Workover Operations: Revision-0 March 2009
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Chapter 2
WORKOVER OPERATIONS
Revision-0 March 2009
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Table of Contents SECTION 1 WELL BARRIERS ACCEPTANCE CRITERIA ..................................... 4 1.
Barriers Acceptance Criteria ........................................................................... 4
SECTION 2 WELL CONTROL IN WORKOVER OPERATIONS ............................ 19 1.
Introduction.................................................................................................... 19
2.
Checking Well Integrity and Installing Pressure Barriers ............................... 19
3.
Un-plugging the Well and Checking Wellhead Pressure ............................... 19
4.
Killing the Well ............................................................................................... 20
5.
Testing Wellhead ........................................................................................... 27
6.
Checking for Trapped Pressure and Bleed off Procedures ........................... 27
7.
Nippling down X-Mas Tree & Nippling up BOP ............................................. 27
SECTION 3 RECOVERING OLD COMPLETION STRINGS .................................. 29 1.
General.......................................................................................................... 29
2.
Recovering Completion - General Procedure ................................................ 29
3.
Releasing Hydraulic Packers......................................................................... 31
4.
Recovering Dual Completion ......................................................................... 36
5.
Abandoning Completion Tail and Packer(s) .................................................. 41
6.
Recovering 7" scab liner ................................................................................ 41
SECTION 4 FISHING GENERAL GUIDANCE ....................................................... 43 1.
Standard Fishing Assembly ........................................................................... 43
2.
Overshot ........................................................................................................ 43
3.
Releasing Spear ............................................................................................ 44
4.
Taper Tap / Pin Tap....................................................................................... 44
5.
Reverse Circulation Junk Basket ................................................................... 45
6.
Fishing Magnet .............................................................................................. 45
7.
Milling Tools................................................................................................... 45
8.
Hydraulically Activated Mills .......................................................................... 46
9.
Fixed Milling Tools ......................................................................................... 46
10. Special Mills................................................................................................... 47 S.G. Rev-00/09
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11. Fishing of Radio-Active Wireline Tools .......................................................... 47 SECTION 5 SIDETRACKING OPERATIONS ........................................................ 50 1.
Sidetracking in Open hole ............................................................................. 50
2.
Sidetracking Inside Casing ............................................................................ 55
SECTION 6 REMEDIAL CEMENTATIONS ............................................................ 67 1.
Balanced Cement Plugs ................................................................................ 68
2.
Squeeze Cementing ...................................................................................... 71
3.
Cementing Through Coiled Tubing ................................................................ 73
4.
Squeezing Off the Aquifers............................................................................ 74
SECTION 7 SETTING INTERNAL CASING PATCH.............................................. 75 1.
Well Preparation ............................................................................................ 75
2.
Procedure ...................................................................................................... 75
SECTION 8 SECURING WELL WITH SHALLOW SET CASING PACKER .......... 77 3.
When to Secure the Well ............................................................................... 77
4.
Minimum Barriers Requirements ................................................................... 77
5.
Safety Precautions ........................................................................................ 77
6.
Securing Well Procedure ............................................................................... 78
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SECTION 1 WELL BARRIERS ACCEPTANCE CRITERIA Well barrier acceptance criteria are technical and operational requirements that need to be fulfilled in order to qualify the well barrier for its intended use. Refer to ADM Vol-1, Chapter-1, Section-12 (Pressure Barriers) for details on Well Barrier Policy for Drilling / Workover operations.
1.
Barriers Acceptance Criteria Sheets Followings are the technical and operational requirements need to be fulfilled during drilling / workover operations in order to qualify the well barrier for its intended use.
1.1
Fluid Column
Features
Acceptance Criteria
Description Function
This is the fluid in the well bore The purpose of the completion fluid column as a barrier / barrier element is to exert a hydrostatic pressure in the well bore that will prevent influx of formation fluid.
Design, Construction and Selection
• The hydrostatic pressure shall at all times be equal to the estimated or measured pore/reservoir pressure, plus a defined safety margin (as mentioned later in Sec-10, Clause-1).
• Critical fluid properties and specific actions shall be described prior to start any operation.
• The density shall be stable within specified tolerances under down hole conditions for a specified period of time when no circulation is performed.
• The hydrostatic pressure should not exceed the formation fracture pressure in the open hole including a safety margin
• Changes in well bore pressure caused by tripping (surge and swab) and Initial Test and Verification Use
circulation of fluid (ECD) should be estimated and included in the above safety margins. Stable fluid level shall be verified. Critical fluid properties, including density shall be within specifications.
• It shall at all times be possible to maintain the fluid level in the well through circulation or by filling
• Acceptable static and dynamic loss rates of fluid to the formation shall be pre-defined (e.g. 20 bbls/hr for producers and 50 bbls/hr for injectors is acceptable for tripping) • There should be sufficient fluid materials, including contingency materials available on the location to maintain the fluid barrier with the minimum acceptable density.
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Features Monitoring
Acceptance Criteria • Fluid level in the well and active pits shall be monitored continuously. • Fluid return rate from the well shall be monitored continuously. • Flow checks should be performed upon indications of increased return rate, increased volume in surface pits, increased gas content, flow on connections or at specified regular intervals. The flow check should last for 15 min. Exploration wells: All flow checks should last for 30 min. • Measurement of fluid density (in/out) during circulation shall be performed regularly. • Measurement of critical fluid properties shall be performed every 1/2 circulating hour and compared with specified properties. • Parameters required for killing of the well must be defined and recorded.
Impairment
• Flow of formation fluids. • Unable to monitor fluid level. • Unable to maintain fluid level or required volume. Table 1.1: Acceptance & verification criteria for Fluid column as a barrier
1.2
Casing
Features
Acceptance Criteria
Description
• This element consists of production casing/liner
Function
The purpose of casing/liner is to provide a physical obstruction to uncontrolled flow of formation fluid or injected fluid between the bore and the back-side of the casing
Design, construction and selection
• Casing-/liner strings, including connections shall be designed to withstand all pressures and loads that can be expected during the lifetime of the well including design factors. • Minimum acceptable design factors shall be defined for each load type. Estimated effects of temperature, corrosion and wear shall be included in the design factors.
• Dimensioning load cases with regards to burst, collapse and tension / compression shall be defined and documented.
• Casing design can be based on deterministic, probabilistic or other acceptable models. Initial test and verification Use
S.G. Rev-00/09
• Casing/liner shall be leak tested to maximum anticipated differential pressure. • Casing/liner that has been drilled through after initial leak test shall be retested during completion activities. Casing/liner should be stored and handled to prevent damage to pipe body and connections prior to installation.
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Features Monitoring
Acceptance Criteria • The A-annulus shall be continuously monitored for pressure anomalies. B-annulus should be monitored if applicable based on well completion and the type of well. • If wear conditions exceed the assumptions from the casing-/liner design, indirect or direct wear assessment should be applied (e.g. collection of metal shavings by use of ditch magnets and wear logs).
Impairment
• Leaking casing/liner. • Unable to leak test. • Unable to monitor annulus pressure. • Unable to monitor or control/assess casing wear. Table 1.2: Acceptance & verification criteria for casing as a barrier
1.3
DRILLING BOP
Features Description Function Design, construction and selection
Acceptance Criterea The element consists of drilling BOP with kill/choke line valves. The function of the BOP is to provide capabilities to close in and seal the well bore with or without tools/equipment through the BOP.
• The drilling BOP shall be constructed in accordance with ADM – volume1, Chapter -3.
• The BOP WP shall exceed the maximum well design pressure including a margin for killing operations.
• It shall be documented that the shear/seal ram can shear the drill pipe, dual string tubing, wireline, coiled tubing or other specified tools, and seal the well bore thereafter. If this can not be documented by the manufacturer, a qualification test shall be performed and documented. • When using tapered string there should be pipe rams or variable ram to fit each pipe size. Initial test & verification Use
All BOP equipment Function and pressure tested frequently as per policy and documented. The drilling BOP elements shall be activated as described in the well control action procedures.
Impairment
• Failure of annular / Shear ram. (should be repaired immediately) • Failure of Pipe ram (repair immediately if no back up for that pipe size otherwise at earliest convenient time)
• Failure of kill/choke line valves. (If both valves in series failed then repair immediately otherwise after setting casing) Table 1.3: Acceptance & verification criteria for BOP equipment as a barrier
1.4
Wellhead
Features Description
S.G. Rev-00/09
Acceptance criteria The element consists of the wellhead body with annulus access ports and valves, seals and casing/tubing hangers with seal assemblies.
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Features Function
Acceptance criteria Its function is to provide mechanical support for the suspending casing and tubing string and production tree and to prevent flow from the bore and annuli to formation or the environment.
• The Working pressure for each section of the wellhead shall exceed the maximum anticipated well shut in pressure the section can become exposed Design, to plus a defined safety factor. construction and selection • There shall be access ports to all annuli to facilitate monitoring of annuli pressures and injection/bleed-off of fluids. Initial test and verification Use
The wellhead body (or bodies and seals), annulus ports with valves and the casing or tubing seal assemblies shall be leak tested to maximum expected shut in pressure for the specific hole section or operation. A wear bushing should be installed in the wellhead whenever movement of tools/work-strings can inflict damage to seal areas.
• Annuli wing valves shall be pressure and function tested frequently. • Pressures in accessible annuli shall be monitored and recorded continuously. Monitoring
• Annulus valve(s) should normally be closed and should only be opened for the purpose of adjusting the annulus pressure
• Movements in the wellhead during well testing (shut-in/start-up) should be observed and compared to design values. Impairment
• Leaking seals or valves. • Unable to leak test. • Unable to monitor accessible annuli. Table 1.4: Acceptance & verification criteria for Wellhead as a barrier
1.5
Deep Set Tubing Plug
Features
Acceptance criteria
Description
This element consists of a equalizing body with a locking or anchoring device and a seal between the bore of the tubing and the body of the plug.
Function
Its purpose is to provide a temporary seal in the bore to prevent flow from the reservoir and U-tubing.
Design, construction and selection
It shall comply with same requirements that apply to packers.
• It shall by preference be leak tested to the maximum expected differential Initial test and verification Use S.G. Rev-00/09
pressure in the direction of flow.
• Alternatively, it shall be inflow tested or leak tested in the opposite direction to the maximum expected differential pressure, providing that ability to seal both directions can be documented. It shall be set at a depth, which allows balancing of the pressure under the plug with a hydrostatic fluid column above the plug.
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Features
Acceptance criteria
Monitoring
The tubing pressure above the plug should be monitored regularly.
Impairment
Inability to pass pressure testing or monitoring requirements. Table 1.5: Acceptance & verification criteria for downhole plugs as a barrier
1.6
Surface Controlled Sub-Surface Safety Valve
Features Description Function Design, construction and selection
Initial test and verification Monitoring
Impairment
Acceptance Criterea This element consists of a tubular body with a close/open mechanism that seals off the tubing bore. Its purpose is to prevent flow of hydrocarbons or fluid up the tubing.
• It shall be -
surface controlled, hydraulically operated, fail-safe closed, flapper type. • It should be placed a minimum of five joints below surface It shall be tested with both low and high differential pressure in the direction of flow. The low pressure test shall be maximum 1000 psi The valve shall be leak tested at specified regular intervals as follows: • test duration shall be 30 min every six months • Acceptance of downhole safety valve leakage tests shall meet API RP 14B requirements being: - 900 scf/hr for gas, - 6.3 gal/hr for liquid. • If the leak rate exceed the accept criteria, the test can be attempted three times to verify the valve status. If the acceptance criteria is still not meet, further investigation and remedial action shall be undertaken, consider involving the drilling/well operations department. Failure to pass the regular tests and maximum allowable leak rate. Table 1.6: Acceptance & verification criteria for SCSSSV as a barrier
1.7
Wireline lubricator
Features
Acceptance criteria
Description
This element consists of a body with a lubricator connection in both ends.
Function
The function is to provide lubricate space for wireline BHA/tools over the closing device when run into and out of well.
Design, construction and selection
S.G. Rev-00/09
• The wire line Lubricator shall be constructed in accordance with API Spec 16A and API RP 5C7
• Pressure rating shall comply with the maximum expected wellhead pressure.
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Features
Acceptance criteria
Initial test and verification
• Function test after installation. • Low- and high pressure leak test after initial installation. • Leak test to maximum expected WHP on following runs.
Use
Length of lubricators shall at all time allow space for BHA above well closing device including items pulled from well.
Monitoring
Visual periodic inspection.
Impairment
Leak through body or connections. Table 1.7: Acceptance & verification criteria for Wireline lubricator as a barrier
1.8
Wireline BOP
Features Description
Function
Acceptance criteria This element consists of a BOP body with rams and riser/lubricator connections • The function of the wire line BOP is to prevent flow from the wellbore in case leakage in stuffing box / grease head or lubricator system above the BOP. • The element is a back-up element to the stuffing box / grease head in the primary barrier.
• The wire line BOP shall be constructed in accordance with ADCO standards
• The BOP shall exceed the maximum well design pressure including a margin for killing operations. Design, • The cable ram shall be able to provide a seal on the selected cable size. construction and selection • For slick line operations in live wells a minimum of one cable ram shall be installed. • For braided line operations in live wells a minimum of two cable rams shall be installed, with the lower ram capable of holding pressure from above. A system for pumping grease between rams shall be included.
Use
• • • •
Monitoring
• Periodic visual inspection for external leaks. • Periodic leak-and functional test, minimum each 14 days when in
Impairment
• Leak in any of the elements, body or connections. • Leak in hydraulic operating system. • Unable to operate or malfunction.
Initial test and verification
Function test after installation. Low- and high pressure leak test after initial installation. Leak test to maximum expected WHP on following runs. The wire line cable rams shall be activated as described in the well control action procedures (contingency procedures).
operation.
Table 1.8: Acceptance & verification criteria for Wireline BOP as a barrier
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1.9
Xmas Tree
Features Description
Acceptance Criteria This element consists of a housing with bores that are fitted with swab, master valve, kill and flow wing valves. Its function is to;
• Provide a flow conduit for hydrocarbons from the tubing into the surface Function
lines with the ability to stop the flow by closing the flow valve and/or the master valve. • Provide monitoring and pressure adjustment.
• Provide vertical tool access through the swab valve. • Provide an access point where kill fluid can be pumped into the tubing. 1. The X-mas tree shall be equipped with; • One master valve and one wing valve in the main flow direction of the well. • If the production tree has side outlets, these shall be equipped with Design, automatic fail-safe valves. construction • One manual swab valve for each bore at a level above any side and selection outlets. • Isolation valves on downhole control lines which penetrates the production tree block. 2. All connections, block etc. that can be exposed to the hydrocarbons shall be fire-resistant. Initial test and verification
• The valves shall be tested with both low and high differential pressure in
Use
• Beware of equalization during opening and closing of valves.
Monitoring
Impairment
the direction of flow. The low-pressure test shall be 500 psi.
• It shall be tested as per API 6A at manufacturing site.
The valves acting as barriers in the xmas tree shall be tested at regular intervals as follows: • Test duration shall be 15 mins. • Monthly, until three consecutive qualified tests have been performed, thereafter • Every three months, until three consecutive qualified tests have been performed, thereafter • Every six months. If the leak rate can not be measured directly, indirect measurement by pressure monitoring of an enclosed volume downstream of the valve shall be performed. Failure to pass the regular test. During rig move due to extra risk involved of hitting / dropping objects Table 1.9: Acceptance & verification criteria for Xmas tree valves as a barrier
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1.10 Completion String Component Features
Acceptance criteria
Description
Function
Design, Construction and selection
Initial test and verification
These elements consist of a housing with a bore. The element may have a side mounted feature or a valve providing communication between tubing and annulus. Its purpose may be to provide support to the functionality of the completion, i.e. gas-lift or side pocket mandrels with valves or dummies, nipple profiles, gauge carriers, Flow coupling etc. 1. The components (pipe and threads) shall be gas tight. 2. Minimum acceptable design factors shall be defined. Estimated effects of temperature, corrosion, wear; fatigue and buckling shall be included in the design factors. 3. The component should be designed/selected with respect to • Tensile, compression and torsional load exposure. • OD clearance and fishing restrictions. • Tubing (and annular) flow rates, also including erosion effects. • Metallurgical composition in relation to exposure to formation or injection fluid. • Odd shaped assemblies in casting material shall be subject to finite element analysis. • Strength reduction due to temperatures effects. 4. For gas lift valves to qualify as a barrier there shall be a qualification test demonstrating the valves ability to be gas tight over number of cycles. The valve shall be subject to frequent testing with acceptable results similar to testing of SCSSSVs Pressure testing to Maximum Expected Temperature & Pressure.
Monitoring
Running of intervention tools shall not accidentally shift a functionality of the tool. Pressure integrity is monitored by independence of the annulus pressure.
Impairment
Inability to maintain a pressure seal.
Use
Table 1.10: Acceptance & verification criteria Completion string components as a barrier
1.11 Completion String Features
Acceptance criteria
Description
This element consists of tubular pipe.
Function
The purpose of the completion string as barrier element is to provide a conduit for formation fluid from the reservoir to surface or vice versa.
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Features
Design, construction and selection
Acceptance criteria 1. All components in the completion string (pipe/housings and threads) shall have gas tight connections, unless the well is used for water injectors, disposal, source water production, or mud/cuttings/liquid disposal. 2. Dimensioning load cases shall be defined and documented. 3. The weakest point(s) in the string shall be identified. 4. Minimum acceptable design factors shall be defined. Estimated effects of temperature, corrosion, wear; fatigue and buckling shall be included in the design factors. 5. The tubing should be selected with respect to • Tensile, compression and torsional load exposure. • Tool joint clearance and fishing restrictions. • Tubing and annular flow rates. • Abrasive formations. • Buckling resistance. • Metallurgical composition in relation to exposure to formation or injection fluid.
Initial test and Pressure testing to Maximum Expected Temperature & Pressure (METP). verification Use
Stab-in safety valve and one way check valve for all type of connections exposed at the drill floor shall be readily available.
Monitoring
Pressure integrity is monitored by independence of the annulus pressure.
Impairment
Leak to or from the annulus. Table 1.11: Acceptance & verification criteria for completion string as a barrier
1.12 Mechanical Tubular Plugs Features Description Function
Design, construction and selection
S.G. Rev-00/09
Acceptance criteria This is a mechanical plug set anywhere inside steel conduits (casing/tubular). The purpose of the element (plug) is to prevent flow of formation fluids and resist pressure from above or below, inside tubulars. 1. The plug shall be designed for the highest differential pressure and highest downhole temperature expected. Installation and test loads shall also be considered. 2. Down hole fluids and conditions (temperature, H2S, CO2, etc.)shall be considered in estimating the life time of the plug. 3. The plug shall be designed such that pressure can be equalized across the plug, if removed mechanically or by drilling out. 4. The plug is not accepted as a barrier element alone in permanent plugging of wells or branches of wells, where design integrity in an eternal perspective is required. 5. To ensure the barrier integrity in using the plug, it shall only be installed in a tubular section of the well, which is cemented, or supported by sufficient wall thickness to withstand radial loads from the plug.
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Features
Acceptance criteria
1. If possible the plug shall be inflow tested (from below), else it shall be pressure tested from above. Initial test and 2. Test pressure shall be minimum ~1000 psi above measured formation strength below casing/ potential leak path, or minimum ~500 psi for verification surface casing. Test pressure shall not exceed casing pressure test, which ever is lower. Inadvertent release of the plug by mechanical motion/ impact shall not be possible.
Use Monitoring Impairmen
Pressure integrity shall be monitored through recording of the pressure above the plug. Inability to maintain a pressure seal.
Table 1.12: Acceptance & verification criteria for Mechanical tubular plugs as a barrier
1.13 Tubing Hanger Features
Acceptance criteria
Description
This element consists of body, seals and a bore which may have a tubing hanger plug profile.
Function
Its function is to • support the weight of the tubing, • prevent flow from the bore and to the annulus, • provide a seal in annulus space between itself and the wellhead, • provide a stab-in connection point for bore communication with the production tree. • provide a profile to receive a BPV or plug to be used for nippling down the BOP and nippling up the production tree.
Design, Construction and Selection
Fire resistant seals should be used.
Initial Test and Verification Use Monitoring Impairment
• The primary seal shall be tested in the flow direction. • The hanger seal can be tested against the flow direction. • If only single seals are used in the tubing hanger, annulus is to be tested. In the case of double seal, an in-between seal test shall be performed. None. Continuous monitoring of annulus pressure. Leak past seals.
Table 1.13: Acceptance & verification criteria for Tubing hanger seal as annulus barrier
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1.14 Tubing Hanger Plug Features
Acceptance criteria
Description
This element consists of an equalising plug with a locking device and a seal between the bore of the tubing hanger and the body of the plug.
Function
Its function is to provide a pressure barrier in the bore through the tubing hanger.
Design, construction and selection Initial test and verification Monitoring
• Fire resistant seals should be used. • It shall only be classified as a barrier element during BOP or x-tree disconnect, providing the plug (and prong) does not extend up above the tubing hanger body. The tubing hanger plug shall be tested in the flow direction. Regular monitoring of pressure above plug or by visual observation.
Impairment
Non-compliance with above mentioned requirements. Table 1.14: Acceptance & verification criteria for Tubing hanger plug as a barrier
1.15 Production Packer Features Description
Acceptance criteria This is element consists of a body with an anchoring mechanism to the casing/liner, and an annular sealing element which is to be activated. Its purpose is to provide
• a seal between the completion string and the casing/liner, to Function
prevent communication between the formation and the A-annulus above the production packer.
• prevent flow from the inside of the body element located above the packer element to the A-annulus(tubing to production casing). 1. The packer shall be set (meaning that it shall not release by up or downward forces), with ability to sustain all known loads. 2. The seal element shall withstand Maximum Expected Differential Pressure, which should be based on the highest of; Design,
• pressure testing of tubing hanger seals,
construction
• reservoir-, formation fracture- or injection pressures less hydrostatic pressure of fluid in annulus above the packer,
and selection
• shut-in tubing pressure plus hydrostatic pressure of fluid in • annulus above the packer less reservoir pressure, • evacuated tubing with pressure in annulus. 3. It shall be qualification tested in accordance with recognized standards, which shall be conducted in unsupported, non-cemented casing.
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Features
Acceptance criteria • It shall by preference be leak tested to the maximum expected differential
pressure in the direction of flow. Initial test & verification • Alternatively, it shall be inflow tested or leak tested in the opposite direction to the maximum expected differential pressure, providing that ability to seal both directions can be documented. Use
Running of intervention tools shall not impair its ability to seal nor inadvertedly cause it to be released.
Monitoring
Sealing performance shall be monitored through continuous recording of the annulus pressure measured at wellhead level.
Impairment
Inability to maintain a pressure seal. Table 1.15: Acceptence & verfication criteria for Production packer as a barrier
1.16 Liner Top Packer Features Description
Function
Design, construction and selection
Initial test and verification Use Monitoring Impairment
Acceptance criteria This is a mechanical plug, consisting of a tubular body with an external seal element, set in the liner lap between casing and liner. Its purpose is to provide a hydraulic seal in the annulus between the casing and liner, to prevent flow of formation fluids, and resist pressures from above or below. 1. The packer shall be designed for the highest differential pressure and highest downhole temperature expected during installation, acceptance testing and throughout its service life. Other down hole conditions, such as formation fluids, H2S, CO2,etc. shall also be considered in estimating the lifetime of the packer. 2. The risk of sealing failure due to variable downhole temperatures/cyclic loading shall be evaluated. 3. It shall be able to seal in oval, worn or scored casing. 4. It shall not need the support of cement in the liner annulus to seal. 5. It shall be designed to avoid prematurely setting and allow rotation before set. It shall be pressure tested from above and inflow tested, if practicably possible. The pressure shall; (a) be minimum ~1000 psi above measured formation strength below casing/ potential leak path, (b) not exceed casing pressure test which ever is lower. It is not accepted as a barrier element in permanently abandoned wells or well bores. None Inability to maintain a pressure seal. Table 1.16: Acceptence & verfication criteria for liner top packer
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1.17 Casing Cement Features
Acceptance criteria
Description
This element consists of cement in solid state located in the annulus between the casing/liner and the formation.
Function
The purpose of the element is to provide a continuous, permanent and impermeable hydraulic seal along hole in the casing annulus or between casing strings, to prevent flow of formation fluids, resist pressures from above or below, and support casing or liner strings structurally. 1.
A design and installation specification (cementing program) shall be issued for each primary casing cementing job.
2.
The in-situ compressive strength of the cement shall be higher than the estimated formation strength of the cemented formation. 3. Cement slurries that will be exposed to permeable and abnormally pressured hydrocarbon bearing zones should be designed to prevent gas migration, when the cement sets. 4.
The cement placement technique applied should ensure a job that meets requirements whilst at the same time imposing minimum overbalance on weak formations. ECD and the risk of lost returns during cementing shall be assessed and mitigated.
