during well treatments. By physically isolating the particular zone(s) of interest from "thief" zones above and below, packers ensure positive injection of treating fluids into the intended strata (assuming a good cement job). An example of this technique is depicted in Figure 1. The packer method, however, is generally the most time-consuming and costly because of the associated packer-tubing manipulations, which require a rig. Hence, packer diversion techniques are used primarily in circumstances in which serious diversion problems exist or in which rig costs are low.

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Fig. 1. Schematic representation of zone isolation with a straddle packer Particulate Diverting Agents Particulate diverting agents are simply solid particles pumped with the treating fluid that are designed to form a low permeability filter cake across the permeable zones. Since the filter cake builds faster on more permeable zones, treating fluids are diverted to the less permeable zones. Particulate diverting agents must satisfy the following requirements: 1. 2. 3. 4. 5.

Have limited solubility in the stimulation fluids. Have low filter cake permeability compared to formation permeability. Exhibit minimal invasion of the rock matrix. Dissolve or breakdown after the treatment. Be thoroughly dispersed in the carrier fluid to allow proper distribution along the entire interval.

Models of matrix acidizing treatments with diversion indicate that the material of preference is one that forms a thin, low permeability filter cake on the sand surface. Figure 2 shows the distribution of injected fluid when such a diverter is added continuously to the acid during matrix treatment. The three zones depicted had widely differing permeabilities, but received roughly equal amounts of acid as the diverter built up a resistant cake in the perforations. The pressure drop between the wellbore and the formation is indicated at the right for each step.

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Fig. 2. Diverter filter cake of low permeability used to improve fluid distribution Treatment Design The size and permeability of the first zone to be treated is seldom known accurately. For this reason the optimum amount of diverter is based on field experience. Table 1 shows the recommended quantities and concentrations of Halliburton and Dowell diverters. Although particulate diverters can be pumped continuously, slug addition is recommended to improve the efficiency. Continuous addition of particulate diverters throughout the treatment is recommended when operational limitations do not allow slug addition. Sandstone Matrix Acidizing In sandstone acidizing, oil soluble resins J-237, materiseal 'O' and materiseal 'OWG' are effective diverting agents. These agents can be adversely affected by additives such as EGMBE (ethylene glycol monobutyl ether) corrosion inhibitors and surfactants, therefore, compatibility studies should be made before using them. Mud acid jobs with particulate diverting agents are conducted in multiple stages. Each stage consists of a preflush, mud acid, afterflush and diverting agent. The number of stages depends on the thickness and permeabilities of the zones to be treated and are usually provided by service companies. Carbonate Matrix Acidizing The worm holes created in the carbonate formations during matrix acidizing make diversion with particulate diverters difficult. Bridging agents such as benzoic acid flakes and rock salt are used in carbonate acidizing. These agents are added continuously or in slugs to form a bridge in the worm holes and vugs. Benzoic acid flakes are soluble in oil,

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water and acid. Rock salt is soluble in water. Both agents are normally slurried in gelled brine at 1-2 lb/gal. The following tables can be used as a guide for selecting the quantities to be used per stage: Benzoic Acid Temperature oF

Open Hole lb/stage

Cased Hole lb/stage

<150 150 - 200 200 - 250

100 200 300

75 150 225

Rock Salt Temperature oF

Open Hole lb/stage

Cased Hole lb/stage

<150 150 - 200

400 600

350 500

Field Application The water injection rate of a North Sea well decreased from 36,000 BPD to 30,000 BPD after perforations were added. The well was stimulated with 200 gal/ft of half strength mud acid (HMA - 6% HCl + 1 1/2 % HF). The treatment consisted of 5 separate stages, each consisting of 2000 gal 7 1/2 % HCl preflush, 6000 gal HMA and 2000 gal 7 1/2 % HCl afterflush with Dowell's J-363 diverting agent (sodium benzoate). The particulate diverting agent was used at a concentration of 3 lbs/perforation. The acid was injected at 9 bpm at 1800 psi WHP. Water injection was resumed immediately after the acid job. Figure 3 depicts the treating log for this job with injectivity index (BPD/psi) plotted versus time (min.) A summary of the results follows: •

A slight positive reaction (injectivity increase) was noticed upon injection of HCl.

•

A significant positive reaction (injectivity increase) occurred each time HMA reached the perforations. Page: 64

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•

A significant reduction in injectivity was observed each time the diverter reached the perforations. This is indicative of good diverter action.

•

Post-treatment performance suggested a rapid dissolution of the diverting agent.

The injection capacity of the well increased from 30,000 BPD to 50,000 BPD following the diverted mud acid job.

Fig. 3. Injection well treatment log depicting injectivity response from acid job with particulate diverting agent

Viscous Fluid Diverting Agents Foam: Viscous foam is used as a diverting agent in matrix acid treatments of oil, gas and water injection wells. Dowell provides a FoamMAT diversion service where diversion is achieved by generating and maintaining a stable foam in the thief zone(s) and not in the tubing during the treatment. The volume of the foam stages is gradually increased throughout the treatment to provide diversion over increasing interval lengths and replenish the degenerating foam pumped during prior stages. The foam is created with water, gelling agent and surfactant, and the foam quality is maintained at 70%. Figure 4 shows the results of stimulating the FoamMAT diversion in the laboratory. The fluid is diverted very efficiently from the thief zone to the damaged zone resulting in 95% of the fluid going directly into the damaged zone.

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Fig. 4. Laboratory core test simulation of FoamMAT Diversion Service resulting in a diversion from the thief zone to the damaged zone (15-100 min). (Dowell Schlumberger) Udhailiyah Production Engineering performed acid stimulation study where 8 old power water injection wells and 4 new wells were stimulated using various acidizing techniques. Four different acid treatment designs were used: (1) (2) (3) (4)

bullhead treatment with benzoic acid / rock salt as diverting agent, bullhead with gel diverter, coiled tubing treatment with nitrogen foam as diverter and coiled tubing treating with no diverter.

The results show that for the old wells, the coiled tubing treatment with nitrogen foam as a diverter was most effective in increasing the injectivity and improving the injection profile. The results from the new wells did not indicate one superior treatment technique. The basic procedure of performing stimulation treatment with foam diverter is as follows: (1) run in the hole with the coiled tubing to the top of the interval to be acidized and begin pumping foam while continuing to run into bottom of the treatment interval to pre-load the wellbore with foam, (2) pump the HCl acid through the coiled tubing while slowly pulling up through the lower most 20' - 50' treatment interval,

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(3) hold the coiled tubing stationary at the top of interval just acidized and pump the specified volume of nitrified foam, (4) repeat steps (2) and (3) with each successively higher treatment interval until the entire interval has been stimulated, (5) displace the last acid stage into the formation with water (diesel for oil wells) and back flow the well for cleanup. The volume of the foam stages was gradually increased throughout the treatment to provide diversion over increasing interval lengths and replenish the degenerating foam pumped in prior stages. Gel Diverters: The gel diverter is used in matrix treatments of oil, water and gas wells. It is an alkalinebased polymer gel designed to set up on contact with the low pH acid and high temperature of the formation. The Halliburton system consists of a gelling agent (WG11), a breaker and a viscosifier (WG-17) batch mixed in a high pH (9-10) water. The recommended concentrations of the additives are 400-600 lb of WG-11 and 30 lb of WG17 per 1,000 gals of water. When mixed in water the gel has a viscosity of 10-15 cp. When the gel contacts the acid in the formation its viscosity increases to 400 cp. The high viscosity gel is designed to temporarily plug the pores of the higher permeability intervals of the formation and divert the acid to the lower permeability intervals. A matrix treatment with gel diverter is pumped in stages. Each stage consists of the following: • 5,000 gals 15% HCl • 5 bbls of high pH water spacer • 500 gals of gel diverter • 5 bbls of high pH water spacer • 5,000 gals 15% HCl The purpose of the water spacers is to prevent the gel diverter from mixing with the acid in the tubing or casing. The number of stages depends on the length and number of high permeability intervals to be treated. After the treatment is completed the gel will break and is recovered by flowing back the well. Perforation Ball Sealers Description: Ball sealers are small spheres intended to seat inside the casing on perforations accepting fluid. They are therefore used strictly in perforated completions.

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When a ball seats on a perforation, it is held in place by the pressure differential developed across the ball and the perforation. Once seated, the ball effectively diverts treating fluids to other perforations or intervals requiring treatment. Once treatment is finished, the balls are designed to unseat from the perforations. They will either sink to the rathole or float toward the surface, depending upon the relative densities of the ball and the wellbore fluid. Performance Factors: A study at Exxon Production Research Company revealed that four factors appear to be the controlling variables in the ball sealer seating process, namely: • • • •

Flow rate through the perforations Flow rate past the perforations Fluid viscosity Density contrast between the ball and the fluid Perforation Flow Rate - Flow rate through the perforations has been identified by others as extremely important in nonbuoyant ball sealer efficiency. In general, increased flow rate through the perforation enhances ball seating efficiency. Perforation flow rates in the 0.25 - 1.0 bpm/perforation range are necessary when attempting to divert with nonbuoyant ball sealers. Wellbore Flow Rate - Flow rate past the perforations affects ball seating efficiency. A high flow rate past the perforations imparts greater momentum on the ball, which in turn decreases its seating probability within a given perforated interval. Fluid Viscosity - Fluid viscosity intensifies the fluid drag force exerted on the ball. Laboratory studies indicate that greater fluid viscosity generally results in greater ball sealer seating efficiency. Ball-Fluid Density Contrast - The single most important parameter affecting ball seating efficiency is the density contrast between the ball and the fluid. By varying the density contrast alone, balls can be adjusted from 0% to 100% seating efficiency under a given set of conditions. Laboratory tests have shown that buoyant ball sealers maintain 100% seating efficiency over a wide range of injection rates, from those characteristics of fracturing

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treatments down to the low rates typical of matrix treatments. Nonbuoyant ball sealers are completely ineffective at lower rates of injection. Figure 5 illustrates the effect of density contrast (and perforation flow rate) on ball seating efficiency in laboratory tests that employed a 3 " ID transparent wellbore model containing five 3/8" diameter perforations. Clearly, ball seating efficiency increases as density contrast is reduced and perforation flow rate is increased.

Fig. 5. Effect of changes in density contrast (ball density minus fluid density) on sealing efficiency in laboratory experimentation.

Several other important facts emerged from these tests. First, the seating of nonbuoyant ball sealers is always a statistical process; therefore, there is uncertainty associated with nonbuoyant ball sealer performance under a given set of treating conditions. Second, seating efficiency is usually much lower than 100%, even at injection rates approaching 20 gal/min per perforation. Rates in this range are characteristic of fracturing treatments. Finally, there exists a threshold perforation flow rate required to seat a ball. This threshold flow rate increases with greater density contrast and was in the range of 3 to 6 gal/min per perforation under the test conditions described. These observations demonstrates that nonbuoyant ball sealers are often not particularly reliable in treating wells, even under relatively high injection rates, and they are totally ineffective in treatments conducted at low flow rates, such as matrix treatments.

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The results of laboratory experiments with buoyant ball sealers (having, for example, a density contrast of -0.02 g/cm3) were entirely different, as is shown by the solid line in Figure 5. In a vertical wellbore, the buoyant ball sealers were 100% efficient at all flow rates above 2 gal/min through five perforations (0.4 gal/min per perforation). Ball Sealer Seating Mechanisms: This 100% efficiency occurs when a buoyant ball is used, because the ball cannot sink into the rathole. As shown by the solid trajectory in Figure 6, when a buoyant ball is transported to the perforations in a vertical wellbore, it will either seat on an upper perforation or be carried to the lowest one accepting fluid, where it must seat. Because of buoyancy the ball can never remain in the quiescent fluid in the rathole. Even in the rare case in which a ball overshoots the lowest perforation because of inertia, the buoyant forces exerted on the ball will cause it to promptly rise out of the rathole. Once out, the ball is again entrained by the moving fluid, is transported towards the lowest perforation accepting fluid, and seats. The result is a 100% efficient process.

Fig. 6. Schematic representation of ball sealer seating processes By contrast, the nonbuoyant balls exhibit strictly statistical seating efficiency. As shown by the dashed trajectory in Figure 6, the heavy ball has two distinct options upon arriving at the perforated interval - either to seat upon a perforation or to pass all of the perforations without seating. Because the nonbuoyant ball passes the perforations only once, its seating effectiveness is strongly dependent upon perforation flow rate and its position within the wellbore as it passes the perforations.

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Laboratory tests have shown that there is also a minimum casing flow rate required for the buoyant ball sealers to be effective. However, this flow rate is characteristically different from the threshold flow rate of heavy balls. For buoyant balls, the minimum flow rate is simply the casing flow rate required to counteract the ball's buoyant force and to transport it to the perforations. It can be held to very low values by minimizing the density contrast between the ball and the carrier fluid. In summary, four major field implications can be drawn from the laboratory tests of the seating characteristics of ball sealers: • • •

•

Buoyant ball sealers can be effectively utilized in treatments conducted at low flow rates, typical of matrix treatments. Extensively perforated intervals can be reliably treated with buoyant ball sealers. The 100% efficiency of buoyant ball sealers in laboratory tests with vertical wellbores establishes the number of balls required for diversion as simply the number of perforations desired to be sealed. Nonbuoyant ball sealers can be effective in those applications where perforations flow rates are high and/or where viscous drag forces, rather than gravity forces, control ball transport and seating characteristics (e.g., fracturing treatments).

Applicability: Ball sealers can only be used effectively in perforated completions where the casing is intact and the annulus behind the casing is sealed. Ball sealer diversion may be difficult in extensively reperforated intervals. Ball sealers cannot divert fluids away from overlapping or interfering perforations. Buoyant ball sealers can be used throughout the range of rates, from matrix treatment to fracturing treatments. In most instances, buoyant ball sealers should be the engineer's first choice. Nonbuoyant balls have exhibited satisfactory seating efficiency in high rate treatments with viscous fluids (i.e., frac jobs). Size and Composition: There are currently several types of ball sealers available to the industry from the service companies. They vary in size, specific gravity, core characteristics and material as shown in Table 2. Note that the nominal 0.9 g/cm3 ball sealer (phenolic-cored) actually has a wide range of densities and is compressible. Because of large irregular voids contained within the ball cores, the balls will unpredictably increase in density as they are exposed to elevated pressures down hole. Because of this serious deficiency, these balls are not satisfactory for use in most treatments.

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Exxon Production Research Company has developed a suite of low-density ball sealers (syntactic foam-cored) suitable for diversion procedures. The compressibility of these balls is similar to that of aqueous treating fluids; hence, changes in density contrast under normal treating pressures and temperatures do not pose a problem. The dimensions and physical properties of these balls are included in Table 3. Theses ball sealers are only available from EPR or licensed service companies. Table 2. Conventional Ball Sealers Ball Diameter (inches)

Core Diameter (inches)

Material

Specific Gravity

5/8 5/8 3/4 7/8 7/8 7/8 7/8 15/16 1 1-1/4

1/2 None 5/8 3/4 3/4 3/4 11/16 None 7/8 1-1/8, 1-1/16

RCN * Rubber RCN RCP ** RCN RCA ⊕ RCA Rubber RCN RCN

1.1, 1.3 1.2 1.3 0.9 ⊗ 1.1, 1.3 1.8 1.9 1.2 1.1, 1.3 1.3

* Rubber-covered nylon ** Rubber-covered phenolic ⊕

Rubber-covered aluminium This is a nominal specific gravity. Actual specific gravity ranges from 0.91 to 1.09 based on lab tests. Also, these balls are subject to increasing density as pressure on the ball is increased.

⊗

Table 3. Low Density Ball Sealers

*

Ball Diameter (inches)

Core Diameter (inches)

Specific Gravity*

1-1/4 7/8 7/8 7/8

1-1/8 3/4 3/4 3/4

0.8 0.9 1.0 0.8

This is a nominal specific gravity. Balls are specially graded to be X.XXX ± 0.005 g/cm3.

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Selection Guidelines: Certain guidelines will be of help in selecting the proper ball sealer size and material: •

• •

Ball sealers are equipped with rigid inner cores to guard against permanent extrusion into perforations. Therefore, the core diameter should be at least 1/4" greater than the maximum predicted perforation size. Nylon balls should not be used at treating temperatures (not reservoir temperatures) greater than about 250 oF, because the nylon core is thermoplastic. Syntactic foam-cored ball sealers should not be used at treating temperatures exceeding 225 oF or pressures exceeding 20,000 psi.

Ball Sealer Treatment Design Ball Injection: Ball sealers are injected into the well by using mechanical positive displacement ball injectors. Each ball is individually loaded and compartmentalized within the ball injector. Each rotation of the crankshaft will force a certain number of balls to be ejected, one at a time. No special precautions need to be taken with regard to ball density when using these devices. All ball injectors should be pre-tested to ensure that the balls will be ejected as expected. Count the ball sealers placed in the ball injector, and open the ball injector after the treatment to be certain that the required number of balls was injected. Finally, it is imperative that pumping continue throughout the treatment once the balls have been displaced to the perforations. Should pumping stop, the balls may unseat. Buoyant balls will rise quite a distance during an extended shutdown. Nonbuoyant balls will sink to the rathole, and diversion is lost until more balls can be displaced from the surface to the perforations. Ball Removal or Control There are basically two ways to handle ball sealers following a buoyant ball sealer diversion treatment. One is to remove the balls from the well, and the other is to cause the balls to sink to the rathole at the end of the job even though they were buoyant during the treatment. Ball catchers have been designed and used to capture buoyant ball sealers produced to the surface following the treatment. These ball catchers are tee-shaped devices containing a

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deflector grid which prevents the ball sealers from being carried down the flowlines to plug chokes or to block separation equipment. As shown in Figure 7, they are usually placed downstream of a full-opening wing valve and up-stream of the choke.

Fig. 7. Schematic representation of ball catcher installed on wellhead. Detail shows deflector grid, which serves to separarte ball sealers from downstream production equipment.

Ball catchers are not usually needed if the balls are designed to be buoyant in the fluids used during stimulation operations and are dense enough so that they sink in subsequently produced or injected fluids.

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ALL CHAPTERS

REFERENCES

1. Well Completions and Workovers, EXXON Production Research Company

2. Howard, G. C., and Fast, C. R. : Hydraulic Fracturing, AIME Monograph Volume 2, New York, 1970

3. Williams, B. B., Gidely, J. L., and Schecter, R. S. : Acidizing Fundamentals, AIME Monograph Vol. 6, New York, 1979

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INTRODUCTION TO WORKOVERS TABLE OF CONTENTS

WHAT IS A WORKOVER? ...............................................................................................1 WORKOVER METHODS ..................................................................................................2 1. CONVENTIONAL ..................................................................................................2 2. NON-CONVENTIONAL ........................................................................................2 A. Coiled Tubing Workovers...............................................................................2 B. Snubbing .........................................................................................................3 C. Concentric Workovers ....................................................................................3 WORKOVER RIGS ............................................................................................................4 1. WORKOVER RIG COMPONENTS.......................................................................4 2. WORKOVER RIG SELECTION............................................................................5 REASONS FOR WORKING OVER A WELL...................................................................6 1. LOW RESERVOIR PRESSURE.............................................................................6 2. LOW RESERVOIR PERMEABILITY ...................................................................7 3. FORMATION DAMAGE .......................................................................................8 4. WELLBORE RESTRICTIONS...............................................................................8 5. EXCESSIVE WATER PRODUCTION ..................................................................9 A. Water Encroachment.......................................................................................9 B. Water Coning and Fingering...........................................................................9 6. MECHANICAL FAILURES.................................................................................10 7. POOR CEMENTING ............................................................................................10 8. OTHER REASONS ...............................................................................................11 A. Recompletions...............................................................................................11 B. Well Assessment...........................................................................................11

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INTRODUCTION TO WORKOVERS

WHAT IS A WORKOVER? A workover can be defined as any work done to a well, after its initial completion, that effects the flow performance or mechanical integrity of the well. This definition includes the plugging and abandoning of the well. While some of these operations can be done without a rig, most require a workover rig and are referred to as conventional workovers. In this chapter, we will briefly discuss workover methods, the rigs used and some of the reasons why workovers are done. The following chapters will contain detailed information on planning and executing workovers.

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WORKOVER METHODS 1. CONVENTIONAL Conventional workovers are those where a rig is brought in, the existing completion removed and work done to alter some aspect of the well. At Saudi Aramco, the most common operations include re-perforating, casing leak repairs, removal of junk and deepenings. 2. NON-CONVENTIONAL Non-conventional workovers are those that are not included above. They may or may not require a rig, but all employ some type of specialized equipment. Some examples are listed below. A. Coiled Tubing Workovers Coiled tubing services are frequently used at Saudi Aramco. Coiled tubing can be used without a rig to perform routine clean-out, washing and treating services at significant savings when compared to conventional methods. The various coiled tubing operations performed at Saudi Aramco will be discusses further in the chapter on COILED TUBING found in the WORKOVER OPERATIONS segment. CRANE

HYDRAULIC POWER SUPPLY

INJECTOR HEAD

TUBING

ASSEMBLY REEL

OPERATOR'S CAB

BLOWOUT PREVENTERS

XMAS TREE

COILED TUBING UNIT COMPONENTS

Figure 1 Page 2

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B. Snubbing During the early 1980's, Saudi Aramco employed a snubbing unit to raise the end of the kill string in their producers completed without packers. Since that time, snubbing operations have not been performed at Saudi Aramco. Still, a brief description of the process is warranted. Snubbing is the process of running in or pulling pipe out of a well under pressure. The basic requirements are a system to push and pull the pipe at a controlled rate, stripper rams (sliding-type sealing elements) and a method of plugging the pipe. Snubbing offers the advantage of being able to workover the well without killing it. In reservoirs prone to damage, this eliminates any formation damage due to the killing operation and allows for a faster clean-up and return to production.

CRANE POWER TONGS

WORKBASKET WITH CONTROLS

TRAVELING SLIPS SWIVEL HEAD

TELESCOPING MAST OPERATING CYLINDERS ACCESS WINDOW STRIPPER BOWL

COUNTERBALANCE WINCH

BLOWOUT PREVENTER STACK XMAS TREE

SNUBBING UNIT COMPONENTS Figure 2

C. Concentric Workovers A concentric workover is simply working with a small diameter string inside an existing string of tubing. This small string is often referred to as macaroni tubing. Concentric workovers include snubbing and coiled tubing operations. A common application for concentric tubing is cleaning out fill in the rathole below a packer. At one time Saudi Aramco had special small diameter tubing strings which could be used for concentric workovers using conventional workover rigs if required. These tubing strings were 1-1/4" and 1-1/2" integral joint Hydril tubing (usually referred to by their maximum OD of 1.6" or 1.9" respectively). Coiled tubing has replaced this small diameter tubing in Saudi Aramco operations.

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WORKOVER RIGS 1. WORKOVER RIG COMPONENTS The drawing below depicts the major components of a typical onshore workover rig. The typical offshore workover rig usually has a similar set up installed on a small jack-up platform. Saudi Aramco utilizes contract workover rigs for most of its offshore workovers. Drilling rigs are used for Khuff workovers and, where logistics dictate, they are occasionally used offshore.

DERRICK OR MAST

CROWN BLOCK

TRAVELING BLOCK

SWIVEL

ROTARY HOSE ROTARY TABLE

KELLY

DRAWWORKS

CONVENTIONAL ONSHORE WORKOVER RIG

Figure 3

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Sizes and capacities of the workover rigs used at Saudi Aramco and the typical workover rig are shown in the table below.

Aramco W/O Rigs

Typical W/O Rig

Double with a hook load capacity of 300,000#

Double with a hook load capacity of ±230,000#

2-3/8" DP or 3-1/2" DP

2-3/8" - 2-7/8" tubing or DP

Mud Pumps

1 Triplex pump capable of approx. 220 gpm at 3000 psi

2 Triplex pumps each capable of approx. 130 gpm at 3000 psi

Depth Rating

10,000' with 3-1/2" DP

9000' to 16,000'

Derrick

Workstring

Table 1 2. WORKOVER RIG SELECTION With a number of workover rigs on contract at any given time, onshore workover rig selection at Saudi Aramco is primarily driven by logistics. Namely, which is the closest available rig. In recent years, Saudi Aramco has employed one jack-up workover rig. For offshore workovers, candidates are normally scheduled to be performed when the workover rig is in the area. In an emergency, the workover schedule is changed or a drilling rig is diverted to do the work.

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Reasons For Working Over A Well Problems involving low reservoir permeability require stimulation. Stimulation techniques are addressed in the Stimulation segment and will not be discussed here. Problems related to high viscosity oil require secondary recovery techniques, namely thermal processes. Production of high viscosity oil is not a concern at Saudi Aramco and, therefore, will not be discussed. Many workovers require perforating to be performed. Perforating during workovers is essentially a re-completion technique and is addressed in the COMPLETIONS segment. The following are a number of other reasons that require a well to be worked over. Many are common to the producing reservoirs of Saudi Aramco. 1. LOW RESERVOIR PRESSURE During the life of a well, its production rate will drop in predictable manner based on the reservoir's drive mechanism. 100

80 WATER DRIVE

RESERVOIR PRESSURE (% of original)

60 GAS CAP DRIVE 40

20 DISSOLVED GAS DRIVE 0

0

20

40

60

80

OIL PRODUCED (% of Original in Place)

EXPECTED OIL RECOVERY BY DRIVE MECHANISM

Figure 4 As the preceding graph shows, this is less of a problem with gas cap and water drive mechanisms than it is with a dissolved gas drive.

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Low reservoir pressure presents special difficulties during a workover. There is insufficient pressure across the perforations to take full advantage of stimulation. Perforating long intervals may improve the situation temporarily but may lead to future problems. At Saudi Aramco, water drives have been successful in maintaining reservoir pressures. Eventually, there will be a point in time where a workover is required to install artificial lift equipment.

PRESSURE

RESERVOIR DRIVE PRESSURE DECREASING

PRESSURE DROP NEAR WELLBORE EFFECT OF LOW RESERVOIR PRESSURE

Figure 5

PRESSURE

2. LOW RESERVOIR PERMEABILITY Once production starts from a reservoir with low natural permeability, the production rate drops Hydraulic fracturing will enhance the permeability away from the wellbore. This type of operation requires a workover rig and is often performed just after the well is drilled.

PERMEABILITY DECREASING

PRESSURE DROP NEAR WELLBORE EFFECT OF LOW PERMEABILITY

At Saudi Aramco, natural permeability is typically high and hydraulic fracture treatments are not

Figure 6

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needed. 3. FORMATION DAMAGE Formation damage results in a zone of reduced permeability adjacent to the wellbore. Damage is often the result of filtrate losses from the drilling mud or workover fluid to the formation and is the most common cause of low well productivity.