5. Cement height in casing annulus (TOC): (a) General: TOC shall be minimum 350 ft above a casing shoe, where the cement column in consecutive operations is pressure tested / the casing shoe is drilled out. (b) Conductor: Cemented conductor is not defined as a barrier element. (c) Surface Casing: TOC Shall be defined based on load conditions from wellhead equipment and future operations. TOC should be inside conductor or to surface. (d) Casing through hydrocarbon bearing formations: TOC shall be defined based on requirements for zonal isolation. Cement should cover potential cross-flow interval between different reservoir zones. For cemented casing strings which are not drilled out, the height above a point of potential inflow/ leakage point / permeable formation with hydrocarbons, shall be 650 ft, or to previous casing shoe, whichever is less.
Design, construction and selection
Initial test and verification
6.
Temperature exposure, cyclic or development over time, shall not lead to reduction in strength.
7.
Requirements to achieve the along hole pressure integrity in slant wells to be identified.
1. It shall be pressure tested if the casing shoe is drilled out. Note, in cases where this may break down formation, the verification may be through exposing the cement column for differential pressure from fluid column above cement in annulus. In the later case the pressure integrity acceptance criteria and verification requirements shall be defined. 2. The verification requirements for having obtained the minimum cement
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Features
Acceptance criteria height shall be described, which can be; • verification by logs (cement bond, temperature, LWD sonic) or • estimation on the basis of records from the cement operation (volumes pumped, returns during cementing, etc.). 3.
Use
The strength development of the cement shall be verified through observation of representative surface samples from the mixing.
None
• The annuli pressure above the cement barrier shall be monitored Monitoring
regularly when access to this annulus exists.
• Surface casing by conductor annulus outlet to be visually observed regularly.
• Non-compliance with any of the above mentioned requirements Impairment
Pressure build-up in annulus as a result of e.g. micro-annulus, channeling in the cement column, etc. Table 1.17: Acceptance & verification criteria for Casing cement as a barrier
1.18 Cement plug Features
Acceptance criteria
Description
This element consists of cement in solid state that forms a plug in the wellbore
Function
The purpose of the plug is to prevent flow of formation fluids inside a wellbore between formation zones and/or to surface, resist pressures from above or below.
Design, construction and selection
1. The in-situ compressive strength of the cement plug shall be higher than estimated formation strength at the depth where plug is installed. 2. Cement slurries that will be exposed to permeable and abnormally pressured hydrocarbon bearing zones should be designed to prevent gas migration, when the cement sets. 3. Permanent cement plugs should be designed for minimal strength reduction and no shrinkage caused by thermal exposure and cyclic loading 4. It shall be designed for the highest differential pressure and highest downhole temperature expected, inclusive installation and test loads. 5.
A minimum cement batch volume shall be defined for the plug in order that homogenous slurry can be made, to account for contamination on surface, downhole and whilst spotting downhole.
6.
The firm plug shall extend minimum 50ft MD above any source of outflow/ leakage point. A plug in transition from open hole to casing should extend at least 150ft MD below casing shoe.
7. If it is set inside casing and with a mechanical plug as a foundation, S.G. Rev-00/09
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Features
Acceptance criteria the minimum length shall be 20 ft MD. 8. A casing/ liner with shoe installed in permeable formations should have a 10 ft MD shoe track plug. 1. 2. 3.
4. Initial test and verification
5.
Cased hole plugs should be tested either in the direction of flow or from above. The strength development of the slurry should be verified through observation of representative surface samples from the mixing. The plug installation shall be verified through documentation of job performance; records of cement operation (volumes pumped, returns during cementing, etc.). In case of Open hole Its position shall be verified, by means of, Tagging, or measure to confirm depth of firm plug. In case of Cased hole Its position shall be verified, by means of, • Tagging, or measure to confirm depth of firm plug • Pressure test, which shall be 1000 psi above estimated formation strength below casing/ potential leak path, or ~500 psi for surface casing plugs, and not exceed casing pressure test less casing wear factor which ever is lower (but never lower than leak-off/fracture pressure). • If a mechanical plug is used as a foundation for the cement plug & this is tagged & pressure tested, the cement plug does not have to be verified.
Use
Ageing test may be required to document long term integrity.
Monitoring
For temporary suspended wells: The fluid level/ pressure above the shallowest set plug shall be monitored regularly when access to the bore exists.
Impairment
Non-compliance with above mentioned requirements and the following: a. Loss or gain in fluid column above plug. b. Pressure build-up in a conduit, which should be protected by the plug. Table 1.18: Acceptance & verification criteria for Casing cement as a barrier
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SECTION 2 WELL CONTROL IN WORKOVER OPERATIONS 1.
Introduction Well control procedures for workover operations are significantly different than those used when drilling. Though basic pressure considerations are the same, implementation methods vary greatly due to well conditions, which are often unique to individual wells. These conditions include the type of completion, formation pressures exposed to the wellbore, and the reasons for performing the workover. Routine workover operations often require the implementation of various well control procedures. An understanding of the principle of killing operations and the effect of routine operations on well control is essential for the Drilling Supervisor. Killing a producing well is often the first step in a workover operation. Prior to performing this step; certain actions must be taken to ensure the kill is performed in the safest and most efficient manner. In this section, the principles and the procedures for killing different types of completion and wells are discussed.
2.
Checking Well Integrity and Installing Pressure Barriers Prior to start killing a well:-
3.
•
Review casing and cementing operations including any mechanical problem encountered during drilling the well.
•
Inspect surface casing, and review the possibility of N/U BOP’s and applying pressure on well integrity.
•
Conduct the required remedial operations such as wellhead scaffolding and adding extra valves.
•
Well head survey should be conducted prior to rig move to verify the condition of wellhead
•
Apply ADCO pressure barrier policy.
Un-plugging the Well and Checking Wellhead Pressure Prior to unplugging the well, the rig must be fully operational and capable of handling any well control situation that may occur as consequences to unplugging the well
•
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A minimum of 500 bbls of workover fluid should be available in the tanks prior to unplugging the well.
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4.
•
Kill and choke lines must be connected to the wellhead and choke manifold and tested to the X-Mas tree working pressure prior to unplugging the well. Flare lines shall be also flushed and tested.
•
Test lubricator to the wellhead working pressure.
•
Retrieve plugs from tubing hanger.
•
After retrieving all plugs or mechanical barrier from Tubing Hanger, Tubing Spool, SC-SSSV and Tubing String, wait for pressure to stabilize (Bleeding off gas cap is not allowed).
•
Record pressures of tubing strings, tubing/ casing annulus, and casing/casing annulus.
•
Check X-Mas tree valves against well pressure
Killing the Well 4.1
General Guidelines Many considerations must be given to selecting the proper method of killing a normally pressured well. The generic well kill guidelines are summarized below
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•
Install kill and choke lines and test against the wing valves to the wellhead working pressure.
•
Rig up and test the wireline lubricator to wellhead working pressure.
•
Retrieve SC-SSSV and any other wireline plug set inside the string.
•
Monitor and record wellhead pressure.
•
Kill well using one or more of the following methods: O
Bullheading
O
Coiled Tubing Killing
O
Lubrication
O
Punch the tubing and circulating.
O
Reverse circulation
O
Killing annulus
O
Through tubing kill with hole in the tubing or leak in the packer
•
Observe the other string or annulus for communication.
•
Observe well for loss or gain.
•
Observe well static prior to N/Down X-Mas tree.
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•
Use LCM Pill to cure losses if needed.
•
Install SC-SSSV if not installed.
•
Install NRV(s), N/D X-Mas tree and plug control line port(s).
•
Check tubing hanger thread
•
N/U BOP, remove NRV after confirming no pressure below, install plug and test BOP.
•
Remove plug, make up landing joint w/ safety valve on top.
•
Retrieve SC-SSSV.
•
Retract lock down screws.
•
POH with completion string. Note: O Tubing string must be secured with safety and circulating valve during stinging out or releasing the hydraulic packer. O Rig floor must be ready with contingency plan to handle strong U tube.
4.2
Equipment required for kill operations
•
Wellhead fittings and x-overs required for killing operations.
•
Kill line, choke line and choke manifold.
•
Pumping Unit.
•
Killing fluid.
•
Flare lines.
•
Coil tubing unit (if required).
•
Wireline unite and tools (if required).
•
Electric wireline unit (if required) with required tools i.e punching, cutting.
Selection of equipment required for well killing must be decided on case by case basis.
4.3
Killing Methods The kill method that is most suitable for a particular completion string and formation pressure / fluid will primarily depend on whether the completion string is in communication with the annulus or not. The text that will follow discuss the most common kill methods, highlighting the factors that must be taken into account while using each method.
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4.3.1 Bullheading Bullheading is a term used to describe the pumping of the fluids into the formation. In the case of well control, the objective is to pump a workover fluid down the tubing and drive the formation fluids out of the tubing, through perforations and back into the formation. A pumping schedule shall be available to avoid fracturing the formation while the killing fluid is descending downhole. The schedule shale be designed to consider the initial shut in pressure and fracture pressure so that the bottom hole pressure is always below the fracture pressure. It is important to note that pressures should decrease as the kill fluid is pumped into the well since the hydrostatic pressure of the kill fluid is greater than the formation fluid. If this occurrence is not observed to the extent expected in the field operations, either the formation's ability to accept the fluid is decreasing (plugging) or gas is migrating upward. It should also be noted that as the low density formation fluids are displaced by greater density killing fluids, the maximum allowable surface pressure decrease. Upward migration of low density fluids through higher density fluids may be a serious problem in workover operations, particularly when bullheading techniques are used. Factors affecting migration rates include: Fluid densities and viscosities, hole geometry, and influx size. In the cases of formations with characteristics that only allow low pump-in rates, upward gas migration rates may equal or exceed the pump rates and result in negating the advantages of bullheading. The addition of viscosifiers to the workover fluid has been found to be a practical field-proven method to reduce migration rates. Formation fluids often affect the feasibility of bullheading procedures. Low viscosity fluids such as gas will flow back through the formation at rates sufficiently greater than oil or water. In addition, gas will have a reduced tendency to plug the formation as it reverses flow.
4.3.2 Coiled Tubing Killing Coiled Tubing is often used for killing a producing well. The objective is to circulate killing fluid down the coiled tubing and up the coiled tubing / production tubing annulus. A primary application for coiled tubing is in cases where the well can not be killed by bullheading because the wellbore is plugged. Applications for coiled tubing may be restricted in deep wells due to strength limitations of the tubing. In some cases, in gas wells, field experience has shown that a coiled tubing section filled with killing S.G. Rev-00/09
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fluid will exceed the tensile strength of the pipe. This is not usually the case in oil wells because the buoyancy provided by the oil reduces the overall tubing load. The following are general guidance procedures when killing a well using coiled tubing:-
•
De-pressurize X-tree.
•
R/U and pressure test C/T BOP and injector head.
•
RIH with the following basic tool string configuration O
Circulating nozzle
O
Two check or flapper valves
O
Straight bar
O
Release joint
O
Tubing connector.
•
Test weight indicator before running coiled tubing into the well.
•
Standard running speed should be 50 ft/min, this speeds must be reduced when running through the riser, X-Mas tree, SC-SSSV and any other downhole restrictions.
•
Run coiled tubing below perforations depth.
•
Displace completion string with kill fluid. Keep pumping until clean fluid returns.
•
Observe pressure and record losses.
•
Report results to town.
•
Pull out of the hole while circulating kill fluid until the tubing end connector tags the stripper, don’t exceed 4000 lb overpull.
•
Close the well master and swab valves.
•
Bleed off pressure in the coiled tubing and surface lines through the closed line drain in case of any hydrocarbon discharge.
•
Rig down the coiled tubing and associated equipments.
Notes: O DS and RM must be alert during killing operations while coiled tubing downhole. O Contingency plan to handle any well control incident must be in place. S.G. Rev-00/09
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O Returns must be routed through choke manifold. O Flaring oil or gas is not allowed without management approval. O Gas detectors, breathing apparatus must be ready in place prior to commenceing killing operations. O Check SC-SSSV ID compared to C/T OD prior to rigging up C/T. For more details about coiled tubing operations refer to Coiled Tubing Manual (the manual is electronically available at ADCO Drilling Website.
4.3.3 Lubrication Lubrication is occasionally used for killing wells during workover operations. It is a process that alternately pumps a kill fluid into the tubing or annulus, and then a volume of gas is allowed to escape from the well until the kill fluid begins to escape through the choke. At this point, brine water or other fluids are pumped into the tubing or annulus, and the cycle is restarted. As each volume of brine is pumped into the tubing, the Shut-In Tubing Pressure should decrease by a calculated value until the well is eventually killed. Caution must be exercised to insure that large volumes of kill fluids are not allowed to escape from the well during the bleeding phase. The lubrication and bleed method is often employed to kill high pressure wells where kill pressures would approach the rated pressure of the wellhead or tubing and in wells that have a plugged wellbore or perforations and will not allow bullheading. Lubrication procedures can be employed to kill the well without necessitating the use of coil tubing. It should be apparent, however, that lubrication is a time consuming process. A certain amount of time is required for the gas to migrate upward through the falling kill fluid after the pumping ceases. Gas migrates upward at 17-35 ft/min; therefore after pumping, it is important to wait several minutes before bleeding gas from the well to prevent bleeding the kill fluid through the choke. Refer to Chapter-3 in Volume-1 for more details.
4.3.4 Perforating the Tubing / Stinging out and Circulating Perforating the tubing and circulating a kill fluid is another primary method of killing producing wells. The method will allow direct circulation or reverse circulation of brine water. This method requires that the packer fluid in the annulus be in circulable condition and not severely gelled.
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Careful attention must be given to the selection of a perforation tool. It is important that the tool be capable of perforating the tubing without damaging the adjacent casing, should the tubing be in close proximity to the casing. In addition, oriented perforating becomes a serious consideration in cases of dual completion to avoid perforating the other string. Tubing punch is normally carried out above the most top packer, in the middle of a tubing joint , far from wireline nipples, blast joint, travel joint…etc In case of pulling the tubing out of the packer, circulating a kill fluid out of the bottom of the tubing is a kill option involves lifting the tubing a sufficient height to pull the seal assembly from the packer. The disadvantage of this method is that the X-Mas tree must be removed, and BOP’s installed in order to pick up the tubing. Some types of completions such as Tandem Dual Completions are not suitable for this method of well killing.
4.3.5
Reverse Circulation Reverse circulation involves pumping kill fluids down the annulus and displacing the formation fluids up the tubing. This procedure requires that a choke is placed in the standpipe or that the surface equipment can be arranged in such a manner that conducts the formation fluids through the standpipe to the choke. The reverse circulation method utilizes the pumping casing pressure to monitor the kill operation. The standpipe choke is used to adjust the pumping casing pressure to the required values. Reverse circulation offers several advantages and disadvantages relative to normal circulation. The advantages include (1)
A significant reduction in the time required to circulate the formation fluid from the well.
The disadvantages of the reverse circulation procedure include (1)
Possible plugging when attempting to reverse flow if circulating ports are in the work string
(2)
The slow circulating rates used in the reverse procedure may allow gas to migrate up the annulus at a rate greater than the downward flow rate.
(3)
It is not suitable method for high pressures
Reverse circulation kills are not as often used as normal circulation. However, During Workover operations the well is usually fully cased S.G. Rev-00/09
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and the pressure of the exposed reservoir is known. The workover fluid is, therefore, probably already of sufficient density to control the formation. In these cases, the kick will usually be the result of an effective underbalance created by swabbing. Thus, the workover fluid need not to be weighted up as long as the tubing is sufficiently close to bottom. The kill method used is then equivalent to the Drillers Method; with the exception that only one circulation is required since the "weight up" is unnecessary.
4.3.6
Killing Annulus A separate annular kill is sometimes required because of a loss of integrity in the tubing string resulting from a hole or leak. In these cases, killing the tubing by lubricating or snubbing will not necessarily kill the annulus. It is therefore necessary to perform kill techniques on the annulus using one of the previously described methods. These include bullheading, circulating or reverse circulating. Gas Migration can be a serious consideration when pumping down the annulus. In all methods of well killing, it is important to maintain a constant pump speed along with the required casing or tubing pressure. If the pump speed is allowed to change or the proper surface pressure not used, bottomhole pressure will be either too high or too low and either loss of circulation or additional influx will occur. If the kill rate must be changed, a new tubing pressure schedule which accounts for a change in the circulating pressure losses must be followed.
4.3.7
Through Tubing Kill with Hole in the Tubing or Leaking A through tubing kill with a hole in the tubing or a packer leak requires additional considerations. The primary concern is determining the location of the hole or leak. Additional concerns include (1) the effect of the annulus pressure exposed on the casing and (2) the kill procedure that will be most effective in each case. Determining the location of the tubing hole generally requires an onsite evaluation of the situation. The hole or leak will be indicated by pressure on the casing string(s). The most common method of locating the leak is by pumping a volume of colored brine water until it is returned to the choke on the annulus. This volume can be used to calculate the location of the hole. Deep holes will generally allow the well to be killed in a conventional circulation manner. Shallow to medium depth holes will require snubbing coil tubing or jointed pipe or lubrication. Bullheading can be attempted only if the dynamic pressures do not exceed the casing burst pressures.
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5.
6.
Testing Wellhead •
Test between primary and secondary seals through T.H.S testing port to either 60% of the collapse pressure of the casing string exposed or to 1500 psi whatever is less.
•
Always observe other side’s ports during testing.
•
Check injectivity down annulus if requested in the drilling program, do not exceed 500 psi, maximum injection pressure is to be decided on case-by-case basis. Town approval is required.
•
Remedial cementation at this stage must be considered.
Checking for Trapped Pressure and Bleed off Procedures After kill operation and when checking the trapped pressure, the following good practices should be followed:
7.
•
Bleed off pressure from the casing side only. The reasons are (1) the primary choke is generally located on the casing side, (2) to avoid contamination of the mud (or brine water) in the tubing.
•
Use the tubing pressure as a guide since it is a direct bottomhole pressure indicator.
•
Bleed small amounts (1/4 to 1/2 barrels) of mud at a time. Close the choke after bleeding and observe the pressure on the tubing or annulus.
•
Continue to alternate the bleeding and subsequent pressure observation procedures as long as the shut-in tubing pressure is continuously decreasing. When the pressure ceases to fall, stop bleeding and record the true SITP and SICP.
•
If the SITP decrease to zero during this procedure, continue to bleed and check pressures on the casing side as long as the casing pressure decreases.
•
These bleeding procedures can be implemented at any time. However, it is advisable to check for trapped pressure when the tubing string is displaced with a clean kill fluid if any pressure remains on the work string.
Nippling down X-Mas Tree & Nippling up BOP •
Refer to in section 1 of this chapter for pressure barriers requirements when removing X-Mas tree.
•
Observe well static (1 hour for oil wells and 2 hours for gas wells)
•
Install downhole plug (if applicable).
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•
Close SC-SSSV (if applicable).
•
Install NRV(s) (use DRN in gas wells), Nipple down X-Mas tree and plug control line port(s).
•
Install BOP with adequate pipe rams (same criteria applied to drilling); remove NRV after confirming no pressure below NRV. Refer to volume-1, chapter-3 “Well Control” and Chapter-1 “Policies” for BOP requirements.
•
Install plugs (2 way check valve) in tubing hanger and test blind/shear rams.
•
Remove plugs, make up landing joint with safety joint on tubing hanger and test Annular Preventer and remaining BOP components as per procedures in ADM, volume – 1, Chapter-3 “Well Control”. Note: Before N/U the BOP, the DS must ensure that the BOP is cleaned from any cuttings or debris that may drop and accumulate on top of the NRV during the BOP pressure test. Check tubing hanger threads are clean.
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SECTION 3 RECOVERING OLD COMPLETION STRINGS 1.
General The following must be taken into account when planning for recovering old completion:
•
Review downhole well status including tubing dimensions, strength and capacities of each item in the string.
•
Identify the point of the weakest tensile strength in the string.
•
Know fluid density and type in the annulus and inside tubing.
•
Inspect tubing hanger after removing X-Mas tree and prior to installing BOP’s o Tubing Hanger thread type and conditions. o Pack off design and retrieving mechanism o Lock down screws condition o
2.
Control line fittings
•
Consider special surface arrangement for handling U-tube.
•
Retrieve SC-SSSV prior to pulling the tubing hanger to surface.
•
All subs and x/overs (with safety valves) required to shut in the well must be ready on rig floor for any emergency.
•
Calculate overpull required to release the tubing from the packer or to shear the pin for releasing the hydraulic packer.
•
Contingency planning must be in place should well control incident occurred
•
Be aware of the design and mechanism of the downhole completion equipment such as packers, SC-SSSV, Travel Joints,…..etc.
•
The landing joint that required for pulling on the completion string must be inspected in particular the minimum ID required to allow free passage of wireline tools.
Recovering Completion - General Procedure The follows are general guidelines for recovering old completion:-
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NRV retrieving tool and watch pressure. If pressure exists, bullhead string with clean kill fluid. During killing operation, trapped pressure below NRV can be due to over charging the formation. This pressure can be released without having extra influx from formation. To bleed-off trapped pressure, follow up the procedures mentioned in the previous section. Pressure that might be exist below the SC-SSSV could pass across, especially at low pressures
•
When well is safe. i.e. wellhead pressure is zero and static losses is less than 20 Bbls/hr, proceed to recover the completion
•
Retrieve SC-SSSV, observe well
•
Make up landing joint (with safety valve) to the tubing hanger. Connect surface lines and valves that allow flexible change between normal circulation and reverse circulation. Note: landing joint must be checked with the proper gauge cutter and cleaned from scale.
•
Retract Tubing Hanger lock down screws.
•
Calculate maximum allowable pull on completion string(s) that is required to do the following: o Retrieve tubing hanger o Open travel joint o Release hydraulic packer or snap out the tubing
•
Pull on the string in gradual increase, retrieve tubing hanger from tubing head spool, open travel joint and work string, as applicable, to sting out seal units / snap latch or to release the hydraulic packer.
•
Maximum allowable pull on tubing is: o For new tubing 85% of the tensile strength of the weakest component o For old tubing 75% of the tensile strength of the weakest component
•
Once packer is unset (wait 30 min. to allow packer element to deflate), or tubing string is snapped out of the packer, start circulating slowly. Circulate one cycle using workover fluid.
•
If unable to recover the completion by direct pull, consider other options such as cutting / milling and fishing operations
•
Ensure no flow and the static loss is less than 20 BPH. Use HVP or LCM if needed.
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•
POH lay down old completion, install pin and box thread protectors
•
Reserve samples of corroded or scaled sections of tubing marked with depth for inspection. Note: o Pull slowly inside 7” liner to avoid swabbing action. o Observe hole on top of liner, when string is half way out of the hole and at 1000 ft o Consider using variable ram to suit different completion sizes. o Have “Kick Joint” ready on V. door to shut in tubing string at any stage while pulling out of the hole.
3.
Releasing Hydraulic Packers The following are general guidelines for releasing dual hydraulic packer:-
•
R/Up tubular equipment for pulling completion string in tandem
•
Define packer setting / releasing side, L.S or S.S. (Assume L.S for this example)
•
Calculate the minimum pull required to shear releasing pin.
•
Calculate the maximum allowable pull on the weakest point in L.S.
•
Make up landing joint (with safety valve) on both strings.
•
Install circulating valve on both sides.
•
Retract lock down screws.
•
Pull S.S, Retrieve TH segment from THS, watch opening travel joint. Apply 10,000 lb over string weight, and set SS on slips.
•
Cut S.S above dual packer, circulate and POOH with S.S (ADCO procedure is not to pull completion in tandem)
•
Pull LS, retrieve TH segment from THS, observe opening travel joint.
•
Record string weight below and above travel joint.
•
Pull on L.S to release dual hydraulic packer, Appling gradual increments of 5000 lb. Refer to the tables in the next page for information about the packers currently used in ADCO operations
•
Work string up and down repeatedly to help shearing the releasing pins
•
Fluid density inside tubing and below packer must be equal or less than that in the annulus.
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•
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If unable to release the packer, proceed to cut and fish completion strings as described in step 4.1 of this section.
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Table 2-5: Hydraulic Packers Specifications
Baker Packers Packer Model
Type
4 ½" Packers Retrievable FH Retrievable
4 ½ ", 5" & 6.5/8" Single Hydraulic Packers
Casing Size in
3.771
--
4.5
9.5-13.5 Hydrostatic
2000
30000
Sour
4.5
9.5-13.5 Hydrostatic
---
30000
Sour
1.978
5
15-18
Hydrostatic
1500
30000
H2S
6.5/8" Packers Retrievable FH
1530
40000
Sour
HS
FHL HS FH
HS
5.603
2.374
6 5/8
24-28
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
5.968
2.370
7
Retrievable
--
--
7
20-26
Retrievable
6.080
2.377
7
Retrievable
5.910
2.373
Retrievable
5.910
2.356
Retrievable
5.983
2.992
7
Retrievable
5.910
2.919
7
Retrievable
8.218
--
9 5/8
Retrievable Retrievable Retrievable
8.218
---
8.310
2.919
9 5/8 9 5/8 9 5/8 9 5/8
40-53.5
9 5/8
40-53.5
7
26-32
7 7 7
Retrievable
Retrievable Retrievable
8.310
2.919
Retrievable 7" Dual Hydraulic
GT
Packers
A-5 AL-5
9 ⅝” Dual Hydraulic Packer
Setting Method
4.125
7" Single Hydraulic Packers
9 ⅝” Hydraulic Packers
Packer Bore ID in
5" Packers Retrievable FH
FH
7" Single Hydraulic Packers
Casing Weight Lb /ft
Pressure Tension Setting Shear Service Min. Release psi lb
Packer OD in
GT A-5 ESP Twin Seal
S.G. Rev-00/09
Retrievable Retrievable
5.937 5.937
Retrievable Retrievable
5.942
1.937
Retrievable Retrievable Retrievable Retrievable
--
--
Hydrostatic
1440
40000
Sour
Hydrostatic
1520
40000
Sour
23-26
Hydraulic
1800
40000
H2S
7
26-29
Hydraulic
2500
40000
H2S
7
23-32
Hydraulic
1800
40000
H2S
7
26-29 Hydrostatic
1530
40000
Sour
Hydraulic
2500
40000
H2S
47-53.5 Hydrostatic
1500
40000
Sour
Hydrostatic 40-47 Hydrostatic 40-53.5 Hydraulic
1500 1500 1800
40000 40000 40000
Sour Sour H2S
Hydraulic
2500
40000
H2S
26-32 26-32
Hydraulic Hydraulic
2100 2100
30000 30000
H2S H2S
23-32
Hydraulic 1750
30000
H2S
8.500
Hydraulic
2150
40000
H2S
8.510
1500
40000
H2S
ADM Volume-2 Drilling Operation -B
Hydraulic
2.968
--
Hydraulic 40-47
9 5/8 9 5/8
Retrievable
23-29
7 7 9 5/8
Retrievable
Sour
40-47
9 5/8
40-47
Hydraulic
9 5/8
40-43.5
Hydraulic
Date Issued: 30/03/2009
Last Revision:
50000
Page 2-33 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Packer Model
Type
4 ½" Packers Retrievable FH Retrievable
4 ½", 5" & 6.5/8" Single Hydraulic Packers
7" Single Hydraulic Packers
Casing Size in
3.771
--
4.5
9.5-13.5 Hydrostatic
2000
30000
Sour
4.5
9.5-13.5 Hydrostatic
---
30000
Sour
Setting Method
4.125
1.978
5
15-18
Hydrostatic
1500
30000
H2S
6.5/8" Packers Retrievable FH
5.603
2.374
6 5/8
24-28
Hydrostatic
1530
40000
Sour
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
--
--
--
Retrievable
5.968
2.370
7
Hydrostatic
1440
40000
Sour
--
--
7
20-26
Hydrostatic
1520
40000
Sour
3.76
1.917
4.500
9.5-13.5
Hydraulic
3500
32000
H2S
4.83 4.83
1.925 1.925
5.00
15-18
Hydraulic
2000
24000
H2S
5.00
15-18
Hydraulic
2000
24000
H2S
5.520
2.360
24-32 24-28
Hydraulic Hydraulic
2000 3500
43000 41000
Retrievable Retrievable
2.360 --2.360
6.5/8 6.5/8
H2S
5.610 -5.880
7.00 7.00
23-32 23-32
Hydraulic Hydraulic
-2000
---
-H2S
Retrievable
--
--
7.00
26-32
Hydraulic
---
---
---
5.880
2.360
Hydraulic
2000
40000
H2S / CO2
Retrievable 4 ½" Packers Retrievable PHL 5” Packers Retrievable RH Retrievable 6.5/8” Packers Retrievable RH Retrievable PHL
7" Single Hydraulic Packers
Packer Bore ID in
5" Packers Retrievable FH
FH
4 ½", 5" & 6.5/8" Single Hydraulic Packers
Casing Weight Lb /ft
Pressure Tension Setting Shear Service Min. Release psi lb
Packer OD in
RH
Retrievable
7.00
26-32
Sour
Halliburton Packer Model
Type Retrievable
7" Single Hydraulic Packers 9 ⅝” Single Hydraulic Packers
7" Dual
PHL
RH
Retrievable
2.360
Retrievable 5.980 Retrievable 8.31 Retrievable 8.31
2.885
Retrievable
RDH
Retrievable
Rev-00/09
6 5.980
PHL
S.G.
Packer Packer Casing Bore ID Size in OD in in
8.45
ADM Volume-2 Drilling Operation -B
Pressure Tension Setting Shear Service Min. Release psi lb 2000 32000 H2S
Casing Weight Lb /ft
Setting Method
7.00
23-29
Hydraulic
7.00
23-29
Hydraulic
3000
40950
H2S
7.00
23-29
Hydraulic
3000
40950
H2S
9 5/8 9 5/8
40-47 40-47
Hydraulic Hydraulic
2000 2000
40000 40000
H2S H2S
9 5/8
40-47
Hydraulic
3500
41300
H2S
7
26-32
Hydraulic
Date Issued: 30/03/2009
Last Revision:
Page 2-34 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Packer Model Hydraulic Packers
BHD RDH
9 ⅝” Dual Hydraulic Packers
Type
Packer Packer Casing OD Bore ID Size in in in
BHD
Setting Method
Pressure Tension Setting Shear Service Min. Release psi lb 2000 30000 Sour
Retrievable Retrievable
5.940
7 7
26-32 26-29
Hydraulic Hydraulic
Retrievable
6.015
7
26-29
Hydraulic
4000
30000
H2S
8.340
9 5/8
43.5-53.5
Hydraulic
2000
40000
Sour
9 5/8
43.5-53.5
Hydraulic
9 5/8
43.5-53.5
Hydraulic
2000
40000
H2S
43.5-47
Hydraulic
3000
40000
H2S
Casing Weight Lb /ft
Setting Method
43.5-53.5 Retrievable Retrievable
RDH
Casing Weight Lb /ft
Retrievable
8.340
43.5-47 Retrievable
9 5/8
8.475
Weatherford Packer Model
Type
7" Dual Hydraulic Hydro-II Retrievable Packers
Packer OD in
Packer Casing Bore ID Size In in
5.938
7
23-32
Casing Size In
Casing Weight Lb /ft
Pressure Setting Min. psi
Tension Shear Release lb
Service
2000
30000
H2S
Pressure Setting Min. psi
Tension Shear Release lb
Service
Hydraulic
Arrow Packer Model
Type
9 ⅝” Dual Hydro-II Retrievable Hydraulic Packers Hydro-II Retrievable Hydro-II Retrievable
Packer Packer OD Bore ID in in
Setting Method
8.50
9 5/8
47 - 53.5 Hydraulic
2000
30000
8.5
9 5/8
47 - 53.5 Hydraulic
2500
40000
H2S / CO2 H2S
8.5
9 5/8
40 - 47
2500
40000
H2S
Casing Size In
Casing Weight Lb /ft
Setting Method
Pressure Setting Min. psi
9 5/8
40-47
Hydraulic
1500
NODECO Packer Model
Type
Packer Packer OD Bore ID in in
9 ⅝” Dual RR (ESP) Retrievable Hydraulic Packers
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Tension Service Shear Release lb 50000
Page 2-35 Printed on: 19/08/2008
H2S
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
4.
Recovering Dual Completion 4.1 Recovering dual completion with Stuck Dual Retrievable Packer The following procedures describes steps to recover dual completion and assume that after recovery of S.S, the dual packer can not be released by pulling on L.S, If unable to release dual hydraulic packer by direct pull, proceed as follows:Step-1: - Cutting short string above dual hydraulic packer
Cut S.S 5 ft above dual packer
•
Make up landing joint (with safety valve) on short string tubing hanger.
•
Apply 10,000 Ibs tension on SS and land on slips.
•
Rig up electric wireline BOP on S.S side and test to 3000 psi.
•
RIH with chemical cutter, cut S.S at +/-5 ft above dual hydraulic packer. POH and rig down electric wire line, circulate hole.
Cut L.S 15 ft above dual packer Dual Packer
Short String Long String
Cut L.S at middle joint above blast joints Blast Joints
Single Packer
Figure 2-2: Step-1 Cut Short string
Figure 2-3: Step-2 Cut Long String below Dual Packer
Figure 2-4: Step -3 Cut Long String above Dual Packer
Printed on: 19/08/2008
S.G.
ADM Volume-2 Date Issued: ADCO Rev-00/09 Drilling Operation -B DRILLING MANUAL
30/03/2009
Last Revision:
Page 2-36
Volume-2/Chapter-2: Workover Operations
Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
POH and lay down S.S.
•
Make up landing joint (with safety valve) on LS tubing hanger. Pull up to 75% of the tension strength of the weakest component and attempt to release dual hydraulic packer and sting out of permanent packer.
•
If packer releases, circulate hole. Observe well, and POH, laying down completion strings.
•
If 75% of the yield strength of the weakest components of LS was not enough to release the packers, proceed to Step–2 to cut L.S below dual packer as follows:-
Step – 2: - Cutting long string below dual hydraulic packer
•
R/U wireline on L.S. and run with chemical cutter, cut L.S between single and dual packer at the middle of the joint above all blast joints.
•
Try again to unset the dual hydraulic packer if not succeeded; proceed to step-3 to cut L.S above the dual packer as follows:
Step – 3: - Cutting long string above dual hydraulic packer
•
RIH with chemical cutter and cut LS at +/-15 ft above dual hydraulic packer), POH and R/Down electric wire line, circulate hole.
•
POH and lay down L.S.
•
Change top pipe ram (if needed), test BOP’s and install wear bushing
•
RIH with overshot on drill pipe. (See section-4 of this chapter for BHA configuration).
•
Latch onto L.S side, Try again to unset the dual hydraulic packer. If not succeeded; proceed to step-4 to mill and fish the dual packer as follow:
Step – 4: - Milling and fishing dual Hydraulic packer
•
RIH with washover assembly, washover dual packer until it became free.
•
RIH with overshot and fishing assembly engage and catch LS. POH and lay down dual packer.
Step – 5: - Stinging the seal units out of the permanent single packer
•
If seal units still stuck inside the permanent single packer, RIH with overshot to top of LS, engage and workout to pull the seal units out of the permanent packer. POH and lay down fish. If unable to pull the seal unit, proceed as per step-6.
Note:In case if single hydraulic packer is retrievable, try to release the packer by direct pull using overshot otherwise wash over the Packer till it become free. Run with overshot, engage fish and POH. S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-37 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
For fishing assemblies and tools refer to section-4 of this chapter. Step–6:- Washing over permanent single packer and recovering seal units If unable to sting out from the permanent packer, proceed as follows:
•
Run wash over shoe with enough extension, wash over the permanent packer until it becomes free. If stick up above permanent packer is long (long section of blast joints), consider cutting below blast joint, noting that washing over long section of tubing across deviated section is not operationally easy
•
Run overshot with proper size of basket garble, engage top of tubing. POH and L/Down fish.
•
If seal units were recovered earlier by direct pull, proceed as per step -7 to mill and recover the permanent packer
Step–7:- Milling and recovering permanent packer For milling and retrieving permanent packers use HE packer milling and retrieving tool. The tool consists of the following components:
•
Packer Retrieving Spear Designed for removal of drillable full bore packers from the well. During the milling operation it will remain in the catching position at all times to engage the lower end of the packer. It consist of three parts, top coupling, mandrel slip and bull plug or mill head at the bottom. The Packer Retrieving Spear dressed with the proper size slip (grapple) for the bore of the packer is made up on sufficient extensions to allow the spear to be below the packer or extension(if any) during milling operation. The spear can be run in hole with slip in catch or release position. As the spear enters the bore of the packer, the slip is forced to move up on the mandrel in an area where the OD is reduced enough to allow passage through the packer. As the slip clears, it automatically drops to catch position. The Packer Retrieving Spear can be released by applying slight overpull and right hand rotation. Also, it can be engaged into the packer by merely lowering through the packer.
•
Extension Sufficient extensions to be made to have the Packer Retrieving Spear below the bottom of the packer or seal bore extension (if any) during milling operation. Extensions is equipped with special locked joint connections which prevent any possibility of whip-off during the milling operation.
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-38 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
Milling Head The packer milling head has an API connection up and an extension connection down.
Recover permanent packer with short seal bore extension (<10 ft) If the permanent packer is connected with short seal bore extension (less than 10 ft), the following procedures are to be followed:-
S.G. Rev-00/09
•
Make up The Packer Retrieving Spear with slips suitable for the packer bore (which is to be milled), Extension and mill head, lock the connections of the extension to avoid back-off during milling operation.
•
Lower the entire milling assembly to the top of the packer. Circulate and check weight of string up and down with and without circulation. Stop the pump.
•
Lower the milling assembly until the Packer Retrieving Spear passes through the bore of the packer.
•
Check that the Packer Retrieving Spear has engaged the packer by applying 10,000 lbs over pull.
•
Start milling the upper slips and packing element of the packer.
•
Push the packer down (~ 50') pump Hi-Vis-Pill and circulate bottom up.
•
POH the milling tool and remainder of packer.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-39 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Assuming that: • Well is killed and fluids equalized. • Unable to release S.S from dual Pkr.
Dual packer Released?
Yes
No (*See Note.1)
Washover dual packer, run overshot assy, latch onto L.S, POH with dual packer.
Cut S.S. above dual packer, circulate and POH with S.S.
Pull 75% of the yield strength of the weakest component of the LS
Run overshot assy, latch onto seal assy above permanent packer.
Yes
Dual Packer Released?
Seal assy Released?
Yes
No
Cut L.S. below dual packer and pull on dual packer.
Dual Packer Released?
Yes
POH and L/D seal assy.
No
Circulate and POH with L.S. and dual packer
Washover permanent packer using packer milling & retrieving tool, and POH fish. OR Washover with milling tool, run overshot, POH with fish
No
*Note.1: Consider to terminate the Fishing operations in special cases as mentioned in Clause-5.
Cut L.S. above dual packer, circulate and POH with L.S.
Run overshot assy, latch onto L.S. to unset dual packer. Figure 2-5: Recovering Dual Completion Flowchart
Printed on: 19/08/2008
S.G.
ADM Volume-2 Date Issued: ADCO Rev-00/09 Drilling Operation -B DRILLING MANUAL
30/03/2009
Last Revision:
Page 2-40
Volume-2/Chapter-2: Workover Operations
Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Note: As an alternative, packers with seal bore extension (millout extension or with x-over and tail pipe attached to the bottom of the packer can be milled and retrieved in one trip by utilizing the Pioneer slick bore packer milling and retrieving tool.
5.
Abandoning Completion Tail and Packer(s) Fishing operation of Completion tail & Packer(s) shall be terminated if these conditions are met.
•
Effective zonal isolation between different zones can be achieved.
•
Abandonment is economically feasible compared to the fishing and milling option.
•
Abandoning completion tail & packer(s) will not have negative impact on the new well target, quality or integrity.
•
Continuing milling / fishing may result in loosing the chance to achieve zonal isolation due to plugging of String/Perforations.
Note: Refer to Chapter-4, Section-6 (Well Abandonment) for details on well abandonment and zonal isolation.
6.
Recovering 7" scab liner Scab liners were set in old dump injection wells to isolate the perforated aquifers. During workover operations, the corroded scab liner is replaced by cemented casing string to surface. Most of the scab liners in ADCO consist of:
•
194-75-60 FA-1 Baker Permanent packer at bottom.
•
190-75, K-22 Anchor seal assembly.
•
7" casing enough to cover the aquifer perforation.
•
194-60, FB-1 Baker Permanent packer at top.
The bottom packer was set on electric wireline while the upper packer together with casing was run and set on DP.
6.1
Retrieving Procedure
•
S.G. Rev-00/09
RIH 8.1/2" X 7.1/16" rotary shoe, wash over FB-1 PKR until it becomes free. POH.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-41 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
RIH with 7" casing spear and hydraulic jar. Latch into 7" casing. Release K-22 Anchor Seal by jarring and rotating ± 20 turns to right while applying overpull equal to 20% of the liners weight.
•
POH and L/D 7" scab liner marking same to carry out corrosion inspection prior to milling/retrieving bottom FA-1 packer with milling retrieving tool.
Notes:
•
a)
If K-22 anchor seal will not released, release the spear, POH and proceed to next step.
b)
RIH with internal casing cutter. Cut 7" casing at ± 5' above scab liner bottom.
c)
POH with casing cutter, RIH with 7" casing spear to recover the 7" scab liner.
d)
If casing is parted, attempt to recover the rest with spear and, if no success, proceed to step b and c above.
RIH with 7" casing releasing spear and hydraulic jar. Latch into 7" casing. POH and L/D 7" scab liner numbering same for corrosion inspection. O
RIH with 8.1/2" X 7.1/16" rotary shoe on 30'X8.1/2" washover pipe.
O
Washover FA-1 packer until same drops down.
O
RIH with 7" casing spear to recover the rest of casing and bottom packer.
Notes: Have available on location 8.3/8" short catch overshot with 7" spiral grapple to be used if spear fails.
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-42 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 4 FISHING GENERAL GUIDANCE This section describes the fishing tools and assemblies used in workover operations and highlight the factors and concerns that must be taken into account when using each tool.
1.
Standard Fishing Assembly •
2.
The standard fishing assembly consists of the following: O
Fishing tool
O
Jar and Bumper Sub
O
Accelerator
O
Drill Collars
O
Heavy Weight Drill Pipe
O
Drill Pipe
•
A Safety Joint should not be run. Since the Safety Joint will not transmit left hand torque, it would not be possible to back-off below it using a string shot. However, a Safety Joint could be run between the catching tool and the jar when a non releasing tool such as taper tap is being employed.
•
Avoid any restrictions in the bore of tools run above the catching tool, which would prevent the use of a cutting tool or the back-off shot within the fish.
•
Where losses or plugging are expected the use of a Circulation Sub in the fishing assembly should be considered.
Overshot •
S.G. Rev-00/09
Plan the operation taking into account the following factors: O
The catching action of the tool will stress the fish neck inwards.
O
A regular, smooth shape of the fish neck is necessary for a successful operation.
O
Jarring is only possible using “The Jarring type overshot”.
O
If the fish diameter is near the maximum catch or size of basket grapple, a spiral grapple is recommended. On the other hand, if the fish diameter is considerably below the maximum catch size, a basket grapple is preferable.
O
If the hole is enlarged, use an oversize guide.
O
When the fish has been milled over, if possible, run an overshot extension to avoid catching the fish by the milled part.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-43 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
3.
•
Run the fishing assembly, space out as required, and make up the Kelly.
•
Lower the overshot to just above the fish and circulate for a few minutes to clean the top of the fish.
•
Prior to engaging the fish, record the weight of fishing string (up, down and rotating) with and without circulation.
•
To engage a fish, the fishing string is lowered and rotated to the right very slowly, pumping at minimum rate. During the engaging operation, continuously monitor the weight indicator and stand pipe pressure.
•
As the fish is engaged, allow the right hand torque to slack out and pull on the fish picking up rapidly the fishing string 5 to 8ft. Drop the string 2 to 4ft and catch it in the brake to make sure that there is a firm grip.
•
If possible, consideration should be given to circulating bottoms up through the fish before pulling out of hole.
•
When tripping out of the hole with the fish, the string must not be rotated; pipe Spinner should be used.
•
If pulling out of the hole wet, flow checks shall be carried out frequently.
Releasing Spear •
• 4.
Plan this operation taking into account the following factors: O
The fish will be stressed outwards due to the catching action of the tool.
O
A regular, smooth shape of the fish is essential for a successful operation.
O
To allow unlatching of the spear, the use of a bumper sub is recommended.
O
Use the fishing jar If jarring is required. In this case the use of a Spear Stop is required. Check the Spear Stop OD when it is used in open hole and use the stop only if hole condition permits.
Perform the fishing job as per overshot procedure.
Taper Tap / Pin Tap •
S.G. Rev-00/09
Plan this operation taking into account the following factors: O
The size of the taper tool should be selected in order to engage the fish with the middle of the tapered point.
O
The taper taps do not allow free passage of the back-off tool.
O
Excessive torque can damage the tapered thread and swell the top of the fish.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-44 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
O
5.
6.
It is very difficult to impossible to release the tool once engaged. For this reason its use has to be considered the last resort.
•
Run the fishing assembly, complete with safety joint, space out as required and make up the Kelly.
•
Lower the catching tool to just above the fish and circulate a few minutes to clean the top of the fish. Do not circulate excessively as this may enlarge the hole.
•
To engage the fish, apply right hand torque. A gradual increase of back torque is an indication of successful operation.
•
Spin the pipe out of hole with the fish.
Reverse Circulation Junk Basket •
This procedure is more successful in soft formations.
•
Use the following parameters: O
WOB = 4000 to 8000 Lbs
O
Rotary = 45 RPM
O
Low Pump Rate (half of pumping rate while drilling).
•
Core approximately 1 foot. Pick up to allow the junk on the side of the basket to fall into the pilot hole, and then proceed coring a further +/-2 feet.
•
Pull the junk basket out of the hole
Fishing Magnet Magnets can be successfully used but only in hard formations to retrieve small steel objects such as bit cones, bearings, slips, tong dies and milling cuttings. To avoid sticking the fish in the hole, weight must not be applied. Fishing magnets may be run on wireline or on drillpipe. Wireline run have the advantage of speed and economy. Drillpipe run has the great advantage of utilizing the circulation to remove cuttings settling above the fish.
7.
Milling Tools The following are general guidelines for the use of milling tools:
•
S.G. Rev-00/09
Milled cuttings are much heavier than drilling cuttings. Therefore, mud yield should be increased or high viscosity pills should be pumped to help in carrying the steel cuttings out of the hole. ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-45 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
Oil based mud has poor carrying capabilities and should be avoided whenever possible. Polymer mud is most suitable for milling.
•
Never mill faster than it is possible to remove the cuttings.
•
Magnets placed in the flow line will help in removing metal particles from drilling mud. Removal of mill cuttings and debris reduces the wear on mud pumps and other equipment.
•
A junk sub placed in the string above the mill can aid in catching the larger cuttings.
•
Always start rotating, with low RPM for about 3 ft above the top of fish. Lower onto the fish and adjust the weight and the rotary speed to obtain satisfactory progress.
•
Generally the most efficient milling rates are obtained by running the rotary at 80 to 100 RPM. Milling with washover shoes is an exception and are usually more efficient at speeds of 60 to 80 RPM.
•
Continuously monitor the torque indicator during milling operations.
•
The type and stability of the fish (cemented or not) together with the hardness of the fish and/or cement are factors that affect milling rates.
There is a wide variety of mills specifically designed for various applications. Two basic categories are available:
8.
Hydraulically Activated Mills 8.1
Section Mill Section mill is a hydraulically actuated tool and is used to mill out a complete section of casing. Downhole section milling of casing, is generally done for the following reasons:
9.
•
To mill a section of casing that permits sidetracking in any direction.
•
To mill the perforated zone in a production casing string or to expose cased-off formations. The formations may be then under-reamed and gravel packed past the original completion.
Fixed Milling Tools The most commonly used Fixed Mills are:
9.1
Junk Mills Used to mill all types of junk, including rock bit cones, reamers cutters, items dropped through the rotary, cemented tubing, etc.
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9.2
Pilot Mills Designed to mill casing, tubing, wash pipe, safety joint, swaged casing, etc.
9.3
Taper Mills Generally used to eliminate restrictions or to mill through collapsed casing.
9.4
Washover Shoes Designed to mill away formation or tool obstructions such as stabilizer blades, reamer cutters, expanded packers and bit bodies which may be holding the drill or tubing string in the hole
10.
Special Mills Window mills, Watermelon mills, etc. for casing sidetracking systems (See Sidetracking Section -5 of this Chapter).
11.
Fishing of Radio-Active Wireline Tools 11.1 Caution Radioactive Source containers release, if broken, very harmful materials that are dangerous to human lives and contaminate the field as these materials migrate in the formation. Therefore, every precaution MUST be taken to avoid breaking these containers while fishing.
11.2 Preparation The whole operation needs good communication and co-ordination between Driller, Derrickman, Floormen and the Wireline Contactor Operator. Therefore, the DS will arrange a pre-job safety meeting.
11.3 Operations
S.G. Rev-00/09
•
When stuck, determine if the tool or the cable is stuck by using the stretch charts provided by the Wireline Contractor.
•
Do not break the cable or the weak point. Chances to recover the tool are reduced by doing either of them.
•
Prepare the overshot using the correct grapple to suit the cable head in use and the guide shoe to suit the hole size. Screw the assembly into the sub to be made up between the overshot and the drill pipe.
•
Pull up 2000 lbs over normal cable tension.
•
Secure the cable with the special T-Clamp, slack off and cut the cable 5-7 feet above the Rotary table.
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S.G. Rev-00/09
•
Lower the block with the upper sheave wheel and fix the top sheave as high as possible in the derrick, at a position where the Derrickman can easily reach the cable.
•
Use the Wireline Contractor’s tension device on the lower sheave.
•
Feed the "hole" end of the cable through the overshot assembly and prepare the male type quick connection.