PRESSURE

DAMAGE

Formation damage can be overcome by bypassing the damaged zone (hydraulic PRESSURE DROP NEAR WELLBORE fracturing or perforating EFFECT OF FORMATION DAMAGE beyond the damage) and by Figure 7 eliminating the damage. Acidizing, solvent and surfactant treatments are the most common forms of elimination. 4. WELLBORE RESTRICTIONS Restrictions in the wellbore are actual physical impediments to flow in the tubing, casing or perforations. Common restrictions found at Saudi Aramco include debris, sand and scale. If the perforations are blocked, washing the perforations with acid and/or surging may remove some of the debris. It is always best to minimize the amount debris left in the perforation tunnels by perforating under-balanced. Other forms of debris include expendable perforating guns or other junk left in the well. If this sort of debris is the cause of the restriction, it can only be removed by mechanical means (milling or fishing). These operations usually require a workover rig. Scale is usually removed by washout operations using mechanical or chemical treatments. Coiled tubing is often used for washout operations and is an effective way

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to clean out sand in the tubing or casing. Fill, or sand in the casing, can also be removed with wireline conveyed bailers. Wireline operations are limited to cases where the hole inclination (angle) allows the tools to fall freely. After the restriction has been removed, the well should be evaluated, prior to being placed back on production, to determine if further remedial work is needed. Often, the kill or workover operation creates formation damage and other problems that will lead to low productivity if not addressed at this time. 5. EXCESSIVE WATER PRODUCTION Water production problems at Saudi Aramco are usually the result of changing reservoir conditions or a poor primary cement job. Water production due to reservoir conditions include: A. Water Encroachment Encroachment is simply the rise of the oil-water contact as the reservoir is depleted. The water, being the heavier of the two fluids, occupies the lower portion of the reservoir. As oil is withdrawn, the water level rises until it reaches the lower perforations when water production begins. Water production of this sort is usually controlled by squeezing off the lower and continuing to produce from the upper perforations. B. Water Coning and Fingering When a well is produced at a high rate, abnormally low pressures often develop around the wellbore. If the well is producing from near the oil-water contact, the underlying water will be drawn up to the perforations. This is referred to as coning because of the shape of the resulting oil-water contact in the vicinity of the well.

OIL

WATER

EXCESSIVE WATER PRODUCTION EXAMPLE OF WATER CONING

Figure 8

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INTRODUCTION TO WORKOVERS Water fingering occurs when these conditions exist in a stratified reservoir. Instead of coning, the water is drawn up, along the bedding planes (usually through an area of high-permeability) and into the well.

OIL

WATER

EXCESSIVE WATER PRODUCTION EXAMPLE OF WATER FINGERING

Figure 9 The Super-K zone of the Arab-D in the Ghawar field is an extreme example of this phenomenon. 6. MECHANICAL FAILURES Occasionally, a well will have a sub-surface safety valve fail, or the production tubing will collapse or part. But the most common mechanical failures occurring in the oil wells of Saudi Aramco are tubing or casing leaks. A poor cement job leads to poor zone isolation and, in time, casing leaks. This type of problem demands that a workover be performed to repair the leak as soon as possible. Not only is the well not producing, but when a tubing leak also exists, water may be flowing into the production reservoir or oil may be flowing from the reservoir into an aquifer. 7. POOR CEMENTING Poor cement jobs, primary or remedial, often manifest themselves in the form of channels in the cement column. This is particularly true where casing string is not adequately centralized, such as in many directional wells. Poor cement jobs often result in poor reservoir drainage, a mechanical failure and/or excessive water production.

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8. OTHER REASONS There are other problems that may require a workover to be performed, but they are not likely to be the cause of a significant number of workovers and will not be discussed here. However, there are two other reasons for performing workovers at Saudi Aramco. A. Recompletions In a case where the original intent of a well is changed, a different type of completion is often required. For example, a producer that is no longer needed may be converted into an observation well . The existing completion will have to be removed and the perforations squeezed. Then the appropriate completion must be installed. Often, a deeper zone is to be exploited. This is not a problem, but still requires a workover to drill out and recomplete. Along the same lines, is the intentional sidetracking of an existing well to increase production. In 1994, Saudi Aramco sidetracked its first well to a horizontal target. This technique has the potential for a very good return on investment. B. Well Assessment A workover may be required to perform some types of well assessment. One example would be to run a casing corrosion log. Much production logging can be done through tubing and usually wouldn't justify a workover. Any logging that requires the completion to be pulled would normally be done when the well is worked over for some other reason.

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TABLE OF CONTENTS INTRODUCTION ...............................................................................................................1 PROBLEM IDENTIFICATION..........................................................................................3 I. WELL HISTORY ..............................................................................................3 II. COMPLETION CHARACTERISTICS ............................................................3 III. OFFSET INFORMATION .............................................................................4 IV. WELL DIAGNOSTICS.....................................................................................4 WORKOVER OPERATIONS AND TECHNIQUES .........................................................5 I. TYPES OF WORKOVER OPERATIONS .......................................................5 A. Killing or stimulating the well ...............................................................5 B. Wireline Work .......................................................................................5 C. Concentric Techniques ..........................................................................5 D. Conventional Techniques ......................................................................6 II. SELECTING THE WORKOVER METHOD...................................................8 A. Equipment Availability..........................................................................8 B. Advantages and Disadvantages .............................................................8 C. Economics..............................................................................................8 D. Other Considerations .............................................................................8 JOB EXECUTION...............................................................................................................9 I. THE WORKOVER PROCEDURE ...................................................................9 A. Workover Program Section....................................................................9 B. Program Attachment Section ...............................................................10 II. FIELD OPERATIONS ....................................................................................11 FOLLOW UP.....................................................................................................................11 I. ANALYSIS OF RESULTS .............................................................................11 II. RECORD KEEPING .......................................................................................11

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INTRODUCTION This chapter describes the workover engineer's responsibilities during the planning phase of a workover. When planning a workover, the need for action on particular well must have already been established. At Saudi Aramco, this need is documented using a WOCP (Workover Candidate Proposal). The WOCP describes briefly the well problem, specifys the objectives of the workover and includes other pertinent well data. Production Engineering will have issued the WOCP after they have completed the first two planning steps below. 1.

Identify the cause of the well problem.

2.

Identify the best type of workover operation to solve the problem. a.

Determine the types of workover techniques that will solve the problem.

b.

Determine what equipment is available.

c.

Determine which techniques are feasible.

d.

List the advantages and disadvantages of each feasible technique.

e.

Determine the economics on each of the alternatives listed above.

f.

Select the best workover technique for the problem at hand.

Once the WOCP is approved by the Production and Reservoir Engineering Divisions, it is forwarded to Wrokover Engineering. The planning process should then continue as follows: 3.

Review the WOCP and the well file. Workover Engineering makes sure the workover objective can be accomplished safely with the rig and equipment available. Workover Engineering approves the WOCP and places the well on the workover schedule.

4.

Implement a safe and efficient workover operation. a.

Prepare the workover procedure. Page 1

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b.

Monitor field operations. The planning may now be finished, but the engineer's job is not. During the workover, the engineer is to see that things proceed as planned. He has already conveyed his requirements for the workover operation via the workover procedure and he must be very diligent now to insure that the procedure is properly implemented. If modifications are necessary, they should be discussed with regard to their impact on all aspects of the operation. Historically speaking, when things go bad, lack of communication is usually found to be the common denominator.

5.

Analyze and record the workover operation and results. The workover has been completed and, again, the workover engineer's job is not yet finished. Analyzing our efforts so that we may learn from our collective successes and failures is the best way to insure profitable workover results. At Saudi Aramco, this information is recorded in the Completion Report. More will be said about Completion Reports later in this chapter.

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PROBLEM IDENTIFICATION The WOCP will state the problem that has developed with the well and propose a method for eradicating it. The WOCP will also contain a brief well history. The workover engineer should review the WOCP, review the wellfile, then visit with the production and reservoir engineers before writing the workover procedure. I.

WELL HISTORY The WOCP will include recent diagnostic information and a production history that may or may not yet have been entered into wellfile kept by Drilling & Workover. If any discrepancies exist between the records, talk with all the parties involved. An effective plan can not be made with defective information. The wellfile will contain many items of useful information regarding the drilling and past operations performed on the well. For example; lost circulation or kicks encountered, muds used, the presence of hydrogen sulfide gas, cement placement (or lack of), the initial completion, previous casing or tubing leaks, production logs, and previous workovers, to name a few. Another source of information that is often overlooked is the drilling or workover rig contractor. In Saudi Aramco, many of these contractors have been working in the Kingdom for a very long time and they all keep records of the operations that they are involved in. Occasionally, their unique vantage point can yield interesting and useful information.

II.

COMPLETION CHARACTERISTICS The current completion type is very important in that it may effect the feasibility of some of the workover techniques under consideration. The wellfile will provide information on the sizes and strengths (pressure ratings) of the tubulars and wellhead equipment used. This information is critical when planning stimulation treatments, squeeze work or when considering whether or not to recomplete in a higher pressured zone. The reservoir engineer can provide information about the reservoir. Such as pressure, oil-water contact, formation sensitivities, sand consolidation and grain size distribution.

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The production engineer will be able to provide information concerning the types of fluids currently being produced, the expected fluid characteristics if the producing reservoir is to be changed and any potential hazards such as H2S gas. III.

OFFSET INFORMATION The Well Database (WDB) of Saudi Aramco has a utility for extracting the nearest offsets to a given well. This is a good place to start. With this list, the production and reservoir engineers' maps can help to pinpoint the offsets that best resemble the well to be worked over. Because of the additional information placed on these maps by their respective engineering departments, they may offer insight regarding the source of or possible solutions to the problem at hand. The individual well histories of these offsets are, perhaps, the best indicator of what to expect on the current workover candidate. Core samples, if they are available can be very useful in determining the best completion technique to use. Open hole and production logs are also useful. They can be good indicators of reservoir damage, porosity, permeability, rock strength and pressure.

IV.

WELL DIAGNOSTICS Well test data, flow tests, spinner surveys, temperature logs, pressure surveys and injectivity tests are just a few of the diagnostic tests used to determine a well's present condition. A review of production decline curves can indicate encroachment, coning, fingering or formation damage. Although well diagnostics is usually the responsibility of the production engineer, it never hurts to give him a call. Talk about the well and its offsets. Run a few "what if..." scenarios past him and note his response. This type of communication will help you to prepare the best workover procedure possible. It may even allow you to foresee and prepare a contingency plan for a problem that you would have otherwise overlooked.

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WORKOVER OPERATIONS AND TECHNIQUES I.

TYPES OF WORKOVER OPERATIONS Workover planning requires the knowledge of workover operations performed in Saudi Aramco. Despite the apparent wide variety of operations listed, they can all be performed by using variations of four basic techniques. These are: A.

Killing or stimulating the well Pipe is usually laid out and connected directly to the well's Xmas tree or the wellhead. The kill or treating fluid is then pumped into the well to kill/stimulate the well.

B.

Wireline Work Wireline operations may be performed with or without a rig. In Saudi Aramco, they are an important part of almost every workover with much of the work being done by Saudi Aramco owned wireline units. There are three types of wireline commonly used. These are slick line, braided line and electric line. The primary advantage of using wireline is the low cost. A rig is not required and when a lubricator is used, the work can be performed under pressure, eliminating the need to kill the well. Operations routinely performed with wireline include setting and retrieving downhole equipment (SSSVs, plugs, etc.), logging and fishing. Some limitations of wireline include the risk of parting the wireline with the possibility that a costly rig workover will be required to fish out the tools, the size of the tools that can be run and the fact that wireline cannot be run into an extended reach (horizontal) well without the help of tubing or drillpipe.

C.

Concentric Techniques As mentioned in the preceding chapter, a concentric workover is simply working with a small diameter string inside an existing string of tubing. Coiled tubing operations are routine in Saudi Aramco. The advantage of concentric workover operations is that they can be performed without removing the completion equipment (tubing and packer). The most common applications for concentric tubing in Saudi Page 5

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WORKOVER PLANNING Aramco are the placement of limestone chips and cleaning out fill in the rathole below a packer. Some limitations of concentric methods are the size of the tools that can be run, higher surface pressures are required, the potential for sticking the string due to tight annular clearance and the possibility of collapsing the tubing.

D.

Conventional Techniques Conventional techniques cover all the operations normally performed with a rig. For the conventional workover, the well must be killed, the Xmas tree, tubing and packer must all be removed before the workover itself can begin. The advantage of a conventional workover is that it affords the most flexibility in operations. In fact, many operations can only be done by conventional means. In Saudi Aramco, workover rigs often clean out fill and deepen wells with 6-1/8" and 3-7/8" bit sizes. The major disadvantage of using a rig to perform a workover is cost.

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The table below lists some of the common problems that develop in the wells of Saudi Aramco and the workover operations that are used to remedy each.

PROBLEM Low Reservoir Pressure

Low Reservoir Permeability Formation Damage

Restricted Wellbore

Excessive Water Production Casing & Tubing Leaks

Other Reasons (non-problem)

WORKOVER OPERATION Perforation of additional intervals Nitrogen lifting Acidizing Artificial Lift Equipment (limited) Acidizing Hydraulic Fracturing (rare) Acidizing Surfactant & Solvent Treatments Reperforating Washing Operations Sand Control Techniques Fishing Squeeze & Reperforate Squeeze & Reperforate Replace Tubing Scab Liner & Reperforate Recompletion, Reperforation Production Logging Table 1

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II.

SELECTING THE WORKOVER METHOD The WOCP will occasionally specify the method to be used to workover the well. Understanding the process and exposure to the various methods and operations will help to evaluate the most effective method used. A.

Equipment Availability Does the workover rig selected have all the equipment to the do the job? Is the rig capable of performing the job? Are the pumps and mud tanks adequate? Does it have the proper workstring for the job? If not, can Saudi Aramco provide it or can it be rented? If there are problems with obtaining equipment, are there any other solutions to the problem that should be considered or is there a properly equipped workover rig available?

B.

Advantages and Disadvantages What are the advantages of the selected technique? Are there any limitations to it? Are there any particular hazards? If another option has been identified, ask the same questions of it.

C.

Economics Since workover costs are expensed at Saudi Aramco, there isn't much point to this exercise unless you have identified one or more options for the workover that the WOCP didn't address. When comparing economics, do not overlook any rental or services costs. These may vary between options and could become significant.

D.

Other Considerations Whether or not the rig can handle the job is a major consideration. For example, is the rig capable of jacking far enough out of the water or cantilever out far enough to center properly over the well to be worked over? Keep in mind that the rig's hook load decreases the farther out the cantilever is extended.

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JOB EXECUTION I.

THE WORKOVER PROCEDURE A workover procedure should communicate all the essential details of the workover operation. Omissions based on the premise that they are common knowledge can lead to costly mistakes. In Saudi Aramco, a workover procedure is made up of two sections, the program and any number of attachments. The most common items in these sections are summarized in the table below: A.

Workover Program Section

ITEM Objectives Location & Elevations

Contacts

Well History Current Status

Procedure

Approvals

DESCRIPTION Major operations that are to be performed during the course of the workover. Coordinates, water depth or surface elevation, original drill floor (ODF) elevation and ODF to tubing spool measurement. The names, office and home phone numbers of the drilling/workover, reservoir and production engineers plus any others required. A brief history of the well . Includes drilling, workovers and diagnostics, etc. Status at the time the procedure is approved. Shut-in tubing and annuli pressures with the dates they were observed. A step-by-step procedure including volumes, densities, lengths, cement slurries, completion fluids, etc. Approval signature lines for Operations and Engineering. Table 2 (a)

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B.

Program Attachment Section

ITEM Well Data Sheet

Wellhead Sketches Tubing Details Wellbore Cross section

Directional Surveys (if applicable) Platform Sketch (if applicable) Other Attachments (if applicable)

DESCRIPTION Reiterates well location and elevation information. Includes completion type, total depth and tubing size, wellbore pressures, mud weights annuli pressures and hole capacity. Includes, both, current and proposed. Existing tubing and packer details and a sketch. A drawing, usually from the well database, showing the existing wellbore. Depths, obstructions, etc. If a sidetrack or deepening is to be performed, the surveys are required. Includes a North arrow, the production facilities and the well bay with the workover candidate clearly marked. Special instructions for a specific technique, such as mixing a diesel-oil bentonite plug or a running procedure for a premium thread. Table 2 (b)

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II.

FIELD OPERATIONS As mentioned earlier, the workover engineer's job is not finished once the procedure is approved. He must now monitor the field operation to ensure that the workover objectives are being met. For routine workovers, the contractor's representative may suffice. Other operations may require a company representative. Some examples would include extensive fishing, a sidetrack or deepening, casing leak repairs, squeezing and reperforating. In addition to the supervision of the operation, the workover engineer may be required to witness certain parts of the workover. At the present time, these include running production casing or a liner and perforation of the well.

FOLLOW UP I.

ANALYSIS OF RESULTS The success or failure of a specific operation during a workover is often valuable information that can be used to prepare future workover procedures. All the details and circumstances surrounding a failure should be collected so that the cause can be determined and avoided in the future. On the other hand, the unexplained success of a given technique should be analyzed to determine the contributing factors.

II.

RECORD KEEPING Saudi Aramco has a well established mechanism for recording the events that take place during its drilling and workover operations. This is the Completion Report. At first, this report was typed by hand, the wellbore and completion sketches hand-drawn and placed in the wellfile. In 1984, the daily morning reports were beginning to be entered into a mainframe database. By 1986, the Completion Reports were being issued directly from this database. Today, the report consists of six sections. The table below summarizes the data included.

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SECTION Cover Page

Summary of Operations

Daily Workover Summary Casing and Cementing Details

Tubing Detail Report Wellhead Sketch Wellbore Cross section

DATA INCLUDED Duration & Purpose of Workover Area, Field, Name, Location & Elevation Casing, Cementing & Perforating Records Plug & Liner Hanger Information Comments, Drilling Foremen & Approvals Days, Depths, Plug & Completion Information Logging and Perforation Details Drilling Foreman & Engineer Time Distribution & Discussion Day-by-day Summary Casing Size, Weight, Grade & Lengths Float Equipment & Centralizer Details Slurry & Displacement Information OD, ID, Top & Length on all items run in the completion string. "After Workover" Wellhead Information "After Workover" Wellbore Sketch Table 3

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TABLE OF CONTENTS INTRODUCTION..........................................................................................................1 WELL KILLING METHODS......................................................................................2 1. Bullheading ....................................................................................................2 2. Circulate.........................................................................................................3 3. Lubricate and Bleed .......................................................................................3 4. Snub and Circulate.........................................................................................4 SURFACE WELL CONTROL EQUIPMENT..........................................................5 1. Annular Preventers ........................................................................................5 2. Ram Type Preventers.....................................................................................7 3. BOP Stack......................................................................................................9 4. Choke Manifold .............................................................................................9 5. Other Equipment............................................................................................10 WELL CONTROL SAFETY........................................................................................11 1. Mixing Mud & Kill Fluids.............................................................................11 2. Killing The Well ............................................................................................11 3. Nippling up BOP equipment..........................................................................11

Run Date: 9/2/2006

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INTRODUCTION Well killing is usually the first step of a conventional workover. It may even be done before the rig moves on location. The well must be dead before tubulars and other equipment can be pulled from the well. A dead well is one in which the density of the fluid in the tubing and/or annulus is high enough to overcome the formation pressure.

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WELL KILLING METHODS 1.

BULLHEADING As mentioned in the WORKOVER PLANNING chapter, bullheading consists of a pipe connected directly to a well's Xmas tree or wellhead with the kill fluid being pumped directly into the tubing or annulus, displacing the produced or other fluids from the top down. The example below shows the tubing, only, being killed by the bullhead method.

Figure 1 SHUT-IN TUBING PRESSURE ANNULUS PRESSURE 0

SHUT-IN TUBING PRESSURE ANNULUS PRESSURE 0

0

0

START PUMPING KILL FLUID DOWN TUBING

KILL FLUID REACHES THE PERFORATIONS (WELL IS DEAD)

(A) START OF KILL

(B) KILL COMPLETE

BULLHEAD KILL PROCEDURE Note that the annulus pressure is unaffected. Although some are completed with brine as a packer fluid, most Saudi Aramco wells are completed using inhibited diesel as a packer fluid. With the tubing killed, the tubing-casing annulus will be under-balanced and must be killed before the tubing can be removed from the well. This is normally accomplished using the circulating method.

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The main advantage of bullheading is its low cost. Since a rig is not required, the tubing can often be killed before the rig moves onto location. This approach assumes that the tubulars are in good condition. If not, control over the placement of the kill fluid is compromised. A second limitation is the risk of formation damage. If there is any scale or debris inside the tubing, it may end up in the perforations causing skin damage. 2.

CIRCULATE Regardless of whether or not the tubing has been killed, the packer fluid must be circulated out before the completion equipment can be pulled. This is most often done by making holes in the tubing just above the packer using either a mechanical type tubing puncher run on slick line or a soft perforating shot run on electric line. The kill is then done by pumping down the tubing and taking returns through the tubing head's side outlet. Mechanical punchers and soft shots are discussed in the chapter on PERFORATING in the COMPLETIONS section of this manual. If it is feasible, circulating is the least damaging way to kill a well.

3.

PUMP KILL FLUID DOWN THE TUBING

TAKE RETURNS THROUGH THE TUBING HEAD SIDE OUTLET

CIRCULATING KILL PROCEDURE Figure 2

LUBRICATE AND BLEED This method is only used if the circulation or bullhead methods are not feasible. The lubricate and bleed method is rarely used at Saudi Aramco. The technique consists of pumping a small volume of very dense fluid into the tubing. Then waiting a period of time for it to fall. The well is then opened and the Page 3

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production fluids and/or gas is bled off until some of the dense fluid is recovered. The process is repeated until the entire tubing volume is displaced with the dense fluid and the well is dead. 4.

SNUB AND CIRCULATE

Although snubbing has not been performed in Saudi Aramco for some time, a brief description of the process follows. Small diameter tubing is forced into the well under pressure. Once it is in place, the tubing can be killed by circulating down the small tubing and taking returns on the small tubing / production tubing annulus. A description of the snubbing process and sketch of the equipment used can be found in the INTRODUCTION TO WORKOVERS chapter of this segment. The well can also be killed by using a coiled tubing unit.

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SURFACE WELL CONTROL EQUIPMENT One of the most important aspects of workover well control is the proper selection and use of surface equipment for pressure control. While this information is covered in detail in any Well Control class, a brief summary follows. 1.

ANNULAR PREVENTERS

Annular preventers are characterized by their elastomer sealing elements. When closed, the element swells into the wellbore sealing on whatever is in the hole at the time. A special design feature of annular preventers is that they will maintain a seal while allowing the drill string to be stripped through the preventer. This is perhaps its greatest advantage as it is often required to strip back to bottom to kill a well that has kicked. The following are two examples of annular preventers.

CAP ELASTOMER SEALING ELEMENT OPENING CHAMBER LIFTING EYES CLOSING CHAMBER PISTON BODY

ANNULAR PREVENTER GK Hydril

Figure 3 Page 5

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CAP ELASTOMER SEALING ELEMENT

PISTON BODY

ANNULAR PREVENTER MSP-30" Hydril

Figure 4 Although many annular preventers will seal on an open hole, this practice is not recommended since it can damage the element. Rotating for extended periods of time with the annular closed will also damage the element. Where it is desired to rotate the drill string with the annular closed, a rotating head should be considered. A specialized variety of annular preventer, the rotating head, differs from other annulars in that they have a stripper rubber designed to seal around the kelly allowing vertical movement. Chevron seals prevent wellbore fluids from leaking around the rotating sleeve. These units are designed to operate with pressures of 1000 psi or less on the annulus. The rotation assembly is locked into the body with a quick release bonnet, allowing normal connections to be made.

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2.

RAM TYPE PREVENTERS

To provide a more reliable seal under high pressure conditions, ram type preventers are used. These differ from annular preventers in that they are usually designed to seal on a specific size of pipe. The variable bore ram is the exception and will be discussed later in this section. In addition to their higher pressure service capabilities, ram type preventers are also easier to service and usually shorter than annular type blow-out preventers.

RAM ASSEMBLY (PIPE RAM SHOWN)

BONNET BODY

LOCKING SCREW

RAM PREVENTER Cameron Type-U

Figure 5 Ram preventers seal by forcing two elements to make contact in the annulus. They have rubber packing to effect a complete seal. There are three basic types of rams in service today: pipe, blind and shear rams. Blind rams will shut the well in when there is no pipe in the hole. Shear rams will shut the well in when there is drill pipe in the hole by shearing off the drill pipe. Examples of each type are shown below.

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PIPE RAM ASSEMBLY

BLIND RAM ASSEMBLY

(one-half of pair shown)

(one-half of pair shown)

SHEAR RAM ASSEMBLY (matched pair shown)

Figure 6 The exception to the three basic types of rams is the variable bore ram. This ram can seal on different sizes of pipe, providing the difference isn't too great. These can be very useful in workovers where a tapered string of tubing is used. The double ram consists of two sets of rams in one body. This arrangement is very short and weighs less than two single ram preventers stacked one on top of the other. Where rig substructure clearance is limited or weight is a concern, the double-ram BOP is usually selected.

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3.

BOP STACK

Any combination of ram type preventers and an annular preventer is referred to as a blowout preventer (BOP) stack. Where rams are used, the normal practice is to include at least two. The figure shows one configuration. The blind rams are normally placed on the top of the pipe rams. This allows the well to be closed in using the blind rams with the drill pipe hung off on the pipe rams. There are many ways to arrange a BOP stack. The arrangement chosen will depend on the tubulars being used, the anticipated pressure at surface and the type of workover being performed.

ANNULAR BLIND RAMS PIPE RAMS KILL LINE CHOKE LINE

The important things to remember in workover well control are: a.

b.

4.

The tubing and annular volumes are much smaller than in drilling. Therefore, things can happen much faster than expected and a small problem can become a serious well control situation very quickly.

TYPICAL BOP STACK Figure 7

The produced fluids are usually flammable and, in the case of hydrogen sulfide gas, highly toxic. Therefore, proper caution must be exercised, and personal protective equipment used.

CHOKE MANIFOLD

The choke manifold is a system of pipes and valves that allows the safe, controlled, discharge of wellbore fluids away from the rig. Page 9

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TO TRIP TANK TO FLARE REMOTELY OPERATED HYDRAULIC CHOKE

4" CHOKE LINE FROM BOP STACK TO SHALE SHAKER PIT OR GAS BUSTER

PRESSURE GAUGE MANUAL CHOKE TO SHALE SHAKER PIT OR GAS BUSTER

NEEDLE VALVE

TYPICAL CHOKE MANIFOLD Figure 8 The manifold gives the rig crew a way to accurately maintain back-pressure on the well while flowing or circulating out wellbore fluids. The details of how to operate a choke manifold in a well control operation are covered in any Well Control course and is beyond the scope of this manual.

5.