•
Prepare the "Unit" end of the cable with the female type quick connection. Make up sufficient sinker bars on this end to overcome the cable weight while lowering the quick connection through the drillpipe.
•
Pick up the first stand of drillpipe and lower the quick connection through the pipe.
•
Engage the quick connections and pull up until the cable is slightly under tension.
•
Make up the overshot assembly to the drill pipe, chain tong tight.
•
Pull up the cable until the T-Clamp is hanging free. Disconnect T-Clamp.
•
Make the overshot assembly to the drillpipe tong tight
•
Lower the stand until the pin end of the quick connection is completely clean of the pipe.
•
Drop in the Rotary slips, place C-Plate into the groove of the quick connection and slack off cable tension.
•
Release the quick connection, pick up the next stand of drillpipe and repeat operation until approaching the fish.
•
Stop one stand above the torpedo and install the circulating sub.
•
Circulate slowly to clean the overshot and note the number of strokes and pressure. While circulating, there is every possibility that a cable loop will be formed at the bottom of the overshot. Therefore, Do Not Lower or Rotate the string while circulating.
•
Disconnect circulating sub and continue the approach until the cable tension is increasing. Do Not Rotate The Pine At Any Time.
•
After engaging the tool into the overshot, circulate again at the same stroke as in above. The pressure should be higher now.
•
Connect clamp and use the traveling block to pull the weak point.
•
Cut off quick connections and make a square knot with the cable ends.
•
Pull out and spool the cable on the drum.
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•
Pull out the fishing string slowly. Do Not Rotate.
•
Disconnect the tool from the head and break overshot connections with the tongs.
Notes: To avoid accidental damage of the containers during fishing and to know as soon as possible if the container is broken: −
Monitor permanently mud return with a gamma-ray tool at the shale shakers while circulating.
−
Never rotate with the drilling string at any stage.
−
Minimize the people working on the rig floor when the tool containing the source is pulled out of the hole.
− If all efforts fail to fish the source and it is decided to abandon the same, it must be protected by a cement plug. −
A gamma-ray log will be taken after the cement job to check that there is no contamination and that the source was not dragged up the hole during the cementing process.
− If at any stage position of the source is not clear, a gamma-ray log will be taken to trace it. −
S.G. Rev-00/09
It must be ensured that the abandonment of such source with exact details as per the depth, date…etc are clearly recorded in the Daily Drilling Report by the Drilling Supervisor on the rig and properly documented in the respective well file by the relevant Drilling Engineer in the office.
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SECTION 5 SIDETRACKING OPERATIONS Sidetracking is creating an exit through openhole or casing to allow a new lateral section to be drilled.
1.
Sidetracking in Open hole Sidetracking through openhole can be done using different techniques as follow
1.1
S.G. Rev-00/09
Cement Plug Method
•
Select the formation which gives the best chance of sidetracking success. This is normally done by analysis of the ROP log. The ideal formation is normally a consolidated formation at the place of best ROP.
•
The minimum distance between the TOF to the Kick-off Point (KOP) is 100 feet and between casing shoe and KOP is 30 ft.
•
Sidetracking in Shale formation is not recommended, because of the high risk of caving.
•
Prior to start any sidetrack operation, ensure first that drill string is in good condition and does not require a tubular inspection, especially after any fishing job.
•
Run in hole with 1000 feet of 2 ⅞" or 3 ½” open ended tubing on drill pipe to the top of fish.
•
Set high compressive strength balanced cement plug on top of fish to cover the distance between the top of fish up to 150 feet above the selected kick-off point depth (KOP). The recipe of the cement slurry should be made such as to obtain very hard cement.
•
In case of losses at the bottom of the hole, several cement plugs may be necessary. In this case, all efforts should be made to cover at least the distance between 150 feet above the KOP down to 100 feet below the KOP with one same cement plug such as to obtain uniform cement plug homogeneity.
•
While waiting on cement, run in hole with milltooth bit and dress TOC to 30 feet above the KOP and circulate hole clean.
•
Test the hardness of the cement by applying 50,000 lbs WOB without rotating the pipe but with a maximum of pumping rate. If no penetration is obtained in such condition, the cement is probably hard enough. If any penetration, WOC a further 8 hours and repeat the cement hardness test.
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•
In both cases, when the cement is hard enough, drill the remaining cement to the KOP required, circulate hole clean, and take a survey with bit as close to bottom as possible and pull out of hole.
Note: In case directional control is required during the sidetracking, RIH enough non-MAG DCs to allow taking a survey prior to POH for sidetracking.
•
RIH the following sidetrack assembly: 1. Tricone bit. 2. Mud motor. 3. Bent Sub (1.1/2° to 2.1/2° depending on hole size). 4. Orienting Sub (In case directional control is required) 5. 1 or 2 non-mag drill collar (In case directional control is requiredLength NMDC' Model depends on angle of hole and direction) 6. Enough HWDP to allow a maximum of 20,000 lbs WOB.
S.G. Rev-00/09
•
Run in hole last 30 feet with low circulation and RPM (Adjust the string length such as to have a full kelly above the RT with the bit on bottom).
•
If directional control is required, orient the tool face in the required direction and start sidetracking.
•
If the well is already a deviated hole the easiest optimum direction for the sidetrack would be on the "Low side" of the hole.
•
If no directional control is required, lock the rotary table and do not allow the string to rotate any more until the kick off is completed.
•
With the rotary table locked and marked, and constant circulation pressure, drill the first 15 feet in 12 hours time at a rate of 1 inch each 4 minutes. Check percentage of cement and formation on the shale shaker.
•
Drill the next 15 feet in 6 hours time at a rate of 1 inch each 2 minutes. Check percentage of cement and formation on the shale shaker.
•
Make the connection carefully ensuring that the string is not rotating. Readjust the pump rates as for above.
•
Continue sidetracking another 30 feet in 6 hours at a rate of 1 inch per minute. Check the percentage of cement and formation on the shale shaker. As soon as 100% of formation is obtained on the shale shaker, increase the WOB to normal drilling condition.
•
Make another connection as previously and drill the next 30 feet normally.
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KOP to TOF = Min 100 ft
Shoe to KOP = Min 60 ft
Volume-2/Chapter-2: Workover Operations
Cement Plug
Fish
Figure 2- 6: Openhole sidetracking cement Plug
Note: The KOP where the first foot of sidetracked hole is drilled is the depth which must be considered for lost hole calculation.
•
Take a survey after a total of 90 feet are sidetracked and compare this survey with the survey taken previously.
•
Continue sidetracking until a total of 5° change of hole angle is obtained, or a total departure from the original hole of 5 feet, whichever comes first. Take a final survey and continue drilling sidetrack hole as per plan.
Note: It is important to ensure always the same pump pressure during the sidetrack operation in order to have always the same "reactive torque" on the drill string. The rotary table being locked during the sidetrack would allow the tool face of the bit to change every time the circulation pressure changes.
•
S.G. Rev-00/09
In case of a vertical hole where the direction of the sidetrack is not critical, RIH with the standard pendulum BHA and drill ahead in normal condition, taking a survey every 90 ft. at the beginning to ensure the hole angle is dropping off. Thereafter only normal surveys are required.
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•
In case the sidetracked hole direction is critical, or in case of deviated sidetracked wells, the required BHA for continuing drilling must be selected according to the hole conditions and the target position.
Note: Remember that a conventional rotary drilling assembly has normally a "righthand roll off" tendency during drilling (tendency to turn the well direction to the right) while turbo-drilling has a "left-hand roll off". This can be considered to help in reaching the target of the deviated hole.
1.2
Openhole Whipstock (Cement Whipstock Method) 1.2.1 General Notes
•
The Cement Type Whipstock although set in open hole conditions, should be set on some type of bottom (i.e., formation, fish, etc.) to prevent it from moving downhole when setting.
•
If required, the cement type whipstock can be oriented to a specific direction.
•
Enough cement is pumped and applied generously around the whipstock and at least 100 feet above the whipstock.
1.2.2 Bottom Hole Assembly
•
Cement Type Whipstock
•
Setting Tool
•
Universal Bottom Hole Orientation Sub (UBHO)
•
Drill pipe joint
•
Pup joints (for space-out if necessary)
Note: The UBHO Sub is required only when orientation is necessary.
1.2.3 Procedure
S.G. Rev-00/09
•
Pick up a single joint of drill pipe and make up the whipstock Setting Tool to the bottom connection.
•
If required, make up the UBHO sub to the top of the drill pipe.
•
Make up the Setting Tool to the whipstock concave by sliding the Setting Tool’s tube over the cementing tube extending through the whipstock’s concave.
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•
Run the whipstock into the hole at a slow, steady rate, 2 to 3 minutes per stand. Fill the drill string every 10 to 15 stands to ensure that the tubes on the whipstock do not plug. Caution: Do not include drill collars in the drill pipe string when setting a cement type whipstock. The small ID of drill collars may cause “flash” setting of the cement.
•
Circulate through the drill pipe string.
•
At 10 ft from bottom, run survey tools on wireline to the UBHO sub, take survey readings and correct direction of whipstock.
•
Pull the wireline from the drill pipe string and lower the whipstock assembly until it rests on the bottom.
•
Connect the cementing line to the drill string. Note: The cementing tube is rated to 3,500 psi. Pump cement at no more than 2 bpm to prevent bursting the tube.
•
Pump the cement to a level approximately 100 feet above the whipstock (see Figure 2-8).
•
Disconnect the cementing line immediately after the cementing procedure is complete.
•
Pick up to the string weight.
•
Pick up 5 to 10 feet and then quickly lower back to the bottom to shear loose from the concave.
•
Once shearing has been verified, pick up the drill pipe string 10 stands (see Figure 2-9).
•
Pull out of the hole, circulating on the way out.
•
Wait on cement to set.
•
Use a drill bit to drill through the cement, above the whipstock down the whipstock’s concave and into the new formation (see Figure 2-10).
•
This run should include a flexible assembly as follows (from top to bottom): 1. Drill pipe string 2. One joint drill pipe
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3. Bit Sub (Minimum length, bored for the float assembly)
4. Drill Bit (Usually PDC or short tooth rotary bit) Caution: Do not rotate stabilizers on the whipstock's concave; this action could cause damage to the whipstock orientation.
Figure 2- 7: Cementing O.H. Whipstock
2.
Figure 2- 8: Releasing Whipstock
Figure 2- 9: Sidetracking
Sidetracking Inside Casing For sidetracking inside casing, two different methods are available:
• S.G. Rev-00/09
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•
To set a Whipstock assembly inside the casing and cut a window in the side of the casing through which the sidetrack is made.
Both the above methods are efficient but the final selection of which to use must be made on the hole condition, as described hereunder.
2.1
Sidetracking through a cut section of casing This method of sidetracking should be used when the casing across the KOP is in poor cemented and/or mechanical conditions, which would not permit the setting of a Whipstock in safe condition.
2.1.1 Standard measures
•
As for sidetracking in open hole, the optimum formation behind the casing should be selected for better chance of success.
•
The very minimum distance of casing to be cut is 60 ft, from which the top 40 feet are reserved for "getting out" of the old hole.
•
The optimum length of cut casing is 75 feet.
•
Distance between the top of fish and the bottom of the cut section of casing is minimum 50 ft.
2.1.2 Section mill description The section mill cuts through casing with three cutter blades working like single-point tools and then mills the casing with six blades at a speed of up to 8 ft/hr. The mill features is a piston actuated cam that locks the cutting blades open during operation and automatically closes them when pump pressure is removed. When cut out is complete, annular flow through the tool is more than doubled resulting in a pressure drop of about 200 psi and a noticeable increase in pump strokes.
2.1.3 Cutting section (window) in casing
S.G. Rev-00/09
•
Run in hole with section mill to the desired depth, filling string every 10 stands.
•
Rig up slickline.
•
RIH with 1.11/16" GR/CCL and correlate driller depth.
•
Pull out of hole and rig down slickline.
•
Rotate section mill at 60 RPM without pump pressure.
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S.G. Rev-00/09
•
Turn pump on and build up pressure to 1500-2000 psi. Record pressure and pump speed and hold pressure as even as possible during cut out.
•
Cut the distance of casing required. During this operation, as casing joints are normally 40 feet long, a maximum of 1 casing collar is to be cut. POOH.
•
When the cut out is completed, a pressure drop of about 200-250 psi will be noticed and the pump speed will increase.
•
After the cut out is made, allow the tool to rotate for about 10 minutes to clean up the cut.
•
Increase RPM to 100-125.
•
Gradually apply 4000-8000 lb/ft weight.
•
Maintain an even weight while milling rather than allowing the weight to "drill off" before adding more weight.
•
After casing has been milled, reduce weight to 2000 lb/ft.
•
Turn the pump off.
•
Rotate 2 to 5 minutes and stop rotation.
•
Pull into casing slowly and continue POOH.
•
RIH with 600 feet of 2 ⅞" or 3 ½" open ended tubing on 3 ½” DP down to at least 30 feet below the base of the cut casing section. The ideal would be to set the base of the cement plug right at the top of the fish.
•
Set a balanced cement plug.
•
Clean out to top of cement as; the KOP will be 10 feet below the upper section of the casing cut.
•
For controlled azimuth side tracks the survey to be taken will require a single shot Gyro tool or continues Gyro tool due to the magnetic interference from the casing string.
•
Proceed with the same sequences as described above in “Cement Plug Method” including all notes and remarks.
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Cut window = 75 ft Optimum (60 ft minimum)
Volume-2/Chapter-2: Workover Operations
Bottom of window to TOF = 50 ft
Cut Window
Fish
Figure 2-10: Cut window in casing with section mill
2.1.4 Mud conditioning for milling
•
Minimum annular velocity of 120 ft/min.
•
Turbulent flow is required to clear the cuttings and avoid the chance to "bird nest" in the wrong place such as above DCs.
•
If well conditions permit, use water based drilling fluid.
•
Increase the yield point of the mud with a moderate increase in viscosity.
•
Keep a minimum of 60-70 cp viscosity.
2.1.5 Removal of cuttings
•
S.G. Rev-00/09
Make sure that all tubulars run with the section mill are full bore because restrictions can cause fluid volumes problems preventing cutting removal and could affect the hydraulically operated section mill.
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2.2
•
Additional nozzles may be installed, pointing up the hole, directly above the section mill.
•
Have a magnet on the flow line.
•
Surface arrangement should be available for flushing flow line to avoid plugging.
Sidetracking in casing with Conventional Whipstock This method of sidetracking should be used when the casing across the KOP is in good cemented and mechanical conditions (only 20 to 30 feet of good casing are required to allow a safe setting of the Whipstock).
2.2.1 Standard measures
•
The optimum formation behind the casing should be selected for better chances of success.
•
The minimum distance required "to get out of the old hole" is 30 feet.
•
There is no need for a special distance between the top of fish (TOF) and the setting depth of the bridge plug.
•
This sidetrack CAN NOT GO WRONG, even if the sidetrack is made through two strings of casing (which is not always the case in open hole technique sidetracks).
2.2.2 Whipstock mills
•
Starting Mill: Used to lower the whipstock into the setting position and to cut the initial window.
•
Watermelon Mills: Typically run above the window Mill and drill pipe to assist in opening the window.
•
Window Mill: Used for cutting windows as a follow-up to the Starting Mill.
•
String Mills: Used on the final run above the Window Mill on a drill collar.
•
Tapered Mill: Used when problems (such as flattened, split, or bent casing) are encountered; not used to cut the formation.
2.2.3 Procedure
• S.G. Rev-00/09
Make a round trip with scraper across the packer setting area.
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•
In case of directional holes which require azimuth control of the side track, the Whipstock packer has to be set on DP to allow orientation of the Whipstock by means of an orienting tool.
•
In this case the BHA would be:
•
•
O
Permanent Bridge Plug (with aligning pins for the Whipstock).
O
Hydraulic setting tool (with ball installed on the seat as the ball will not pass the orienting sub above it).
O
Orienting sub (with mule shoe guide).
O
HWDP and DP.
The setting procedure will be as follows: O
Run in hole with above BHA to packer setting depth.
O
Fill string every 10 stands.
O
Orient the packer into the required direction using single shot gyro instrument.
O
Set the permanent packer by applying pressure.
O
Release the setting tool by pull shearing the release pin.
O
Pull out of hole.
In wells where directional control of the well is not required, the packer can be set on DP as said above, but without having to orient the string, or can be set on electric wireline.
Note: It is advisable to set the packer about 10 feet above a casing collar such as having the Whipstock (the later window) in smooth casing.
•
With the permanent packer set, run in hole with Whipstock assembly # 1 as follows: 1. Casing Whipstock with its latching device assembly at bottom. 2. Starting mill shear pinned to the Whipstock.
•
S.G. Rev-00/09
3. HWDP and DP. Fill the string every 10 stands.
•
When this assembly is on top of the permanent packer, the Whipstock is latched/secured automatically onto the packer. In case of required directional control, the Whipstock is automatically oriented by means of the aligning key which is in the permanent packer, prior to being latched / secured. DO NOT ROTATE THE PIPE in any attempt to help the alignment.
•
The shear pin connecting the nose of the "starting mill" is then sheared-off by applying weight (normally 12,000 lbs).
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•
Cutting the window is made by normal rotation of the mill and slacking-off the string at a rate of one inch every 15 minutes over a distance of 2 to 3 feet (observe the RT torque carefully). The tapered shape of the "starting mill" by "sliding down the slope of the Whipstock, is pushing the cutting edge of the mill against the casing wall. Cutting will progress until the bottom nose of the starting mill touches the wall of the casing. The string is pulled out when the starting mill begins to take weight. Note: A magnet should be installed in the mud ditch such as to collect steel cuttings and evaluate the volume of casing wall cut-off. Check also for cement and formation cuttings.
•
The BHA # 2 to be as follows: 1. Diamond mill. 2. Watermelon mill. 3. 15 joints of HWDP.
Note: The reason for the 5" HWDP is because a flexible BHA is required.
•
At the top of the Whipstock, start reaming at approximately 90 RPM. Ream the "starting cut" made previously maintaining smooth cutting and acceptable Rotary torque. When the torque has disappeared the diamond mill starts to cut its own window. Increase RPM to 130 and adjust WOB for smooth torque until 10 to 15 feet of formation is drilled. POOH.
•
Run in hole the following reaming assembly # 3: 1. Taper mill 2. String mill. 3. Watermelon mill. 4. Normal size DCs (use non-mag in case of directional control).
S.G. Rev-00/09
•
Continue drilling until 5° inclination is obtained or 5 to 10 feet departure from the old hole is obtained, whichever comes first, and POOH.
•
RIH building-up assembly consisting of Rock bit, N.B. stabilizer, and DC's.
•
Drill 70-100 ft. Take survey and if 5° inclination is achieved POH, otherwise drill more to get 5° inclination or + 10 ft departure from old hole. POOH.
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2.3
•
RIH with drop off assembly consisting of rock bit and string stab at 60 ft above bit and resume normal drilling operation.
•
In case of azimuth control, remember that magnetic interferences of the string of casing (and the fish) will require the use of the single shot gyro surveying instrument until approximately 40 feet distance is reached.
Sidetracking in casing with Single-Trip Whipstock The single-trip whipstock is hydraulically set in the casing, eliminating the need for a false bottom. This system enables setting, orienting the whipstock, detach the milling assembly, mill a full-size window, and drill a pilot hole all in a single trip.
2.3.1 Milling fluids
•
Utilize the mud which will be used to drill the next hole section. The fluid properties planned for the next section are usually adequate for hole cleaning during milling.
•
Consider the fracture gradient at the previous shoe if there is a risk of milling into an un-cemented annulus.
2.3.2 Wellbore preparation
S.G. Rev-00/09
•
Make a round trip with scraper and full gauge, rough outer diameter string mill to ensure that the wellbore is clean/free of debris.
•
In deviated holes or in special drift casing strings, scraper plus two full gauge mills spaced out with short DC is recommended.
•
Pump viscous pill and work scraper at the whipstock setting depth. If there is a lot of cement to be drilled, consider using adequate scraper. Check the string mill gauge when out of the hole, if there is evidence of junk in hole when this assembly is pulled, an additional cleanout run including junk basket is recommended.
•
Be sure that casing across whipstock’s setting depth is in good cemented and mechanical conditions (only 20 to 30 feet of good casing are required to allow a safe setting of the Whipstock).
•
The whipstock should be positioned so that the window is milled through the wall of the casing joint, and not across a casing collar. This milling practice will help avoid the possibility of parting the casing string if the cement behind the casing is poorly set and unconsolidated, if a CBL is available, avoid centralizers.
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•
The optimum formation behind the casing should be selected for better chances of success.
•
There is no need for a special distance between the top of fish (if any) and the whipstock setting depth. However all precautions should be made to get as far from the original hole as possible.
2.3.3 Bottom hole assembly
•
Lead mill.
•
Full gauge string mill.
•
One joint of drill pipe
•
Orienting sub or MWD.
•
Drill collar or HWDP.
•
Concave.
•
Hydraulic Anchor and Hydraulic Packer (packer is optional).
2.3.4 Running in hole
S.G. Rev-00/09
•
The whipstock engineer must be on rig floor while making up and running the system in hole.
•
Make certain that the hole is full of fluid prior to tripping.
•
Slowly lower the system into the hole ensuring that whipstock and milling BHA do not hang up on the Blowout Preventer or casing top.
•
Run in hole slowly. The maximum speed for running in the hole with the system is two minutes per stand.
•
Fill the string every 10 stands while RIH.
•
Use back-up tongs properly while making up the drillstring. If the drillstring turns sharply below the drill floor, this can fatigue the shear screws resulting in premature shear between the milling BHA and the whipstock.
•
Set down and pick up easy on the slips, any jolting pipe movement will fatigue the shear attachment bolt.
•
Should circulation need to be established at any time while running in hole, monitor the flow rate as not to accidentally set the Whipstock (whipstock engineer must be on rig floor)
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•
Run in hole slowly until approximately 30 feet of setting depth.
•
Move the drillstring up and down 5 to 20 feet, recording accurate string weights and removing torque from the drillstring.
•
Place the Whipstock at setting depth.
2.3.5 Orienting
•
The Directional Driller should be on rig floor during the entire process.
•
Determine orientation of the whipstock by wireline conveyed Gyro or flowing through the MWD.
•
The whipstock may be oriented using MWD in inclined holes (greater than ~ 5 degrees), or using a surface readout gyro in near-vertical holes.
2.3.6 Setting the whipstock
•
The whipstock engineer must be on rig floor during the entire process.
•
Slowly increase the pump flow rate and set whipstock as by manufacturer’s instructions.
•
Turn off the pumps and slack off the drillstring. The drillstring weight will decrease indicating the whipstock is set.
•
With the whipstock set, move the drillstring down applying WOB to shear the milling BHA from the whipstock. Weight in excess of the shear value may be required to shear the attachment bolt in deviated wells.
•
Once the milling BHA shears from the whipstock, apply an additional weight (~15,000 lbs) above the recorded shear WOB to ensure the whipstock is set.
•
Lift the drillstring 10 feet above the top of the whipstock in preparation for milling.
2.3.7 Milling procedures
S.G. Rev-00/09
•
Do not commence milling while displacing to a different mud system. The variations in standpipe pressure can make it difficult to monitor and control the milling operation.
•
Install ditch magnets (two to four magnets) to catch metal junk.
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S.G. Rev-00/09
•
Begin rotating the string slowly; increase the RPM to appropriate milling speed (50 to 70 RPM).
•
Reciprocate the string up and down, recording the pick-up and slack-off string weights, free rotary torque, and pump pressure.
•
Lower the string to commence milling. Once the Lead Mill reaches the top of the whipstock, there will be an immediate increase in rotary torque.
•
Begin milling with approximately 1,000 Ibs WOB down on the Lead Mill for the first 6 inches of milling depth.
•
Slowly bring the RPM up to the recommended range.
•
Slowly increase the WOB until a rate of penetration of one to six feet per hour is achieved. After the Lead Mill passes the bottom of the concave, a significant increase in ROP should be observed.
•
Continue to mill with enough weight to maintain a minimum ROP of 1 ft/hr. The optimum ROP from this point on is 2 to 4 ft per hour.
•
Check the fluid returns frequently for the presence of cement and/or formation.
•
When the casing window has been milled and the Lead Mill is out into the formation, increase the WOB as necessary to drill the formation. The optimum milling distance is to mill formation beyond the end of the concave.
•
Make sure that the string mill has completely passed through the window.
•
Once the total milling depth has been reached, the WOB has been milled off, and "bottoms up" circulation has been achieved, reduce the pump flow, RPM, and start reaming the window.
•
Continue reaming up and down through window, recording torque and string weights, until torque does not increase while reaming.
•
Pump Hi-Vis pill as required and circulate wellbore clean.
•
Drill 1 – 1.5 ft extra rat hole to ensure bottom is free of junk.
•
Stop pumps and rotary and slowly slide the BHA through the milled window; there should be no decrease in string weight.
•
Pull the Milling BHA out of the hole and gauge mills to verify window’s condition is acceptable.
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2.3.8 Drilling ahead
S.G. Rev-00/09
•
Run in hole with drilling bottom hole assembly.