OTHER EQUIPMENT

Depending on the nature of the workover, other equipment may be required. The back pressure valve, for example, is one item that is often used in conventional workovers. It is installed in a recess of the tubing hanger as a safety measure while removing the tree and nippling up the BOP stack.

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WELL CONTROL SAFETY 1.

MIXING MUD & KILL FLUIDS

a.

All personnel should be informed of the hazards involved with mixing toxic or caustic chemicals. i) ii) iii)

Proper protective clothing should be worn. When chemicals are to be mixed with water or drilling mud, mix them into the water or mud to minimize the potential for a violent chemical reaction. Eye wash facilities are to be located near the mixing area.

Material Safety Data Sheets should be on file at the rig site for all materials in use. b.

2.

3.

Mud materials and chemicals should be stacked to a safe and reasonable height to minimize handling.

KILLING THE WELL

a.

A check valve should be installed in the pump line near the wellhead and a choke manifold should be used to control the flow in the return line.

b.

The flare pit should be down wind from the wellhead. The flare line should be staked down to the ground adequately to prevent it from moving (or whipping) when flaring high pressure gas and oil.

c.

Personnel should remain clear of pressured lines during the kill operation.

NIPPLING UP BOP EQUIPMENT

a.

Be sure the well is dead and the BOP is ready to install before the XMAS tree is removed.

b.

Install a back pressure valve in the tubing hanger as an additional safety measure if required before removing the XMAS tree.

c.

The BOP stack should be properly bridled in order to safely position it without loss of time. Personnel should stay clear of suspended loads.

d.

The BOP's should be tested to the maximum anticipated surface pressure as soon as practical after being installed, then at regular periods thereafter.

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e.

If the well is left temporarily unattended during the workover, a fullopening safety valve should be installed in the string and the BOP closed.

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RUNNING and CEMENTING LINERS

TABLE OF CONTENTS INTRODUCTION ...............................................................................................................1 LINER EQUIPMENT..........................................................................................................2 FLOAT (or) SET SHOE ..........................................................................................2 FLOAT COLLAR....................................................................................................2 LATCH COLLAR ...................................................................................................2 LINER HANGER ....................................................................................................3 Mechanical Liner Hangers...........................................................................3 Hydraulic Liner Hangers .............................................................................4 Rotating Liner Hangers................................................................................4 LINER HANGER SETTING TOOL.......................................................................5 PUMP DOWN PLUG..............................................................................................5 LINER WIPER PLUG .............................................................................................5 SETTING COLLAR AND TIE-BACK RECEPTACLE ........................................6 TIE-BACK STEM ...................................................................................................6 RUNNING LINERS ............................................................................................................7 PRECAUTIONS ......................................................................................................7 PROCEDURE..........................................................................................................7 CEMENT FUNDAMENTALS .........................................................................................11 HISTORY OF PORTLAND CEMENT ................................................................11 MANUFACTURE OF PORTLAND CEMENT ...................................................11 COMPONENTS OF PORTLAND CEMENT.......................................................11 API CEMENT CLASSES......................................................................................12 Class A:......................................................................................................12 Class B: ......................................................................................................12 Class C: ......................................................................................................12 Class D:......................................................................................................12 Class E: ......................................................................................................12 Class F: ......................................................................................................12 Class G:......................................................................................................13 Class H:......................................................................................................13 CEMENT SETTING PROCESS ...........................................................................13 EFFECT OF TEMPERATURE .............................................................................14 EFFECT OF PRESSURE ......................................................................................14 CEMENT PROPERTIES...................................................................................................15 THICKENING TIME ............................................................................................15 FLUID-LOSS RATE .............................................................................................16 DENSITY ..............................................................................................................17 FREE WATER.......................................................................................................17 COMPRESSIVE STRENGTH ..............................................................................18

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FACTORS AFFECTING JOB DESIGN...........................................................................19 CHEMICAL ENVIRONMENT ............................................................................19 BOTTOM-HOLE STATIC TEMPERATURE......................................................19 BOTTOM-HOLE CIRCULATING TEMPERATURE.........................................20 PORE PRESSURES ..............................................................................................20 FORMATION PERMEABILITY .........................................................................20 FORMATION INTEGRITY .................................................................................21 HOLE GEOMETRY..............................................................................................21 CEMENT SLURRY DESIGN...........................................................................................22 CEMENT ADDITIVES.........................................................................................22 WATER REQUIREMENTS..................................................................................22 ACCELERATORS ................................................................................................23 RETARDERS ........................................................................................................23 FLUID-LOSS ADDITIVES ..................................................................................24 ADDITIVES TO DECREASE DENSITY ............................................................25 ADDITIVES TO INCREASE DENSITY .............................................................26 DISPERSANTS .....................................................................................................26 SILICA...................................................................................................................27 DEFOAMERS .......................................................................................................27 PLANNING A CEMENT JOB..........................................................................................28 CEMENT VOLUME CALCULATIONS .............................................................28 SPECIFYING A SLURRY....................................................................................29 SPACER FLUIDS .................................................................................................29 DISPLACING FLUID ...........................................................................................29 PRIMARY CEMENTING OPERATIONS .......................................................................30 MUD CONDITIONING........................................................................................30 MUD DISPLACEMENT.......................................................................................30 LINER MOVEMENT............................................................................................31 PUMPING RATE ..................................................................................................31 PRESSURE CONSIDERATIONS ........................................................................31 DISPLACEMENT VOLUME ...............................................................................31 AFTER-CEMENTING CONSIDERATIONS ......................................................32 WAITING-ON-CEMENT TIME ..........................................................................32

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INTRODUCTION A liner is a casing string run and cemented in a well with its top below the surface. The objectives of running liners during workovers are: 1. To shut off the production of undesireable fluids (water or gas) from the producing interval. 2. To scab off leaks or corroded sections of the casing. A liner set across the producing zone is called a production liner, Fig. (1). A tie-back liner or "scab liner" is run to extend an existing liner further up the well to cover damaged or corroded casing as shown in Fig. (2).

4 - 1 / 2" x 7 " L ine r H a ng e r

C o r r o de d P ip e S e c t io n 4 - 1 / 2" T ie - B a c k L ine r 4 - 1 / 2" x 7 " L ine r H a ng e r

4 - 1 / 2" x 7 " L ine r H a ng e r

7 " C a s i ng

4 - 1 / 2" P r od u c t io n L ine r

Fig. ( 1 ) . Pr o duc t ion Lin er

7 " C a s i ng

4 - 1 / 2" P r od u c t io n L ine r

Fig. ( 2 ) . Pr o duc t ion Lin er wit h T ie- Back Lin er acr o ss co r ro de d 7 " casing .

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LINER EQUIPMENT A liner assembly consists of the following parts FLOAT (OR) SET SHOE The float (or) set shoe, Fig. (3), is commonly used on the bottom of the liner to guide the string into the hole and directs it away from any ledges. It has a spring-loaded back pressure valve to prevent fluid from entering the liner while the pipe is run in the hole or backflow following cementing operations. The outside body is made of steel of the same strength as the casing. The back pressure valve is made of plastic and enclosed in high-strength concrete. The set shoe is different from the conventional float shoe in that the shoe has four (4) ribs, oriented at 900 to each other, protruding from the bottom that provides a grip on the bottom of the hole when rotating free of the liner. The cast iron nose at the bottom of the shoe is made for easy drillout. Fig. 3 Float Shoe

FLOAT COLLAR A float collar, Fig. (4), is normally placed two to three joints above the float shoe. The float collar also has a back pressure valve similar to the one in the float shoe to prevent the cement slurry from backflowing into the liner. The float collar serves as a back-up to the float shoe in the event the back pressure valve of the float shoe fails to provide the necessary seal.

Fig. 4 Float Collar

LATCH COLLAR The latch collar, shown in Fig. (5), or landing collar is run one to two joints above the float collar. It serves to catch and seal the liner wiper plug. It keeps the wiper plug from moving uphole and seals pressure from below. It also prevents the wiper plug from turning while drilling out. The space between the latch collar and float shoe serves as a trap for any contaminated cement that may accummulate from the wiping action of the liner wiper plug. The contaminated cement is thus kept away from the shoe, where the best cement bond is required.

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Fig. 5: Latch Collar

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LINER HANGER The liner hanger is connected to the top of the liner and is set in the casing to suspend the liner in the well. Liner hangers may be mechanically or hydraulically set. In addition, certain designs allow for rotation of the liner during the cementing operation. Mechanical Liner Hangers The mechanical liner hanger consists of a swivel, hanger, setting collar, and tie-back receptacle. The mechanical-set liner hanger is available with a one piece integral barrel for maximum pressure integrity. Liner hangers are set by picking up on the liner and rotating to disengage the J-slot. As the liner is lowered, springs hold the cage stationary. This allows the barrel to move downward engaging the cone against the slips. This action moves the slips outward against the casing wall. The swivel, shown in Fig. (6), is connected at the bottom of the hanger. It allows for the left-hand rotation of the hanger which is necessary to disengage the J-slot and set the liner without requiring liner rotation. This permits the setting of the hanger even if the liner becomes stuck. Only the setting collar, hanger and setting string are rotated when the hanger is set.

Fig. 6: Liner Swivel

If the liner hanger cannot be set, the swivel contains a clutch to release the setting tool. The liner is set on bottom. The weight of the setting string, applied on the swivel, engages this clutch against right-hand rotation, permitting release of the setting tool.

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The hanger, shown in Fig. (7), is either a single cone or a tandem cone mechanically set hanger. The hanger is set by mechanical manipulation of the drill pipe. It consists of drag springs, slip cone, slips, and a J-slot mechanism. The slips are designed such that there is enough flow area for fluid circulation around the hanger. The tandem cone, with staggered slip alignment, is also available for extra bypass and additional hanging capacity. Hydraulic Liner Hangers The hydraulically set liner hanger uses pump pressure to move the slips up the cone for engagement with the casing. The hanger does not have drag springs and does not require surface manipulation for setting the slips. The hydraulically set hanger is preferable for running liners in deep or deviated holes where it is difficult to transmit surface manipulation of drill pipe downhole.

Single Cone

Rotating Liner Hangers Rotating liner hangers can be set hydraulically or mechanically. Rotation of the liner during cementing aids to a more efficient mud displacement behind the liner. Rotating liner hangers are of two general types, requiring:

Tandem Cone Fig. 7: Mechanical Liner Hanger

1. Slip engagement and release of the setting tool prior to cementing. 2. Slip engagement and setting tool release after cementing is completed. This type of hanger will also allow reciprocation of the liner while cementing.

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RUNNING and CEMENTING LINERS LINER HANGER SETTING TOOL This tool is normally furnished by the liner hanger service company and is used to set the hanger in the casing. The setting tool includes a retrievable packoff bushing (RPOB), which eliminates the need for drilling out a bushing after cementing operations are complete. It provides a firm seal between the setting tool and the liner and is retrieved with the setting tool after cementing. The setting tool performs the following functions 1. It connects the drillpipe to the liner. The tool is connected to the setting collar below the tie-back receptacle. 2. It forms a pressure tight seal inside the tie-back receptacle by using a pack-off bushing. The seal prevents the cement slurry from circulating around the setting tool to the DP Casing annulus. 3. It carries the weight of the liner. 4. It provides an attachment for the liner wiper plug on its tailpipe stinger. A Texas Iron Works setting tool is shown in Fig. (8). PUMP DOWN PLUG The drill pipe pump down plug has a series of four rubber wipers of different sizes to allow the plug to wipe the inside of the drill pipe, tool joints and liner setting tool. The plug is dropped into the drill pipe following the cement. It is displaced down hole by the mud until it seats securely into the liner wiper plug. Pressure is applied to shear the liner wiper plug from the setting tool and both plugs move down as a single unit until they latch into and seal in the latch collar. The pump down plug and liner wiper plug are shown in Fig. (9). LINER WIPER PLUG

Fig. 8: Liner Hanger Setting Tool

Fig. 9: Pump Down Plug and Liner Wiper Plug

In conjunction with the drill pipe pump down plug, the liner wiper plug keeps mud separated from the cement and cleans the cement out of the liner as it moves down hole. The plug is normally shear-pinned to the bottom of the setting tool. Page 5

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RUNNING and CEMENTING LINERS SETTING COLLAR AND TIE-BACK RECEPTACLE A combination liner setting collar and tie-back receptacle are shown in Fig. (10). The collar is connected at the upper end of the liner hanger. The setting collar has a left-hand thread for connecting to the liner hanger setting tool. Disengagement of the setting tool from the setting collar requires 12 to 15 right-hand turns of the setting string. The tie-back receptacle is a six foot (6 ft) section of pipe which has a polished bore. It is used to extend an existing liner further up the hole or to the surface. Its polished bore facilitates the entry and seating of the Tie-back stem seal nipple when a tie-back is required.

Fig. 10: Setting Collar and Tie-Back Receptacle

TIE-BACK STEM The tie-back stem, shown in Fig. (11), is run at the bottom of a tie-back liner instead of the float shoe. It is used only in cases where an existing liner is to be extended further up the hole. It has a series of O-ring seals and a lead faced locator shoulder. The O-rings form a seal in the tie-back receptacle. The practice in Saudi Aramco is to remove the top O-ring and drill four (4) - 1" circulating holes above the bottom O-rings to permit circulation. The tie-back stem is inserted into the tie-back receptacle of an existing liner hanger before the liner is cemented.

Fig. 11: Tie-Back Stem

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RUNNING LINERS PRECAUTIONS Before a liner is run, attempts should be made to ensure that full circulation is established in the well. If the purpose of the liner is to scab off a casing leak, attempts must be made to squeeze the leak with cement by the Bradenhead method or by using a cement retainer. After the cement is drilled out, the leak should be pressure tested to ensure it can withstand the hydrostatic pressure of the cement column above it. This will ensure that the cement will rise behind the liner and will not be lost into the leak. Prior to running the liner in the hole, the operator should check all connections on the float shoe, float collar, latch collar, and liner hanger and make sure they are of the proper type and size liner to be run. PROCEDURE A procedure for running and setting the liner is outlined below 1. Run the required length of liner with the float collar and latch (landing) collar spaced two (2) joints and four (4) joints respectively above the float shoe. If a tie-back liner is run, a tie-back stem should be run in place of the float shoe. The bottom five (5) joints should be made up by using a thread-locking compound. Pump through the first few joints to make sure the float equipment is working properly. 2. Fill each 1000 feet of liner with mud or workover fluid while running in hole. 3. Install a centralizer on each of the bottom five (5) joints and every third joint thereafter in vertical holes. In deviated joles, enough centralizers should be installed to give about 70% stand-off between the liner and the casing or the open hole. 4. Install the liner hanger and setting tool. Record the weight of the liner using the rig weight indicator. 5. Drift the drill pipe to make sure it is free of obstructions that may prevent the passage of the pump down plug. 6. Run the liner on drill pipe at a speed of 1-2 min. per stand while in casing and 2-3 min. per stand while in open hole. Install the cement manifold and circulate and wash the last joint to bottom. Slowly reciprocate the liner in 15 20 ft. strokes while circulating and conditioning the mud or workover fluid. Shut down the pumps and hang the liner a few feet from bottom. 7. Rotate the setting tool to the right to release it from the hanger. Pick up the Page 7

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RUNNING and CEMENTING LINERS drill pipe to ensure the setting tool is free, then slack off on the drill pipe and leave 10,000 lbs. weight on the liner hanger.

8. Circulate bottoms up one hole volume. If a rotating liner hanger is used, rotate the liner at 15 rpm while circulating. Pump a 10 bbl. water spacer ahead of the cement. 9. Mix and pump the cement slurry. Release the pump down plug into the drill pipe and displace the cement with mud or the workover fluid. Slow down the pumping rate before the pump down plug reaches the liner wiper plug. Watch for the increase in pressure when the wiper plug shears from the setting tool. Continue pumping until both plugs reach and land in the latch collar. Record the pressure at which the plug bumps the latch collar. Stop pumping and pull out of the hole. As the setting tool seals are removed from the hanger, any excess cement above the hanger will flow back into the drill pipe from the annulus. This back flow or U-tube effect can be observed at the surface and it is a good indication of how much cement is above the liner.

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CEMENT FUNDAMENTALS HISTORY OF PORTLAND CEMENT Although cementatious materials have been used since ancient times, the invention of modern Portland cement is usually attributed to Joseph Aspdin, an Englishman, who filed a patent for Portland cement in 1824. He called it "Portland" cement because it resembled the limestone quarried in Portland, England. MANUFACTURE OF PORTLAND CEMENT Portland cement is manufactured with materials and methods that have changed little since Aspdin's time. The material is prepared by sintering fixed proportions of calciumcontaining materials (limestone, chalk, seashells) with aluminosilicates (clays) in a kiln at 2600-2800 0F (1425-1535 0C). The resulting material, clinker, is then cooled and interground with gypsum which controls the setting time of the cement. Small percentages of other substances, such as sand, bauxite or iron ore are sometimes used in the kiln feed to adjust the properties of the clinker. COMPONENTS OF PORTLAND CEMENT Portland cement consists primarily of the four chemical compounds shown in Table I. All grades or classes of Portland cement contain these four compounds. However, the relative percentages of the compounds can vary, depending on the feed materials in the manufacturing process. The relative percentages of these compounds along with the grind of the cement have been found to strongly affect the cement performance. Table I Principal Components of Portland Cement

Compound Tricalcium Silicate Dicalcium Silicate Tricalcium Aluminate Tetracalcium Aluminoferrite Other Oxides

Standard Formula Designation C3S 3CaO-SiO2 2CaO-SiO2 C2S 3CaO-Al2O3 C3A 4CaO-Al2O3-Fe2O3 C4AF

Typical %(Wt) 50% 25% 10% 10% 5%

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API CEMENT CLASSES Specifications for cements used in oil-well applications have been written by the American Petroleum Institute (API). These specifications are found in "API Specifications for Materials and Testing for Well Cements", (API Spec 10). There are eight API cement classes. Table II provides a summary of the chemical composition, grind and special properties of some of these API cements. Most oil-field operations use Class A, C, G, or H. The different classes of API cement and their compositions are shown below and in Table II. Class A: Intended for use from surface to a depth of 6,000 ft when special properties are not required. Available only in Ordinary type (similar to ASTM C150, Type I). Class B: Intended for use from surface to a depth of 6,000 ft when conditions require moderate to high sulfate resistance. Available in both Moderate type (similar to ASTM C150, Type II) and High Sulfate Resistant types. Class C: Intended for use from surface to a depth of 6,000 ft when conditions require high early strength. Available in Ordinary type and in Moderate and High Sulfate Resistant types. Class D: Intended for use at depths from 6,000 to 10,000 ft and at moderately high temperatures and pressures. Available in both Moderate and High Sulfate Resistant types. Class E: Intended for use at depths from 10,000 to 14,000 ft and at high temperatures and pressures. Available in both Moderate and High Sulfate Resistant types. Class F: Intended for use at depths from 10,000 to 16,000 ft and at extremely high temperatures and pressures. Available in High Sulfate Resistant types.

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Class G: Intended for use as a basic cement from the surface to a depth of 8,000 ft as manufactured. With accelerators and retarders it can be used at a wide range of depths and temperatures. It is specified that no additions except calcium sulfate or water, or both, shall be interground or blended with the clinker during the manufacture of Class G cement. Available in Moderate and High Sulfate Resistant types. Class H: Intended for use as a basic cement from the surface to a depth of 8,000 ft as manufactured. This cement can be used with accelerators and retarders at a wide range of depths and temperatures. It is specified that no additions except calcium sulfate or water, or both, shall be interground or blended with the clinker during the manufacture of Class H cement. Available only in Moderate Sulfate Resistant type. Table II Typical Composition and Properties of API Classes of Portland Cement API Class

Compounds (percentage) C3S C2S C3A C4AF

Wagner Fineness (sq cm/gm)

A B C D&E G&H

53 47 58 26 50

1,600 to 1,800 1,600 to 1,800 1,800 to 2,200 1,200 to 1,500 1,600 to 1,800

24 32 16 54 30

8+ 58 2 5

8 12 8 12 12

Property High Early Strength Better retardation Low heat of hydration Resistance to sulfate attack

CEMENT SETTING PROCESS When water is added to Portland cement, a chemical reaction (hydration) takes place that eventually causes the cement particles to bond together to form an impermeable, hard, rock-like material. The strength and impermeability of the cement is due to the formation of a dense network of interlocking fibers. Two of the byproducts of the cement hydration are calcium hydroxide [Ca(OH)2] crystals and heat. The Ca(OH)2 crystals cause the cement to be very basic (high pH). Because of this, a cement sheath will provide corrosion protection for the steel casing. The heat given off during the hydration reaction is sometimes used to detect the top of cement by temperature logging. The time at which the slurry achieves its maximum temperature depends on the particular slurry and its curing conditions, but generally is between 3 and 12 hours. Page 13

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RUNNING and CEMENTING LINERS EFFECT OF TEMPERATURE Temperature is perhaps the most important factor that affects the performance of cement in a well. As with most chemical reactions, the hydration of cement is accelerated by increasing temperature. This effect is illustrated in Fig. (12), which shows the effect of temperature on the thickening time of the cement. The thickening time is the length of time necessary for the cement to reach a certain viscosity in a standard measuring device and is a measure of the rate of hydration. Fig. 1 shows that, as the temperature increses, the thickening time decreases, indicating that the hydration reaction rate has increased.

EFFECT OF PRESSURE The effect of pressure on the thickening time of a Class H slurry is shown in Fig. (13). Generally above 5000 psi, increasing pressure increases the rate of reaction and thus decreases the thickening time. The effect of pressure, however, is not as significant as the effect of temperature. Page 14

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CEMENT PROPERTIES Cement has a number of measurable properties that can be used to predict its performance in a well. THICKENING TIME Perhaps the most important property of a cement slurry for well applications is its thickening time. The thickening time provides an indication of the length of time the slurry will remain pumpable. A thickening time that is too short can result in the cement setting inside the casing, tubing or drill pipe with severe economic consequences. A thickening time that is too long, on the other hand, can necessitate an unduly long and costly delay waiting for the cement to set. The API defines the thickening time of a cement slurry to be the time required for the slurry to reach 100 Bearden units of consistency (Bc), using the methods of API Spec 10. One hundred Bearden units of consistency is roughly equivalent to a viscosity of 100 poise. Cement is considered to be unpumpable at this viscosity. The thickening time is measured in a device called a consistometer. Consistometers are designed so that the consistency of the cement slurry can be continually monitored while the cement is subjected to a temperature, shear, and pressure history that simulates what the cement will see as it is pumped downhole. Since the thickening time depends not only on the slurry being tested, but also on the simulated downhole conditions, it is important to simulate these conditions as accurately as possible. The API has published a series of cementing schedules, based on field measurements, that can be used to simulate the downhole conditions for many wells. There are different API schedules, depending on the type of job (casing, liner, or squeeze), well depth, and the bottom hole static temperature. The API schedules have proven to be accurate and reliable over many years. However, there are certain situations where the API cementing schedules may not be appropriate. If unusual temperature conditions are encountered, such as geothermal gradients outside the 0.9-1.9 0F/100 ft API range, highly deviated wells or offshore cementing through long risers, it may be necessary to develop a cement testing schedule using computer simulation. The thickening time of a cement slurry is generally selected to be equal to the job time plus a safety factor. The job time is the estimated time required to mix the slurry and pump it into place. Usual practice is to employ a 50-100% safety factor, depending on the type of job and the experience in the area. Through the use of the appropriate additives, well cement slurries have been designed with thickening times as short as 60 minutes or as long as 12 hours. Page 15

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FLUID-LOSS RATE The rate at which a cement slurry loses water through a permeable barrier when a differential pressure is imposed is referred to as filtration rate or fluid-loss rate. The water lost is the water that does not take part in the chemical reaction, that is, the water required for slurry fluidity. When this water is lost, the slurry viscosity increases, and the slurry loses its fluidity. In addition, as water is lost, the concentration of the cement particles increases. This may result in the formation of cement bridges in areas of narrow clearance. Thus, control of the fluid-loss rate of a slurry is necessary when: -

Cementing past very permeable intervals Cementing through narrow clearances (for example, liners) Squeeze cementing perforations or channels

Because the water lost is that used to maintain slurry fluidity, there is still sufficient water to complete the hydration reaction. In fact, because the cement particles are closer together, the strength of a slurry that has lost water is greater than the strength of the parent slurry (that is, the slurry that did not lose any water). Testing procedures for fluid loss rates are given in API Spec 10. There are two types of tests: 1) 2)

low temperature/low pressure (LT/LP) and the well-simulation or high temperature/high pressure (HT/HP)

The HT/HP fluid-loss rate of a neat cement slurry (i.e. just cement and water) is on the order of 1000-2000 cc/30 min. However, through the use of certain additives, the fluidloss rate can be adjusted to lower values. Table III presents some general fluid loss guidelines for different cementing operations. Table III Guidelines for Cement Slurry Fluid-Loss Rates

Operation Casing Cementing (past high permeability formations) Liner Cementing Squeeze Perforations or Repair Channels

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HT/HP Fluid-Loss Rate (cc/30 min.) 300-450 100 50

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DENSITY The density of a cement slurry is important for well control and the prevention of lost circulation while cementing. Density is also a useful field monitor of whether or not the slurry has been mixed with the designed water requirement. With the appropriate additives, cement slurries can be designed with densities ranging from about 8 ppg to about 20 ppg. Density of cement is measured by using either a unpressurized or pressurized mud balance. Because cement slurries often contain entrapped air, the pressurized mud balance provides a more accurate measurement. Errors of 1-2 ppg may occur using the unpressurized balance. In the field, in-line radioactive densitometers are often used to monitor density as the job is pumped.

FREE WATER The water added to the dry bulk cement is used both as a reactant in the hydration reaction and to provide fluidity to the slurry. When properly mixed, about 2/3 of the water is involved in the chemical reaction while 1/3 provides fluidity. All of the water in a properly mixed slurry, however, is either bound to the cement particles by chemical bonds or loosely attracted to the cement particles to form a stable suspension. If excess water is added, the cement particles will settle, leaving a layer of free water above the suspension. Excessive cement free water may lead to the formation of water pockets in a well, especially on the high side of deviated wells. Also, since excessive free water indicates solids settling, it may result in difficulty in mixing and displacing the slurry. Procedures for determining the free water content of a cement slurry have been specified by the API. There are two types of tests: a specification test conducted at 80 0F and a new (tentative) operating free water test conducted under downhole conditions. Under the API specification procedure, the maximum allowable free water is 1.4% (3.5 ml water from 250 ml of cement).

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COMPRESSIVE STRENGTH The compressive strength of set cement is the stress required to cause failure of the cement under a uniaxial compressive load. Fig. (14) shows the compressive strength development for a class A cement. The rate of strength development depends on the type of cement, the type and concentration of additives and the curing temperature. However, 75-80% of the ultimate compressive strength is generally achieved within 3 days. Compressive strength data are used for -

Establishing waiting-on-cement (WOC) time Determining optimum time to perforate, and Monitoring the stability of the set cement.

After cement has been pumped into the annulus, it must obtain sufficient strength so that further operations will not damage the cement sheath. Although the loadings placed on the cement downhole are not necessarily uniaxial compressive loads, the compressive strength has been found to be a convenient indirect measure of the ability of the cement to withstand these loads. The industry has generally accepted a value of 500 psi as the minimum required compressive strength before further drilling operations can commence. Tests have shown that a cement sheath with 500 psi can easily support the weight of the casing, even under rather poor bonding conditions. Similarly, laboratory experiments indicate that a well should not be perforated until the cement has achieved at least 2000 psi compressive strength. Above this value, the tests indicate that perforating does not damage the cement bond. The API testing procedures for determining compressive strength are in API Spec 10. These tests use conventional compressive strength testing equipment. An Ultrasonic Cement Analyzer (UCA) is also avialable for making non-destructive compressive strength measurements. The UCA is based on the measurement of the travel time of ultrasonic waves pulsed through a cement sample. While the UCA provides a useful time history of strength development, the actual values of compressive strength predicted by the UCA may not agree with conventional crush tests, especially for non-standard slurries. Therefore compressive strength values obtained from the UCA should be used with caution. Page 18

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FACTORS AFFECTING JOB DESIGN A number of factors influence the design of a primary or remedial cement job. The chemical environment and physical parameters such as bottom-hole temperature, formation integrity, pore pressures, formation permeability, and hole geometry all influence the behavior of the cement as it is pumped into place and as it solidifies.

CHEMICAL ENVIRONMENT The parameters which make up the chemical environment of the cement include: -

Mix Water Wellbore Fluids Formation Types Formation Fluids

Since the cement setting process is a chemical reaction, these factors may affect the behavior of the cement slurry and will sometimes even affect the properties of the cured cement. For example, inorganic salts in the mix water or formation may accelerate the cement set. The chemical composition of substances that will contact the cement should be kept in mind when designing the cement slurry and when planning the cementing operation.

BOTTOM-HOLE STATIC TEMPERATURE The bottom-hole static temperature (BHST) is one of the most important parameters to establish when designing a cement job. It is important for two reasons: -

The bottom-hole static temperature is often used to help estimate the temperature history that the cement will see as it is pumped into place. The temperature history strongly affects the thickening time of the cement.

-

The bottom-hole static temperature is usually the maximum temperature the cement will see during its lifetime. This temperature affects the rate at which the cement gains compressive strength. Also, if this temperature exceeds 250 0F, silica should be added to the slurry to prevent long term stregth retrogression.

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BOTTOM-HOLE CIRCULATING TEMPERATURE When designing a cement slurry, the bottom-hole circulating temperature (BHCT) is considered to be the temperature of an element of cement as it reaches the bottom of the hole. The BHCT will usually be less than the BHST because the inlet temperature of the cement at the surface is usually less than the BHST. For testing, the BHCT is taken to represent the highest temperature the slurry will see as it is pumped into place. The API thickening time testing procedure calls for holding the slurry at the BHCT after it has been brought up to temperature according to the appropriate schedule. There are two methods for determining the slurry temperature history: -

API Cementing Schedules Computer Simulation

To use the API Cementing Schedules, it is necessary to know only the type of job (casing, liner, or squeeze), the well depth, and the BHST. The job type and well depth are used to select the appropriate schedule type. The BHST is used to calculate the temperature gradient from: T. Grad. = (BHST-80) ÷ (Depth/100 ft) Once the temperature gradient is known, the particular schedule for that gradient can be identified. The BHCT is the highest (final) temperature for that gradient. As mentioned earlier, for unusual conditions such as highly deviated wells or offshore cementing through long risers, it may be necessary to use computer simulation to develop a cement testing schedule. PORE PRESSURES The pore pressures of the fluid-bearing formations also affect the design of the cement job. The density of the cement should be such that the hydrostatic pressure exceeds the pore pressure at all depths in the well. Generally, this will be the case if the cement density exceeds the drilling fluid density used to drill the well. FORMATION PERMEABILITY Another factor to consider when designing a cement job is the formation permeability that the cement may see. Long intervals of high permeability formation increase the potential for fluid loss from the cement. This may cause high slurry viscosities leading to increased pumping pressures and lost circulation or perhaps total loss of slurry mobility.

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It should be recognized, however, that the drilling fluid filter cake or particle plugging from the drilling fluid may reduce the permeability that the cement sees. However, any broach in this shield (i.e. by fracturing or erosion) could lead to disaster without the appropriate cement fluid-loss control. FORMATION INTEGRITY Another fundamental consideration in designing a cement job is formation integrity. The breakdown fracture pressure (often expressed as a fracture pressure gradient) will limit the density of the cement and/or the surface pumping pressure that can be used without losing returens. Losing returns while cementing is generally undesirable because -

Since some cement is lost to the formation, the top-of-cement (TOC) may not be high enough to cover all necessary zones.

-

A cement-filled fracture may adversely alter fluid flow in the reservoir.

-

Fracturing may cause undesired interzonal flow.

-

Fracturing could expose the cement to high permeability and lead to a costly bridge-off in the annulus.

-

Cement may plug up a naturally-fractured pay zone.

Information on formation integrity can often be obtained from the Daily Drilling Reports for the well. If returns were lost while drilling, the mud weight being used at the time provides some indication of the formation integrity. More direct information may be available from pressure integrity tests (PITs). HOLE GEOMETRY Hole geometry is another important factor in designing a cement job. The hole geometry can influence the cement job in a number of ways. For example: -

The hole size, casing size, and desired top of cement will affect the volume of cement to be pumped.

-

The amount of annular clearance may affect the amount of fluid loss control required to prevent bridging. It may also limit the pumping rate to prevent excessive friction pressures.

-

The angle of deviation may necessitate reducing the free water content of the slurry to prevent high-side water pockets. The deviation angle may also affect the placement of centralizers.

For many wells the hole geometry is obtained from caliper logs. In those wells where caliper logs are not run, the size of the annulus can be roughly estimated from a fluid caliper. In this method, the volume required to pump a marker pill down the casing and up the annulus is monitored. The annular volume is then obtained by subtracting the casing volume. Page 21

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CEMENT SLURRY DESIGN While there are a number of different API cement classes, class 'G' is the standard cement used in oil well cementing by Saudi Aramco. Neat cement slurry is a mixture of cement in water containing no other component. One sack (94 lbs) of class 'G' cement mixed with 5 gals. of water will yield 1.15 ft3 of cement slurry with a density of 118 lb/ft3. To achieve the desired cement properties, additives are usually required. Additives are substances added to change the properties of cement. CEMENT ADDITIVES There is a wide variety of cement additives. Most cement additives are powders or granular materials that are dry blended with the cement at the cementing service company bulk plant. By convention, the concentration of all additives, except sodium and potassium chloride, is expressed as a percentage of the weight of the dry cement used in mixing up the slurry. Thus, a cement containing 0.75% of Additive A contains 0.75 lbs of Additive A for every 100 lbs of dry cement used. The concentration of sodium chloride is usually expressed as a percent by weight of the mix water. In remote areas, liquid additives are sometimes used. This facilitates formulating different slurries without dry blending. Liquid additive concentrations are usually expressed in gal. per sack of cement. Density control is very important when using liquid additives, since variations in density can cause significant changes in the cement to additive ratio. WATER REQUIREMENTS All of the API cement classes have a recommended water requirement. This water requirement is based on the cement composition and grind. Too much water in a neat cement may lead to free water break out and mixing problems. Too little water may cause excessive viscosity and increase the rate of set. Some cement additives also have water requirements. Table IV lists the water requirements for some common additives. More extensive information on additive water requirements is usually available in cementing company literature. Table IV Water Requirements of Some Common Cement Additives Additive Bentonite Silica Flour Hematite

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Water Requirement 1.3 gal/ 2% in cement 1.6 gal/ 35% in cement 0.36 gal/ 100 lb sk

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RUNNING and CEMENTING LINERS Gilsonite

2.0 gal/ 50 lb

ACCELERATORS The additive most commonly used to accelerate the set of cement is calcium chloride (CaCl2). This compound is used in the concentration range 1 to 4%. The effect of CaCl2 concentration on thickening time is shown below in Fig. (15). Since CaCl2 is effective at relatively low concentrations, it is an economical additive. In addition, the accelerating effect of CaCl2 is predictable, and it has few adverse side effects. The presence of CaCl2, however, will decrease the effectiveness of some fluid loss additives. Another additive sometimes used as an accelerator is sodium chloride (NaCl). At concentrations below 18% (by weight of mix water), NaCl accelerates the set of cement. At greater concentrations, however, NaCl acts as a retarder. Sodium chloride is not compatible with most fluid loss additives. In addition, it increases the tendency for slurry foaming.

RETARDERS Retarders are additives that delay the set of cement. Most commercially available retarders are organic materials. Table V presents a summary of the generic types of organic retarders. Retarders are generally used in the concentration range of 0.1 to 1.0%. Since retarders are generally composed of heat-sensitive organic molecules, particular attention should be paid to the recommended temperature range for using the retarder. Information on specific retarders is available from cementing company literature. Another additive that will retard the set of cement at certain concentrations is sodium chloride (NaCl). At concentrations greater than about 18% (by weight of mix water), NaCl will act as retarder. Sodium chloride is incompatible with most fluid loss additivies, has an increased tendency for slurry foaming, a limited extent of retardation, and has to be used in large concentrations to be effective as a retarder. Page 23

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RUNNING and CEMENTING LINERS Table V Cement Retarders used by Saudi Aramco

Application

BHCT Range, 0F

Low Temperature Low Temperature/Dispersing

<200

Moderate Temperature Moderate Temperature

150-250 180-225

High Temperature

225-400

High Temperature

>300

Service Co. Equivalents HB D-S

<200 HR5 HR7

HR4 D13

--D120 Diacel LWL D8

HR12 HR15 HR20 Borax

D28 D99 D93

NOTES ---

---

-CMHEC: Also acts as a fluid-loss additive, and viscosifies the slurry. ---Borax: Added to enhance the behavior of high temp. retarders. Not to be used alone.

FLUID-LOSS ADDITIVES Fluid-loss additives are used to reduce the rate of fluid loss from the cement. There are two basic types of fluid loss additives: polymers and bentonite. Polymers function primarily by plugging the pore space in the cement filter cake. Polymeric fluid loss additives -

are sensitive to temperature, seem to have a threshold concentration of about 0.8%, generally retard the slurry and tend to increase the viscosity of the slurry.

Bentonite functions as a fluid loss additive by decreasing the permeability of the cement filter cake. As a fluid loss agent, bentonite generally -

will result in a lower slurry density, will increase thickening time, will decrease compressive strength and is sensitive to mix-water salinity.

Attapulgite clay is sometimes used as a fluid-loss additive in slurries containing salts because it is not sensitive to the salts. Attapulgite, however, does not have the same water-absorbing power as bentonite. Page 24

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ADDITIVES TO DECREASE DENSITY There are a number of additives available to lower slurry density. Table VI presents a summary of additives to lower slurry density. These additives lower the density of the slurry because they have a lower specific gravity than the cement, and in most cases, have a higher water requirement than the cement. Perhaps the most widely used additive to decrease slurry density is bentonite. Bentonite in cement lowers density chiefly because of its high water requirement. Whereas each pound of Class G cement requires 0.05 gal water, each pound of bentonite requires 0.69 gal water. Thus, for example, the density of a Class G cement can be lowered from 15.8 ppg (neat) to 12.8 ppg by the addition of 12% bentonite. Because of loss of compressive strength, bentonite is generally not used at concentrations greater than 12%. When bentonite is dry blended with the cement, the high calcium content of the cement prevents full hydration of the bentonite. If bentonite is prehydrated, i.e. allowed to hydrate in fresh water before being added to the cement, it will have a greater capacity for water. One part by weight of bentonite prehydrated in the mix water has an effect that is essentially equivalent to 3.6 parts by weight of bentonite dry blended with the slurry. In other words, if the bentonite is to be prehydrated (usually 2-12 hours is sufficient) the amount of bentonite can be reduced by the factor 3.6. To obtain ultra lightweight slurries, ceramic spheres, glass beads, or foam can be used. Although ceramic spheres and glass beads are relatively expensive, slurry densities as low as 8.3 ppg can be achieved while maintaining good compressive strength properties. However, because the spheres will crush at sufficiently high hydrostatic pressure (generally around 4000 psi), there are density and depth limitations associated with their use. Ultra lightweight slurries can also be achieved by incorporating air or nitrogen into the cement as a foam. Using foam, slurry densities as low as 9 ppg can be achieved while maintaining good strength properties in the cured cement. Table VI Additives to Lower Density Additive Bentonite Attapulgite Diatomaceous Earth Gilsonite Pozzolan Ceramic Spheres Glass Beads

Specific Water Gravity Requirement 2.65 2.89 2.10 1.07 2.50 0.72 0.39

1.3 gal/ 2% sk cmt. 1.3 gal/ 2% sk cmt. 3.3-7.4 gal/ 10% sk cmt. 2.0 gal/ 50 lb 3.6-3.9 gal/ 74 lb 0.31 gal/ 2 lb 0.36 gal/ 2 lb

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2.40

3.2-12.3 gal/ 2-3% sk cmt.

ADDITIVES TO INCREASE DENSITY For purposes of well control, it is sometimes necessary to use additives that increase the slurry density. Table VII presents a summary of the additives commonly used to increase slurry density. Table VII Additives to Increase Density Additive Class G Cement Barite Hematite Okla. #1 Sand

Specific Water Gravity Requirement 3.14 4.23 5.02 2.63

5.0 gal/ 94 lb 2.64 gal/ 100 lb 0.36 gal/ 100 lb 0

These additives generally increase the slurry density because they have a high specific gravity and/or a low water requirement in comparison to the cement. Hematite is more commonly used than barite because it has a higher specific gravity and a lower water requirement. A pumpable slurry with a density as high as 20 ppg can be achieved with hematite. Although Oklahoma #1 sand has a lower specific gravity than cement, it can increase slurry density (up to 17.5 ppg) because of its zero water requirement. Since these weighting additives "dilute" the cement particles, the final strength of the set cement will be lower than that of a neat cement. Reductions in compressive strength can be minimized by using a reduced water content in conjunction with a dispersant. This method is discussed further in the next section below. DISPERSANTS Dispersants (also called thinners or turbulence inducers) are used to reduce slurry viscosity or increase slurry density. A reduction in slurry viscosity may sometimes be desireable to reduce friction pressures. This may occasionally be necessary when the cement column is long, the annulus is narrow or when the annulus might be partially obstructed. However, dispersants to thin a slurry should be used with care. Their misuse can lead to high free water breakout and they can affect the behavior of other additives. Dispersants are also helpful for increasing slurry density. Because dispersants thin the slurry, when a dispersant is present a pumpable slurry can be formulated with a lower water requirement than normally recommended for the neat cement. By adding a dispersant and reducing the water content, slurry densities as high as 17.5 ppg can be achieved without the addition of barite or hematite (Table VIII). Page 26

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RUNNING and CEMENTING LINERS Table VIII Use of Dispersants to Increase Class G Slurry Density CFR-2 % (bwc) 0 0.75 0.75 0.75

Mix Water (gal/sack) 5.0 4.0 3.78 3.38

Density (lb/gal) 15.8 16.7 17.0 17.5

An advantage of using this technique for increasing slurry density is that the cement particles are not diluted. In fact, since the concentration of cement particles is increased, the strength of the set cement will be higher than that of a neat cement. SILICA On being cured at temperatures in excess of 250 0F, one of the components of Portland cement (C2S) undergoes a change in structure that results in a significant loss in compressive strength and a significant increase in permeability. This phenomenon is called strength retrogression. It has been found that the addition of 35% or more of silica can prevent this degradation (see Fig. 16). Any silica sand finer than 100 mesh can be used. Note that the use of less than 20% silica will intensify the problem, whereas the maximum benefit is obtained at around 40% concentration. DEFOAMERS Excessive foam makes it difficult to maintain slurry density control and can cause other problems, such as "air locking" of the pumps. This is often a problem in slurries containing salt. Chemical foam inhibitors, which minimize air entrainment and foaming are available. These materials can be obtained in liquid or solid form. With the exception of foam cements, these compounds have no known detrimental effects on other cement properties. Page 27

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PLANNING A CEMENT JOB Planning a cement job should begin weeks in advance. Generally the steps involved in planning the cement job involve reviewing government regulations, estimating the volume of cement to be pumped, specifying the slurry, testing the slurry, and selecting the spacer and displacing fluids to be used. CEMENT VOLUME CALCULATIONS When cementing liners, the cement volume is calculated as the sum of the volumes of the liner-casing annulus, the liner-open hole annulus, and the volume of the liner between the latch collar and the float shoe. The size of the open hole is obtained from caliper logs. In Saudi Aramco, the calculated volume of cement is increased by an excess volume equivalent to 400' + of cement rise above the liner hanger. Example: An open-hole (6" dia.) Arab-D producer is 7500 ft. deep and has a 7" 26 lb/ft liner set at 7000 ft. An 800 ft. 4-1/2" 11.6 lb/ft liner is to be run on 3-1/2" DP with the latch collar four (4) joints above the shoe and set on bottom across the open hole. Calculate the number of sacks of class 'G' cement required to cement the liner. Given: I.D. of 7" liner = 6.276 in. I.D. of 4-1/2" liner = 4.0 a)

Volume of 4-1/2" x 7" annulus V1 = π (6.2762 - 4.52) * 300 ft. 4 * 144

in. = 31.3 ft3

b)

Volume of 4-1/2" x open hole annulus = 42.9 ft3 V2 = π (62 - 4.52) * 500 ft 4 * 144

c)

Volume of 4-1/2" casing shoe track V3 = π (42) * 160 ft = 13.9 ft3 4 * 144

d)

Excess volume V4 = π (6.2762 - 3.52) * 400 ft 4 * 144

= 59.2 ft3

Therefore, Vt = V1 + V2 + V3 + V4 Number of sacks of cement = Cmt. Vol. Page 28

= 147.3 ft3 = 147.3 ft3

= 128 sacks

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1.15 ft3/sk

SPECIFYING A SLURRY After the cement volume is calculated, the type of cement slurry is specified by the engineer and the service cementing company. The engineer is resposible for providing the bottom hole static temperature, temperature gradient, thickening time required to pump the slurry, slurry density, and any special properties that may be required. Generally, a low fluid-loss cement slurry is used for cementing liners. The service company will perform lab tests and provide a cement slurry design that meets the requirements set forth by the engineer.

SPACER FLUIDS A spacer or preflush is a fluid pumped ahead of the cement to separate the cement from the drilling or workover fluid and to improve the displacement of the drilling fluid. Separation of the cement from the drilling mud is sometimes required because of incompatibility. For example, a drilling mud that contains CaCl2 could cause a premature set when mixed with the cement. Even if the mud and cement are compatible, a spacer or preflush fluid should be used to enhance mud displacement. Research has shown that, for water-base muds, fresh water can significantly improve mud displacement. For oil-base muds, diesel has been reported to be effective. Other spacer/preflush products are sold by the cementing service companies. For displacement purposes, generally the more spacer pumped the better. However, hydrostatic pressure conditions or economic constraints often limit the spacer volume. Typically 10-50 bbls of spacer are pumped.

DISPLACING FLUID The choice of the fluid used to displace the top plug depends on the next operation to be carried out. If additional drilling is required, drilling fluid is often the displacement fluid. If the next operation requires completing the well, the displacing fluid generally should be a formation-compatible completion fluid.

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PRIMARY CEMENTING OPERATIONS After the cementing equipment and cementing materials have been selected, careful consideration should be given to the operations involved in executing the cement job. MUD CONDITIONING Before running the liner, a final bit trip should be made to circulate and condition the mud. This circulation breaks the gel structure of the mud that develops while the mud is static. Solids control equipment should be operated and the mud circulated until the in and out mud properties have stabilized at values conducive to good displacement. For vertical wells, a 10-min. gel strength less than 10 lb/100 ft2 at 120 0F is often specified. The mud should also be circulated and conditioned after the liner is run. Generally the rate should be as fast as possible without losing returns to promote good hole cleaning. The mud again should be conditioned to the predetermined properties. At a minimum, one casing volume should be pumped to ensure that nothing blocks the float equipment. In deeper wells, this circulation period is critical, as it should be of sufficient volume and duration to cool the wellbore down prior to beginning the cement job.

MUD DISPLACEMENT Perhaps the most important factor for achieving a succesful primary cement job is obtaining good mud displacement. Failure to displace all of the mud from the annulus will leave a mud channel within the cement sheath. In some cases the mud channel may occupy a significant portion of the annulus. The mud channel can greatly reduce the integrity of the cement sheath. For example, if perforations penetrate such a channel, unwanted fluid may flow along the channel to the perforations. Research and field experience have identified a number of factors to enhance mud displacement while cementing. These include -

Liner centralization

-

Mud conditioning

-

Using spacer fluids

-

Pipe movement (rotation or reciprocation)

-

High pumping rates

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LINER MOVEMENT Research and field experience have clearly shown that liner movement while cementing improves cementing success. Two types of pipe movement are possible: reciprocation and rotation. Reciprocation is usually accomplished using the rig drawworks. Typically the casing is reciprocated in 20 ft strokes at speeds not exceeding the last running speed. Rotation requires the use of a rotaing liner hanger. Typically the liner is rotated at 15-25 rpm. The applied torque, however, should not exceed the makeup torque of the liner. PUMPING RATE Laboratory studies have demonstrated that for best mud displacement the best pumping rate is the fastest rate possible. The experiments indicate that mud displacement improves with increasing flow rate whether or not the cement is in turbulent flow. Therefore, the best practice is to pump as fast as possible without losing returns. (Of course the rate should be slowed as the pump down plug shears the liner wiper plug and also as the liner wiper plug approaches the latch collar). PRESSURE CONSIDERATIONS The major limitation to pumping at high rates is the risk of exceeding the formation fracture pressure at some point. Lost returns while cementing can lead to cement bridging, too low a top-of-cement, and possible formation damage. To avoid lost returns while cementing, the surface pumping pressure should be low enough so that the bottom hole pressure is below the fracture pressure of the well. The bottom hole pressure is approximately equal to the surface pressure plus the hydrostatic pressure of the liquids in the drill pipe or liner, since friction pressure is relatively minor. DISPLACEMENT VOLUME The volume of displacement fluid to be pumped is the volume from the latch collar to the surface. This volume should be carefully monitored using the calibrated cementing company displacement tanks. If the rig pumps are used for displacement, the volume can be monitored from the pump stroke count, however, the rig pumps should be calibrated before hand. If the liner wiper plug does not bump when the calculated displacement volume has been pumped, it is generally inadvisable to overdisplace (i.e. pump additional fluid). This is because of the risk of leaving the critical lower portion of the annulus around the shoe Page 31

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uncemented with the displacement fluid by-passing a hung-up plug. AFTER-CEMENTING CONSIDERATIONS After all the fluids have been pumped, the remaining steps to complete the cementing operation include: -

Pull out setting tool from the hanger and check for U-tube

-

Check that the float equipment check valves are holding

-

Rig down the cementing equipment

-

If warranted, reverse out excess cement above the liner top. [Note: Reversing should only be considered when there is a low risk of breaking down the formation (i.e. exceeding the formation fracture pressure).]

-

Wait on the cement to set

WAITING-ON-CEMENT TIME The required waiting-on-cement (WOC) time varies, depending on well conditions, cement slurry, and local practice or regulations. WOC time should be long enough to provide a minimum compressive strength of 500 psi before the well is drilled out and 2000 psi before it is perforated.

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TABLE OF CONTENTS INTRODUCTION ...............................................................................................................1 SQUEEZE CEMENTING ...................................................................................................1 Purpose.....................................................................................................................1 Squeeze Terminology ..............................................................................................2 Slurry Design ...........................................................................................................3 Temperature and Pressure............................................................................3 Type and Quantity of Cement......................................................................3 Fluid-Loss Control .......................................................................................4 Workover Fluids ..........................................................................................4 Squeeze Techniques.................................................................................................5 Low Pressure Squeeze .................................................................................5 Hesitation Squeeze.......................................................................................6 High Pressure Squeeze.................................................................................7 Squeezing Fractured Zones......................................................................................8 Methods .................................................................................................................10 Bradenhead Squeeze ..................................................................................10 Packer Squeeze ..........................................................................................11 Packer Squeeze Tools ............................................................................................13 Drillable Squeeze Packers .........................................................................13 Retrievable Squeeze Packers .....................................................................14 CEMENT PLUGS .............................................................................................................15 Placement Precautions ...........................................................................................16 Placement Techniques ...........................................................................................16 Balanced Plug Method...........................................................................................17 Balanced Plug Technique ..........................................................................18 Balanced Plug Formulas ............................................................................19 Example Problem.......................................................................................20

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INTRODUCTION Remedial cementing operations generally fall into two categories: - Squeeze Cementing involves placing cement under pressure to seal off perforations or repair defects in the primary cement sheath. - Cement Plugs are placed to isolate all or part of the wellbore. This section will discuss both the well conditions that affect the performance of a remedial cementing operation and the techniques that have been developed to place the cement slurry.

SQUEEZE CEMENTING Squeeze cementing is an operation in a well whereby a cement slurry is hydraulically forced or squeezed under pressure (1) into a formation void or porous zone via an open hole, (2) into a channel behind casing or between casings, or (3) through perforation holes placed in the casing, and it is considered to be the most common type of down-hole remedial cementing methods. Its objective is to obtain a seal between the casing and the formation. One of the earliest oilwell problems was to isolate down-hole water production. The problem was partially solved by using a cement slurry and squeeze pressure. It was observed that the higher the pressure, the greater the volume of cement that could be displaced and the more successful the isolation is around the wellbore. This high-pressure technique has been widely used for many years for remedial cementing. PURPOSE Squeeze cementing operations are often used in wells for the following reasons1. To repair a defective primary cement job around casing or liners when cement channeling has occurred or when the cement fails to reach the desired height. 2. To repair casing leaks or defects such as corrosion holes, joint leaks, a hole in the casing, or parted casing. 3. To isolate zones in permanent completions. It is common practice in many areas, after a well with multiple producing zone potential has been cased, to isolate the first zone by squeezing and then produce the next zone to depletion. 4. To seal off thief zones or lost circulation zones. 5. To protect against fluid migration into a producing zone (block squeezing). 6. To reduce or shut-off excessive water or gas production. By isolating the oil zone from an adjacent gas zone, the GOR can usually be improved to help increase oil production. Water production can also be squeezed off below the oil zone to help decrease the water-oil ratio.