•
The driller must always be aware of whipstock top and bottom depths and orientation. Post this information clearly.
•
Always orient the bit towards window opening when tripping in/out with directional BHA. Enter the window slowly, watching weight indicator.
•
DO NOT ROTATE BIT (particularly PDC bits) OR STABILIZERS ACROSS THE WHIPSTOCK FACE. Know the positions of these items with respect to the whipstock at all times.
•
DO NOT CIRCULATE THROUGH MOTOR WHEN BIT IS ACROSS THE CASING WINDOW.
•
Be particularly aware of items in the drill string above the bottom hole assembly (especially reamers), which are sometimes forgotten. None of these items should be rotated over the whipstock, and caution should be used when POOH these items through the window.
•
The Directional Driller must be on site every time these items are tripped through the window.
•
If the bit could not pass easily through the window, run in hole with dressing assembly.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 6 REMEDIAL CEMENTATIONS Remedial cementation during workover operations may be required in the following cases.
•
Repair primary cement job.
•
Plug back old/watered out holes.
•
Well abandonment.
•
Directional requirements/sidetracking.
•
Casing leaks.
•
Abandon non productive or depleted zones.
•
Seal off lost circulation zones.
The remedial cementing techniques typically used during workover operations are:
•
Balance Plug cementing.
•
Cement through EZSV.
•
Cementing through coiled tubing.
•
Macaroni Tube.
The matrix below presents the different technique that might be used for each application: Table 2- 6: Techniques used for different remedial applications
Technique Purpose
Balanced Plug
Squeeze with EZSV
Coiled Tubing
Macaroni Tube
Repair primary cement job-channels
X
√
X
X
Cement Top Job
X
X
X
√
Well abandonment
√
√
√
X
For directional requirements and sidetracking
√
X
X
X
Casing leaks.
√
√
X
X
Abandon non productive or depleted zones
√
√
√
X
Selective Shut-Off for Water Injection
X
√
√
X
Shut-off fluid migration into production zone.
X
√
√
X
Plug back existing perforations
√
√
√
X
S.G. Rev-00/09
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1.
Balanced Cement Plugs 1.1
S.G. Rev-00/09
General Notes
•
Plugs are set by “spotting” cement through tubing tail pipe with a ported side outlet sub on bottom. Length of tubing tail pipe should be equal to the plug length plus 30 %.
•
2 ⅞" tubing is used in slim holes of 8½” diameter or smaller. 3½” tubing is used in larger holes. Coupling OD’s of the tubing must be minimized.
•
If no tubing is available, 3½” drillpipe may be considered. The tail length should be equal to the plug length plus 30%.
•
Caution should be taken not to plug the cementing string while RIH.
•
The minimum thickening time should be the job time plus 1-2 hours safety margin.
•
Cement slurry should be mixed in a batch mixer. If cement is mixed using a re-circulating jet mixer, dump the slurry until the correct slurry density is achieved.
•
If a hole is badly washed out, it is better to set 2 short plugs over the washed-out interval rather than to try to cover the interval in one go with a large amount of cement. Gauge hole sections are preferred for cement plugs.
•
When setting abandonment plugs in potential loss zones it is better to set a cement plug in two stages, i.e. first a small one, which acts as a carrier for the next plug.
•
Balance Plug length should not exceed 700 ft.
•
Pull the pipe back to at least 500 ft above theoretical top of plug before commencing reverse circulation. This does not apply if a series of plugs are to be set continuously. O
Always calculate the loss in hydrostatic pressure before using water or base oil ahead of a cement plug. Consider gauge hole for calculations.
O
Never stab the cement string back into the plug following displacement.
O
Always use spacers ahead and behind the slurry. Use spacer volumes to give at least 100 ft. linear height in the tubing and annulus.
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1.2
S.G. Rev-00/09
Spotting Procedure
•
Make up and run cement string to the bottom of the plug depth and circulate hole clean.
•
Pump a low viscous pill, of the same weight as the mud.
•
Pump weighted spacer ahead. The quantity of the spacer depends on hole size.
•
Pump the mixed cement slurry.
•
Pump sufficient spacer behind the cement to balance pre-flush.
•
Displace with mud to balanced position where level of cement slurry and spacer inside tubing are the same as annulus. O
Do not over displace.
O
Do not reciprocate the pipe during cement displacement.
•
Pull back slowly (20 ft/minute) to at least 500 ft above theoretical top of the plug. Pulled out stands shall be hammered, cleaned and drifted after lay-down on racks.
•
Reverse circulate 2 times string capacity to clean the cement string (except if tail pipe bottom is below Nahr Umr), Drop two 6” Foam balls (with minimum 15 bbls of mud spacing) and circulate through string with maximum allowable pumping rate for 1-1/2 string volume.
•
In case if tail pipe bottom is below Nahr Umr, POOH above top of cement (at least 500 ft), drop two 6” Foam balls (with minimum 15 bbls of mud spacing) and circulate through string with maximum allowable pumping rate for two cycles. O
Reverse circulation is not permitted across Nahr Umr to avoid string plugging by shale cuttings/cavings.
O
Reverse circulation may induce losses, or cause differential sticking of the cementing string.
O
6” foam ball is applicable for all sizes of Drill pipes or Tubing between 2-7/8” to 5-7/8”.
•
Close pipe ram and squeeze cement at a maximum of 0.65 psi/ft, hold pressure for 6 hours. This step is applicable only if mentioned in the program.
•
Bleed off (if there is any pressure) & POOH. During POOH Hammer every stand. Lay down, clean & drift if any joint is not cleaned by foam balls. Inspect, clean & drift all the x-overs used in cement string.
•
Wait on Cement as required.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
1.3
Balanced Cement Plugs for Kick-off Following are general notes for setting balanced cement plugs for kick-off purpose;
1.4
•
In soft formation e.g. Zone A or B, use 125 pcf normal G cement as kickoff plug.
•
For kick-off plugs in hard or medium hard formations, Sand cement slurry with 142 pcf weight or Metallic ribbon reinforced slurry (e.g. Durastone) with 147 pcf weight shall be used.
•
Cement slurry should be mixed properly in the Batch mixer to get the designed uniform slurry weight.
•
In all types of kick-off plugs, a weighted spacer of 90 pcf shall be used ahead and after of cement and volume shall be calculated as per balance plug calculations.
•
If the plug length is more than 600 ft, cement slurry of 125 pcf shall be spotted below it as a carrier / foundation for the kick off plug.
•
The cement string to be circulated clean by using 2 foam balls spaced by mud as mentioned in clause 1.2 above.
•
For kick-off plugs, cement shall be tagged and dressed as per program.
Balanced Cement Plug in Deviated Wellbore A successful cement plugs in a deviated (30º-75º) wellbore require the following conditions to be met.
S.G. Rev-00/09
•
Reduce the density differential between the drilling fluid and cement.
•
Increase the yield point or gel strength of the drilling fluid below the cement plug.
•
Place high viscous pill or stable reactive spacer pill between the cement and the drilling fluid.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
2.
Squeeze Cementing 2.1
Cementing through EZSV Cement squeeze through retainer may be used when circulating cement behind casing, between two sets of perforations is required.
2.1.1 Cement Squeeze through retainer for high injectivity.
•
Rig up W/L BOP on 7" shooting nipple and test to 1000 psi.
•
Set EZ-Drill cement retainer between the two sets of perforations with W/L (avoid setting cement retainer against casing collar or the final production packer setting depth).
•
RIH EZ stinger with 1000 ft. of 2 ⅞" tubing on Drill pipe.
•
Sting into EZ cement retainer. Check circulation through retainer, by repeating volumetric communication test for 15 minutes each way. If communication is not established as before, inform town.
•
Keep stinger in retainer if injection rate is more than 2 BPM at 0.65 psi/ft or 1500 psi surface pressure.
•
R/U circulating head and test cement lines to 3000 psi for 15 minutes.
•
Mix and pump the designed cement volume and additives as per cement recipe.
•
Circulate ½ volume of cement through retainer at maximum 0.65 psi/ft. (do not squeeze for more than 15 minutes if unable to circulate the above cement volume).
•
Sting out and spot the rest of cement as balanced plug on top of EZ-Drill retainer. Check for losses during job.
•
POH 10 stands or to 50' below top of liner (above all perforations) whichever is the case. Reverse out at a maximum pressure of 0.65 psi/ft or 1500 psi whichever is less recording any losses. POH one more stand.
•
Close rams and squeeze cement at 0.65 psi/ft or 1500 psi whichever is less until lock up pressure is reached then increase pressure to 0.75 psi/ft. or 2000 psi whichever is less. Hold pressure for 6 hours.
Note: If lock up pressure is not achieved, release pressure, check for back flow and POH. S.G. Rev-00/09
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•
Release pressure, check and record back-flow, open rams, POH.
•
RIH with appropriate bit and two junk subs, tag top of cement, clean out to 50 ft. above top perforations.
•
After total 24 hours WOC, drill out cement, cement retainer, cement and RIH to PBTD. Circulated hole clean, POH.
Note: If cement is still soft after 24 hours, stop DOC, circulate one cycle and W.O.C. to complete 30 hours prior to clean out to PBTD.
•
Trip with bit and scraper to PBTD. Circulate hole clean and displace with new clean fluid.
•
Repeat the communication test.
2.1.2 Cement squeeze through retainer for low Injectivity Formation To be made when communication rate is established at more than 0.5 BPM and less than 2 BPM at 0.65 psi/ft or 1500 psi surface pressure.
S.G. Rev-00/09
•
Rig up W/L BOP on 7" shooting nipple and test to 1000 psi.
•
Set cement retainer.
•
RIH with stinger and 1000 ft. of 2 ⅞" tubing on DP.
•
Circulate at 10 ft. above retainer for 15 minutes. Record circulation rate and pressure. Sting into retainer and establish injection rate at 0.65 psi/ft or 1500 psi whichever is less. Record rate of injection for 15 minutes.
•
Sting out of retainer, circulate for 15 minutes.
•
R/U circulating head and test cement lines to 3000 psi.
•
Mix cement and pump down D/P the following: O
5 Bbls 15% HCL with additives (this should be done in case of iniectivity less than 0.5 BPM, otherwise acid is not necessary).
O
5 Bbls fresh water
O
Cement with additives as per cement recipe
O
5 Bbls fresh water.
O
Displace cement to 5 Bbls inside DP above the drillpipe to minimize U-tube prior to sting in (use choke manifold if required to control U-tube effect).
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3.
•
Sting into retainer, bullhead by pumping down D/P at 0.65 psi/ft. or 1500 psi whichever is less for a maximum duration of 15 minutes or 1/2 the cement volume or lock up pressure whichever comes first.
•
Increase surface pressure gradually until reaching to 0.75 psi/ft. if necessary.
•
Sting out of retainer and spot the remainder of cement as balanced plug of cement above retainer.
Cementing Through Coiled Tubing 3.1
Applications Cementing through coiled tubing has different applications as follows:
3.2
3.3
S.G. Rev-00/09
•
Isolate / Abandon perforations during multi-zone testing.
•
Shut off gas or water production zone.
•
Squeeze- off perforations riglessly prior to rig move.
•
Horizontal hole abandonment
Slurry Design Criteria
•
Low Rheological Values (PV & YP)
•
Laboratory mixing energy = Field mixing energy
•
Good slurry stability
•
Minimum gellation under static downhole condition
•
Safe thickening time (Optimized)
Placement Procedure
•
Run with suitable gauge cutter to reconfirm Coiled Tubing accessibility.
•
R/U and RIH with Coiled Tubing to the desired plug depth.
•
Circulate coiled Tubing while RIH.
•
Perform pull test every 3000 ft.
•
Slow down Coiled Tubing running speed at any restriction.
•
Circulate at the plug setting depth and at the same time observe the well stability.
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4.
•
Pump 5 bbls fresh water followed by 7 bbls weighted spacer ahead of the cement recipe.
•
Pump the designed cement slurry until 2 bbls of cement exit from the coiled tubing nozzles.
•
Pump 5 bbls weighted spacer followed by 5 bbls fresh water.
•
POOH w/ Coiled Tubing at a speed maintaining 2 bbls of cement coverage above C.T nozzle.
•
Continue displacing and spotting cement, POOH to 100 ft above the T.O.C.
•
Circulate above the top of cement.
•
Wash down to the planned T.O.C.
Squeezing Off the Aquifers Sealing off the aquifers (Dammam, UER and Simsima) with cement is normally done prior to running and cementing tie-back casing. The objective of sealing off the aquifers prior to running the tie-back casing is to protect the casing from the corrosive action of aquifer water, and to avoid the erosion resulting from the cross flow between the different aquifer perforations of Dammam, UER and Simsima.
4.1
Procedure
• •
Isolate the reservoir perforation with either cement plug or Bridge Plug.
•
Spot 500 SKS class "G" cement with a light weight cement (+ 95 pcf) as balanced plug. POH 15 stands and flush string with location water.
• •
POH another 10 stands and W.O.C 6 hours.
•
RIH bit and clean out casing down to top of liner or as specified in well programme.
•
DO NOT test the squeezed off perforations. Observe well for losses or flow.
RIH with 1000', 2 ⅞" tbg. tail pipe on 3 ½" DP to 50' below aquifer perforations.
RIH with cementing string with circulation, tag T.O.C and repeat steps above as required.
Note: If losses are more than 15 BPH, another cement plugs should be spotted as above to cure losses. S.G. Rev-00/09
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SECTION 7 SETTING INTERNAL CASING PATCH This technique could be used in some water supply wells to seal off holes in corroded surface casing to prevent sand entry to well. A corrugated pipe 1/8" thick and plated with resin was mechanically expanded and set across the corroded part of casing using special setting tool after the holes being squeezed of with cement to isolate the aquifer water from contact with the patch.
1.
2.
Well Preparation •
RIH with bit and casing scraper. Clean out casing ± 100 ft below expected leak point.
•
Circulate with 54 pcf viscofied emulsion or as specified in well Program and test casing to 500 psi. If leaking, proceeds to next step .
•
Run casing packer and locate leak in casing by selective testing at 500 psi.
•
Cure leak with ± 200 sks cement, (volume of cement will be determined based on injectivity rate). Repeat steps above.
Procedure •
Lay out and prepare the casing patch (Welder to weld sections of patch to obtain the required length).
•
Pick up setting tool, extension bar and safety joint assembly.
•
Pick up patch with tugger and strip onto extension bar.
•
Make up cone, collet, and bullnose assembly, grease liberally.
•
Lower patch into well and apply epoxy to outside of liner.
•
Make up BHA comprising of:
•
1. Casing Patch 2. Setting tool 3. Single drill pipe 4. Impact sub 5. Single drill pipe 6. Drill pipe pup joint (master joint if required) 7. Drill pipe to surface Run in hole with patch (Medium speed whilst running to depth).
S.G. Rev-00/09
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•
Pick up kelly and position patch (Taking up and down string weight).
•
Slowly pressure up drill pipe, to set patch, Tool will stroke at approximately 1000 psi. Continue to pressure to 3000 psi, to assure full stroke.
•
Bleed to zero pressure and leave bleeder open.
•
Pull tool open at string weight. When tool is open, overpull will be encountered. Continue to pull cone and collect through patch and set some. Overpull will be approximately 40 klbs to 70 klbs, dependent on the condition of the casing. Pull out of top of patch.
•
Drop bar and shear out impact sub pin.
•
Pull out, break and lay down tools.
•
Test casing to 500 psi. If OK proceed to well programme.
Important Note: Setting casing patch will result in reducing the casing inside diameter by more than 0.25 inches. (I.e. 13.3/8 csg patch will reduce the ID of 13.3/8, 68 lbs/ft from 12.415 to 12.115 so that 12.1/4 bit will not pass).
S.G. Rev-00/09
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 8 SECURING WELL WITH SHALLOW SET CASING PACKER 3.
When to Secure the Well Securing the well with kill string and casing packer hanged at shallow depth is required prior to performing the following operations.
4.
•
Repairing or changing a BOP element which would not allow shutting-in the well in case of a kick.
•
Repairing of the upper casing or tubing spool which would not allow shutting-in the well in case of a kick, even if the repair does not require any welding or torch cuttings.
•
Changing the upper casing or tubing head spool.
•
Any welding or torch cutting on the wellhead, even if the fluid in hole does not contain hydrocarbons, and the well is overbalanced with drilling fluid
•
Any urgent well suspension needs.
Minimum Barriers Requirements It is preferable to carry out the required wellhead repairs immediately after a remedial cement jobs or liner cementing job. Refer to the table bellow for the minimum barriers requirements: Table 2- 6: Techniques used for different remedial applications
Water Injectors (Except Bab Mid Dip Injectors)
Oil Wells (and Bab Mid Dip Injectors)
Gas Wells Producer, Injectors
2 Barriers
3 Barriers
3 Barriers
(1 Mechanical and 1 Hydraulic)
(2 Mechanical & 1 Hydraulic)
(2 Mechanical & 1 Hydraulic)
Cemented casing with non drilled shoe track is a Barrier that can substitute the 2 Mechanical Barriers
5.
Safety Precautions Prior to commencing welding / cutting operations after removing old tubing head spool, the following safety measures must be considered as minimum:
• S.G. Rev-00/09
Test fire fighting unit prior to the job, keep it ready during the whole job. ADM Volume-2 Drilling Operation -B
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
6.
•
Clean well cellar and cover with dry sand.
•
Displace the top 5 ft inside casing with foam, circulate through wing valves. Check for any effluents.
•
Safety officer (drilling) to confirm the cellar is free of gas prior to any welding.
•
Issue hot work permit
Securing Well Procedure This operation must be planned to be carried out during a programmed day time trip (bit change or POH / RIH open ended pipe after cement job).
•
Make up the 9 ⅝” casing packer.
•
Make up the SC-SSSV onto the top of casing packer. Ensure that the threaded joint between the seal mandrel and the upper body of the SC-SSSV is only hand tight. Check the rating of the safety plug shear pin if rated to 1500 or 3000 psi, and record same in daily report (Note that the 3.72" size SC-SSSV uses only 1700 psi shear pin).
•
Install the DP rubber wiper plug over the string to avoid dropping of foreign matter on top of the packer and RIH casing packer to approximately 300 feet below rotary table. Break circulation a few minutes. Record the string handling weight with and without circulation.
•
Set the casing packer and pressure test above the packer to 2000 psi. Slack off the total string weight of string below packer, after the pressure test.
•
The casing packer mandrel must have adequate strength to support the weight of drill pipe or tubing string. The 9 ⅝” casing tensile and burst capacity must be strong enough to withstand the addition of the string weight below the packer and the pressure test load above the packer, even if the casing is not cemented behind.
•
As the SC-SSSV is a combination of safety valve and back-off safety joint:
S.G. Rev-00/09
1.
Apply left hand rotation to close the balanced valve inside the SSC tool. At this stage the SC-SSSV being closed will retain any amount of pressure from below the packer AND ONLY 1500 or 3000 psi pressure from above because of limited shear rate capacity of the safety plug inside the SSC tool.
2.
By applying further left hand turns the string will unscrew and release from the safety joint. A total of 20 turns are required to close and unscrew the 3.72" size SC-SSSV while 22 turns are required for the 4.3/4" and 6 ⅛" SC-SSSV.
3.
Pick up one foot and pressure test the annulus above the packer to 1000 psi to ensure the SC-SSSV is closed. Spot clean viscous mud pill above
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ADCO the packer (about 25 bbls in case of 9 ⅝” DRILLING MANUAL exact backed-off string weight and POOH.
casing).
Record the
Volume-2/Chapter-2: Workover Operations
•
Proceed with the required repairs or other work to be carried out after having taking all surface safety precautions, like removing/ cleaning all hydrocarbon fluids from the cellar, issuing Hot Work Permits if welding or torch cutting, etc. are required, or proceed with well abandonment program after closing the BOP, if this is the case. Notes:
Any welding on wellhead or casing has to be done by Production Operations Division's certified welder.
O
All welds on casing must be X-rayed and approved by Production Operations Division before proceeding further with the job.
O
O
Production Operations Division must be notified 24 hours in advance if any welding on casing is required.
O
If any component of the BOP stack or the wellhead has been removed, opened, or changed, each of above element must be re-pressure tested after nippling up.
•
When the repairs are completed, or the temporary abandonment is over; RIH the same backed off string to the top of the SC-SSSV above the casing packer. Pick up the Kelly and break circulation a few minutes. Engage the mandrel inside the SC-SSSV without circulation. Use the drill pipe rubber wiper plug around the string while RIH to prevent dropping of foreign matters down the hole on top of packer. O
Apply same amount of right hand turns as in disconnecting step to reconnect and to open the balanced valve inside the SSC tool and equalize pressure on both sides of the packer.
O
Unset the casing packer and circulate bottom up to ensure the hole is safe.
Notes:
•
O
If unable to unset the casing packer because the SC-SSSV is not opened, so that the pressures above and below the packer are not equalized, pressure up the string to the shear pin capacity and pump out the safety plug then unset the packer Circulate bottoms up to ensure hole is safe.
O
When necessary to perform wireline operations through the SC-SSSV after it is re-opened, the safety plug in the bottom of the valve can be knocked out with a sinker bar, this would provide an unobstructed opening through the tool. It is also possible to pump out this plug when the valve is closed as already said in note above.
POOH casing packer to surface without rotating the string. Lay down SCSSSV and casing packer and proceed with program.
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WORKOVER OPERATIONS
Revision-0 March 2009
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Table of Contents SECTION 1 WELL BARRIERS ACCEPTANCE CRITERIA ..................................... 4 1.
Barriers Acceptance Criteria ........................................................................... 4
SECTION 2 WELL CONTROL IN WORKOVER OPERATIONS ............................ 19 1.
Introduction.................................................................................................... 19
2.
Checking Well Integrity and Installing Pressure Barriers ............................... 19
3.
Un-plugging the Well and Checking Wellhead Pressure ............................... 19
4.
Killing the Well ............................................................................................... 20
5.
Testing Wellhead ........................................................................................... 27
6.
Checking for Trapped Pressure and Bleed off Procedures ........................... 27
7.
Nippling down X-Mas Tree & Nippling up BOP ............................................. 27
SECTION 3 RECOVERING OLD COMPLETION STRINGS .................................. 29 1.
General.......................................................................................................... 29
2.
Recovering Completion - General Procedure ................................................ 29
3.
Releasing Hydraulic Packers......................................................................... 31
4.
Recovering Dual Completion ......................................................................... 36
5.
Abandoning Completion Tail and Packer(s) .................................................. 41
6.
Recovering 7" scab liner ................................................................................ 41
SECTION 4 FISHING GENERAL GUIDANCE ....................................................... 43 1.
Standard Fishing Assembly ........................................................................... 43
2.
Overshot ........................................................................................................ 43
3.
Releasing Spear ............................................................................................ 44
4.
Taper Tap / Pin Tap....................................................................................... 44
5.
Reverse Circulation Junk Basket ................................................................... 45
6.
Fishing Magnet .............................................................................................. 45
7.
Milling Tools................................................................................................... 45
8.
Hydraulically Activated Mills .......................................................................... 46
9.
Fixed Milling Tools ......................................................................................... 46
10. Special Mills................................................................................................... 47 S.G. Rev-00/09
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11. Fishing of Radio-Active Wireline Tools .......................................................... 47 SECTION 5 SIDETRACKING OPERATIONS ........................................................ 50 1.
Sidetracking in Open hole ............................................................................. 50
2.
Sidetracking Inside Casing ............................................................................ 55
SECTION 6 REMEDIAL CEMENTATIONS ............................................................ 67 1.
Balanced Cement Plugs ................................................................................ 68
2.
Squeeze Cementing ...................................................................................... 71
3.
Cementing Through Coiled Tubing ................................................................ 73
4.
Squeezing Off the Aquifers............................................................................ 74
SECTION 7 SETTING INTERNAL CASING PATCH.............................................. 75 1.
Well Preparation ............................................................................................ 75
2.
Procedure ...................................................................................................... 75
SECTION 8 SECURING WELL WITH SHALLOW SET CASING PACKER .......... 77 3.
When to Secure the Well ............................................................................... 77
4.
Minimum Barriers Requirements ................................................................... 77
5.
Safety Precautions ........................................................................................ 77
6.
Securing Well Procedure ............................................................................... 78
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SECTION 1 WELL BARRIERS ACCEPTANCE CRITERIA Well barrier acceptance criteria are technical and operational requirements that need to be fulfilled in order to qualify the well barrier for its intended use. Refer to ADM Vol-1, Chapter-1, Section-12 (Pressure Barriers) for details on Well Barrier Policy for Drilling / Workover operations.
1.
Barriers Acceptance Criteria Sheets Followings are the technical and operational requirements need to be fulfilled during drilling / workover operations in order to qualify the well barrier for its intended use.
1.1
Fluid Column
Features
Acceptance Criteria
Description Function
This is the fluid in the well bore The purpose of the completion fluid column as a barrier / barrier element is to exert a hydrostatic pressure in the well bore that will prevent influx of formation fluid.