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7. To prevent zonal communication and potential fluid migration from abandoned zones or wells. Squeeze cementing is employed to seal old perforations or to isolate and plug depleted producing zones. SQUEEZE TERMINOLOGY Squeeze cementing terms and their definitions vary from area to area. The meanings can be confusing at times, so a discussion of terminolgy is outlined below. Squeeze Pressure - Squeeze cementing objectives are usually defined by pressure requirements. The "high-pressure" technique involves breaking down the formation and pumping a cement slurry into the formation until a specific surface pressure can be maintained without bleedoff. The "low-pressure" technique involves placing cement over the interval to be squeezed and applying a pressure sufficient to form a filter cake of dehydrated cement in perforations, channels, or fractures that may be open. Block Squeezing - To block squeeze is to perforate above and below the pay section and then squeeze cement through the perforations. It is used to isolate the producing zone before completing a well. The technique normally involves two perforating steps, two squeeze steps, and drilling out. Breakdown Pressure - Breakdown pressure is the pressure necessary to break down or fracture the formation so that it will accept fluid. In high-pressure squeezing, this is the pressure that must be achieved before putting cement slurry or cement filtrate into a formation. If the formation is permeable, filtrate will go into it at any pressure above the formation pore pressure. With the low-pressure technique, a satisfactory squeeze can be performed without breaking down the formation. Fracture Gradient - Fracture gradient is usually defined as the pressure per foot of depth required to initiate a fracture. Less pressure is required to extend and prop a fracture than to create it. Bottom-hole Treating Pressure - Bottom-hole treating pressure is the pressure exerted on the formation during a squeeze operation. It is the surface pressure plus the hydrostatic pressure of well fluids minus the frictional pressure. To fracture a formation, this pressure must be exceeded. Cement Dehydration - In dehydration, the water is squeezed from the cement slurry and a filter cake of solid cement particles forms on the face of the formation. If excessive pressure is exerted, the formation will fracture and some slurry will be forced into the fractures during the squeeze.

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SLURRY DESIGN The properties of the cement slurry must be tailored according to the characteristics of the formation to be squeezed off and the technique to be used. The follwoing factors should be considered in designing the cement slurry for any squeeze operation. Temperature and Pressure In squeezing, as in primary cementing, both temperature and pressure influence the placement and thickening time of a cement slurry. Hydrostatic pressure and surface pressures must be controlled during the job. A high cement column in the work string during the displacement could cause the breakdown of low pressure or depleted formations. Squeeze pressure also affects the dehydration of the slurry. Temperatures encountered in squeezing can be higher than those on primary jobs because the well usually has not been circulated long enough to decrease the bottom-hole temperature significantly. When large quantities of cement are necessary, the use of an extended slurry may be necessary, and likewise, if a shallow cavity is to be filled or if perforations are to be abandoned to move back up the hole, the slurry may be designed for a fairly short pumping time. A hesitation, low-pressure, squeeze may require a pumping time of 4 to 6 hours. A cement slurry must obviously remain fluid long enough not only to be placed properly, but also to achieve the desired squeeze pressure and to be reversed out. Type and Quantity of Cement For most squeeze operations carried out today, API Class G cement can be used. For deeper wells, silica flour may be blended to improve cement strength retrogression that occurs at the higher temperatures and retarders also blended to provide adequate time to carry out the job. The volume of cement slurry to be used depends on the length of interval to be cemented and the placement technique to be used. The quantity of cement to be used in a given squeeze operation can vary from a few sacks on a wireline job to several hundred sacks on a difficult stage job. If fractured formations are to be cemented the cement volume used might be considerably larger. The average volume ranges between 100 and 200 sacks; however, the specific amount will depend on whether perforations or channels are being squeezed. Besides being wasteful, excess cement can be detrimental to the productivity of the formation being squeezed. The volume of cement slurry to be squeezed cannot be controlled precisely, and experience in the vicinity of the job is the best guide, however, there are some useful indexes and rules of thumb: 1. The volume should not exceed the capacity of the cementing string. 2. Two sacks of cement should be used per foot of perforated interval. 3. The minimum volume should be 100 sk if an injection rate of 2 bbl/min. can be achieved after breakdown; otherwise it should be 50 sk 4. The volume should not be so great as to form a column that cannot be reversed out. Page 3

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Fluid-Loss Control Fluid loss of neat cement slurries (cement and water) is usually very rapid and cement may build up in the casing before the slurry can completely cover a given area of formation. The result can be a cement plug across open perforations at the top of a zone and no coverage of cement across the lower perforations. When cement is squeezed against a permeable medium, the differential pressure forces water out of the cement leaving the cement solids to form a filtercake at the formation face. Filtration control helps avoid both premature loss of fluid from the slurry and rapid buildup of cement solids in the casing. Cement containing a fluid-loss control additive loses filtrate to the formation much more slowly than does neat cement, so the developing filter cake is denser and more uniform and pressure resistant. As fluid loss occurs into the formation, little or none is taking place in the remaining slurry in the casing; therefore, it is often possible to obtain cement plugging or dehydration in the formation and across the perforations and still have sufficient time to reverse any excess slurry from the casing. Fluid loss is particularly important when cementing against high permeability formations using low pressure techniques. A properly designed slurry should allow for the complete filling of perforation cavities, leaving a minimum cement node buildup in the casing.

1000 cc - Neat Cement Cement Slurry

Casing

Primary Cement

Formation

300 cc - Gel Cement Filter Cake

150 cc - Cement plus Fluid Loss Additive 25 cc - Cement plus Fluid Loss Additive Filtrate

Filter Cake build-up

Cement Node buildup effect with filtration control (API fluid loss, cc/30 min @ 1000 psi)

Workover Fluids The job design should take into consideration the type of workover fluid that is in use when the squeeze job is performed and the use of an appropriate spacer to isolate the slurry. Where well conditions permit and where it is obtainable, salt or fresh water is the preferred workover fluid for both low-pressure and high-pressure squeeze jobs. However, even if clean fluids are used and pressures are great enough to fracture the formation, if a well has been perforated in mud, some mud solids may remain and more than one squeeze job may be needed. Page 4

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SQUEEZE TECHNIQUES Squeeze cementing can generally be devided into classifications depending on the way the cement is placed behind the casing. Most squeeze jobs are defined by the pressure required to accomplish a down-hole seal or shut-off. Low Pressure Squeeze The low pressure squeeze method is usually associated with a small volume of cement slurry circulated in place against the open perforations, with cement filter cake being deposited with a moderate pressure differential from inside the wellbore to the formation. The pressures are intentionally kept low to avoid any potential fracture of the formation face. By preventing a fracture, the volume required is kept low. The low pressure technique has become an efficient method of squeezing with the development of controlled fluid-loss cements and use of isolation packers. With this technique, cement slurry is forced through the perforations at pressures below the formation fracture pressure avoiding formation breakdown. The aim of this technique is to fill the perforation cavities and interconnected voids with dehydrated cement. To be able to to do that, formations surrounding these voids must have enough permeability and the cavities themselves must be free of damaging fluids such as muds, asphalts, or solidsbearing completion brines. The presence of damaging fluids in front of the slurry might inhibit the dehydration of cement in some perforations or even prevent the slurry from entering. Low pressure squeeze cementing is usually confined to completion or workover operations conducted with solids-free fluids and cannot be used successfully when all the perforation holes are full of mud filter cake or other solids. To remove these solids, some operations will require that perforations be washed, treated with acid to remove any acid soluble material, or back surged. Pressure is achieved by shutting down or hesitating during the squeeze process. In this hesitation method, the cement may be placed in a single stage, by alternating pumping and waiting periods. The controlled fluid-loss properties of the slurry cause filter cake to collect against the formation or inside the perforations while the parent slurry remains in a fluid state inside the casing. Casing

Primary Cement

Formation

Dehydrated Cement Cement Nodes

When squeezing perforations in depleted formations, spotting the total volume of cement in front of the perforations may be the only way to prevent the formation from fracturing as a result of hydrostatic pressure.

Perforation Channel

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Hesitation Squeeze Building up filter cake inside perforation tunnels, or into previously induced fractures, requires the application of differential pressure to induce slurry dehydration against the formation face. The relatively small amount of filtrate lost from a slurry makes it impractical, or impossible, to continuously pump slow enough to replace the volume lost to the formation while maintaining a constant differential pressure. The only procedure that makes the dehydration of small quantities of cement into perforations or formation cavities possible is the intermittent application of pressure, separated by a period of pressure leakoff caused by the loss of filtrate into the formation. The initial pressure leakoff is usually fast because there is no filter cake, thus allowing short periods between stages. As the filter cake builds up, the filtration periods become longer and the difference between initial and final pressures smaller, until the pressure leakoff becomes negligible. At this stage, a pressure test of 300 to 500 psi over the final injection pressure followed by a constant, zero slope, will indicate the end of the dehydration process.

Final Squeeze Pressure Reverse out 1 1/2 bbls.

Staging at 1/4 bpm

1000

Displace at 1/4 bpm

1500

Mixing 2nd Stage at 2 bpm

2000

Mix 1st Stage and Clear Squeeze Perfs w/4 bbls at 4 bpm

2500

Estab. Inj. Rate - 4.5 bpm

SURFACE PRESSURE, PSI

3000

500

0 0

20

40 60 80 TIME, MINUTES

Steps in a Hesitation Squeeze

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100

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High Pressure Squeeze There are some cases where low pressure squeezing of perforations will not accomplish the job objectives. Channels behind casing might not be directly connected with perforations; small cracks or microannuli may permit the flow of gas but not of a cement slurry. In such cases, they need to be enlarged to accept a viscous cement slurry. Additionally, many low pressure operations cannot be performed because it is sometimes impossible to remove fluids laden with solids ahead of the cement slurry or from inside the perforations. A high pressure squeeze is usually considered as mandatory when the perforation holes are filled with mud filter cake. The "high pressure" is the pressure needed to fracture the formation to be squeezed. This fracturing operation removes the mud filter cake from the perforation holes so that cement slurry can be placed and dehydrated against the formation face. Once a fracture is initiated, considerable fracture volume is created before the fracture is filled with cement filter cake that will ultimately bridge off preventing further fluid entry. Thus, the high pressure squeeze operation requires mixing relatively large cement volumes. The high pressure technique uses a Mud CASING quantity of water or Cement chemical wash to Filter determine the breakCake down pressure of the Filtrate formation to be Mud squeezed. Mud should not be used as a breakdown fluid as it can plug or damage the formation. After Vertical establishing the Fracture breakdown pressure, a slurry of cement and water is spotted near the zone and then Vertical Fracture Generated by High Pressure pumped or squeezed into the formation at a low rate. As pumping continues, injection pressures begin to build up until the surface pressure indicates that either cement dehydration or a squeeze is occurring. Further application of the hesitation technique will dehydrate more slurry against the formation walls leaving all the channels filled with cement. Pressure is held momentarily on the formation to verify static conditions and then released to determine if the cement will stay in place. Any excess slurry above the perforations is then reversed out. Dehydrated Cement

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During high pressure squeeze cementing the location and orientation of the generated fracture cannot be controlled. When sufficient hydraulic pressure is applied through the wellbore against a particular formation, the formation rock fractures along the plane perpendicular to the direction of the least principal stress. A horizontal fracture will be created if fracturing pressure is greater than the overburden pressure and a vertical fracture will occur if the overburden pressure is the greater. Generally, a fracture in a formation deeper than 2000 ft is oriented vertically and at depths less than about 2000 ft, the fracture may be oriented either vertical or horizontal. If the desired squeeze pressure is not obtained, a hesitation, or staging period, is often employed. This involves mixing one batch of cement, placing it against the formation, waiting at least until the initial set, and then repeating the operation as required.

SQUEEZING FRACTURED ZONES When squeezing fractured limestone and dolomite formations, greater emphasis must be placed on effectively sealing the fracture network or channel system that exist behind the casing. It is necessary to modify the slurry design from that used to squeeze permeable sandstones. In squeezing a fractured carbonate formation it is more important that the cement fill the fracture or channels than build up a filter cake. Larger volumes of cement slurry is required than that used for squeezing permeable sandstone reservoirs.

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FRACTURE ORIENTATION Wellbore, Frac. Press; Pf Vertical Stress, ∂v

Horizontal Stress, ∂H1

∂H2 Pf

Pf

Induced Horizontal Fracture Pf > ∂v; ∂v< ∂H1 or ∂H2

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METHODS Bradenhead Squeeze The original method of squeezing was the bradenhead method, which is accomplished through tubing or drillpipe without the use of a packer. BOP rams are closed around the tubing or drill pipe and the injection test carried out to determine the formation breakdown pressure. The cement slurry is then spotted as a balanced plug, and the work string is pulled up and out of the slurry. The annulus is then shut off by closing the annular preventers or pipe rams around the cementing string. Displacing fluid is pumped down the tubing forcing the cement slurry into the zone until the desired squeeze pressure is reached or until a specific amount of the fluid has been pumped. This method is used extensively in squeezing shallow wells and sometimes when squeezing off zones of partial lost circulation during drilling operations.

Spot Cement

Apply Squeez e Pressure

Rev erse Circulat ion

Br adenhead Squeeze When shallow wells are squeezed by this method, fluids in the tubing are displaced into the formation ahead of the cement. In deeper wells, the cement may be spotted halfway down the tubing before the annulus is shut-in at the surface. The applicability of bradenhead squeezing is restricted because the casing must be pressure tight above the point of squeezing and because maximum pressures are limited by the burst strength of the casing and the pressure rating of the wellhead and BOP equipment at the surface. Also, it is sometimes difficult to spot the cement accurately across the interval without using a packer. Page 10

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Packer Squeeze The main objective of this method is the isolation of the casing and wellhead while high pressure is applied downhole. The selective testing and cementing of multiple zones is an operation where isolation packers are commonly used. The packer squeeze method uses either an expendable, drillable, packer such as a cement retainer or a retrievable packer tool run on a work string and positioned near the top of the zone to be squeezed. This method is generally considered superior to the bradenhead method since it confines pressures to a specific point in the hole. Before the cement is placed, an injection test is conducted to determine the formation breakdown pressure. When the desired slurry volume has been pumped or squeeze pressure is obtained, the remaining cement slurry is reversed out. Squeezing objectives and zonal conditions will govern whether high pressures or low pressures are used.

Displacement Brine Fresh Water Spacer

Brine Pumped

Cement Slurry Brine Fresh Water Spacer

Fresh Water Pre-Flush

Cement Retainer Brine Water

Cement Slurry at Perfs

Perfs

PACKER SQUEEZE JOB

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There are two common methods for placing the cement at the zone of interestBullheading

BU L L H EA D I N G

Ap p lie d Casi ng Pressu re

Ap p lie d Casi ng Pressu re

Di spl ace me nt Fl ui d

Sometimes it is necessary to bullhead cement between casing strings into the annulus in order to bring cement back to surface and to seal off the annulus. If this is required, precautions must be taken not to exceed the collapse rating of the inner casing string when squeezing the cement slurry down the casing annulus.

Cem en t Cem en t

Mud

Mud

P u m p Ce m en t w i t h P a c ke r se t D i sp l a c e M u d i n t o F o r m a t i o n Ho l d A n n u l u s P r e ss u r e

A p p ly Sq u e e z e P r e ss u r e

Spotting

SPOT T I N G

Ap p lie d Casi ng Pressu re

Di spl ace me nt Fl ui d

Cem en t

Cem en t

Mud Mud

S p o t Ce m en t

Page 12

In this method, a packer is set and pressure is applied to the annulus. An injection rate is established into the zone; then the cement is mixed and pumped down the work string. The mud, or brine, as well as the cement is then forced into the zone under pressure until the desired squeeze pressure is obtained. The packer is not released until the job is completed.

S t a b i n t o P ac k e r A p p l y C as i n g P r es s ur e D i sp l a c e C e m e n t A p p l y S q u e e z e P r e s su r e

In this method, after establishing an injection rate into the zone, the packer is released or the by-pass opened. The cement slurry is circulated down the work string to just above the packer. The packer is then re-set or the by-pass closed, and the cement slurry is squeezed away into the zone until the desired squeeze pressure and volumes are reached. With this method, the amount of mud or brine that will be forced into the perforations ahead of the cement is kept to a minimum.

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PACKER SQUEEZE TOOLS The use of squeeze packers makes it possible to apply higher pressures to specific downhole points than can be applied with the bradenhead method. The two commonly used packers are the drillable and the retrievable. Drillable Squeeze Packers Drillable packers, which are expendable, are left in the well and can be drilled out after the squeeze operation. The drillable packer contains a poppet-type backpressure valve to prevent backflow at the completion of displacement and a sliding valve for when it is desireable to hold pressure in either or both directions. The sliding valve makes it possible to support the weight of the hydrostatic fluid column and relieve the cement of this weight while it is setting. Excess cement can be reversed out of the drillpipe without applying the circulating pressure to the squeezed area below the packer. The tubing or drillpipe can also be withdrawn from the well without endangering the squeeze job. Another advantage is that they can be set close to the perforations or between sets of perforations and are easily drilled if required. Cement retainers set on drillpipe or wireline are used instead of packers to prevent backflow when no cement dehydration is expected or when high negative differential pressures may disturb the cement cake. In certain situations, potential communication with upper perforations could make use of a retrievable packer a risky operation. When cementing multiple zones, the cement retainer will isolate the lower perforations, and subsequent zone squeezing can be carried out without waiting for the cement to set. Cement retainers are drillable packers provided with a two-way valve that prevents flow in either or both directions. The valve is operated by a stinger run at the end of the work string.

Drillable Squeeze Packer

Drillable bridge plugs are normally used to isolate the casing below the zone to be treated. They are of similar in design to the cement retainer, and they can be set on wireline or on drillpipe. Bridge plugs do not allow flow through the tool.

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REMEDIAL CEMENTING OPERATIONS Retrievable Squeeze Packers Retrievable packers are usually rented on a job basis and, after the squeeze job, is removed from the well. Unlike drillable packers, the retrievable packer can be set and released as many times as necessary. Retrievable packers with different design features are available on the market. Most are of a nondrillable material and are available in most API sizes. The ones used in squeeze cementing, compression or tension set packers, have a bypass valve to allow the circulation of fluids when running in and once the packer is set. This packer feature permits the spotting of pre-wash fluids and cement down to the zone, cleaning of tools after the job, reversing of excess cement without excessive pressures, and prevents a piston or swabbing effect when tripping the packer in or out of the hole. Retrievable bridge plugs are easily run and operated tools with the same function as the drillable bridge plugs. They are generally run in one trip with the retrievable packer and retrieved later after the cement has been drilled out. Most operators will spot frac sand or acid soluble calcium carbonate on top of the retrievable bridge plug before doing the squeeze job to prevent cement from settling over the top of the retrievable bridge plug.

Retrievable Squeeze Packer

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CEMENT PLUGS Many operations require that a cement plug be set in the open-hole or casing to plug back a well to a shallower depth for a number of reasons. The most important and common applications include the following: Lost Circulation When mud circulation is lost during drilling, it is sometimes possible to restore lost returns by spotting a cement plug across the thief zone and then drilling back through the plug. Sidetracking In sidetracking a hole around unrecoverable junk, such as a stuck drillstring, it is necessary to place a cement plug above the junk at a required depth that will allow sufficient distance to kick off the cement plug and drill around, bypassing, the original hole and junk.

Producing Zone

Cement Plug Depleted Zone

PLUG BACK DEPLETED ZONE

Zone Isolation One common reason for plugging back is to isolate a specific zone. The purpose may be to recomplete a zone at a shallower depth, to shut-off water, or to prevent fluid migration into a low-pressure depleted zone. Abandonment To seal off selected intervals of a dry hole or abandon an older, depleted well, a cement plug is placed at the required depth to prevent zonal communication and migration of fluids in the wellbore.

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PLACEMENT PRECAUTIONS When planning for placement of a cement plug, one must consider the type of formation across which the plug is to be placed. For maximum bonding, a clean, hard formation should be selected, particularly for zone isolation or abandonment. For directional drilling, an easily drilled formation should be selected and a high dense cement slurry used that will yield high compressive strengths. When placing plugs in deep, hot wells, extra circulating time is warranted to not only condition the mud but to cool the wellbore down; whereas in combatting lost circulation in a shallow thief zone, extensive circulating will have the effect of retarding the development of cement strength when it is desireable to achieve early strength. Plug failures can be prevented by taking the following precautions: 1. Selecting, with the aid of a caliper log when available, a gauge section of hole. plan

2. Carefully calculate cement, water, and displacement volumes, and always to use more than enough cement. 3. Thoroughly circulate and condition the mud to uniform density and reology. 4. Use a densified cement that will tolerate mud contamination. 5. Use sufficient spacer that is compatible with the mud ahead of the cement. 6. Place the plug with care and move the pipe slowly out of the cement to minimize swabbing action and mud contamination. 7. Allow ample time for the cement to set.

PLACEMENT TECHNIQUES Where cement volumes are small and accuracy is critical, the dump bailer method is recommended. However fluid spotting or balancing is the most commonly used placement technique. Cement plugs are typically spotted using the balanced plug technique, wherein the cement plug is placed by balancing the fluid columns so that the same height of slurry and displacing fluid exists both on the inside and outside of the drill pipe or tubing. Cement plugs are usually placed with open-end drill pipe or tubing, and the success of these jobs depends on preventing contamination of the cement and allowing it to set without agitation. Placement failures commonly occur due to fluid backflow, slugging, or improper displacement volumetric calculations. The discussion below outlines the proper placement technique for the balanced cement plug.

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BALANCED PLUG METHOD The ideal cement plug is placed so there is no tendency for the cement slurry to continue to flow in any direction at the time pumping is stopped. This involves balancing the hydrostatic pressures inside and outside the drill pipe or tubing so that the height of cement and displacing fluid inside the drill pipe or tubing equals the height of fluids in the annulus. The pipe or tubing is then pulled slowly from the slurry, leaving the plug in place. To allow the pulling of a "dry" string of tubing, common field practice is to cut the displacement volume short by 1/2 to 1 barrel. The characteristics of the mud are very important when balancing a cement plug in a well, particularly the ability to circulate freely during displacement. Whenever possible, the mud should be conditioned thoroughly to uniform densities and reological properties and the same mud used as the displacement fluid. Movement of well fluids while the cement plug is setting may affect the quality of the plug, therefore, it is imperative that care be taken in accurately spotting the slurry and moving the pipe slowly out of the slurry to avoid backflow, slugging, or swabbing action. The amount of pre-flush or spacer, cement slurry, and volume of displacement fluid must be carefully calculated to ensure equal volumes of fluid ahead of and behind the cement plug as it is being placed in the hole. The quantities that must be calculated are as follows: 1. 2. 3. 4. 5.

Determine the drill pipe or tubing capacity, the annular capacity, and hole or casing capacity. The length of the cement plug or the number of sacks of cement for a given length of plug. The volumes of spacer needed before and after the cement to balance the plug properly. The height of the plug before the pipe is withdrawn. The volume of the displacement fluid.

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M M

M

W

W

M

M

M

W

W

W

(a) Displacing cement.

M

M

M M

W

W

M

M

M

(b) Cement, water and mud balanced.

(c) Pulling string above top of cement.

W

M

M

M

(d) Reversing out.

M = Mud Balanced Plug Technique

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Cement requirements:

Spacer Volume behind the slurry to balance plug:

Length of balanced plug before pulling pipe from slurry:

Mud Volume for pipe displacement:

N = L * Ch Y

where: N = sacks of cement L = plug length, ft. Ch = hole or casing capacity, cu ft/ft Y = slurry yield, cu ft/sack

Vb = Cp* Va Ca

where: Va = spacer volume ahead, bbl Vb = spacer volume behind, bbl Ca = annulus capacity, cu ft/ft Cp = pipe capacity, cu ft/ft

Lw = N * Y where: Lw = Plug length before pulling the pipe from the slurry, ft (Ca+Cp)

Vd = [(Lp - Lw) * Cp] - Vb where: Vd = displacement volume, bbl Lp = total pipe length, ft *Cp = pipe capacity, bbl/ft Vb = spacer volume behind, bbl * Note pipe capacity, Cp, is expressed in different units.

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Example Problem Conditions: A 300 ft cement plug is to be placed at a depth of 5000 ft in order to sidetrack around a stuck BHA in 8-1/2" open hole. The plug will be spottedthrough 5" 19.5 lb/ft open end drill pipe with 10 barrels of water pumped ahead of the slurry which has a yield of 1.15 cu ft/sk. Assume 25% excess due to hole washout. Determine: 1. 2. 3. 4.

Number of sacks of cement required. Volume of water spacer behind the slurry to balance the plug. Length of balanced plug before pulling pipe Amount of displacement mud required to spot plug

therefore,

N = L*Ch Y

1.

where: N = sacks of cement L = 300 ft. Ch = 0.3941 cu ft/ft Y = 1.15 cu ft/sack

N = 300 ft * 0.3941 cu ft/ft * 1.25 = 129 sacks of cement 1.15 cu ft/ sack 2.

Vb = Cp* Va Ca

where: Va = 10 bbl. water ahead Vb = water volume behind, bbl Ca = 0.2577, cu ft/ft Cp = 0.0997, cu ft/ft

Vb = [0.0997 cu ft/ft * 10 bbl] = 3.1 bbls of water behind (0.2577 cu ft/ft * 1.25) 3.

Lw = N * Y (Ca+ Cp)

= 129 sacks * 1.15 cu ft/ sack [(0.2577 * 1.25)+ 0.0997 cu ft/ft]

Lw = 148.35 cu ft = 352 ft plug length with DP 0.4218 cu ft/ft 4.

Vd = [(Lp - Lw) * Cp] - Vb

where: Vd = displacement volume, bbl Lp = 5000 ft Lw = 352 ft * Cp = 0.01776 bbl/ft Vb = 3.1 bbls water behind

Vd = [(5000 - 352 ft) * 0.01776 bbl/ft] - 3.1 bbl Vd = 82.5 bbls - 3.1 bbls = 79.4 bbls of mud displacement to balance the plug Page 20

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SAND CONTROL

TABLE OF CONTENTS INTRODUCTION ...........................................................................................................1 1. Sand Problems ...............................................................................................1 2. Causes of Sand Production............................ ................................................2 3. Effects of Sand Production ............................................................................3 MECHANICAL SAND CONTROL ...............................................................................5 1. Background ....................................................................................................5 2. Gravel & Screen Selection.............................................................................6 3. Open-Hole Gravel Packs ...............................................................................7 4. Cased Hole Gravel Packs...............................................................................7 GRAVEL PACK DESIGN ..............................................................................................8 1. Formation Sand Comparison .........................................................................8 2. Gravel Sand Ratio ..........................................................................................9 3. Screen Slot Width ..........................................................................................10 WELL PREPARATION ..................................................................................................12 1. Cleaning the Casing .......................................................................................12 2. Perforating .....................................................................................................12 3. Perforation Surging........................................................................................14 4. Overbalance Perforating & Prepacking .........................................................14 5. Extreme Overbalance Perforating & Prepacking...........................................15 GRAVEL PLACEMENT ................................................................................................16 Slurry Packing................................................................................................16

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INTRODUCTION SAND PROBLEMS Formation sand produced into a well is one of the oldest problems in the oil & gas industry. The sand not only plugs wells but also erodes equipment and accumulates in surface equipment. Aramco spends millions of riyals every year dealing with sand related problems as well as trying to prevent them. When considering sand control it is essential to differentiate between load-bearing solids and the fine particles. Fine particles are generally not considered part of the mechanical structure of the formation. In other words they are not the particles that support the overburden. Sand refers to the load bearing particles, those that support the overburden. A problem arises in just how much sand is too much. A general rule of thumb is any sand production greater that 0.1% is considered excessive. Sand production can be experienced in practically every part of the world that produces oil or gas from sandstone reservoirs (see Fig. 1). Sand production is the most common in geologically young reservoirs. As such, the reservoirs are usually found at shallow depths and therefore have moderate consolidation (»100 psi compressive strength).

Sand Problems Around the World

Figure 1

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CAUSES OF SAND PRODUCTION Stresses are imposed on sand grains when fluid is produced from a sandstone reservoir that is inclined to move them into the wellbore along with the produced fluid (Fig. 2). These stresses are created by fluid frictional forces, the weight of the overburden, and by pressure differences in the formation. Sand will be produced when the combined magnitude of these forces exceeds the strength of the formation. For many wells there is a minimum production rate at which the sand will not be produced. Most times this reduced rate is prohibitively low and uneconomical to produce. Therefore mechanical steps must be taken in order to control the sand production as either an initial or remedial part of the well's completion (initial is always preferable to remedial).

Figure 2 If good completion and production methods are followed, then formations with compressive strengths greater than 1000 psi usually produce sand free. Occasionally sand production can change due to changing well conditions over time. These time related changes include:

Page 2

y

Reservoir pressure decreases can increase the overburden stresses on the sand grains.

y

Natural cementing materials can be dissolved by increased water production, weakening intergranular bonds.

y

Permeability can be reduced by water production, dislodging fines and plugging up pore spaces. This can increase fluid flow and increase stresses on the sand grains.

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EFFECTS OF SAND PRODUCTION In most wells, continued production of large quantities of sand cannot be permitted either because production will be curtailed too much, or the well and/or production equipment will be damaged. Three common problems associated with sand are: 1. Erosion-abrasion of down-hole equipment and surface facilities. 2. Bridging or "sanding up" in tubing or casing. 3. Casing or liner failures by buckling-collapse Tubulars that are run across producing intervals are frequently eroded by sand. Weakening of casing by metal removal can be serious if it makes the pipe susceptible to buckling or collapse. Surface equipment such as manifolds and separators can accumulate sand and require cleaning out regularly if sand production is not controlled downhole. A worse problem can occur when a well producing sand is producing at a high velocity. Sand is produced along with the producing fluid and can erode out chokes, turns in the surface piping and valves. This situation can cause a dangerous leak if not detected early and stopped. A well "sands up" when bridges form in the casing or tubing and obstruct flow. The bridges must be removed to restore production. This is accomplished usually by bailing or by coil tubing operations to wash the sand out of the wellbore. This is an expensive operation. When bridging is severe, sand control may be required to maintain production. This is the most common reason for sand control. Casing and perforated liners that are designed for adequate collapse loads can fail in collapse. The reason is that the pipe can be buckled by forces that place the pipe in a nonuniform loading situation. Such forces can be caused by removal of a portion of sand that has previously supported that side of the pipe, thereby causing a large lateral load that bends the pipe (Fig. 3) and collapsed casing can take place. Pipe damage in the buckling mode can be prevented if sand production is avoided. Aramco experiences sand problems in two fields, Safaniya and Hawtah in Central Arabia. The approximate compressive strengths in these fields are 30 psi & 20 psi respectively, so they are prime for sand problems. Aramco treats these problems two separate ways. In Safaniya the sand is allowed to produce and is periodically cleaned out with coil tubing sand washes. The thought is that any gravel packing performed would decrease the PI of

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the well to a level that would cost more in deferred production than the coil tubing work costs. On the other hand, in Hawtah where a lot of the production is on artificial lift, i.e. submersible pumps, sand control is a necessity because produced sand damages the pumps and eventually covers the perforations.

Figure 3

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MECHANICAL SAND CONTROL BACKGROUND A method of preventing formation sand production in Central Arabia is to physically restrain its entry into the wellbore. It has been found that spherical particles will not flow through circular holes up to three times their diameter. They tend to bridge across these openings, thereby preventing further particle movement. If the size of the larger particles varies, retention of the larger particles causes the smaller particles to bridge behind them. Mechanical retention is based upon this principle of holding a certain portion of formation material to prevent the rest of it from entering into the wellbore. Devices used to restrict sand movement are referred to as screens or slotted liners. The placement of large clean and uniformly sized sand (known as gravel because it is much larger than the formation sand), between the screening device and the formation is referred to as gravel packing. All formation sand grain stoppage is accomplished by the gravel and the screen stops the gravel pack gravel from being produced. Methods of sizing gravel and screens are discussed in the following section. Figure 4 shows a cross sectional view of a gravel pack completion, including the gravel filled perforations.

Ï

Ï

Ï

Wire Wrapped Screen Gravel Casing

Ï Cement

Ï Formation

Figure 4

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GRAVEL AND SCREEN SELECTION Since the basic requirement is to mechanically block entry of formation sand in the case of gravel packing, the design must begin with an evaluation of the particular formation to be protected. The objective is to select the gravel size that will effectively stop sand production and at the same time permit the highest flow rate with the least resistance. Permeability increases with grain size, so the largest effective gravel size for the smallest formation sand to be restrained should be selected. The first step is to take a representative formation sand sample. Core samples are the best source of information, side wall cores can be used but contain crushed sand and may indicate a need for smaller gravel than is actually required. Actual produced formation sand can be used if core data is unavailable. Once a representative sample is secured, it is carefully crushed and by sieve analysis, grain size distribution curves are prepared. Gravel grain size can then be determined by the curve data. In addition to properly sized gravel, the gravel has to be retained around the wellbore by a mechanical device. Either a slotted liner or a wire wrapped screen is used for this purpose. A slotted liner normally consists of vertical slots evenly spaced around the pipe. The slot width must be properly sized relative to the gravel pack sand size to be excluded. With wire wrapped screens (all stainless steel), the wire is wrapped directly on the pipe base which is usually drilled, slotted, or grooved (Fig, 5). These wire wrapped screens offer much more open area per linear foot than a slotted liner provides. Therefore they are less susceptible to plugging. Aramco uses the screens rather than the slotted liners for this reason.

Cut Away View of an All-Welded Screen

Figure 5

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OPEN-HOLE GRAVEL PACKS Hole stability is the critical factor in open hole gravel packing because there is no mechanical support of the wellbore wall other than completion fluid prior to and during screen and gravel installation. The gravel pack serves two important functions: (1) It supports the wellbore to prevent caving or sloughing, (2) it provides mechanical bridging to prevent the sand from flowing into the wellbore. This completion has the greatest productivity of all gravel pack completions. The primary disadvantage of the open hole gravel pack is the inability to isolate gas or water at the sand face. Also, some sand formations are not stable enough to support this kind of completion.

CASED-HOLE GRAVEL PACKS The cased hole gravel pack consists of a screen or slotted liner that is gravel packed inside perforated casing. This completion is the most widely used gravel pack method today. Usually when a new well is completed it is not yet known whether the well will produce sand or not. Therefore many wells are cased, perforated then produced. If no sand appears, then an expensive gravel pack is not required. However if sand presents a problem later, then a cased hole gravel pack can be performed. It must be remembered that remedial gravel packs do not end up with as high a PI as initial completions. So if field experience shows that wells produce sand from a certain formation then gravel packing should be considered a part of the initial well’s completion program To perform cased-hole packing properly, all perforations must be filled with gravel of the highest permeability able to control sand production and free of formation sand.

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GRAVEL PACK DESIGN The problem that exists is how to prevent sand production without restricting oil prod-duction and reducing the well's productivity. To achieve this, a good gravel pack design is required. The design covers three areas: y

Formation grain size distribution analysis

y

Selecting an ideal gravel size in relation to formation sand size to control formation sand movement

y

Optimize screen slot width to retain the gravel

FORMATION SAND COMPARISON A representative formation sample is required in order to get a sieve analysis. Grain size distribution varies throughout a sand body, therefore several samples are needed to insure accuracy particularly from one zone to another. Formation sand is controlled with the proper sized gravel in a gravel pack. Gravel packs should always be designed to bridge off formation sand grains yet allow fines to be produced to prevent or delay serious plugging. To determine the best gravel size to use, the formation's grain size must be determined accurately. The most widely used method of assigning grain size is based on the U.S. Series Screen scales. These scales grade the screen or sieve sizes in mesh numbers. Representative samples are extracted, dried, weighed and then passed through a series of varying sized screens. A sieve analysis curve is then drawn from the results of this procedure (Fig. 6). The practice has been to describe the distribution curve at the 50 percentile point. Using the 50 percentile point yields a simpler and more straight forward design. The slope of this curve indicates the sands uniformity. For uniform sands (see curve A) it yields the same design that the 10 percentile design point does. For non-uniform sands (see curve D), it avoids a gravel size so small that the small gravel blocks the well's productivity by decreasing the well’s permeability. The practice has been to describe the distribution curve at two specific points, 40 & 90. By taking the dimension of the grain size at the 40 percentile and dividing it by the dimension of the 90 percentile point you get the uniformity coefficient, (CU=d40/d90). With a CU<3 the sand is considered uniform, if the CU>3 the sand is considered non-uniform.

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Figure 6 GRAVEL-SAND RATIO The ratio of the gravel grain size to the formation sand grain size at equal percentage points is called the gravel-sand ratio and is one of the most important parameters in gravel pack design. When the gravel-sand (G-S) ratio is too high, the oversized gravel is invaded by formation sand, reducing the permeability of the packed zone to sometimes less than the reservoir's original permeability, reducing the well's productivity. If the G-S ratio is too low it will provide good sand control but reduce the productivity. The optimum range for the G-S ratio is ±5-6 (Fig. 7), for uniform sands. With a ratio of 6, productivity is at a maximum and sand control is achieved. At a ratio of 14, the pack permeability is good but the sand control is poor. This is because the sand can move easily through the pack. With a ratio of 10, formation sand can move into the gravel pack but has difficulty moving through it, this results in a severe loss in gravel pack productivity.

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SAND CONTROL

To compensate for possible erroneous design points a G-S ratio of 5 to 6 should be used. This means the diameter of the gravel to be used for packing should be 5 to 6 times the diameter of the formation sand to be retained at the 50 percentile point, selected from the grain size analysis curve of the formation sand.

SCREEN SLOT WIDTH Absolute gravel stoppage is recommended when liners or screens are used to restrain the gravel pack. Slot widths should be as large as possible while restraining sand grains and not restricting the flow of fluid and interstitial fines. Because it is important that all gravel be tightly packed and retained, screen slot width should be about one-half the smallest gravel diameter. Screen slot width should never be greater than 70% of the smallest gravel diameter.

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EXAMPLE An example of a typical gravel pack design is shown graphically below for a sieve analysis whose 50 percentile point is about 0.004 inches. Six times this quantity is 0.024 inches. The gravel size for this sand is taken from the table below for the closest median grain size. Therefore the nearest standard gravel size is 20/40 U.S. mesh. The slot width is taken as 1/2 the smallest gravel, which is 1/2 x 0.0165=0.00825 inches.

U.S. Sieve Number 10 t o 20 10 to 30 20 to 40 30 to 40 40 to 50 40 to 60 50 to 60 60 to 70

Grain Diam. (in) 0.033 to 0.079 0.023 to 0.079 0.0165 to 0.033 0.0165 to 0.023 0.0117 to 0.0165 0.0098 to 0.0165 0.0098 to 0.0117 0.083 to 0.0098

Median Grain Diameter (in) 0.048 0.051 0.023 0.019 0.014 0.013 0.011 0.009

Perm. k., in Darcies 500 191 121 110 66 45 43 31

Common Gravel Sizes

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WELL PREPARATION When performing a gravel pack, attention to details can determine whether the job is a success or a failure. Therefore a logical and well executed completion procedure can offer the best results when performing a gravel pack. Casing cleaning, perforating and perforation surging are a few of the things that can be done to help perform a successful job.

CASING CLEANING Casing cleaning consists of making bit & scraper runs to remove cement, rust and other foreign materials from the inside of the casing. Acid, caustic and surfactant pills are then pumped down the casing followed with a thick polymer slug to bring back all the debris that the acid and surfactant dissolve. It is important to get the casing as clean as possible so that fines from the pipe do not get pumped into the formation and gravel pack, thereby reducing the formation permeability. It is essential that the gravel in the tunnel through the casing cement sheath is as clean as possible to reduce pressure drop through this linear flow area.

PERFORATING Proper perforating of cemented casing is critical to the success of cased hole gravel packing. Factors to be considered are: y Hole size y Penetration depth (length) y Shot density Sand filled perforations are the main restriction to flow in a cased hole gravel pack. Therefore, increasing the size of the perforations is recommended (Fig. 8). The perforation charges selected should yield the largest diameter and the deepest penetration possible. Perforation diameter is a more critical parameter to the flow capacity of cased hole gravel packs than is perforation length, just so the perforation extends beyond the cement. A minimum of 4 shots per foot should be used (Fig. 9). Aramco typically shoots 0.75 holes at 12 spf for gravel pack jobs in the Central Area.

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PERFORATION SURGING Jet perforating is damaging to the formation despite the fact that they penetrate deeply and apparently create an open channel. In reality perforation debris is usually left in the channel and the perforating process actually crushes the sand around the channel, leaving a sheath of compacted material that reduces permeability. If plugged perforations are not cleaned out then an effective gravel pack is not possible. Perforation surging is one way of cleaning out perforations and removing plugging material from them. The perforating is done in conjunction with a tool that is no more than a cylindrical chamber with a packer that can be sealed so that the fluid inside the chamber is at a lower pressure than formation pressure. The tool is run to the specified depth and the packer is set to separate the formation from hydrostatic pressure in the casing/tubing annulus. The completion fluid is then displaced down and out of the tubing through the packer by-pass with a lighter fluid (usually diesel). Once the lighter fluid is in place the by-pass is closed and the well perforated. The pressure change creates a surge thereby forcing the perforation debris out of the channels into the well, then falls into the rathole, leaving the perforation open.

OVERBALANCE PERFORATING Occasionally there is a need to perforate overbalanced. This situation arises when there is a sand that is so unconsolidated it will probably cave in once perforated. In order to solve this problem a well is pressured up then perforated with enough pressure on the wellbore to hold the perfs open until some pre-pack gravel is pumped into place, see figure 10. This will prop the perfs open and not allow them to close or cave in after perforating.

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PRE-PACK

GP ASSEMBLY

Figure 10

EXTREME OVER BALANCE PERFORATING Another method of perforating is called extreme overbalance perforating. The reason to perforate with this method is to enhance the productivity by mini-fracing the formation through the perfs then pumping the pre-pack sand. The well is pressured up higher than its fracture pressure then perforated, pre-pack sand is pumped into the perfs and the fraced formation. The pre-pack acts as a propant to the fractures and keeps them open.

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GRAVEL PLACEMENT The gravel pack is performed using the special tools shown in figure 11. One of the primary tools used is the sump packer, this is normally set 5 below the perfs and provides a rat hole so that during the job the gravel does not fall into the casings rathole. It is also good for depth control. Other tools are: the gravel pack screens and the gravel pack packer, all these items stay in the well after the gravel pack is performed, and the multi- service circulating tool, which is pulled out after the gravel pack is finished.

SLURRY PLACEMENT The following is a brief procedure of how a gravel pack is performed: 1. The sump packer is run and set on depth (5 below the bottom planned perforation) by wireline prior to any perforating for the gravel pack. 2. After the perforating is completed, the gravel pack assembly is run in the hole and stung into the sump packer. 3. The gravel pack packer is then set. 4. With the circulating tool by-pass in reverse circulating position, a “pickle” is pumped down the completion string to the end of the string. The “pickle” is then reverse circulated out of the well. This “pickle” is composed of acid and gel. 5. The tool is then put into the circulating position and filtered brine is pumped down the string. Once the brine is at the end of the tubing the tool is lowered 1 into the squeeze position and the brine is pumped into the perfs to establish an injection pressure and rate. 6. The tool is then opened to the circulating position and the pre-pack slurry composed of two pills of 4lb gel and 500 lbs. 20/40 gravel is spotted to within 2 bbls of the tool. 7. The tool is then closed by slacking off into the squeeze position and the pre-pack gravel is squeezed into the perfs so that they remain open prior and during the gravel packing.

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8. The tool is then opened to the circulating position and the gravel pack gravel is pumped down the tubing string with filtered brine and spotted to within two bbls of the tool. The tool is then lowered 1 into the squeeze position and the gravel is both squeezed into the perfs and falls below on the outside of the screen on top of the sump packer until the perfs “screen out” (fill up with sand). 9. The circulating tool is then picked up 1 into the circulating position and pumping is continued with brine returns coming up through the gravel pack screen and out the top of the circulating tool into the annulus, until gravel covers the screen and circulation stops with the well pressuring up to 1400-1500 psi. 10. The well is then repressured up to 1400-1500 psi and bled off three times. 11. The work string is picked up into the reverse position and sand is reversed out until returns are clean. 12. Two tubing volumes of clean brine is then reverse circulated. 13. After one hour the work string is then lowered into circulating position again & pressured up to 1400 psi to check the pack for returns. 14. If there are no returns then the circulating tool is pulled out of the packer and out of the hole. The well is now ready to be brought back onto production slowly at first with sand content, if any, monitored.

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Figure 11

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COILED TUBING

TABLE OF CONTENTS INTRODUCTION .............................................................................................................. 1 EQUIPMENT ..................................................................................................................... 2 1. Injector Head........................................................................................................ 2 2. Coiled Tubing BOP.............................................................................................. 2 OTHER EQUIPMENT AND CONSIDERATIONS.......................................................... 3 1. Tubing .................................................................................................................. 3 2. Circulating System............................................................................................... 3 3. Depth Capabilities................................................................................................ 4 4. Working Pressure................................................................................................. 4 5. Tubing Collapse ................................................................................................... 4 6. Circulating Rates.................................................................................................. 4 COILED TUBING WORKOVER OPERATIONS ............................................................ 5 1. Acid Washes ........................................................................................................ 5 2. Nitrogen Lifting (livening) .................................................................................. 5 3. High-Angle Conveyance...................................................................................... 5 COILED TUBING SAFETY.............................................................................................. 6 1. Rigging Up........................................................................................................... 6 2. Pre-job Testing..................................................................................................... 6 3. Operational Considerations.................................................................................. 6

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INTRODUCTION Coiled tubing units have been used in Saudi Aramco operations since 1980. Their most common uses include nitrogen kick-offs, spotting acid and cleaning out fill. Recently, they've been used for conveying open-hole logs, setting and retrieving tubing plugs and acidizing horizontal wells.

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EQUIPMENT A sketch of a typical coiled tubing unit can be found in the WORKOVER METHODS section of the INTRODUCTION TO WORKOVERS chapter. For Saudi Aramco operations, all the individual pieces of equipment are mounted on skids so the same units can be used for onshore or offshore operations . 1.

INJECTOR HEAD In operation, the coiled tubing is fed from the reel, over a guide and into the injector head. A drive mechanism using chains with contoured metal blocks for traction can safely generate up to 24,000 lbs. of pushing or pulling force. This system allows the tubing to be fed into or pulled from the well at speeds up to 200 ft/min. Because the tubing is reel mounted, rotation of the string is not possible. In some cases, a mud motor can be fixed to the end of the coil to provide rotation. This set up has applications in cleaning out fill below a packer.

2.

COILED TUBING BOP

STUFFING BOX

From the injector head, the tubing passes through the coiled tubing BOP before it goes into the tree and the well below. This is a specialized BOP stack designed to meet the needs of coiled tubing operations.

BLIND RAMS CUTTER SIDE OUTLET SLIPS

The uppermost component of the stack is the stripper. This is a small annular preventer designed to withstand vertical movement of the coiled tubing while maintaining a pressure seal. The side outlet allows access to the production tubing for pumping or bleeding operations. The slips and cutter allow the tubing to be isolated, supported and cut should a leak at the surface occur.

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PIPE RAMS CROWN VALVE AND XMAS TREE

COILED TUBING BOP

Figure 1

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OTHER EQUIPMENT AND CONSIDERATIONS 1.

TUBING The pipe used in coiled tubing operations is made up of a number of sections of tubing welded together to form a single string of pipe. There are no threaded connections. Reels typically start at 15,000' but can be ordered in excess of 18,000'. As they age, a portion is periodically cut from the end of the tubing string in a manner similar to cutting and slipping a drill line. This prevents the same interval of tubing from being fatigued or over-stressed. There are five coiled tubing units (CTU's) currently available to Saudi Aramco. All are rated at 5000 psi and are equipped as follows:

No. of Coils

Tubing Size

Wall Thickness

Coil Length

Yield Strength

1

1-1/4"

0.095"

11,000'

70,000 psi

2

1-1/2"

0.109"

15,000'

80,000 psi

1

1-1/2"

0.095"-0.134"

15,000'

70,000 psi

1

1-3/4"

0.095"-0.156"

14,000'

70,000 psi

Table 1 2.

CIRCULATING SYSTEM Under most workover conditions, a rig will be present. The circulating systems found on the rigs working for Saudi Aramco typically consist of 1000-1500 bbls of compartmentalized mud tanks with solids control equipment and the ability to pump 220 gpm at 3000 psi.

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3.

DEPTH CAPABILITIES Normal tubing is good for about 12,000'. Reels with tapered strings (heavy wall welded to normal wall thickness tubing) can reach deeper. The depth that a CTU can reach is normally determined by how much tubing is on its reel. For safety reasons, 500'± of tubing must remain on the reel at all times.

4.

WORKING PRESSURE As previously mentioned, the published pressure rating of coiled tubing units currently available in Saudi Aramco is 5000 psi. In some cases this pressure can be limited by the injector head.

5.

TUBING COLLAPSE Coiled tubing is thin-walled tubing and, as a result, it is very susceptible to collapse. Therefore, reverse circulating is not permitted. It is important that procedures are followed to prevent solids build-up in the annulus that could potentially stick the coiled tubing. For this reason, the coiled tubing is normally circulated while it is being run into and pulled out of the well.

6.

CIRCULATING RATES Pumping pressures can be very high, even at shallow depths. This is because the entire length of tubing must be circulated through regardless of the depth of the end. For this reason, pumping rates are typically restricted to a few barrels per minute.

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COILED TUBING

COILED TUBING WORKOVER OPERATIONS Much of the coiled tubing work done for Saudi Aramco is performed by the producing departments without a rig on location. Other jobs are performed in conjunction with a workover or drilling rig. Some of these are: 1.

2.

3.

ACID WASHES An acid wash, or soak, may be done with the rig on location to remove minor damage to an open hole interval or debris left in the perforations after the workover or completion. A typical job might consist of the following steps. a.

Rig up CTU and BOP's. Pressure test equipment and pre-job meeting.

b.

Run in hole to PBTD and pull up to just below the treatment interval.

c.

Place acid across the treatment interval. Pull up a safe distance and let the acid soak for one hour.

d.

RIH with coiled tubing and circulate out spent acid. The next operation is quite often nitrogen lifting, or livening, as described below.

NITROGEN LIFTING (LIVENING) Occasionally, the well will be lifted (livened) with nitrogen while the rig is still on location. This operation often follows an acid wash. The procedure may be as follows. a.

Start pumping nitrogen down the coiled tubing at 3 gpm until the spent acid and mud/brine is circulated out of the well.

b.

When the well begins to flow unassisted, continue pumping the nitrogen as slow as possible while POH with the coiled tubing.

c.

Rig down the CTU.

HIGH-ANGLE CONVEYANCE Recently, Saudi Aramco has been using coiled tubing as a means for conveying logs and other downhole equipment in horizontal wells. Much of this work to date has been done during the initial completion. Future workovers of these horizontal wells will probably require a several coiled tubing unit operations as well.

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COILED TUBING SAFETY 1.

2.

3.

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RIGGING UP a.

Avoid the use of flexible high pressure hoses in applications exposed to well pressures. Never use a rubber hose on the return flow line when washing sand with nitrogen.

b.

Secure all treating lines with chains.

PRE-JOB TESTING a.

Fill the BOP's with water and pressure test to 150 psi, then test again to the rated working pressure.

b.

If using nitrogen, drain out the water and test the BOP's again with nitrogen to the rated working pressure.

c.

If working with water or acid, fill the coil with water and pressure test to the maximum anticipated surface pressure.

d.

If using nitrogen, drain out the water and test the coil again with nitrogen to the maximum anticipated surface pressure.

OPERATIONAL CONSIDERATIONS a.

Jetting should always be done through a choke to control flow. A valve should be placed in the return flow line, upstream of the choke manifold, in case the choke washes out during coiled tubing operations.

b.

Always hold a pre-job meeting. Check well control training of the coiled tubing crew.

c.

Make sure personal protective equipment is available and used. Eye wash facilities should be located near the working area.

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d.

When using nitrogen, the end of the flare line should be a minimum of 150' from the wellhead. A pilot light should be lit at the end if a potential for hydrocarbons exists.

e.

Personnel should remain clear of pressured lines and pump cylinders during CTU operations.

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WIRELINE OPERATIONS

TABLE OF CONTENTS INTRODUCTION............................................................................................................. 1 I.

SURFACE EQUIPMENT .........................................................................2 A. Wireline Units..................................................................................2 B. Types of Wire ..................................................................................2 C. Lubricator Assembly........................................................................2

II.

SLICK & BRAIDED LINE OPERATIONS ...........................................4 A. General Wireline Tool Design .........................................................5 B. Rope Socket .....................................................................................5 C. Sinker Bars.......................................................................................6 D. Mechanical Jars................................................................................7 E. Hydraulic Jars ..................................................................................8 F. Knuckle Joint ...................................................................................8 G. Running Tools and Locking Devices...............................................9 H. Landing Nipples...............................................................................9 I. Tubing Plugs ..................................................................................10 J. Static Pressure & Temperature Measurements..............................10 K. Gauge Ring & Junk Basket............................................................11 L. Gauge Cutter ..................................................................................11 M. Other Tools ....................................................................................12

III.

ELECTRIC LINE OPERATIONS ........................................................13 B. Cement Bond Logs ........................................................................14 C. Collar Locator ................................................................................15 D. Gamma Ray Logs ..........................................................................15 E. Flow Meters ...................................................................................15 F. Neutron Logs .................................................................................16

IV.