Design, Construction and Selection
• The hydrostatic pressure shall at all times be equal to the estimated or measured pore/reservoir pressure, plus a defined safety margin (as mentioned later in Sec-10, Clause-1).
• Critical fluid properties and specific actions shall be described prior to start any operation.
• The density shall be stable within specified tolerances under down hole conditions for a specified period of time when no circulation is performed.
• The hydrostatic pressure should not exceed the formation fracture pressure in the open hole including a safety margin
• Changes in well bore pressure caused by tripping (surge and swab) and Initial Test and Verification Use
circulation of fluid (ECD) should be estimated and included in the above safety margins. Stable fluid level shall be verified. Critical fluid properties, including density shall be within specifications.
• It shall at all times be possible to maintain the fluid level in the well through circulation or by filling
• Acceptable static and dynamic loss rates of fluid to the formation shall be pre-defined (e.g. 20 bbls/hr for producers and 50 bbls/hr for injectors is acceptable for tripping) • There should be sufficient fluid materials, including contingency materials available on the location to maintain the fluid barrier with the minimum acceptable density.
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Features Monitoring
Acceptance Criteria • Fluid level in the well and active pits shall be monitored continuously. • Fluid return rate from the well shall be monitored continuously. • Flow checks should be performed upon indications of increased return rate, increased volume in surface pits, increased gas content, flow on connections or at specified regular intervals. The flow check should last for 15 min. Exploration wells: All flow checks should last for 30 min. • Measurement of fluid density (in/out) during circulation shall be performed regularly. • Measurement of critical fluid properties shall be performed every 1/2 circulating hour and compared with specified properties. • Parameters required for killing of the well must be defined and recorded.
Impairment
• Flow of formation fluids. • Unable to monitor fluid level. • Unable to maintain fluid level or required volume. Table 1.1: Acceptance & verification criteria for Fluid column as a barrier
1.2
Casing
Features
Acceptance Criteria
Description
• This element consists of production casing/liner
Function
The purpose of casing/liner is to provide a physical obstruction to uncontrolled flow of formation fluid or injected fluid between the bore and the back-side of the casing
Design, construction and selection
• Casing-/liner strings, including connections shall be designed to withstand all pressures and loads that can be expected during the lifetime of the well including design factors. • Minimum acceptable design factors shall be defined for each load type. Estimated effects of temperature, corrosion and wear shall be included in the design factors.
• Dimensioning load cases with regards to burst, collapse and tension / compression shall be defined and documented.
• Casing design can be based on deterministic, probabilistic or other acceptable models. Initial test and verification Use
S.G. Rev-00/09
• Casing/liner shall be leak tested to maximum anticipated differential pressure. • Casing/liner that has been drilled through after initial leak test shall be retested during completion activities. Casing/liner should be stored and handled to prevent damage to pipe body and connections prior to installation.
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Features Monitoring
Acceptance Criteria • The A-annulus shall be continuously monitored for pressure anomalies. B-annulus should be monitored if applicable based on well completion and the type of well. • If wear conditions exceed the assumptions from the casing-/liner design, indirect or direct wear assessment should be applied (e.g. collection of metal shavings by use of ditch magnets and wear logs).
Impairment
• Leaking casing/liner. • Unable to leak test. • Unable to monitor annulus pressure. • Unable to monitor or control/assess casing wear. Table 1.2: Acceptance & verification criteria for casing as a barrier
1.3
DRILLING BOP
Features Description Function Design, construction and selection
Acceptance Criterea The element consists of drilling BOP with kill/choke line valves. The function of the BOP is to provide capabilities to close in and seal the well bore with or without tools/equipment through the BOP.
• The drilling BOP shall be constructed in accordance with ADM – volume1, Chapter -3.
• The BOP WP shall exceed the maximum well design pressure including a margin for killing operations.
• It shall be documented that the shear/seal ram can shear the drill pipe, dual string tubing, wireline, coiled tubing or other specified tools, and seal the well bore thereafter. If this can not be documented by the manufacturer, a qualification test shall be performed and documented. • When using tapered string there should be pipe rams or variable ram to fit each pipe size. Initial test & verification Use
All BOP equipment Function and pressure tested frequently as per policy and documented. The drilling BOP elements shall be activated as described in the well control action procedures.
Impairment
• Failure of annular / Shear ram. (should be repaired immediately) • Failure of Pipe ram (repair immediately if no back up for that pipe size otherwise at earliest convenient time)
• Failure of kill/choke line valves. (If both valves in series failed then repair immediately otherwise after setting casing) Table 1.3: Acceptance & verification criteria for BOP equipment as a barrier
1.4
Wellhead
Features Description
S.G. Rev-00/09
Acceptance criteria The element consists of the wellhead body with annulus access ports and valves, seals and casing/tubing hangers with seal assemblies.
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Features Function
Acceptance criteria Its function is to provide mechanical support for the suspending casing and tubing string and production tree and to prevent flow from the bore and annuli to formation or the environment.
• The Working pressure for each section of the wellhead shall exceed the maximum anticipated well shut in pressure the section can become exposed Design, to plus a defined safety factor. construction and selection • There shall be access ports to all annuli to facilitate monitoring of annuli pressures and injection/bleed-off of fluids. Initial test and verification Use
The wellhead body (or bodies and seals), annulus ports with valves and the casing or tubing seal assemblies shall be leak tested to maximum expected shut in pressure for the specific hole section or operation. A wear bushing should be installed in the wellhead whenever movement of tools/work-strings can inflict damage to seal areas.
• Annuli wing valves shall be pressure and function tested frequently. • Pressures in accessible annuli shall be monitored and recorded continuously. Monitoring
• Annulus valve(s) should normally be closed and should only be opened for the purpose of adjusting the annulus pressure
• Movements in the wellhead during well testing (shut-in/start-up) should be observed and compared to design values. Impairment
• Leaking seals or valves. • Unable to leak test. • Unable to monitor accessible annuli. Table 1.4: Acceptance & verification criteria for Wellhead as a barrier
1.5
Deep Set Tubing Plug
Features
Acceptance criteria
Description
This element consists of a equalizing body with a locking or anchoring device and a seal between the bore of the tubing and the body of the plug.
Function
Its purpose is to provide a temporary seal in the bore to prevent flow from the reservoir and U-tubing.
Design, construction and selection
It shall comply with same requirements that apply to packers.
• It shall by preference be leak tested to the maximum expected differential Initial test and verification Use S.G. Rev-00/09
pressure in the direction of flow.
• Alternatively, it shall be inflow tested or leak tested in the opposite direction to the maximum expected differential pressure, providing that ability to seal both directions can be documented. It shall be set at a depth, which allows balancing of the pressure under the plug with a hydrostatic fluid column above the plug.
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Features
Acceptance criteria
Monitoring
The tubing pressure above the plug should be monitored regularly.
Impairment
Inability to pass pressure testing or monitoring requirements. Table 1.5: Acceptance & verification criteria for downhole plugs as a barrier
1.6
Surface Controlled Sub-Surface Safety Valve
Features Description Function Design, construction and selection
Initial test and verification Monitoring
Impairment
Acceptance Criterea This element consists of a tubular body with a close/open mechanism that seals off the tubing bore. Its purpose is to prevent flow of hydrocarbons or fluid up the tubing.
• It shall be -
surface controlled, hydraulically operated, fail-safe closed, flapper type. • It should be placed a minimum of five joints below surface It shall be tested with both low and high differential pressure in the direction of flow. The low pressure test shall be maximum 1000 psi The valve shall be leak tested at specified regular intervals as follows: • test duration shall be 30 min every six months • Acceptance of downhole safety valve leakage tests shall meet API RP 14B requirements being: - 900 scf/hr for gas, - 6.3 gal/hr for liquid. • If the leak rate exceed the accept criteria, the test can be attempted three times to verify the valve status. If the acceptance criteria is still not meet, further investigation and remedial action shall be undertaken, consider involving the drilling/well operations department. Failure to pass the regular tests and maximum allowable leak rate. Table 1.6: Acceptance & verification criteria for SCSSSV as a barrier
1.7
Wireline lubricator
Features
Acceptance criteria
Description
This element consists of a body with a lubricator connection in both ends.
Function
The function is to provide lubricate space for wireline BHA/tools over the closing device when run into and out of well.
Design, construction and selection
S.G. Rev-00/09
• The wire line Lubricator shall be constructed in accordance with API Spec 16A and API RP 5C7
• Pressure rating shall comply with the maximum expected wellhead pressure.
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Features
Acceptance criteria
Initial test and verification
• Function test after installation. • Low- and high pressure leak test after initial installation. • Leak test to maximum expected WHP on following runs.
Use
Length of lubricators shall at all time allow space for BHA above well closing device including items pulled from well.
Monitoring
Visual periodic inspection.
Impairment
Leak through body or connections. Table 1.7: Acceptance & verification criteria for Wireline lubricator as a barrier
1.8
Wireline BOP
Features Description
Function
Acceptance criteria This element consists of a BOP body with rams and riser/lubricator connections • The function of the wire line BOP is to prevent flow from the wellbore in case leakage in stuffing box / grease head or lubricator system above the BOP. • The element is a back-up element to the stuffing box / grease head in the primary barrier.
• The wire line BOP shall be constructed in accordance with ADCO standards
• The BOP shall exceed the maximum well design pressure including a margin for killing operations. Design, • The cable ram shall be able to provide a seal on the selected cable size. construction and selection • For slick line operations in live wells a minimum of one cable ram shall be installed. • For braided line operations in live wells a minimum of two cable rams shall be installed, with the lower ram capable of holding pressure from above. A system for pumping grease between rams shall be included.
Use
• • • •
Monitoring
• Periodic visual inspection for external leaks. • Periodic leak-and functional test, minimum each 14 days when in
Impairment
• Leak in any of the elements, body or connections. • Leak in hydraulic operating system. • Unable to operate or malfunction.
Initial test and verification
Function test after installation. Low- and high pressure leak test after initial installation. Leak test to maximum expected WHP on following runs. The wire line cable rams shall be activated as described in the well control action procedures (contingency procedures).
operation.
Table 1.8: Acceptance & verification criteria for Wireline BOP as a barrier
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1.9
Xmas Tree
Features Description
Acceptance Criteria This element consists of a housing with bores that are fitted with swab, master valve, kill and flow wing valves. Its function is to;
• Provide a flow conduit for hydrocarbons from the tubing into the surface Function
lines with the ability to stop the flow by closing the flow valve and/or the master valve. • Provide monitoring and pressure adjustment.
• Provide vertical tool access through the swab valve. • Provide an access point where kill fluid can be pumped into the tubing. 1. The X-mas tree shall be equipped with; • One master valve and one wing valve in the main flow direction of the well. • If the production tree has side outlets, these shall be equipped with Design, automatic fail-safe valves. construction • One manual swab valve for each bore at a level above any side and selection outlets. • Isolation valves on downhole control lines which penetrates the production tree block. 2. All connections, block etc. that can be exposed to the hydrocarbons shall be fire-resistant. Initial test and verification
• The valves shall be tested with both low and high differential pressure in
Use
• Beware of equalization during opening and closing of valves.
Monitoring
Impairment
the direction of flow. The low-pressure test shall be 500 psi.
• It shall be tested as per API 6A at manufacturing site.
The valves acting as barriers in the xmas tree shall be tested at regular intervals as follows: • Test duration shall be 15 mins. • Monthly, until three consecutive qualified tests have been performed, thereafter • Every three months, until three consecutive qualified tests have been performed, thereafter • Every six months. If the leak rate can not be measured directly, indirect measurement by pressure monitoring of an enclosed volume downstream of the valve shall be performed. Failure to pass the regular test. During rig move due to extra risk involved of hitting / dropping objects Table 1.9: Acceptance & verification criteria for Xmas tree valves as a barrier
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1.10 Completion String Component Features
Acceptance criteria
Description
Function
Design, Construction and selection
Initial test and verification
These elements consist of a housing with a bore. The element may have a side mounted feature or a valve providing communication between tubing and annulus. Its purpose may be to provide support to the functionality of the completion, i.e. gas-lift or side pocket mandrels with valves or dummies, nipple profiles, gauge carriers, Flow coupling etc. 1. The components (pipe and threads) shall be gas tight. 2. Minimum acceptable design factors shall be defined. Estimated effects of temperature, corrosion, wear; fatigue and buckling shall be included in the design factors. 3. The component should be designed/selected with respect to • Tensile, compression and torsional load exposure. • OD clearance and fishing restrictions. • Tubing (and annular) flow rates, also including erosion effects. • Metallurgical composition in relation to exposure to formation or injection fluid. • Odd shaped assemblies in casting material shall be subject to finite element analysis. • Strength reduction due to temperatures effects. 4. For gas lift valves to qualify as a barrier there shall be a qualification test demonstrating the valves ability to be gas tight over number of cycles. The valve shall be subject to frequent testing with acceptable results similar to testing of SCSSSVs Pressure testing to Maximum Expected Temperature & Pressure.
Monitoring
Running of intervention tools shall not accidentally shift a functionality of the tool. Pressure integrity is monitored by independence of the annulus pressure.
Impairment
Inability to maintain a pressure seal.
Use
Table 1.10: Acceptance & verification criteria Completion string components as a barrier
1.11 Completion String Features
Acceptance criteria
Description
This element consists of tubular pipe.
Function
The purpose of the completion string as barrier element is to provide a conduit for formation fluid from the reservoir to surface or vice versa.
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Features
Design, construction and selection
Acceptance criteria 1. All components in the completion string (pipe/housings and threads) shall have gas tight connections, unless the well is used for water injectors, disposal, source water production, or mud/cuttings/liquid disposal. 2. Dimensioning load cases shall be defined and documented. 3. The weakest point(s) in the string shall be identified. 4. Minimum acceptable design factors shall be defined. Estimated effects of temperature, corrosion, wear; fatigue and buckling shall be included in the design factors. 5. The tubing should be selected with respect to • Tensile, compression and torsional load exposure. • Tool joint clearance and fishing restrictions. • Tubing and annular flow rates. • Abrasive formations. • Buckling resistance. • Metallurgical composition in relation to exposure to formation or injection fluid.
Initial test and Pressure testing to Maximum Expected Temperature & Pressure (METP). verification Use
Stab-in safety valve and one way check valve for all type of connections exposed at the drill floor shall be readily available.
Monitoring
Pressure integrity is monitored by independence of the annulus pressure.
Impairment
Leak to or from the annulus. Table 1.11: Acceptance & verification criteria for completion string as a barrier
1.12 Mechanical Tubular Plugs Features Description Function
Design, construction and selection
S.G. Rev-00/09
Acceptance criteria This is a mechanical plug set anywhere inside steel conduits (casing/tubular). The purpose of the element (plug) is to prevent flow of formation fluids and resist pressure from above or below, inside tubulars. 1. The plug shall be designed for the highest differential pressure and highest downhole temperature expected. Installation and test loads shall also be considered. 2. Down hole fluids and conditions (temperature, H2S, CO2, etc.)shall be considered in estimating the life time of the plug. 3. The plug shall be designed such that pressure can be equalized across the plug, if removed mechanically or by drilling out. 4. The plug is not accepted as a barrier element alone in permanent plugging of wells or branches of wells, where design integrity in an eternal perspective is required. 5. To ensure the barrier integrity in using the plug, it shall only be installed in a tubular section of the well, which is cemented, or supported by sufficient wall thickness to withstand radial loads from the plug.
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Features
Acceptance criteria
1. If possible the plug shall be inflow tested (from below), else it shall be pressure tested from above. Initial test and 2. Test pressure shall be minimum ~1000 psi above measured formation strength below casing/ potential leak path, or minimum ~500 psi for verification surface casing. Test pressure shall not exceed casing pressure test, which ever is lower. Inadvertent release of the plug by mechanical motion/ impact shall not be possible.
Use Monitoring Impairmen
Pressure integrity shall be monitored through recording of the pressure above the plug. Inability to maintain a pressure seal.
Table 1.12: Acceptance & verification criteria for Mechanical tubular plugs as a barrier
1.13 Tubing Hanger Features
Acceptance criteria
Description
This element consists of body, seals and a bore which may have a tubing hanger plug profile.
Function
Its function is to • support the weight of the tubing, • prevent flow from the bore and to the annulus, • provide a seal in annulus space between itself and the wellhead, • provide a stab-in connection point for bore communication with the production tree. • provide a profile to receive a BPV or plug to be used for nippling down the BOP and nippling up the production tree.
Design, Construction and Selection
Fire resistant seals should be used.
Initial Test and Verification Use Monitoring Impairment
• The primary seal shall be tested in the flow direction. • The hanger seal can be tested against the flow direction. • If only single seals are used in the tubing hanger, annulus is to be tested. In the case of double seal, an in-between seal test shall be performed. None. Continuous monitoring of annulus pressure. Leak past seals.
Table 1.13: Acceptance & verification criteria for Tubing hanger seal as annulus barrier
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1.14 Tubing Hanger Plug Features
Acceptance criteria
Description
This element consists of an equalising plug with a locking device and a seal between the bore of the tubing hanger and the body of the plug.
Function
Its function is to provide a pressure barrier in the bore through the tubing hanger.
Design, construction and selection Initial test and verification Monitoring
• Fire resistant seals should be used. • It shall only be classified as a barrier element during BOP or x-tree disconnect, providing the plug (and prong) does not extend up above the tubing hanger body. The tubing hanger plug shall be tested in the flow direction. Regular monitoring of pressure above plug or by visual observation.
Impairment
Non-compliance with above mentioned requirements. Table 1.14: Acceptance & verification criteria for Tubing hanger plug as a barrier
1.15 Production Packer Features Description
Acceptance criteria This is element consists of a body with an anchoring mechanism to the casing/liner, and an annular sealing element which is to be activated. Its purpose is to provide
• a seal between the completion string and the casing/liner, to Function
prevent communication between the formation and the A-annulus above the production packer.
• prevent flow from the inside of the body element located above the packer element to the A-annulus(tubing to production casing). 1. The packer shall be set (meaning that it shall not release by up or downward forces), with ability to sustain all known loads. 2. The seal element shall withstand Maximum Expected Differential Pressure, which should be based on the highest of; Design,
• pressure testing of tubing hanger seals,
construction
• reservoir-, formation fracture- or injection pressures less hydrostatic pressure of fluid in annulus above the packer,
and selection
• shut-in tubing pressure plus hydrostatic pressure of fluid in • annulus above the packer less reservoir pressure, • evacuated tubing with pressure in annulus. 3. It shall be qualification tested in accordance with recognized standards, which shall be conducted in unsupported, non-cemented casing.
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Features
Acceptance criteria • It shall by preference be leak tested to the maximum expected differential
pressure in the direction of flow. Initial test & verification • Alternatively, it shall be inflow tested or leak tested in the opposite direction to the maximum expected differential pressure, providing that ability to seal both directions can be documented. Use
Running of intervention tools shall not impair its ability to seal nor inadvertedly cause it to be released.
Monitoring
Sealing performance shall be monitored through continuous recording of the annulus pressure measured at wellhead level.
Impairment
Inability to maintain a pressure seal. Table 1.15: Acceptence & verfication criteria for Production packer as a barrier
1.16 Liner Top Packer Features Description
Function
Design, construction and selection
Initial test and verification Use Monitoring Impairment
Acceptance criteria This is a mechanical plug, consisting of a tubular body with an external seal element, set in the liner lap between casing and liner. Its purpose is to provide a hydraulic seal in the annulus between the casing and liner, to prevent flow of formation fluids, and resist pressures from above or below. 1. The packer shall be designed for the highest differential pressure and highest downhole temperature expected during installation, acceptance testing and throughout its service life. Other down hole conditions, such as formation fluids, H2S, CO2,etc. shall also be considered in estimating the lifetime of the packer. 2. The risk of sealing failure due to variable downhole temperatures/cyclic loading shall be evaluated. 3. It shall be able to seal in oval, worn or scored casing. 4. It shall not need the support of cement in the liner annulus to seal. 5. It shall be designed to avoid prematurely setting and allow rotation before set. It shall be pressure tested from above and inflow tested, if practicably possible. The pressure shall; (a) be minimum ~1000 psi above measured formation strength below casing/ potential leak path, (b) not exceed casing pressure test which ever is lower. It is not accepted as a barrier element in permanently abandoned wells or well bores. None Inability to maintain a pressure seal. Table 1.16: Acceptence & verfication criteria for liner top packer
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1.17 Casing Cement Features
Acceptance criteria
Description
This element consists of cement in solid state located in the annulus between the casing/liner and the formation.
Function
The purpose of the element is to provide a continuous, permanent and impermeable hydraulic seal along hole in the casing annulus or between casing strings, to prevent flow of formation fluids, resist pressures from above or below, and support casing or liner strings structurally. 1.
A design and installation specification (cementing program) shall be issued for each primary casing cementing job.
2.
The in-situ compressive strength of the cement shall be higher than the estimated formation strength of the cemented formation. 3. Cement slurries that will be exposed to permeable and abnormally pressured hydrocarbon bearing zones should be designed to prevent gas migration, when the cement sets. 4.
The cement placement technique applied should ensure a job that meets requirements whilst at the same time imposing minimum overbalance on weak formations. ECD and the risk of lost returns during cementing shall be assessed and mitigated.
5. Cement height in casing annulus (TOC): (a) General: TOC shall be minimum 350 ft above a casing shoe, where the cement column in consecutive operations is pressure tested / the casing shoe is drilled out. (b) Conductor: Cemented conductor is not defined as a barrier element. (c) Surface Casing: TOC Shall be defined based on load conditions from wellhead equipment and future operations. TOC should be inside conductor or to surface. (d) Casing through hydrocarbon bearing formations: TOC shall be defined based on requirements for zonal isolation. Cement should cover potential cross-flow interval between different reservoir zones. For cemented casing strings which are not drilled out, the height above a point of potential inflow/ leakage point / permeable formation with hydrocarbons, shall be 650 ft, or to previous casing shoe, whichever is less.
Design, construction and selection
Initial test and verification
6.
Temperature exposure, cyclic or development over time, shall not lead to reduction in strength.
7.
Requirements to achieve the along hole pressure integrity in slant wells to be identified.
1. It shall be pressure tested if the casing shoe is drilled out. Note, in cases where this may break down formation, the verification may be through exposing the cement column for differential pressure from fluid column above cement in annulus. In the later case the pressure integrity acceptance criteria and verification requirements shall be defined. 2. The verification requirements for having obtained the minimum cement
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Features
Acceptance criteria height shall be described, which can be; • verification by logs (cement bond, temperature, LWD sonic) or • estimation on the basis of records from the cement operation (volumes pumped, returns during cementing, etc.). 3.
Use
The strength development of the cement shall be verified through observation of representative surface samples from the mixing.
None
• The annuli pressure above the cement barrier shall be monitored Monitoring
regularly when access to this annulus exists.
• Surface casing by conductor annulus outlet to be visually observed regularly.
• Non-compliance with any of the above mentioned requirements Impairment
Pressure build-up in annulus as a result of e.g. micro-annulus, channeling in the cement column, etc. Table 1.17: Acceptance & verification criteria for Casing cement as a barrier
1.18 Cement plug Features
Acceptance criteria
Description
This element consists of cement in solid state that forms a plug in the wellbore
Function
The purpose of the plug is to prevent flow of formation fluids inside a wellbore between formation zones and/or to surface, resist pressures from above or below.
Design, construction and selection
1. The in-situ compressive strength of the cement plug shall be higher than estimated formation strength at the depth where plug is installed. 2. Cement slurries that will be exposed to permeable and abnormally pressured hydrocarbon bearing zones should be designed to prevent gas migration, when the cement sets. 3. Permanent cement plugs should be designed for minimal strength reduction and no shrinkage caused by thermal exposure and cyclic loading 4. It shall be designed for the highest differential pressure and highest downhole temperature expected, inclusive installation and test loads. 5.
A minimum cement batch volume shall be defined for the plug in order that homogenous slurry can be made, to account for contamination on surface, downhole and whilst spotting downhole.
6.
The firm plug shall extend minimum 50ft MD above any source of outflow/ leakage point. A plug in transition from open hole to casing should extend at least 150ft MD below casing shoe.
7. If it is set inside casing and with a mechanical plug as a foundation, S.G. Rev-00/09
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Features
Acceptance criteria the minimum length shall be 20 ft MD. 8. A casing/ liner with shoe installed in permeable formations should have a 10 ft MD shoe track plug. 1. 2. 3.
4. Initial test and verification
5.
Cased hole plugs should be tested either in the direction of flow or from above. The strength development of the slurry should be verified through observation of representative surface samples from the mixing. The plug installation shall be verified through documentation of job performance; records of cement operation (volumes pumped, returns during cementing, etc.). In case of Open hole Its position shall be verified, by means of, Tagging, or measure to confirm depth of firm plug. In case of Cased hole Its position shall be verified, by means of, • Tagging, or measure to confirm depth of firm plug • Pressure test, which shall be 1000 psi above estimated formation strength below casing/ potential leak path, or ~500 psi for surface casing plugs, and not exceed casing pressure test less casing wear factor which ever is lower (but never lower than leak-off/fracture pressure). • If a mechanical plug is used as a foundation for the cement plug & this is tagged & pressure tested, the cement plug does not have to be verified.