WIRELINE SAFETY..............................................................................17 A. Rigging Up.....................................................................................17 B. Pre-job Testing...............................................................................17 C. Operational Considerations............................................................17

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WIRELINE OPERATIONS

INTRODUCTION Wireline work is the running and pulling of tools and other downhole devices into and out of a well using small diameter wire from a surface mounted reel. Operations routinely performed with wireline include setting and retrieving downhole equipment (SSSV's, plugs, etc...), logging and fishing. The primary advantages of using wireline are: 1.

The low cost resulting from savings in rig time.

2.

When a lubricator is used, the work can be performed under pressure, eliminating the need to kill the well.

Some limitations of wireline include: 1.

The risk of parting the wireline with the possibility of a costly fishing job.

2.

Since most wireline work is performed through tubing, the size of the tools that can be run is limited by the ID of the completion.

3.

Wireline cannot be used to convey logs or tools into high angle extended reach or horizontal wells.

4.

The inability to rotate tools downhole.

5.

Fluid circulation is impossible.

This chapter describes typical wireline operations performed in Saudi Aramco.

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I.

SURFACE EQUIPMENT A.

Wireline Units Wireline units vary from the simple skid mounted units to complex computerized units. The minimum requirements are a powered reel, depth gauging and a weight indicator. Saudi Aramco Wireline units are equipped with two reels, usually a 0.105" single strand and a 3/16" braided line. Wireline operations may be performed with or without a rig. At Saudi Aramco, they are an important part of almost every workover

B.

Types of Wire 1.

Slick Line Slick line is a solid, single strand of wire. A diameter of 0.105" is the standard for Saudi Aramco operations. This wire is made of alloy steel for sour service. It's maximum operating load is 1000 lbs. A larger single strand wire, 0.125" is also available where more load capacity is required. It's maximum operating load rating is 2000 lbs. It is also made of alloy steel (grade-70) for sour service. For fishing operations this wire is beginning to be used more often due to its superior strength/weight ratio when compared to 3/16" braided line.

2.

Braided Line This is a stranded (braided) wire with a diameter of 3/16" being the current standard for Saudi Aramco wireline fishing operations. It is also made of alloy steel for sour service and has a maximum operating load rating of 3500 lbs. This may change as 0.125" wire is cheaper and is being installed on more Saudi Aramco's wireline units.

3.

Electric Line Offered by the logging service companies, electric line is a braided line capable of transmitting signals to surface.

C.

Lubricator Assembly When working under pressure, a lubricator assembly is required that will be long enough to contain the longest combination of tools plus any equipment

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WIRELINE OPERATIONS retrieved from the well. A lubricator may be thought of as an air-lock except that water is used instead of air. The packing on the stuffing box allows the wire to pass into the well while maintaining a seal around the diameter of the wire thereby containing wellbore pressure, if any. A combination gland nut and oil cap on top of the stuffing box allows the pack-off force to be adjusted periodically to compensate for wear. If mud continues to leak out of the top when the nut is fully tightened, it usually means that it is time to change out the packing. Passing tools into a well under pressure is accomplished with a lubricator. After rigging up and testing each component of the assembly, the basic procedure is as follows. 1.

With the crown valve shut, the wire is fed through the stuffing box and lubricator. The rope socket is then installed on the end.

2.

The tool string is made up, attached to the rope socket and fed into the lubricator.

3.

The lubricator is made up on the WL BOPE and pressure tested.

4.

The pressure is equalized with the well. The crown valve is then opened and the tool string lowered by slacking off on SHEAVE the wireline reel's brake. ASSEMBLY Several checks are made when WL WIRE STUFFING BOX tools are run into a well. Some of these are: 1.

Check the master valve to ensure that it is open. Care should be taken not to close it on the tool string or wire. Closing the master valve on the tools can damage the tools and the valve. Closing the valve on the wire will cut it, dropping the tools down the tubing.

2.

Check the pack-off force on the wire. This force should be loose enough to allow the wire to

LUBRICATOR SECTIONS WIRELINE BOP CROWN VALVE & XMAS TREE

LUBRICATOR ASSEMBLY Figure 1

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WIRELINE OPERATIONS slide through the packing and just great enough to contain the well's pressure. 3.

Tool string weight. If the packing has been bled off to the point where it leaks and the string still wont fall, then increase the weight of the string by adding sinker bars.

II.

SLICK & BRAIDED LINE OPERATIONS The choice of whether to use slick or braided line depends on what will be required of the wire and, for Saudi Aramco operations, what the available units are equipped with. In Saudi Aramco, 0.105" slick line is normally used to set and pull ball valves, plugs and other tools in tubing sizes up to 4-1/2". For 7" and larger sizes, 3/16" braided line or 0.125" slick line is used to perform these tasks. Regardless of the tubing size, wireline fishing is usually performed with 3/16" braided line or 0.125" slick line. The wireline tool string is attached to the wire by a rope socket. The typical tool string would include sinker bars (stem), spang jars (mechanical jars), a knuckle joint and the tool selected to do the job at hand. An example of a WL tool string is shown at the right. The following sub-sections will discuss the wireline tools commonly used in Saudi Aramco operations.

WIRE

ROPE SOCKET

SINKER BARS (STEM)

MECHANICAL JARS (SPANG JARS)

KNUCKLE JOINT

ANY OF A NUMBER OF WIRELINE TOOLS RUNNING TOOL PICTURED HERE

WIRELINE TOOL STRING Figure 2 Page 4

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A.

General Wireline Tool Design The threaded connections and fishing necks are standardized for each string size to provide maximum flexibility in operations with a minimum number of tools on location. Saudi Aramco uses two basic tool strings as outlined below: String Size (Tool OD) Fishing Neck OD Connection (Sucker Rod Thread)

1-1/2" 1-3/8" 15/16"

1-7/8" 1-3/4" 1-1/16"

One other body size is occasionally used by Saudi Aramco. These are sinker bars 2-1/8" in diameter. They employ the same 1-1/16" sucker rod connection found on the 1-7/8" tools. They are used in heavy jarring where high impact forces are required. Connections should be clean and dry before making up a wireline tool string. Do not dope or otherwise lubricate the threads of wireline tools. B.

Rope Socket The rope socket connects the wire to the tool string. With the old style, the wire passes through the body, the spring and spring support, around a grooved disc and is tied back on itself. With the new style, the spring and disc are replaced by a wedge system. The wire is wrapped around the thimble and the thimble is wedged into the eye. No tying is required. STRIKING SURFACE PULLING FLANGE FISHING NECK SPRING THIMBLE EYE BODY SPRING SUPPORT GROOVED DISC GROOVED SUCKER ROD THIMBLE THREAD (a) Old Style (b) New Style

ROPE SOCKETS Figure 3 On both designs, a groove in the disc or thimble allows the wire to be held firmly without being pinched and damaged.

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The reduced O.D. section near the top is the fishing neck. The pulling flange, with its tapered top, at the upper end of the fishing neck allows the tool to be easily engaged and pulled out of the hole during fishing operations. C.

Sinker Bars The sinker bars, or stem, are a solid steel bar with threaded ends. They are placed in the wireline tool string to add weight. Standard sinker bars come in 2', 3' and 5' lengths. There are generally two ways to calculate how much sinker bar weight to use for a given wireline string. The first requires a minimum of 5' up to 1000 psi plus 2' of stem for each 1000 psi over the initial 1000 psi. The second method is to use 30 lbs. for the first 1000 psi and 6 lbs. for each 1000 psi thereafter. The weight of the other components in the tool string is not counted. The following formula can be used to estimate sinker bar weight. D2 x 8 = lbs/ft 3 Where D = Bar O.D. (in.)

SUCKER ROD THREAD PULLING FLANGE FISHING NECK WRENCH FLAT

BODY WRENCH FLAT SUCKER ROD THREAD

SINKER BAR (STEM) Figure 4

Add approximately 12 lbs to this estimate to overcome stuffing box friction when using 0.105" slick line and about 20 lbs for 3/16" braided line. Wrench flats are provided so sucker rod wrenches can be used to make up the sinker bars. Sinker bars are analogous to drill collars in the drilling bottom hole assembly. They are the members that are expected to withstand the cyclic loading (tension and compression) during jarring operations. Therefore, the sinker bars must be made up properly using the sucker rod wrenches.

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D.

Mechanical Jars Many wireline operations require that an impact force be delivered to set or free a particular device. Mechanical, or Spang jars are used to generate an impact force in either the upward or downward direction. The weight of the sinker bars provides the energy for the impact. They are placed directly above the jars. Picking up on the tools until the jars are open, then allowing the tools to fall, rapidly closes the jars, applying a downward impact. The size and straightness of the tubing, depth, pressure, fluid viscosity and density all affect the impact force.

SUCKER ROD THREAD PULLING FLANGE FISHING NECK WRENCH FLAT

STROKE

WRENCH FLAT SUCKER ROD THREAD

MECHANICAL JAR By pulling up quickly, the jars open and the momentum of the stem will provide the upward impact. The factors mentioned Figure 5 above do not impair upward jarring to the extent that they do downward. Therefore, a higher upward impact force can be generated than downward. For tubing up to 3-1/2" OD, 1-1/2" jars are good. For larger tubing, Saudi Aramco uses 1-7/8" jars. Jars are a key component of any wireline tool string.

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E.

Hydraulic Jars Hydraulic wireline jars (not pictured) are designed to provide a dependable, controlled upward blow. The jar's body has large and small ID sections. When tension is applied to the top of the tool, the piston is pulled upward through the small section of the body. In this part of the tool, the hydraulic fluid has only a small area to flow around the piston causing the piston to move slowly. Once the piston has traveled into the large ID section, the hydraulic fluid can move past it freely. The piston accelerates and impacts the top of the tool creating the jarring force. Because impact force is a function of momentum, the velocity and mass of the piston/stem configuration both contribute to the jarring force. The greater the tension used, the more the piston will accelerate after it clears the small ID section. This increases the velocity component of the SUCKER ROD momentum equation. If the weight THREAD of the stem is increased (adding PULLING FLANGE sinker bars), the mass component of the momentum equation increases. FISHING NECK

F.

Knuckle Joint The knuckle joint provides flexibility in the wireline tool string. It is almost always run below the jars, just above the running or pulling tool. If crooked tubing is expected, knuckle joints may also run above the jars or in between sinker bars. As a safety precaution, knuckle joints should be inspected frequently to avoid having them come apart downhole.

WRENCH FLAT BALL JOINT

WRENCH FLAT

KNUCKLE JOINT Figure 6

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G.

Running Tools and Locking Devices Running tools are simply a top sub secured to the locking device with a shear pin. There are two types of locking devices commonly used in Saudi Aramco operations: selective and non-selective. The selective tools have locking keys that are matched to a specific profile nipple in the tubing. When they are run into the tubing, their spring loaded keys pop into the proper profile automatically. Non-selective devices must be set by first lowering the tool past the nipple and then pulling back through the nipple to activate the locking keys. Next, the tool is lowered a second time until the keys pop into the nipple's profile. Once the keys of either type have engaged the profile, downward blows are given to the tool to drive the mandrel down and lock the keys in the extended position. Finally, the running tool is sheared off by upward jarring and pulled out of the hole. There are other locking devices that can be run. The collar lock that can be set in any collar and the slip lock that can be set anywhere inside the tubing. These locking devices are not normally used in Saudi Aramco.

H.

Landing Nipples Although landing nipples are not part of the wireline tool string, wireline tools are hung off in them and they need to be discussed. There are three types of landing nipples, non-selective, selective and polished. Saudi Aramco uses all three.

TUBING PIN

TUBING PIN

LOCKING RECESS

LOCKING RECESS

NO-GO

SEALING SECTION

TUBING PIN

TUBING PIN

(a) Non-Selective

(b) Selective

TUBING PIN HONED SEALING SECTION TUBING PIN (c) Polished

LANDING NIPPLES Figure 7

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A landing nipple is termed non-selective if there is a no-go profile in the nipple. This no-go profile does not allow the plug to pass below the nipple and can only be set in that specific nipple. A selective nipple does not have this profile and therefore allows the plug to pass through the nipple and be set in any one of a number of nipples below the selective nipple, or in the selective nipple itself. To set a plug inside tubing with wireline, Saudi Aramco Wireline (SAWL) uses Otis "PX" and "PXN" plugs almost exclusively. These plugs come equipped with a pressure equalization valve and matching prong. They are used with Otis "X" (selective) and "XN" (non-selective, no-go) landing nipples respectively. The plug is run without the prong. The prong is then inserted on the second trip, sealing the equalization ports and preventing sand or fill from falling into the interior of the plug. Prior to retrieval, the prong is removed. This provides an equalization path across the plug, preventing it from being blown uphole. Note that two wireline trips are required to run or pull these plugs. Where it is desirable to make only one trip, or where difficulty inserting the prong is expected, such as a highly deviated well, Otis "XX" or "XXN" are used. The plug is run or retrieved and the equalizing ports are closed and opened in the same trip. There is nothing to prevent fill from falling into the inside of the tool and preventing the retrieving tool from seating in the profile. The recent horizontal drilling program has brought the running and retrieving of these plugs on wireline to their limit. Coiled tubing conveyance has been used to replace wireline in many of these wells. J.

Static Pressure & Temperature Measurements Saudi Aramco uses mainly Amerada gauges (bombs) to measure static pressures and temperatures. Production Engineering routinely monitors for casing leaks by sampling temperatures at 500' intervals and plotting the results. If anomalies exist, they may repeat the sampling at shorter intervals to pinpoint the leak.

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Depth (Ft)

Depth (Ft)

UP FLOWING CASING LEAK

NORMAL GRADIENTS

NORMAL GRADIENTS

DOWN FLOWING CASING LEAK .

Temperature (°F)

Temperature (°F)

TEMPERATURE SURVEY PLOTS Figure 8 K.

Gauge Ring & Junk Basket This tool (not shown) consists of a section of body that has a specific OD (normally the drift ID of the casing) and a section of perforated or slotted pipe designed to catch anything which attempts to pass through the tool as it is run into the hole. Prior to running and setting production packers, a gauge ring and junk basket are run repeatedly until no wellbore or mud debris is retrieved in the junk basket. This operation reduces the chance of setting the packer prematurely due to junk floating in the hole or stuck to the inside of the casing.

L.

SUCKER ROD THREAD PULLING FLANGE FISHING NECK

BODY

Gauge Cutter A Gauge cutter (Figure 9) can be used to check the ID of tubing for any obstructions. It can also verify the tubing ID of a producer at the beginning of a workover.

GAUGE CUTTER Figure 9

It is run before any

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other tools are run into the well. The tool is hollow with windows machined into the body to allow fluid and debris to flow through the tool. The bottom is beveled on the inside and is the full drift diameter of the tubing. M.

Other Tools Although this chapter has focused on wireline tools most common to Saudi Aramco operations, there are many other tools that can be run on wireline. Information on other tools can be found in other wireline manuals and in wireline service company catalogues.

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III.

ELECTRIC LINE OPERATIONS

Electric line is used for two types of operations in workovers: as an ignition source for explosive charges and to convey electrical signals from logging tools to the surface. Explosive charges are mainly used in perforating operations. Other uses include string back-off's, cutting tubulars and the setting of production packers and bridge plugs. These operations are discussed in other sections of this manual. This section will address only production, or cased hole, logging applications. The primary task of production logs is to document the movement of fluids. This can be inside the tubing, in the tubing-casing annulus (TCA), other annuli or through the reservoir itself. The fluids of interest may be formation water, hydrocarbons or fluids injected for pressure maintenance, disposal or stimulation. Each log provides information about a specific aspect of the environment being logged. Therefore, suites of complementary logs are run to get the whole picture. The following are typical production logging services available to Saudi Aramco. A.

Temperature Logs Most temperature logs run today employ a small probe whose electrical resistance changes with temperature. The changes in resistance with depth are recorded at the surface.

2000

Temp (°F) 3000

NORMAL GRADIENT

4000 Temperature logs can determine casing leaks or the top of cement (when cement does not reach the surface during a cement job). Temperature logs are usually done 5000 from the top down in order to keep TEMPERATURE ANOMALY fluid disturbances to a minimum.

The normal gradient is determined by placing a straight-edge along the temperature trace on the log. The best fit straight line is the gradient. The portions of interest are usually the deviations from the normal gradient.

TEMPERATURE LOG Figure 10

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B.

Cement Bond Logs Cement bond logs, usually refer to a CBL-VDL-GR-CCL combination.

FREE PIPE 57 µsec/ft

GOOD BOND TO PIPE BUT NOT TO THE FORMATION

The CBL tool consists of an TIME acoustic transmitter and one or ZERO two receivers 3 feet apart with GOOD BOND an acoustic insulator to prevent TO PIPE AND sound-wave transmissions FORMATION through the tool. It continually measures the amplitude of the CBL SIGNALS first arrival. Free pipe produces Figure 11 high amplitudes while well bonded pipe produces very little signal. The VDL (Variable Density Log) adds receivers 5' feet from the transmitter to simultaneously measure amplitude. These are positioned so that they give information relating to the cement bond with the formation. Casing Collar and Gamma Ray measurements are added for depth correlation. The bond log operates on the principal that cemented casing will not resonate like un-cemented casing in the presence of sound waves. If the pipe is free (not bonded to the cement) it will ring when struck with an acoustic signal. Little or no signal from the formation will be returned. If the pipe is bonded to the cement but the cement is not bonded to the formation, little or no signal is received from the formation. Because the pipe is bonded to the cement, the cement sheath dampens the casing's vibrations and no pipe signal is detected. If the cement has bonded with the pipe and the formation, no acoustic energy is lost in the pipe (no pipe signal) and a strong signal is received from the formation. The CBL information is normally presented on three tracks. The full wave train signal (sometimes called the VDL) is at the right, dark portions indicating positive signals. The center track contains the amplitude and transit time for the first signal received. The left track usually contains a Gamma Ray and Collar Locator trace for depth correlation.

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C.

Collar Locator The casing collar locator (CCL) is an essential tool for depth correlation and is run with most other production logging tools. It is very popular for perforating depth control. When the tool's sensor moves past either end of a casing collar, a disturbance in the magnetic field is registered as successive voltages of opposite polarity. The resulting plot at the surface is a "tic" mark normally placed to the right of the gamma ray track. These tic marks appear at every collar and can be lined up to compare two or more logs on depth with respect to each other. This can only work if there are differences in joint length. If all the casing joints were exactly the same length, the CCL tics would line up at all depths, creating confusion. To remove a possible source of error, Saudi Aramco occasionally uses flag joints (short joints of casing, typically 10') in the casing strings near the zones of interest. These are easily spotted on the log, simplifying depth correlation.

D.

Gamma Ray Logs The gamma ray tool does not contain a radioactive source. It simply measures incoming gamma rays (a byproduct of natural radioactive decay). Gamma rays easily penetrate the casing making this one of the most useful tools in production logging. Since each type of rock encountered in the wellbore and the dissolved minerals in the fluids within them decay at their own characteristic halflives, gamma ray readings will vary as the tool is pulled past the stratified formation. This produces a signature of the formation that will largely remain constant for the life of the well. The major exception is in areas of high porosity, where migrating fluids can change the concentrations of suspended minerals or leave deposits. Information about water flow within the reservoir can be gained by examining gamma ray logs taken at intervals during the life of the well. Gamma ray logs are also used to detect radioactive tracers that have been injected into the formation.

E.

Flow Meters Spinners record the shaft movement of a propeller mounted in a fluid stream. They are affected by hole angle, turbulence and multiphase flow. In two-phase flow applications, spinners are combined with a density measuring device. Knowing the densities of both fluids (surface samples), the production engineer can accurately determine the flowrate and the fraction of each fluid.

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F.

Neutron Logs There are a number of neutron tools available. All contain a radioactive source that bombards the formation with neutrons causing the effected atoms to emit a gamma ray. The resulting count will be higher for gas sands than for oil/water sands. Therefore, conventional neutron tools are widely used to determine gas-liquid contacts. Some common production logs run for Saudi Aramco are listed below. CNL

Compensated Neutron Log Employs two detectors to provide borehole compensation. Used to estimate porosity behind casing.

NFD

Nuclear Fluid Density (NFD) A fluid stream is passed between a source and a detector. Changes in the fluid density produce a change in the count rate at the detector. Used to determine fluid density and local gradient.

TDT

Thermal Decay Time Log Also referred to as the PNL (Pulsed Neutron Log). The tool measures the amount of thermal neutron absorption by the formation. Since chlorine is the best naturally occurring neutron absorber, the log reflects the amount of chlorine (sodium chloride) in the formation water. The Sigma track discriminates between water and hydrocarbons, and is used to monitor the oil-water contact. The count rate curves provide an indication of gas and the ratio provides a porosity index. If lithology, shaliness and porosity are known, the TDT log can be used to determine water saturation.

PLT

Production Logging Tool A combination of a flow meter and a nuclear fluid densimeter. Used extensively by Saudi Aramco to determine the flow and the oil/water ratio while a well is producing.

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IV.

WIRELINE SAFETY

A.

B.

Rigging Up 1.

Ensure that the lubricator is long enough to contain the entire tool string plus the fish.

2.

Secure the lubricator if working under pressure.

3.

Secure the wireline unit so it will not skid toward the well when line tension is high.

4.

Make sure the pack-off can be reached easily and safely.

Pre-job Testing 1.

C.

Test the lubricator and wireline BOP's to the anticipated pressure plus 500 psi.

Operational Considerations 1.

When bleeding off lubricator pressure, avoid freezing of the bleeder valve by opening and closing it several times.

2.

When handling explosives, no radios are to be in use when the guns are within 200' of surface.

3.

Check well control training of the wireline crew.

4.

Make sure personal protective equipment is available and used.

5.

Non-essential personnel should remain clear of perforating guns and other explosive charges.

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TABLE OF CONTENTS

INTRODUCTION ...............................................................................................................1 PACKER RETRIEVAL.........……............…..……...................................................….....2 DETERMINING STUCK POINT ....................……………......................................…....4 FREE-POINT INSTRUMENTS .....................……………................................…............5 PARTING THE PIPE STRING.............................................…………….......…...............6 1. 2. 3. 4.

Back-Off .................................…................………………....…...............6 Jet Cut ................…..............................………………...........…...............7 Chemical Cut ...................................……....……………..........................7 Mechanical Cut ........................................…………………….................10

FISHING TOOLS ...................…................................................…………………..........12 1. 2. 3. 4. 5. 6. 7. 8.

Releasing Overshot ...……………............................................................12 Releasing Spear ....................……………….............................................13 Oil Jars ..................................………………............................................14 Milling Tools ......................................................………………..............15 Taper Tap ......................................................………………....................16 Junk Baskets...........................................…………….....…......................17 Reverse Circulating Junk Baskets...............…………...............................18 Fishing Magnets......................................………………...........................19

WASHOVER OPERATIONS..............................................……………….....................20 WIRELINE FISHING TOOLS .........................................………………........................21 1. 2.

Wireline Spears......................………………............................................21 a. Center Spear.................................……............................…………...... b. Two-Pronged Grab..................................................…………….......... Hydrostatic Bailer.....................................…………….............................22

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INTRODUCTION Fishing can be defined as any operation to remove undesireable objects from the wellbore. Almost every fishing job presents special problems requiring proper analysis, creative thinking, and the exercise of good judgement to successfully accomplish the objective. Often, fishing jobs require many tools and frequent trips with the work string, which may consume much rig time and can result in high operational costs. Tools and equipment are lost in the hole for a variety of reasons. In workover operations, common causes of fishing involve the retrieval of packer completion equipment , a parted tubing production or work string, wireline tools which are left in the hole, and other tools which inadvertently fall or are left in the wellbore. Each of these different types of 'fish' require special tools and techniques for retrieval. To explain and discuss all the tools and techniques as applied to the variety of fishing operations would require a large volume; therefore, this discussion of the fundamentals must be limited to the most common problems and the generally accepted methods of solution. The costs and inherent risks when fishing make it imperative that the operations and engineering personnel involved communicate freely. Predicted additional cost and risk in certain types of fishing operations may make it necessary to change the whole job plan and objective. Factors that should be considered when planning a fishing job are: - The mechanical condition of the wellbore tubulars and the fluids or solids that they contain. - Knowledge of the size, amount, and type of fish (all dimensions are important). - Location of the fish. - Predicted cost, probability of success, and risks of failure. For relatively simple, straightforward fishing jobs such as the recovery of pipe inadvertently dropped or left in the hole, an overshot can be used for fast, inexpensive recovery. For a more complicated job-such as recovery of stuck, cemented, or plasticized pipe, or recovery of several wireline tools with the wireline on top of them-special fishing tools and skills will be required. When cases such as these arise, an experienced fishing-tool operator should be considered.

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Packer Retrieval Cutting over and retrieving permanent production packers is a very common job during workover operations. A Packer Milling tool, such as the unit shown below, is designed to mill over and retrieve the production packer from the wellbore in one trip.

Junk Basket

Packer Milling Tool

Retainer Production Packer

Retainer Retrieved Production Portion Packer

Milling Shoe

of Packer

Catch Sleeve

Fig. 1 Drill String Make-Up

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Fig. 2 Milling Packer

Fig. 3 Retrieving Packer

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Normally only a small portion of a packer, the slips and packing element, needs to be milled up. The packer milling and retrieving tool consists of a carbide rotary mill shoe, an inner mandrel, with a catch sleeve on the lower end which extends through and below the packer body during milling operations. Retrieving tools are made in several designs, but most can be operated through a 'J' on the mandrel with springs to provide back-up for operation. The retriever is run in the retracted position and is small enough to go through the packer bore. It is then set so that the grapple or catch sleeve is extended so that it will not come back through the packer bore. After the slips and packing element have been milled up, the catch sleeve will catch the remaining packer body and it will be removed with the milling tool by pulling tension in the work string to dislodge the packer from the casing. When a seal bore extension and tail pipe assembly is run below the packer, a millout extension must also be included below the seal bore extension in order to accomodate the catch sleeve. The millout extension should be twice the length of the packer to fully accomodate the stinger and catch sleeve when the mill has cut through the entire packer. If the packer is small such as in 4-1/2" O.D. casing, a rotary mill shoe should be selected rather than a milling and retrieving tool of this type, as a tool of this size would be weak. After the top packer slips are milled, the packer is retrieved with a taper tap or spear.