Use
Ageing test may be required to document long term integrity.
Monitoring
For temporary suspended wells: The fluid level/ pressure above the shallowest set plug shall be monitored regularly when access to the bore exists.
Impairment
Non-compliance with above mentioned requirements and the following: a. Loss or gain in fluid column above plug. b. Pressure build-up in a conduit, which should be protected by the plug. Table 1.18: Acceptance & verification criteria for Casing cement as a barrier
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SECTION 2 WELL CONTROL IN WORKOVER OPERATIONS 1.
Introduction Well control procedures for workover operations are significantly different than those used when drilling. Though basic pressure considerations are the same, implementation methods vary greatly due to well conditions, which are often unique to individual wells. These conditions include the type of completion, formation pressures exposed to the wellbore, and the reasons for performing the workover. Routine workover operations often require the implementation of various well control procedures. An understanding of the principle of killing operations and the effect of routine operations on well control is essential for the Drilling Supervisor. Killing a producing well is often the first step in a workover operation. Prior to performing this step; certain actions must be taken to ensure the kill is performed in the safest and most efficient manner. In this section, the principles and the procedures for killing different types of completion and wells are discussed.
2.
Checking Well Integrity and Installing Pressure Barriers Prior to start killing a well:-
3.
•
Review casing and cementing operations including any mechanical problem encountered during drilling the well.
•
Inspect surface casing, and review the possibility of N/U BOP’s and applying pressure on well integrity.
•
Conduct the required remedial operations such as wellhead scaffolding and adding extra valves.
•
Well head survey should be conducted prior to rig move to verify the condition of wellhead
•
Apply ADCO pressure barrier policy.
Un-plugging the Well and Checking Wellhead Pressure Prior to unplugging the well, the rig must be fully operational and capable of handling any well control situation that may occur as consequences to unplugging the well
•
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A minimum of 500 bbls of workover fluid should be available in the tanks prior to unplugging the well.
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4.
•
Kill and choke lines must be connected to the wellhead and choke manifold and tested to the X-Mas tree working pressure prior to unplugging the well. Flare lines shall be also flushed and tested.
•
Test lubricator to the wellhead working pressure.
•
Retrieve plugs from tubing hanger.
•
After retrieving all plugs or mechanical barrier from Tubing Hanger, Tubing Spool, SC-SSSV and Tubing String, wait for pressure to stabilize (Bleeding off gas cap is not allowed).
•
Record pressures of tubing strings, tubing/ casing annulus, and casing/casing annulus.
•
Check X-Mas tree valves against well pressure
Killing the Well 4.1
General Guidelines Many considerations must be given to selecting the proper method of killing a normally pressured well. The generic well kill guidelines are summarized below
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•
Install kill and choke lines and test against the wing valves to the wellhead working pressure.
•
Rig up and test the wireline lubricator to wellhead working pressure.
•
Retrieve SC-SSSV and any other wireline plug set inside the string.
•
Monitor and record wellhead pressure.
•
Kill well using one or more of the following methods: O
Bullheading
O
Coiled Tubing Killing
O
Lubrication
O
Punch the tubing and circulating.
O
Reverse circulation
O
Killing annulus
O
Through tubing kill with hole in the tubing or leak in the packer
•
Observe the other string or annulus for communication.
•
Observe well for loss or gain.
•
Observe well static prior to N/Down X-Mas tree.
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•
Use LCM Pill to cure losses if needed.
•
Install SC-SSSV if not installed.
•
Install NRV(s), N/D X-Mas tree and plug control line port(s).
•
Check tubing hanger thread
•
N/U BOP, remove NRV after confirming no pressure below, install plug and test BOP.
•
Remove plug, make up landing joint w/ safety valve on top.
•
Retrieve SC-SSSV.
•
Retract lock down screws.
•
POH with completion string. Note: O Tubing string must be secured with safety and circulating valve during stinging out or releasing the hydraulic packer. O Rig floor must be ready with contingency plan to handle strong U tube.
4.2
Equipment required for kill operations
•
Wellhead fittings and x-overs required for killing operations.
•
Kill line, choke line and choke manifold.
•
Pumping Unit.
•
Killing fluid.
•
Flare lines.
•
Coil tubing unit (if required).
•
Wireline unite and tools (if required).
•
Electric wireline unit (if required) with required tools i.e punching, cutting.
Selection of equipment required for well killing must be decided on case by case basis.
4.3
Killing Methods The kill method that is most suitable for a particular completion string and formation pressure / fluid will primarily depend on whether the completion string is in communication with the annulus or not. The text that will follow discuss the most common kill methods, highlighting the factors that must be taken into account while using each method.
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4.3.1 Bullheading Bullheading is a term used to describe the pumping of the fluids into the formation. In the case of well control, the objective is to pump a workover fluid down the tubing and drive the formation fluids out of the tubing, through perforations and back into the formation. A pumping schedule shall be available to avoid fracturing the formation while the killing fluid is descending downhole. The schedule shale be designed to consider the initial shut in pressure and fracture pressure so that the bottom hole pressure is always below the fracture pressure. It is important to note that pressures should decrease as the kill fluid is pumped into the well since the hydrostatic pressure of the kill fluid is greater than the formation fluid. If this occurrence is not observed to the extent expected in the field operations, either the formation's ability to accept the fluid is decreasing (plugging) or gas is migrating upward. It should also be noted that as the low density formation fluids are displaced by greater density killing fluids, the maximum allowable surface pressure decrease. Upward migration of low density fluids through higher density fluids may be a serious problem in workover operations, particularly when bullheading techniques are used. Factors affecting migration rates include: Fluid densities and viscosities, hole geometry, and influx size. In the cases of formations with characteristics that only allow low pump-in rates, upward gas migration rates may equal or exceed the pump rates and result in negating the advantages of bullheading. The addition of viscosifiers to the workover fluid has been found to be a practical field-proven method to reduce migration rates. Formation fluids often affect the feasibility of bullheading procedures. Low viscosity fluids such as gas will flow back through the formation at rates sufficiently greater than oil or water. In addition, gas will have a reduced tendency to plug the formation as it reverses flow.
4.3.2 Coiled Tubing Killing Coiled Tubing is often used for killing a producing well. The objective is to circulate killing fluid down the coiled tubing and up the coiled tubing / production tubing annulus. A primary application for coiled tubing is in cases where the well can not be killed by bullheading because the wellbore is plugged. Applications for coiled tubing may be restricted in deep wells due to strength limitations of the tubing. In some cases, in gas wells, field experience has shown that a coiled tubing section filled with killing S.G. Rev-00/09
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fluid will exceed the tensile strength of the pipe. This is not usually the case in oil wells because the buoyancy provided by the oil reduces the overall tubing load. The following are general guidance procedures when killing a well using coiled tubing:-
•
De-pressurize X-tree.
•
R/U and pressure test C/T BOP and injector head.
•
RIH with the following basic tool string configuration O
Circulating nozzle
O
Two check or flapper valves
O
Straight bar
O
Release joint
O
Tubing connector.
•
Test weight indicator before running coiled tubing into the well.
•
Standard running speed should be 50 ft/min, this speeds must be reduced when running through the riser, X-Mas tree, SC-SSSV and any other downhole restrictions.
•
Run coiled tubing below perforations depth.
•
Displace completion string with kill fluid. Keep pumping until clean fluid returns.
•
Observe pressure and record losses.
•
Report results to town.
•
Pull out of the hole while circulating kill fluid until the tubing end connector tags the stripper, don’t exceed 4000 lb overpull.
•
Close the well master and swab valves.
•
Bleed off pressure in the coiled tubing and surface lines through the closed line drain in case of any hydrocarbon discharge.
•
Rig down the coiled tubing and associated equipments.
Notes: O DS and RM must be alert during killing operations while coiled tubing downhole. O Contingency plan to handle any well control incident must be in place. S.G. Rev-00/09
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O Returns must be routed through choke manifold. O Flaring oil or gas is not allowed without management approval. O Gas detectors, breathing apparatus must be ready in place prior to commenceing killing operations. O Check SC-SSSV ID compared to C/T OD prior to rigging up C/T. For more details about coiled tubing operations refer to Coiled Tubing Manual (the manual is electronically available at ADCO Drilling Website.
4.3.3 Lubrication Lubrication is occasionally used for killing wells during workover operations. It is a process that alternately pumps a kill fluid into the tubing or annulus, and then a volume of gas is allowed to escape from the well until the kill fluid begins to escape through the choke. At this point, brine water or other fluids are pumped into the tubing or annulus, and the cycle is restarted. As each volume of brine is pumped into the tubing, the Shut-In Tubing Pressure should decrease by a calculated value until the well is eventually killed. Caution must be exercised to insure that large volumes of kill fluids are not allowed to escape from the well during the bleeding phase. The lubrication and bleed method is often employed to kill high pressure wells where kill pressures would approach the rated pressure of the wellhead or tubing and in wells that have a plugged wellbore or perforations and will not allow bullheading. Lubrication procedures can be employed to kill the well without necessitating the use of coil tubing. It should be apparent, however, that lubrication is a time consuming process. A certain amount of time is required for the gas to migrate upward through the falling kill fluid after the pumping ceases. Gas migrates upward at 17-35 ft/min; therefore after pumping, it is important to wait several minutes before bleeding gas from the well to prevent bleeding the kill fluid through the choke. Refer to Chapter-3 in Volume-1 for more details.
4.3.4 Perforating the Tubing / Stinging out and Circulating Perforating the tubing and circulating a kill fluid is another primary method of killing producing wells. The method will allow direct circulation or reverse circulation of brine water. This method requires that the packer fluid in the annulus be in circulable condition and not severely gelled.
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Careful attention must be given to the selection of a perforation tool. It is important that the tool be capable of perforating the tubing without damaging the adjacent casing, should the tubing be in close proximity to the casing. In addition, oriented perforating becomes a serious consideration in cases of dual completion to avoid perforating the other string. Tubing punch is normally carried out above the most top packer, in the middle of a tubing joint , far from wireline nipples, blast joint, travel joint…etc In case of pulling the tubing out of the packer, circulating a kill fluid out of the bottom of the tubing is a kill option involves lifting the tubing a sufficient height to pull the seal assembly from the packer. The disadvantage of this method is that the X-Mas tree must be removed, and BOP’s installed in order to pick up the tubing. Some types of completions such as Tandem Dual Completions are not suitable for this method of well killing.
4.3.5
Reverse Circulation Reverse circulation involves pumping kill fluids down the annulus and displacing the formation fluids up the tubing. This procedure requires that a choke is placed in the standpipe or that the surface equipment can be arranged in such a manner that conducts the formation fluids through the standpipe to the choke. The reverse circulation method utilizes the pumping casing pressure to monitor the kill operation. The standpipe choke is used to adjust the pumping casing pressure to the required values. Reverse circulation offers several advantages and disadvantages relative to normal circulation. The advantages include (1)
A significant reduction in the time required to circulate the formation fluid from the well.
The disadvantages of the reverse circulation procedure include (1)
Possible plugging when attempting to reverse flow if circulating ports are in the work string
(2)
The slow circulating rates used in the reverse procedure may allow gas to migrate up the annulus at a rate greater than the downward flow rate.
(3)
It is not suitable method for high pressures
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and the pressure of the exposed reservoir is known. The workover fluid is, therefore, probably already of sufficient density to control the formation. In these cases, the kick will usually be the result of an effective underbalance created by swabbing. Thus, the workover fluid need not to be weighted up as long as the tubing is sufficiently close to bottom. The kill method used is then equivalent to the Drillers Method; with the exception that only one circulation is required since the "weight up" is unnecessary.
4.3.6
Killing Annulus A separate annular kill is sometimes required because of a loss of integrity in the tubing string resulting from a hole or leak. In these cases, killing the tubing by lubricating or snubbing will not necessarily kill the annulus. It is therefore necessary to perform kill techniques on the annulus using one of the previously described methods. These include bullheading, circulating or reverse circulating. Gas Migration can be a serious consideration when pumping down the annulus. In all methods of well killing, it is important to maintain a constant pump speed along with the required casing or tubing pressure. If the pump speed is allowed to change or the proper surface pressure not used, bottomhole pressure will be either too high or too low and either loss of circulation or additional influx will occur. If the kill rate must be changed, a new tubing pressure schedule which accounts for a change in the circulating pressure losses must be followed.
4.3.7
Through Tubing Kill with Hole in the Tubing or Leaking A through tubing kill with a hole in the tubing or a packer leak requires additional considerations. The primary concern is determining the location of the hole or leak. Additional concerns include (1) the effect of the annulus pressure exposed on the casing and (2) the kill procedure that will be most effective in each case. Determining the location of the tubing hole generally requires an onsite evaluation of the situation. The hole or leak will be indicated by pressure on the casing string(s). The most common method of locating the leak is by pumping a volume of colored brine water until it is returned to the choke on the annulus. This volume can be used to calculate the location of the hole. Deep holes will generally allow the well to be killed in a conventional circulation manner. Shallow to medium depth holes will require snubbing coil tubing or jointed pipe or lubrication. Bullheading can be attempted only if the dynamic pressures do not exceed the casing burst pressures.
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5.
6.
Testing Wellhead •
Test between primary and secondary seals through T.H.S testing port to either 60% of the collapse pressure of the casing string exposed or to 1500 psi whatever is less.
•
Always observe other side’s ports during testing.
•
Check injectivity down annulus if requested in the drilling program, do not exceed 500 psi, maximum injection pressure is to be decided on case-by-case basis. Town approval is required.
•
Remedial cementation at this stage must be considered.
Checking for Trapped Pressure and Bleed off Procedures After kill operation and when checking the trapped pressure, the following good practices should be followed:
7.
•
Bleed off pressure from the casing side only. The reasons are (1) the primary choke is generally located on the casing side, (2) to avoid contamination of the mud (or brine water) in the tubing.
•
Use the tubing pressure as a guide since it is a direct bottomhole pressure indicator.
•
Bleed small amounts (1/4 to 1/2 barrels) of mud at a time. Close the choke after bleeding and observe the pressure on the tubing or annulus.
•
Continue to alternate the bleeding and subsequent pressure observation procedures as long as the shut-in tubing pressure is continuously decreasing. When the pressure ceases to fall, stop bleeding and record the true SITP and SICP.
•
If the SITP decrease to zero during this procedure, continue to bleed and check pressures on the casing side as long as the casing pressure decreases.
•
These bleeding procedures can be implemented at any time. However, it is advisable to check for trapped pressure when the tubing string is displaced with a clean kill fluid if any pressure remains on the work string.
Nippling down X-Mas Tree & Nippling up BOP •
Refer to in section 1 of this chapter for pressure barriers requirements when removing X-Mas tree.
•
Observe well static (1 hour for oil wells and 2 hours for gas wells)
•
Install downhole plug (if applicable).
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•
Close SC-SSSV (if applicable).
•
Install NRV(s) (use DRN in gas wells), Nipple down X-Mas tree and plug control line port(s).
•
Install BOP with adequate pipe rams (same criteria applied to drilling); remove NRV after confirming no pressure below NRV. Refer to volume-1, chapter-3 “Well Control” and Chapter-1 “Policies” for BOP requirements.
•
Install plugs (2 way check valve) in tubing hanger and test blind/shear rams.
•
Remove plugs, make up landing joint with safety joint on tubing hanger and test Annular Preventer and remaining BOP components as per procedures in ADM, volume – 1, Chapter-3 “Well Control”. Note: Before N/U the BOP, the DS must ensure that the BOP is cleaned from any cuttings or debris that may drop and accumulate on top of the NRV during the BOP pressure test. Check tubing hanger threads are clean.
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SECTION 3 RECOVERING OLD COMPLETION STRINGS 1.
General The following must be taken into account when planning for recovering old completion:
•
Review downhole well status including tubing dimensions, strength and capacities of each item in the string.
•
Identify the point of the weakest tensile strength in the string.
•
Know fluid density and type in the annulus and inside tubing.
•
Inspect tubing hanger after removing X-Mas tree and prior to installing BOP’s o Tubing Hanger thread type and conditions. o Pack off design and retrieving mechanism o Lock down screws condition o
2.
Control line fittings
•
Consider special surface arrangement for handling U-tube.
•
Retrieve SC-SSSV prior to pulling the tubing hanger to surface.
•
All subs and x/overs (with safety valves) required to shut in the well must be ready on rig floor for any emergency.
•
Calculate overpull required to release the tubing from the packer or to shear the pin for releasing the hydraulic packer.
•
Contingency planning must be in place should well control incident occurred
•
Be aware of the design and mechanism of the downhole completion equipment such as packers, SC-SSSV, Travel Joints,…..etc.
•
The landing joint that required for pulling on the completion string must be inspected in particular the minimum ID required to allow free passage of wireline tools.
Recovering Completion - General Procedure The follows are general guidelines for recovering old completion:-
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NRV retrieving tool and watch pressure. If pressure exists, bullhead string with clean kill fluid. During killing operation, trapped pressure below NRV can be due to over charging the formation. This pressure can be released without having extra influx from formation. To bleed-off trapped pressure, follow up the procedures mentioned in the previous section. Pressure that might be exist below the SC-SSSV could pass across, especially at low pressures
•
When well is safe. i.e. wellhead pressure is zero and static losses is less than 20 Bbls/hr, proceed to recover the completion
•
Retrieve SC-SSSV, observe well
•
Make up landing joint (with safety valve) to the tubing hanger. Connect surface lines and valves that allow flexible change between normal circulation and reverse circulation. Note: landing joint must be checked with the proper gauge cutter and cleaned from scale.
•
Retract Tubing Hanger lock down screws.
•
Calculate maximum allowable pull on completion string(s) that is required to do the following: o Retrieve tubing hanger o Open travel joint o Release hydraulic packer or snap out the tubing
•
Pull on the string in gradual increase, retrieve tubing hanger from tubing head spool, open travel joint and work string, as applicable, to sting out seal units / snap latch or to release the hydraulic packer.
•
Maximum allowable pull on tubing is: o For new tubing 85% of the tensile strength of the weakest component o For old tubing 75% of the tensile strength of the weakest component
•
Once packer is unset (wait 30 min. to allow packer element to deflate), or tubing string is snapped out of the packer, start circulating slowly. Circulate one cycle using workover fluid.
•
If unable to recover the completion by direct pull, consider other options such as cutting / milling and fishing operations
•
Ensure no flow and the static loss is less than 20 BPH. Use HVP or LCM if needed.
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•
POH lay down old completion, install pin and box thread protectors
•
Reserve samples of corroded or scaled sections of tubing marked with depth for inspection. Note: o Pull slowly inside 7” liner to avoid swabbing action. o Observe hole on top of liner, when string is half way out of the hole and at 1000 ft o Consider using variable ram to suit different completion sizes. o Have “Kick Joint” ready on V. door to shut in tubing string at any stage while pulling out of the hole.
3.
Releasing Hydraulic Packers The following are general guidelines for releasing dual hydraulic packer:-
•
R/Up tubular equipment for pulling completion string in tandem
•
Define packer setting / releasing side, L.S or S.S. (Assume L.S for this example)
•
Calculate the minimum pull required to shear releasing pin.
•
Calculate the maximum allowable pull on the weakest point in L.S.
•
Make up landing joint (with safety valve) on both strings.
•
Install circulating valve on both sides.
•
Retract lock down screws.
•
Pull S.S, Retrieve TH segment from THS, watch opening travel joint. Apply 10,000 lb over string weight, and set SS on slips.
•
Cut S.S above dual packer, circulate and POOH with S.S (ADCO procedure is not to pull completion in tandem)
•
Pull LS, retrieve TH segment from THS, observe opening travel joint.
•
Record string weight below and above travel joint.
•
Pull on L.S to release dual hydraulic packer, Appling gradual increments of 5000 lb. Refer to the tables in the next page for information about the packers currently used in ADCO operations
•
Work string up and down repeatedly to help shearing the releasing pins
•
Fluid density inside tubing and below packer must be equal or less than that in the annulus.
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•
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If unable to release the packer, proceed to cut and fish completion strings as described in step 4.1 of this section.
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Table 2-5: Hydraulic Packers Specifications
Baker Packers Packer Model
Type
4 ½" Packers Retrievable FH Retrievable
4 ½ ", 5" & 6.5/8" Single Hydraulic Packers
Casing Size in
3.771
--
4.5
9.5-13.5 Hydrostatic
2000
30000
Sour
4.5
9.5-13.5 Hydrostatic
---
30000
Sour
1.978
5
15-18
Hydrostatic
1500
30000
H2S
6.5/8" Packers Retrievable FH
1530
40000
Sour
HS
FHL HS FH
HS
5.603
2.374
6 5/8
24-28
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
5.968
2.370
7
Retrievable
--
--
7
20-26
Retrievable
6.080
2.377
7
Retrievable
5.910
2.373
Retrievable
5.910
2.356
Retrievable
5.983
2.992
7
Retrievable
5.910
2.919
7
Retrievable
8.218
--
9 5/8
Retrievable Retrievable Retrievable
8.218
---
8.310
2.919
9 5/8 9 5/8 9 5/8 9 5/8
40-53.5
9 5/8
40-53.5
7
26-32
7 7 7
Retrievable
Retrievable Retrievable
8.310
2.919
Retrievable 7" Dual Hydraulic
GT
Packers
A-5 AL-5
9 ⅝” Dual Hydraulic Packer
Setting Method
4.125
7" Single Hydraulic Packers
9 ⅝” Hydraulic Packers
Packer Bore ID in
5" Packers Retrievable FH
FH
7" Single Hydraulic Packers
Casing Weight Lb /ft
Pressure Tension Setting Shear Service Min. Release psi lb
Packer OD in
GT A-5 ESP Twin Seal
S.G. Rev-00/09
Retrievable Retrievable
5.937 5.937
Retrievable Retrievable
5.942
1.937
Retrievable Retrievable Retrievable Retrievable
--
--
Hydrostatic
1440
40000
Sour
Hydrostatic
1520
40000
Sour
23-26
Hydraulic
1800
40000
H2S
7
26-29
Hydraulic
2500
40000
H2S
7
23-32
Hydraulic
1800
40000
H2S
7
26-29 Hydrostatic
1530
40000
Sour
Hydraulic
2500
40000
H2S
47-53.5 Hydrostatic
1500
40000
Sour
Hydrostatic 40-47 Hydrostatic 40-53.5 Hydraulic
1500 1500 1800
40000 40000 40000
Sour Sour H2S
Hydraulic
2500
40000
H2S
26-32 26-32
Hydraulic Hydraulic
2100 2100
30000 30000
H2S H2S
23-32
Hydraulic 1750
30000
H2S
8.500
Hydraulic
2150
40000
H2S
8.510
1500
40000
H2S
ADM Volume-2 Drilling Operation -B
Hydraulic
2.968
--
Hydraulic 40-47
9 5/8 9 5/8
Retrievable
23-29
7 7 9 5/8
Retrievable
Sour
40-47
9 5/8
40-47
Hydraulic
9 5/8
40-43.5
Hydraulic
Date Issued: 30/03/2009
Last Revision:
50000
Page 2-33 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Packer Model
Type
4 ½" Packers Retrievable FH Retrievable
4 ½", 5" & 6.5/8" Single Hydraulic Packers
7" Single Hydraulic Packers
Casing Size in
3.771
--
4.5
9.5-13.5 Hydrostatic
2000
30000
Sour
4.5
9.5-13.5 Hydrostatic
---
30000
Sour
Setting Method
4.125
1.978
5
15-18
Hydrostatic
1500
30000
H2S
6.5/8" Packers Retrievable FH
5.603
2.374
6 5/8
24-28
Hydrostatic
1530
40000
Sour
Retrievable
--
--
7
26-29
Hydrostatic
Retrievable
--
--
7
26-29
Hydrostatic
--
--
--
Retrievable
5.968
2.370
7
Hydrostatic
1440
40000
Sour
--
--
7
20-26
Hydrostatic
1520
40000
Sour
3.76
1.917
4.500
9.5-13.5
Hydraulic
3500
32000
H2S
4.83 4.83
1.925 1.925
5.00
15-18
Hydraulic
2000
24000
H2S
5.00
15-18
Hydraulic
2000
24000
H2S
5.520
2.360
24-32 24-28
Hydraulic Hydraulic
2000 3500
43000 41000
Retrievable Retrievable
2.360 --2.360
6.5/8 6.5/8
H2S
5.610 -5.880
7.00 7.00
23-32 23-32
Hydraulic Hydraulic
-2000
---
-H2S
Retrievable
--
--
7.00
26-32
Hydraulic
---
---
---
5.880
2.360
Hydraulic
2000
40000
H2S / CO2
Retrievable 4 ½" Packers Retrievable PHL 5” Packers Retrievable RH Retrievable 6.5/8” Packers Retrievable RH Retrievable PHL
7" Single Hydraulic Packers
Packer Bore ID in
5" Packers Retrievable FH
FH
4 ½", 5" & 6.5/8" Single Hydraulic Packers
Casing Weight Lb /ft
Pressure Tension Setting Shear Service Min. Release psi lb
Packer OD in
RH
Retrievable
7.00
26-32
Sour
Halliburton Packer Model
Type Retrievable
7" Single Hydraulic Packers 9 ⅝” Single Hydraulic Packers
7" Dual
PHL
RH
Retrievable
2.360
Retrievable 5.980 Retrievable 8.31 Retrievable 8.31
2.885
Retrievable
RDH
Retrievable
Rev-00/09
6 5.980
PHL
S.G.