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Determining Stuck Point When pipe becomes stuck in the wellbore for any reason, one of the first steps is to determine at what depth the sticking has occurred. When retrieving production tubing from a well, it is often common to find that the tubing is stuck, with the seal unit siezed, or locked, up in the production packer bore due to scale or an abundance of solids that have settled around the outside of the seal unit in the tubing- casing annulus. Stretch in pipe can be measured and a calculation made to estimate the depth to the top of the stuck pipe. All pipe is elastic and all formulae and charts are based on the modulus of elasticity of steel, which is approximately 30,000,000 lb/sq. in. If the length of stretch in the pipe with a given pull is measured, the amount of free pipe can be calculated or determined from a chart available in data books. Since all wellbores are crooked to some extent, there is friction between the pipe and the wellbore. Steps should be taken to reduce this friction to a minimum. The pipe should be worked for a period of time by pulling approximately 10%-15% more than the weight of the string and then slacking off an equal amount. There are certain techniques that reduce error in estimating stuck points from stretch data. It is also necessary to assume certain arbitrary conditions. Stretch charts and formulaes do not take into consideration drill collars or heavy weight drill pipe. First, pull tension on the pipe at least equal to the normal hook load (air weight) of the pipe prior to getting stuck. This should then be marked on the pipe as point "a". Next, pull additional tension which has been predetermined within the range of safe tensional limits on the pipe. Now slack off this weight back down to the hook load weight. Mark this point "b". It will be lower than point "a". This difference is accounted for by friction of the pipe in the wellbore. Next pull additional tension on the pipe to a predetermined amount within the safe working limits of the string. Mark this point as "c". Then pull additional tension on the pipe in the same amount used to determine points "a" and "b" and slack off to tension used to locate point "c". Mark this point "d". The mid-point between "a" and "b" and between "c" and "d" will be the marks used. Measure the distance between these average marks and use this number as the stretch in inches. The amount of free pipe can be determined by using the following formula: length of free pipe (ft) = 1,000,000 x (stretch - in.) K x (pull over string wt., lbs) where K = constant The constant in this formula can be determined by: K=

Page 4

1.5 for drill pipe or K = 1.4 for tubing and casing. pipe wt, lb/ft pipe wt, lb/ft

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This method of estimating the stuck point of pipe is not completely reliable and accurate as there are many variables caused by friction, doglegs, hole angle, and pipe wear. However, it frequently indicates the cause of sticking such as possible areas of a key seat or differential sticking in open holes and collapsed tubing or tubing leaks in producing wells. In addition to the basic formula provided above for calculating the amount of free pipe, there are reference manuals available that provide stretch charts from which the length of free pipe can be read directly. The same procedures and precautions, as outlined above, should be followed to obtain the pipe stretch with a predetermined pull over the string weight. Accuracy of the charts and the formula is approximately the same, as both are affected by the same problems of hole friction, loss of material in used pipe, and the accuracy of weight indicators. Note, however, that the modulus of elasticity of all grades of steel is the same. The grade of the pipe does not affect its stretch. Also, when pipe is stuck, buoyancy forces are not effective. Immediately when the pipe is freed, the buoyant forces are again in effect and should be considered accordingly.

Free-Point Instruments Electric wireline service companies run instruments on conductor lines inside the stuck drillpipe or tubing and are able to accurately determine the stuck point of pipe. The instruments are highly sensitive electronic devices which measure both stretch and torque movement in a string of pipe. This information is transmitted through the electric conductor cable to a surface panel in the control unit where the operator interprets the data. The basic free-point instrument consists of a mandrel which encompases a strain gauge or microcell. At the top and bottom of the instrument are friction springs, friction blocks, or magnets, which hold the tool rigidly in the pipe. When an upward pull or torque is applied at the surface, the pipe above the stuck point stretches or twists. The change in the current passing through the instrument is measured by the microcell and transmitted to the surface for interpretation. When the instrument is run in stuck pipe, there is no movement of the pipe, therefore there is no tension or torque transmitted to the instrument. In turn, the gauge at the surface shows no change in its reading. Free-point indicators are frequently run with collar locators and in combination with string shots, chemical cutters, and jet cutters. This combination run saves expensive rig time, and it will also maintain a continuous sequence in measuring so that there is less chance of a misrun in cutting or backing-off. Since fishing operations usually begin as soon as the pipe is parted following the freepoint determination, it is a good practice to have the fishing tool supervisor or operator on the location during the free-point and back-off or cutting operations. Frequently there are suggestions that can be made to improve the fishing situation when the fishing operator is present to observe the free-point and parting operations. Page 5

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Parting the Pipe String After determining the stuck point in a pipe string, it is normal procedure to part the string so that fishing tools such as a jarring string or a washpipe string may be run. The cutting method for the particular job should be selected carefully. Only the back-off method, listed below, leaves threads looking up, and therefore should be selected if it is desired to screw back into the fish. There are four acceptable methods of parting the pipe string:

1. Back-Off

-

Unscrewing the pipe at a selective threaded joint above the stuck point using a prima cord explosive run on an electric wireline.

Back-off is the procedure of applying left-hand torque to a pipe string and firing a shot of prima cord explosive across a tool joint which produces a concussion to effectively partially unscrew the threads. The back-off method of parting pipe is probably the most popular of all, particularlly in drill pipe. Tool joints on drill pipe, drill collars, and other drilling tools have coarse threads, large tapers and seal by the flat surfaces or faces. These characteristics make the back-off method attractive as it leaves a threaded connection looking up, making it possible to screw back into the fish with a jarring work string. Tubing or other coupled pipe does not lend itself to back-off in the same way as drill pipe. Tubing threads are usually fine, at least eight per inch; there is only a small taper, and the threads are commonly in tension with a high degree of thread interference. Furthermore, there is a high chance of damaging the fine threads such that cross-threading will likely occur if attempting to screw back into the fish. To prevent an accidental back-off in a loose connection up the hole, the pipe should first be tightened by applying right-hand torque and then reciprocating the pipe while holding the torque. Once the pipe is made up, left-hand torque is introduced in the string. This torque must also be "worked down" by reciprocating the pipe as the torque is increased. This action distributes the torque throughout the string and assures that there is left-hand torque at the point of back-off. Theoretically just prior to firing the string shot, the pipe at the back-off point should be in a neutral condition, with neither tension nor compression. Since this condition is very difficult to obtain, any choice should lead toward slight tension in the pipe. Since buoyancy is not effective in the stuck pipe, air weight of the string is used in calculations. However, the moment the pipe starts to spin free, buoyancy produces an upward lifting force against the free pipe string. The left-hand torque is held, and the determined weight of the string is picked up when the string-shot is fired. The concussion at the joint momentarily loosens the threads and the pipe begins to unscrew. It usually must be manually unscrewed completely and then the freed pipe can be removed from the well. When ordering a string-shot, the service company needs to know the size and weight of pipe to be backed off, the approximate depth of the stuck point, the weight of the mud or fluid in the hole, and the temperature of the well. This information will dictate the strength of the charge needed as well as the type of fuse. Page 6

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2. Jet Cut

-

A cut made by an explosive shaped with a concave face and formed in a circle. It is also run and fired on an electric line.

The jet cutter is a shaped charge of explosive which is run on an electric wireline. The modified parabola face of the plastic explosive is formed in a circular shape to conform to the shape and size of the pipe to be cut. When an explosive such as this is used to cut pipe, the end of the pipe is flared, and it is necessary to mill over and remove this flare if the pipe is to be fished with an overshot from the outside. The jet cutter is often used when abandoning a well during salvage operations or when low fluid level, heavy mud, or cost would preclude the use of the chemical cutter. Jet cutters are available for practically all sizes of tubing, drill pipe, and casing. There is a possibility of damage to an adjacent string or to casing if the pipe to be cut is touching at the point where the cut is made.

3. Chemical Cut -

An electric wireline tool and procedure that uses a propellant and a chemical, halogen fluoride, to burn a series of holes in the pipe thereby weakening it so that it easily pulls apart with a slight pull.

This method of cutting pipe is the most recent innovation. It was patented and for years was an exclusive process of one wireline company. Today it is available through most electric wireline service companies for practically all sizes of tubing and drill pipe and most popular sizes of casing. All wireline cuts are generally economical because rig time is reduced to a minimum. The big advantage of the chemical cut is that there is no flare, burr, or swelling of the pipe that is cut. Therefore, no dressing of the cut is necessary in order to catch it on the outside with an overshot or on the inside with a spear. The chemical cutting tool consists of a body having a series of chemical flow jets spaced around the lower part of the tool. The tool contains a propellant which forces the chemical reactant through the jets under high pressure and at high temperature to react with the metal of the pipe. Electric current ignites the propellant which forces the chemical, halogen fluoride or bromide trifluoride, through the reaction section which heats the chemical and forces it out the jets. The tool also contains pressure-actuated slips to prevent a vertical movement of the tool up the hole and insure a successful cut. The chemical cutting tool may also be explained as producing a series of perforations around the periphery of the pipe. The reaction of the chemical produces harmless salts which do not damage adjacent casing. The products of the chemical reaction are harmless and are rapidly dissipated in the well fluid. The chemical cutter will not operate successfully in dry pipe and requires at least one hundred feet of fluid above the tool when a cut is made. Since it is not necessary to apply torque to the pipe when chemically cutting as compared with the string shot back-off, it is a safer process for rig personnel.

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FISHING OPERATIONS Explosive Jet Cutter

Ex pl osi v e

Shaped Char ge

Pipe cut with explosive Jet Cutter

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Ch e m i c a l Cut t e r

Pi p e cu t w i t h a Ch emi c al Cu t t er .

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4. Mechanical Cut - A cut made with a set of knives installed in a tool and run on a small diameter work string. This is referred to as an internal or inside cut. Internal mechanical pipe cuts are most common when removing sections of casing and wellhead equipment during final well abandonment operations. The internal cutter is made on a mandrel with a wickered sleeve or split nut fitted to threads on the mandrel. This allows the slips to be released and the tool to set at any specific depth desired. Friction blocks or drag springs are fitted to the mandrel to furnish back-up for this release operation. As weight is applied to the set tool, knives are fed out on tapered blocks, and as the tool is rotated, they engage the pipe and cut it in two. Upon reaching the desired cutting depth, the internal cutter is anchored by slowly rotating to the right while slowly lowering the work string. The wiper blocks resist rotation and lowering by maintaining friction on the pipe and continued lowering of the work string until the slips, which move upward and outward, engage and anchor the cutter to the pipe wall. The mandrel is free to travel downward under the knife blocks forcing the knives upward and outward to start the cut. Slight weight additions are applied while slowly rotating to the right. The main spring in the upper part of the cutter is partially compressed by the applied weight and assists in maintaining a uniform feed to the knives and to help absorb any shock that may accidentally be applied to the work string causing the knives to gouge or to break. Cutting is accomplished by slow rotation to the right with just enough weight being gradually applied to feed the knives into the metal. For best operation, the work string is lowered in 1/16" intervals (never more than 1/8") a total of 1-1/4" on the work string to complete the cut. Free rotation, with little or no reverse torque, indicates that the cut is completed. To prove the cut, increase the rotating speed; and if there is no increase in torque noted, it will indicate that the cut has been successfully completed. Care should be exercised not to hurry the cutting operation, as excess weight will cause the knives to dig into the pipe burning the knife points or possibly even breaking the knife blades. Fishing tool operators will usually run a bumper sub above the cutter so that excessive weight is not exerted on the knives causing them to break or dig into the pipe. To release the cutter, raise the work string one foot. This will cause the grip jaws to engage the wickered sleeve, and now the tool is ready to be raised or lowered, as desired.

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Internal Cutter Mandrel

Knife Knife Block

Main Spring

Slips Bowl

Wiper Block & Spring

Bottom Nut

Running In

Cutting

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Fishing Tools Releasing Overshot The Releasing Overshot is used to externally engage and retrieve all sizes of tubing, drill pipe, and casing. Top Sub

Packer

Bowl Spiral Grapple Grapple Control

Guide

The overshot is designed to assure positive external engagement over a large area of the fish and is ruggedly built to withstand severe jarring and pulling strains without damage or distortion to either tool or fish. Most overshots consist of a bowl, top sub, guide and the grapple or slip, a control, and packoff. The overshot bowl is turned with a taper on a helical spiral internally and then the grapple, which is turned with an identical spiral and taper, is fitted to it. Overshots are very versatile and may be fitted for a variety of problems. Mill controls may be used to dress the area that the grapple will catch in order to remove burrs and splinters on the pipe. When the pipe has been "shot off" or parted in such a way to heavily damage it, it may be necessary to fit a mill extension, or mill guide, to the overshot bowl so that extensive milling can be accomplished for the catch to be made on the same trip in the hole. These extensions, or guides, are "dressed" inside with tungsten carbide and can mill off a substantial amount of material so that the "fish" is trimmed down to the grapple size. Controls may also be designed with a pack-off, or packer, that seals off around the fish and allows the circulating fluid to be pumped through the fish to aid in freeing the stuck fish.

To properly engage an overshot on a fish, slowly rotate the overshot as it is lowered onto the fish. The pump may be engaged to help clean the fish and also to indicate when the overshot goes over the object. Once this has been indicated by an increase in pump pressure, stop the pump, as there may be a tendency to kick the overshot off the fish. Set the grapple with gradually increasing, light upward blows. An excessively hard upward impact may strip the grapple off the fish and cause the wickers to be dulled, resulting in a misrun and trip to replace the grapple. To release overshots, it is first necessary to free the two tapered surfaces, bowl, and grapple, from each other. This freeing of the grapple or "shucking" can be accomplished by jarring down with the fishing string. Usually a bumper sub is run just above the overshot and is used for this purpose. After bumping down on the overshot the grapple is usually free and the overshot can be rotated to the right and released from the fish. If a large amount of the fish has been swallowed, it may be necessary to free or " shuck" the grapple more than once.

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FISHING OPERATIONS Releasing Spear The Releasing Spear is used to internally engage and to retrieve all sizes of tubing, drill pipe, and casing as opposed to overshots which catch on the ouside. It is designed to assure positive internal engagement with the fish and is ruggedly built to withstand severe jarring and pulling strains without distorting the fish.

Mandr el

Usually a spear is not the first choice, as the spear will have a smaller internal bore than an overshot which limits running of some tools and instruments through it for cutting, freepointing, and in some cases, backing-off. Spears, however, are popular for use in pulling liners, picking up parted or stuck casing, or fishing any pipe that has become enlarged when parted due to explosive shots, fatigue, or splintering.

Gr appl e

Rel ease Ri ng

Nut

The most popular spears in use today are built on the same principles as overshots with a tapered helix on the mandrel and a matching surface on the inside of the grapple. The slip, or gripping surface is on the outside surface of the spear so that it will catch and grip the inside of the pipe that is being fished. Due to the design with the small bore in the mandrel, spears are usually very strong. The spear is run inside the fish and positioned. The slips are released by action of the J-slot by using left-hand torque, moving the drill string down a short distance, and then picking it back up slowly. This action releases the slips so they can slide up over a taper on the body of the spear as the spear is moved uphole. The slips move outward engaging the inner wall of the fish. In order to release a spear, it is rotated to the right. If the grapple is frozen to the mandrel, it may be necessary to bump down to free or 'shuck' the grapple. Usually a bumper sub is run just above the spear and this can be used to effectively jar down and free the grapple. The spear is a very versatile tool, in that it can be run in the string above an internal cutting tool if desired or in combination with other tools. Milling tools may be run below the spear to open up the pipe so that the spear can enter and catch the fish.

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FISHING OPERATIONS Oil Jars Jars are impact tools used to strike heavy blows either up or down upon a fish that is stuck. Jars fall into two catagories as to use: drilling jars and fishing jars. Jars can further be classified as to the basic principle of operation; either hydraulic or mechanical. Most jarring strings used in conjunction with fishing operations consist of hydraulic "Oil" jars. Oil Jars are very effective in freeing stuck fish as the energy stored in the stretched drill pipe or tubing is converted to an impact force, which can be varied according to the pull exerted on the string. The oil jar is designed to strike a blow upward only, while an additional tool, the bumper sub is designed to strike a blow downward on the fish. The oil jar consists of a mandrel and piston operating within a hydraulic cylinder. When the oil jar is in the closed position, the piston is in the down position in the cylinder where it provides a very tight fit and restricts the movement of the piston within the cylinder. The piston is fitted with a set of packing which slows the passage of oil from the upper chamber to the lower chamber of the cylider when the mandrel is pulled by picking up on the work string at surface. About half way through the stroke, the piston reaches an enlarged section of the cylinder and is no longer restricted so the piston moves up very quicly and strikes the mandrel body. The intesity of this impact can be varied by the amount of strain taken on the work string. This variable impact is the main advantage of the oil jar over the mechanical jar for fishing.

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Milling Tools Sometimes a packer or fish cannot be removed from the wellbore intact. It is then necessary to reduce the fish to small pieces that can be circulated to the surface. Mills dressed on the bottom with tungsten carbide have been used extensively for this purpose and with good results. Flat bottom mills are often used to mill over the slip segments and packer element on permanent production packers. Milling tools are available in a number of sizes and design shapes for various applications. Some common types of mills are shown below.

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Taper Tap

Taper Tap

Fish

Page 16

The Taper Tap is used to engage a tubular fish internally. This tool screws into the fish and cuts threads as it goes. Cutting new threads is a more positive engagement than attempting simply to screw on or into existing threads on a fish that may be damaged, misaligned, or incomplete. New threads can also be cut on blank pipe. Frequently, the Taper Tap is used to retrieve a production packer after the slip segments and packer element have been milled with conventional mills.

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FISHING OPERATIONS Junk Baskets The Core-Type Junk Basket, as shown, was the old stand-by for years for fishing bit cones and similar junk from the open hole. It consists of the top sub, a barrel, a shoe, and usually two sets of finger-type catchers. This tool is still used quite often, and it is made to circulate out the fill and to cut a core in the formation. The two sets of fingers help to break the core off and retrieve it. Any junk that is in the bottom of the hole is retrieved on top of the core.

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FISHING OPERATIONS Reverse Circulation Junk Baskets The reversing action is extremely helpful in lifting junk into the barrel and catcher, that might otherwise be held away from the catcher by fluid flow. The reverse circulation junk basket design incorporates an inner barrel with the fluid flow between the outer and inner barrels when a ball is dropped and closes off the center flow through the seat. With this design, when the ball is circulated down, the flow is diverted between the two barrels and reverse circulation flow is created back up the inside of the junk catcher with the fluid exiting into the annulus through the upper ports near the top of the barrel.

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FISHING OPERATIONS Fishing Magnets

Fishing magnets are either permanent magnets fitted into a body with circulating ports or electromagnets which are run on a conductor line. Permanent magnets, as shown, have circulating ports around the outer edge so that fill and cuttings can be washed away and contact made with the fish. Ordinarily the magnetic core is fitted with a brass sleeve between it and the outer body so that all of the magnetic field is contained and there is no drag on the pipe or casing. Permanent magnets have the advantage of the circulation washing away any fill so that the junk is exposed. Ordinarily, by rotation, one can detect when contact is made with the fish. The operator should then thoroughly circulate the hole, shut the pump off, and retrieve the fish without rotation.

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WASHOVER OPERATIONS Very often it is not enough merely to catch hold of the fish and pull. In those cases, washpipe and a rotary shoe can be used to rotate over the fish to remove annular material that may be causing it to stick and free up a section of stuck pipe so that it may be retrieved. The outside diameter of the washpipe must be small enough to run inside the casing, and its inside diameter must be large enough to fit over the fish. Washpipe is therefore thin walled and the length of it run in the well must normally be limited to a few hundred feet. The rotary shoe is placed on the end of the washpipe to drill-up and circulate out any material around the fish.

Washover Pipe

Casing

Tubing Fish

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Rotary Shoe

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Wireline Fishing Tools

Wireline Spears One of the most challenging of fishing operations may be the recovery of wireline and the tools or instruments run with it. Often times wireline has been parted. When this occurs, wireline slumps down the hole in a coil. The wireline center spear or the two-pronged wire grab, shown at left, are used frequently to remove parted wireline from the wellbore. TWO-PRONGED WIRELINE GRAB

When the tools are used in casing, a guide should be run above the tool to prevent the wire from getting above the spear.

WIRELINE CENTER SPEAR

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FISHING OPERATIONS Hydrostatic Bailer When cleaning out miscellaneous junk in a wellbore, it may be practical to run a hydrostatic bailer. Different designs are made for running on pipe as well as sand lines. All bailers work on the hydrostatic head principle, as they depend on the weight of the fluid in the hole to force the junk into the bailer and past the catchers. Many bailers can be surged repeatedly until the basket is full of junk or the hole is clean. Bailers can be effective in cleaning out bit cone parts, bearings, pipe slivers, nuts, bolts, perforator debris, and other material that is non-magnetic.

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TABLE OF CONTENTS INTRODUCTION ...........................................................................................................1 OPEN HOLE ...................................................................................................................1 1. Hydrocarbons.................................................................................................1 2. Porous Aquifers .............................................................................................1 3. Last Casing Shoe ...........................................................................................2 4. Extended Open Hole ......................................................................................2 CASED HOLE.................................................................................................................2 1. Casing to Formation Annulus ........................................................................2 2. Hydrocarbon Zones........................................................................................2 3. Water Source Zones.......................................................................................3 4. Injection Zones ..............................................................................................3 5. Extended Cased Hole.....................................................................................3 6. Casing to Casing Annuli ................................................................................3 7. Other Protective Plugs ...................................................................................3 ABANDONMENT MARKERS ......................................................................................4 1. Onshore Markers............................................................................................4 2. Offshore Markers ...........................................................................................4 TYPICAL ARAB-D WELL ABANDONMENT SCHEMATIC ....................................5

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INTRODUCTION Wells may be abandoned for any one of a number of reasons. Abandonment procedures in newly drilled or existing wells are largely dictated by individual well conditions. Factors affecting abandonment programming include: • • • • • • • •

Well age and mechanical condition. Location. Casing configuration and cementation integrity. Productive nature and interrelation of porous aquifers and/or hydrocarbon bearing zones. Corrosion considerations Local development plans Governmental directives Economic considerations

Proper abandonment is therefore a combination of sound judgment and applicable oilfield practices tailored to a particular well. The guidelines presented herein are intended to establish uniform abandonment objectives while recognizing practical limits often imposed by well conditions. OPEN HOLE 1.

Hydrocarbons Cement plugs are placed across all hydrocarbon bearing zones and extend at least 100' below and 100' above each zone. The presence of the plug across the hydrocarbon zone nearest the last casing shoe is to be confirmed by setting down string weight on the plug after waiting on cement (WOC). Presence of all plugs isolating gas reservoirs should be checked in the same manner.

2.

Porous Aquifers Porous aquifers are to be isolated by cement plug placed across and/or between zones resulting in at least 100' of plug height separation between zones where possible. Check integrity (drill string weight) of the plugs as follows: a. b.

c.

Separating aquifers from uphole hydrocarbon zones. Separating aquifers any of which are potable or suitable for irrigation purposes. The workover engineer should check with the Hydrology Dept. for this information. Separating all abnormally pressured water bearing zones.

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3.

Last Casing Shoe A 300' cement plug should be placed across the last casing shoe and will extend at least 150' above the shoe. The plug should be tagged with the drill string and pressure tested to at least the maximum equivalent mud weight used in the open hole plus 25%. The tag up and pressure test should be witnessed by the Aramco representative on the rig and noted in the tour report.

4.

Extended Open Hole In long sections of open hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 2000' intervals. The plug placement should be tagged with the work string. Long open hole sections are common on deep exploratory wells.

CASED HOLE 1.

Casing to Formation Annulus Where cement is not returned to surface during a cement job, the top of cement can be estimated from volumes of cement pumped, fluid returned and the hole diameter. Cement bond logs and/or temperature surveys can be run to determine the cement top and should normally be adequate confirmation of annular shut off integrity in critical situations. Under certain circumstances, however, perforating, cement squeezing and a dry test may be warranted. If the bond is questionable, the annulus should be cement squeezed between hydrocarbon reservoirs, between hydrocarbon and separate porous aquifers, and between separate porous aquifers. The UER is usually isolated from the Khobar by cement squeezing the RUS whereas the Wasia is isolated from the upper aquifers by cement squeezing the LAS.

2.

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Hydrocarbon Zones All hydrocarbon zones tested or commercially produced then abandoned should be squeeze cemented after ensuring annular shut off and pressure tested to at least 50% above the balance mud weight equivalent. Gas zones are to be squeezed through a cement retainer, capped with at least 50' of cement, tagged and pressure tested as above. Depending upon the condition of the casing, a retrievable isolation test packer may be run for this pressure test if required.

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3.

Water Source Zones Annular shut-off (formation to casing) should be ensured prior to squeeze cementing water source zones. If squeezing is unfeasible, an interior cement plug extending at least 100' below and 100' above will be placed, tagged, and pressure tested to the safe casing limit.

4.

Injection Zones Abandoned injection zones (water injection, disposal, product injection) should be cement squeezed after confirming annular shut off above and below the zone. Squeeze integrity should be pressure tested to BH injection pressure + 25% equivalent.

5.

Extended Cased Hole In long sections of cased hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 3000' intervals. The plug placement should be tagged with the work string.

6.

Casing to Casing Annuli In some cases, an attempt should be made to cement sections of previously uncemented casing to casing annuli particularly when such section lie opposite hydrocarbon zones or corrosive aquifers having no cement rise on the outside string.

7.

Other Protective Plugs Abandonment cement plugs should be spotted across other susceptible points in the well as follows: a) 300' cement plug centered on any exposed liner top(s). b) 300' cement plugs centered across exposed stage cementing equipment. c) Cement plug having adequate height to extend 100' below and above any problem points (casing parts, splits, patches, prior remedial perforations, etc.) in the innermost string. d) From surface to 300' depth (onland) and to 300' below mudline (offshore).

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ABANDONMENT MARKERS Once a well has been plugged with cement to the surface, an abandonment marker is installed on the wellhead for future identification. 1.

Onshore Markers Abandoned wells onshore should have the tubing spool removed (and additional spools removed if necessary). A blind flange should be installed on the wellhead with a 4-1/2" OD steel post welded to the top of the flange. The post should be at least 4' long and extend at least 4' above ground level. The well name and abandonment date should be clearly embossed on the post with weld material.

4-1/2" STEEL POST (with well name and abandonment date)

BLIND FLANGE 13-3/8" SW X 13-5/8" CASING HEAD 2-1/16" BLIND FLANGE

2-1/16" BLIND FLANGE

13-3/8" CASING 9-5/8" CASING

TYPICAL WELL ABANDONMENT MARKER

2.

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Offshore Markers Offshore markers are similar to onshore markers except there is no post. The blind flange is labeled with the well name and abandonment date.

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TYPICAL ARAB-D WELL ABANDONMENT SCHEMATIC The following schematic shows a generalized abandonment cross-section for a typical Ghawar well. Perforations would be required opposite the RUS or LAS if the primary cement job between the surrounding aquifers was questionable.

? ?

1000'

RUS UER

PERF & SQUEEZE RUS

LAS

PERF & SQUEEZE LAS

? ?

26" CONDUCTOR

18-5/8" CASING

2000' 13-3/8" CASING ? 3000'

?

WASIA SAF

4000'

BIYADH 9-5/8" PRODUCTION CASING

5000' SULAIY

6000' 7" PRODUCTION LINER ARAB-D

TAG OPEN HOLE PLUGS

7000'

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