Packer Packer Casing Bore ID Size in OD in in
8.45
ADM Volume-2 Drilling Operation -B
Pressure Tension Setting Shear Service Min. Release psi lb 2000 32000 H2S
Casing Weight Lb /ft
Setting Method
7.00
23-29
Hydraulic
7.00
23-29
Hydraulic
3000
40950
H2S
7.00
23-29
Hydraulic
3000
40950
H2S
9 5/8 9 5/8
40-47 40-47
Hydraulic Hydraulic
2000 2000
40000 40000
H2S H2S
9 5/8
40-47
Hydraulic
3500
41300
H2S
7
26-32
Hydraulic
Date Issued: 30/03/2009
Last Revision:
Page 2-34 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Packer Model Hydraulic Packers
BHD RDH
9 ⅝” Dual Hydraulic Packers
Type
Packer Packer Casing OD Bore ID Size in in in
BHD
Setting Method
Pressure Tension Setting Shear Service Min. Release psi lb 2000 30000 Sour
Retrievable Retrievable
5.940
7 7
26-32 26-29
Hydraulic Hydraulic
Retrievable
6.015
7
26-29
Hydraulic
4000
30000
H2S
8.340
9 5/8
43.5-53.5
Hydraulic
2000
40000
Sour
9 5/8
43.5-53.5
Hydraulic
9 5/8
43.5-53.5
Hydraulic
2000
40000
H2S
43.5-47
Hydraulic
3000
40000
H2S
Casing Weight Lb /ft
Setting Method
43.5-53.5 Retrievable Retrievable
RDH
Casing Weight Lb /ft
Retrievable
8.340
43.5-47 Retrievable
9 5/8
8.475
Weatherford Packer Model
Type
7" Dual Hydraulic Hydro-II Retrievable Packers
Packer OD in
Packer Casing Bore ID Size In in
5.938
7
23-32
Casing Size In
Casing Weight Lb /ft
Pressure Setting Min. psi
Tension Shear Release lb
Service
2000
30000
H2S
Pressure Setting Min. psi
Tension Shear Release lb
Service
Hydraulic
Arrow Packer Model
Type
9 ⅝” Dual Hydro-II Retrievable Hydraulic Packers Hydro-II Retrievable Hydro-II Retrievable
Packer Packer OD Bore ID in in
Setting Method
8.50
9 5/8
47 - 53.5 Hydraulic
2000
30000
8.5
9 5/8
47 - 53.5 Hydraulic
2500
40000
H2S / CO2 H2S
8.5
9 5/8
40 - 47
2500
40000
H2S
Casing Size In
Casing Weight Lb /ft
Setting Method
Pressure Setting Min. psi
9 5/8
40-47
Hydraulic
1500
NODECO Packer Model
Type
Packer Packer OD Bore ID in in
9 ⅝” Dual RR (ESP) Retrievable Hydraulic Packers
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Tension Service Shear Release lb 50000
Page 2-35 Printed on: 19/08/2008
H2S
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
4.
Recovering Dual Completion 4.1 Recovering dual completion with Stuck Dual Retrievable Packer The following procedures describes steps to recover dual completion and assume that after recovery of S.S, the dual packer can not be released by pulling on L.S, If unable to release dual hydraulic packer by direct pull, proceed as follows:Step-1: - Cutting short string above dual hydraulic packer
Cut S.S 5 ft above dual packer
•
Make up landing joint (with safety valve) on short string tubing hanger.
•
Apply 10,000 Ibs tension on SS and land on slips.
•
Rig up electric wireline BOP on S.S side and test to 3000 psi.
•
RIH with chemical cutter, cut S.S at +/-5 ft above dual hydraulic packer. POH and rig down electric wire line, circulate hole.
Cut L.S 15 ft above dual packer Dual Packer
Short String Long String
Cut L.S at middle joint above blast joints Blast Joints
Single Packer
Figure 2-2: Step-1 Cut Short string
Figure 2-3: Step-2 Cut Long String below Dual Packer
Figure 2-4: Step -3 Cut Long String above Dual Packer
Printed on: 19/08/2008
S.G.
ADM Volume-2 Date Issued: ADCO Rev-00/09 Drilling Operation -B DRILLING MANUAL
30/03/2009
Last Revision:
Page 2-36
Volume-2/Chapter-2: Workover Operations
Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
POH and lay down S.S.
•
Make up landing joint (with safety valve) on LS tubing hanger. Pull up to 75% of the tension strength of the weakest component and attempt to release dual hydraulic packer and sting out of permanent packer.
•
If packer releases, circulate hole. Observe well, and POH, laying down completion strings.
•
If 75% of the yield strength of the weakest components of LS was not enough to release the packers, proceed to Step–2 to cut L.S below dual packer as follows:-
Step – 2: - Cutting long string below dual hydraulic packer
•
R/U wireline on L.S. and run with chemical cutter, cut L.S between single and dual packer at the middle of the joint above all blast joints.
•
Try again to unset the dual hydraulic packer if not succeeded; proceed to step-3 to cut L.S above the dual packer as follows:
Step – 3: - Cutting long string above dual hydraulic packer
•
RIH with chemical cutter and cut LS at +/-15 ft above dual hydraulic packer), POH and R/Down electric wire line, circulate hole.
•
POH and lay down L.S.
•
Change top pipe ram (if needed), test BOP’s and install wear bushing
•
RIH with overshot on drill pipe. (See section-4 of this chapter for BHA configuration).
•
Latch onto L.S side, Try again to unset the dual hydraulic packer. If not succeeded; proceed to step-4 to mill and fish the dual packer as follow:
Step – 4: - Milling and fishing dual Hydraulic packer
•
RIH with washover assembly, washover dual packer until it became free.
•
RIH with overshot and fishing assembly engage and catch LS. POH and lay down dual packer.
Step – 5: - Stinging the seal units out of the permanent single packer
•
If seal units still stuck inside the permanent single packer, RIH with overshot to top of LS, engage and workout to pull the seal units out of the permanent packer. POH and lay down fish. If unable to pull the seal unit, proceed as per step-6.
Note:In case if single hydraulic packer is retrievable, try to release the packer by direct pull using overshot otherwise wash over the Packer till it become free. Run with overshot, engage fish and POH. S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-37 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
For fishing assemblies and tools refer to section-4 of this chapter. Step–6:- Washing over permanent single packer and recovering seal units If unable to sting out from the permanent packer, proceed as follows:
•
Run wash over shoe with enough extension, wash over the permanent packer until it becomes free. If stick up above permanent packer is long (long section of blast joints), consider cutting below blast joint, noting that washing over long section of tubing across deviated section is not operationally easy
•
Run overshot with proper size of basket garble, engage top of tubing. POH and L/Down fish.
•
If seal units were recovered earlier by direct pull, proceed as per step -7 to mill and recover the permanent packer
Step–7:- Milling and recovering permanent packer For milling and retrieving permanent packers use HE packer milling and retrieving tool. The tool consists of the following components:
•
Packer Retrieving Spear Designed for removal of drillable full bore packers from the well. During the milling operation it will remain in the catching position at all times to engage the lower end of the packer. It consist of three parts, top coupling, mandrel slip and bull plug or mill head at the bottom. The Packer Retrieving Spear dressed with the proper size slip (grapple) for the bore of the packer is made up on sufficient extensions to allow the spear to be below the packer or extension(if any) during milling operation. The spear can be run in hole with slip in catch or release position. As the spear enters the bore of the packer, the slip is forced to move up on the mandrel in an area where the OD is reduced enough to allow passage through the packer. As the slip clears, it automatically drops to catch position. The Packer Retrieving Spear can be released by applying slight overpull and right hand rotation. Also, it can be engaged into the packer by merely lowering through the packer.
•
Extension Sufficient extensions to be made to have the Packer Retrieving Spear below the bottom of the packer or seal bore extension (if any) during milling operation. Extensions is equipped with special locked joint connections which prevent any possibility of whip-off during the milling operation.
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-38 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
Milling Head The packer milling head has an API connection up and an extension connection down.
Recover permanent packer with short seal bore extension (<10 ft) If the permanent packer is connected with short seal bore extension (less than 10 ft), the following procedures are to be followed:-
S.G. Rev-00/09
•
Make up The Packer Retrieving Spear with slips suitable for the packer bore (which is to be milled), Extension and mill head, lock the connections of the extension to avoid back-off during milling operation.
•
Lower the entire milling assembly to the top of the packer. Circulate and check weight of string up and down with and without circulation. Stop the pump.
•
Lower the milling assembly until the Packer Retrieving Spear passes through the bore of the packer.
•
Check that the Packer Retrieving Spear has engaged the packer by applying 10,000 lbs over pull.
•
Start milling the upper slips and packing element of the packer.
•
Push the packer down (~ 50') pump Hi-Vis-Pill and circulate bottom up.
•
POH the milling tool and remainder of packer.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-39 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Assuming that: • Well is killed and fluids equalized. • Unable to release S.S from dual Pkr.
Dual packer Released?
Yes
No (*See Note.1)
Washover dual packer, run overshot assy, latch onto L.S, POH with dual packer.
Cut S.S. above dual packer, circulate and POH with S.S.
Pull 75% of the yield strength of the weakest component of the LS
Run overshot assy, latch onto seal assy above permanent packer.
Yes
Dual Packer Released?
Seal assy Released?
Yes
No
Cut L.S. below dual packer and pull on dual packer.
Dual Packer Released?
Yes
POH and L/D seal assy.
No
Circulate and POH with L.S. and dual packer
Washover permanent packer using packer milling & retrieving tool, and POH fish. OR Washover with milling tool, run overshot, POH with fish
No
*Note.1: Consider to terminate the Fishing operations in special cases as mentioned in Clause-5.
Cut L.S. above dual packer, circulate and POH with L.S.
Run overshot assy, latch onto L.S. to unset dual packer. Figure 2-5: Recovering Dual Completion Flowchart
Printed on: 19/08/2008
S.G.
ADM Volume-2 Date Issued: ADCO Rev-00/09 Drilling Operation -B DRILLING MANUAL
30/03/2009
Last Revision:
Page 2-40
Volume-2/Chapter-2: Workover Operations
Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
Note: As an alternative, packers with seal bore extension (millout extension or with x-over and tail pipe attached to the bottom of the packer can be milled and retrieved in one trip by utilizing the Pioneer slick bore packer milling and retrieving tool.
5.
Abandoning Completion Tail and Packer(s) Fishing operation of Completion tail & Packer(s) shall be terminated if these conditions are met.
•
Effective zonal isolation between different zones can be achieved.
•
Abandonment is economically feasible compared to the fishing and milling option.
•
Abandoning completion tail & packer(s) will not have negative impact on the new well target, quality or integrity.
•
Continuing milling / fishing may result in loosing the chance to achieve zonal isolation due to plugging of String/Perforations.
Note: Refer to Chapter-4, Section-6 (Well Abandonment) for details on well abandonment and zonal isolation.
6.
Recovering 7" scab liner Scab liners were set in old dump injection wells to isolate the perforated aquifers. During workover operations, the corroded scab liner is replaced by cemented casing string to surface. Most of the scab liners in ADCO consist of:
•
194-75-60 FA-1 Baker Permanent packer at bottom.
•
190-75, K-22 Anchor seal assembly.
•
7" casing enough to cover the aquifer perforation.
•
194-60, FB-1 Baker Permanent packer at top.
The bottom packer was set on electric wireline while the upper packer together with casing was run and set on DP.
6.1
Retrieving Procedure
•
S.G. Rev-00/09
RIH 8.1/2" X 7.1/16" rotary shoe, wash over FB-1 PKR until it becomes free. POH.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-41 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
RIH with 7" casing spear and hydraulic jar. Latch into 7" casing. Release K-22 Anchor Seal by jarring and rotating ± 20 turns to right while applying overpull equal to 20% of the liners weight.
•
POH and L/D 7" scab liner marking same to carry out corrosion inspection prior to milling/retrieving bottom FA-1 packer with milling retrieving tool.
Notes:
•
a)
If K-22 anchor seal will not released, release the spear, POH and proceed to next step.
b)
RIH with internal casing cutter. Cut 7" casing at ± 5' above scab liner bottom.
c)
POH with casing cutter, RIH with 7" casing spear to recover the 7" scab liner.
d)
If casing is parted, attempt to recover the rest with spear and, if no success, proceed to step b and c above.
RIH with 7" casing releasing spear and hydraulic jar. Latch into 7" casing. POH and L/D 7" scab liner numbering same for corrosion inspection. O
RIH with 8.1/2" X 7.1/16" rotary shoe on 30'X8.1/2" washover pipe.
O
Washover FA-1 packer until same drops down.
O
RIH with 7" casing spear to recover the rest of casing and bottom packer.
Notes: Have available on location 8.3/8" short catch overshot with 7" spiral grapple to be used if spear fails.
S.G. Rev-00/09
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-42 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 4 FISHING GENERAL GUIDANCE This section describes the fishing tools and assemblies used in workover operations and highlight the factors and concerns that must be taken into account when using each tool.
1.
Standard Fishing Assembly •
2.
The standard fishing assembly consists of the following: O
Fishing tool
O
Jar and Bumper Sub
O
Accelerator
O
Drill Collars
O
Heavy Weight Drill Pipe
O
Drill Pipe
•
A Safety Joint should not be run. Since the Safety Joint will not transmit left hand torque, it would not be possible to back-off below it using a string shot. However, a Safety Joint could be run between the catching tool and the jar when a non releasing tool such as taper tap is being employed.
•
Avoid any restrictions in the bore of tools run above the catching tool, which would prevent the use of a cutting tool or the back-off shot within the fish.
•
Where losses or plugging are expected the use of a Circulation Sub in the fishing assembly should be considered.
Overshot •
S.G. Rev-00/09
Plan the operation taking into account the following factors: O
The catching action of the tool will stress the fish neck inwards.
O
A regular, smooth shape of the fish neck is necessary for a successful operation.
O
Jarring is only possible using “The Jarring type overshot”.
O
If the fish diameter is near the maximum catch or size of basket grapple, a spiral grapple is recommended. On the other hand, if the fish diameter is considerably below the maximum catch size, a basket grapple is preferable.
O
If the hole is enlarged, use an oversize guide.
O
When the fish has been milled over, if possible, run an overshot extension to avoid catching the fish by the milled part.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-43 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
3.
•
Run the fishing assembly, space out as required, and make up the Kelly.
•
Lower the overshot to just above the fish and circulate for a few minutes to clean the top of the fish.
•
Prior to engaging the fish, record the weight of fishing string (up, down and rotating) with and without circulation.
•
To engage a fish, the fishing string is lowered and rotated to the right very slowly, pumping at minimum rate. During the engaging operation, continuously monitor the weight indicator and stand pipe pressure.
•
As the fish is engaged, allow the right hand torque to slack out and pull on the fish picking up rapidly the fishing string 5 to 8ft. Drop the string 2 to 4ft and catch it in the brake to make sure that there is a firm grip.
•
If possible, consideration should be given to circulating bottoms up through the fish before pulling out of hole.
•
When tripping out of the hole with the fish, the string must not be rotated; pipe Spinner should be used.
•
If pulling out of the hole wet, flow checks shall be carried out frequently.
Releasing Spear •
• 4.
Plan this operation taking into account the following factors: O
The fish will be stressed outwards due to the catching action of the tool.
O
A regular, smooth shape of the fish is essential for a successful operation.
O
To allow unlatching of the spear, the use of a bumper sub is recommended.
O
Use the fishing jar If jarring is required. In this case the use of a Spear Stop is required. Check the Spear Stop OD when it is used in open hole and use the stop only if hole condition permits.
Perform the fishing job as per overshot procedure.
Taper Tap / Pin Tap •
S.G. Rev-00/09
Plan this operation taking into account the following factors: O
The size of the taper tool should be selected in order to engage the fish with the middle of the tapered point.
O
The taper taps do not allow free passage of the back-off tool.
O
Excessive torque can damage the tapered thread and swell the top of the fish.
ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-44 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
O
5.
6.
It is very difficult to impossible to release the tool once engaged. For this reason its use has to be considered the last resort.
•
Run the fishing assembly, complete with safety joint, space out as required and make up the Kelly.
•
Lower the catching tool to just above the fish and circulate a few minutes to clean the top of the fish. Do not circulate excessively as this may enlarge the hole.
•
To engage the fish, apply right hand torque. A gradual increase of back torque is an indication of successful operation.
•
Spin the pipe out of hole with the fish.
Reverse Circulation Junk Basket •
This procedure is more successful in soft formations.
•
Use the following parameters: O
WOB = 4000 to 8000 Lbs
O
Rotary = 45 RPM
O
Low Pump Rate (half of pumping rate while drilling).
•
Core approximately 1 foot. Pick up to allow the junk on the side of the basket to fall into the pilot hole, and then proceed coring a further +/-2 feet.
•
Pull the junk basket out of the hole
Fishing Magnet Magnets can be successfully used but only in hard formations to retrieve small steel objects such as bit cones, bearings, slips, tong dies and milling cuttings. To avoid sticking the fish in the hole, weight must not be applied. Fishing magnets may be run on wireline or on drillpipe. Wireline run have the advantage of speed and economy. Drillpipe run has the great advantage of utilizing the circulation to remove cuttings settling above the fish.
7.
Milling Tools The following are general guidelines for the use of milling tools:
•
S.G. Rev-00/09
Milled cuttings are much heavier than drilling cuttings. Therefore, mud yield should be increased or high viscosity pills should be pumped to help in carrying the steel cuttings out of the hole. ADM Volume-2 Drilling Operation -B
Date Issued: 30/03/2009
Last Revision:
Page 2-45 Printed on: 19/08/2008
ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
•
Oil based mud has poor carrying capabilities and should be avoided whenever possible. Polymer mud is most suitable for milling.
•
Never mill faster than it is possible to remove the cuttings.
•
Magnets placed in the flow line will help in removing metal particles from drilling mud. Removal of mill cuttings and debris reduces the wear on mud pumps and other equipment.
•
A junk sub placed in the string above the mill can aid in catching the larger cuttings.
•
Always start rotating, with low RPM for about 3 ft above the top of fish. Lower onto the fish and adjust the weight and the rotary speed to obtain satisfactory progress.
•
Generally the most efficient milling rates are obtained by running the rotary at 80 to 100 RPM. Milling with washover shoes is an exception and are usually more efficient at speeds of 60 to 80 RPM.
•
Continuously monitor the torque indicator during milling operations.
•
The type and stability of the fish (cemented or not) together with the hardness of the fish and/or cement are factors that affect milling rates.
There is a wide variety of mills specifically designed for various applications. Two basic categories are available:
8.
Hydraulically Activated Mills 8.1
Section Mill Section mill is a hydraulically actuated tool and is used to mill out a complete section of casing. Downhole section milling of casing, is generally done for the following reasons:
9.
•
To mill a section of casing that permits sidetracking in any direction.
•
To mill the perforated zone in a production casing string or to expose cased-off formations. The formations may be then under-reamed and gravel packed past the original completion.
Fixed Milling Tools The most commonly used Fixed Mills are:
9.1
Junk Mills Used to mill all types of junk, including rock bit cones, reamers cutters, items dropped through the rotary, cemented tubing, etc.
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9.2
Pilot Mills Designed to mill casing, tubing, wash pipe, safety joint, swaged casing, etc.
9.3
Taper Mills Generally used to eliminate restrictions or to mill through collapsed casing.
9.4
Washover Shoes Designed to mill away formation or tool obstructions such as stabilizer blades, reamer cutters, expanded packers and bit bodies which may be holding the drill or tubing string in the hole
10.
Special Mills Window mills, Watermelon mills, etc. for casing sidetracking systems (See Sidetracking Section -5 of this Chapter).
11.
Fishing of Radio-Active Wireline Tools 11.1 Caution Radioactive Source containers release, if broken, very harmful materials that are dangerous to human lives and contaminate the field as these materials migrate in the formation. Therefore, every precaution MUST be taken to avoid breaking these containers while fishing.
11.2 Preparation The whole operation needs good communication and co-ordination between Driller, Derrickman, Floormen and the Wireline Contactor Operator. Therefore, the DS will arrange a pre-job safety meeting.
11.3 Operations
S.G. Rev-00/09
•
When stuck, determine if the tool or the cable is stuck by using the stretch charts provided by the Wireline Contractor.
•
Do not break the cable or the weak point. Chances to recover the tool are reduced by doing either of them.
•
Prepare the overshot using the correct grapple to suit the cable head in use and the guide shoe to suit the hole size. Screw the assembly into the sub to be made up between the overshot and the drill pipe.
•
Pull up 2000 lbs over normal cable tension.
•
Secure the cable with the special T-Clamp, slack off and cut the cable 5-7 feet above the Rotary table.
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S.G. Rev-00/09
•
Lower the block with the upper sheave wheel and fix the top sheave as high as possible in the derrick, at a position where the Derrickman can easily reach the cable.
•
Use the Wireline Contractor’s tension device on the lower sheave.
•
Feed the "hole" end of the cable through the overshot assembly and prepare the male type quick connection.
•
Prepare the "Unit" end of the cable with the female type quick connection. Make up sufficient sinker bars on this end to overcome the cable weight while lowering the quick connection through the drillpipe.
•
Pick up the first stand of drillpipe and lower the quick connection through the pipe.
•
Engage the quick connections and pull up until the cable is slightly under tension.
•
Make up the overshot assembly to the drill pipe, chain tong tight.
•
Pull up the cable until the T-Clamp is hanging free. Disconnect T-Clamp.
•
Make the overshot assembly to the drillpipe tong tight
•
Lower the stand until the pin end of the quick connection is completely clean of the pipe.
•
Drop in the Rotary slips, place C-Plate into the groove of the quick connection and slack off cable tension.
•
Release the quick connection, pick up the next stand of drillpipe and repeat operation until approaching the fish.
•
Stop one stand above the torpedo and install the circulating sub.
•
Circulate slowly to clean the overshot and note the number of strokes and pressure. While circulating, there is every possibility that a cable loop will be formed at the bottom of the overshot. Therefore, Do Not Lower or Rotate the string while circulating.
•
Disconnect circulating sub and continue the approach until the cable tension is increasing. Do Not Rotate The Pine At Any Time.
•
After engaging the tool into the overshot, circulate again at the same stroke as in above. The pressure should be higher now.
•
Connect clamp and use the traveling block to pull the weak point.
•
Cut off quick connections and make a square knot with the cable ends.
•
Pull out and spool the cable on the drum.
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•
Pull out the fishing string slowly. Do Not Rotate.
•
Disconnect the tool from the head and break overshot connections with the tongs.
Notes: To avoid accidental damage of the containers during fishing and to know as soon as possible if the container is broken: −
Monitor permanently mud return with a gamma-ray tool at the shale shakers while circulating.
−
Never rotate with the drilling string at any stage.
−
Minimize the people working on the rig floor when the tool containing the source is pulled out of the hole.
− If all efforts fail to fish the source and it is decided to abandon the same, it must be protected by a cement plug. −
A gamma-ray log will be taken after the cement job to check that there is no contamination and that the source was not dragged up the hole during the cementing process.
− If at any stage position of the source is not clear, a gamma-ray log will be taken to trace it. −
S.G. Rev-00/09
It must be ensured that the abandonment of such source with exact details as per the depth, date…etc are clearly recorded in the Daily Drilling Report by the Drilling Supervisor on the rig and properly documented in the respective well file by the relevant Drilling Engineer in the office.
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SECTION 5 SIDETRACKING OPERATIONS Sidetracking is creating an exit through openhole or casing to allow a new lateral section to be drilled.
1.
Sidetracking in Open hole Sidetracking through openhole can be done using different techniques as follow
1.1
S.G. Rev-00/09
Cement Plug Method
•
Select the formation which gives the best chance of sidetracking success. This is normally done by analysis of the ROP log. The ideal formation is normally a consolidated formation at the place of best ROP.
•
The minimum distance between the TOF to the Kick-off Point (KOP) is 100 feet and between casing shoe and KOP is 30 ft.
•
Sidetracking in Shale formation is not recommended, because of the high risk of caving.
•
Prior to start any sidetrack operation, ensure first that drill string is in good condition and does not require a tubular inspection, especially after any fishing job.
•
Run in hole with 1000 feet of 2 ⅞" or 3 ½” open ended tubing on drill pipe to the top of fish.
•
Set high compressive strength balanced cement plug on top of fish to cover the distance between the top of fish up to 150 feet above the selected kick-off point depth (KOP). The recipe of the cement slurry should be made such as to obtain very hard cement.
•
In case of losses at the bottom of the hole, several cement plugs may be necessary. In this case, all efforts should be made to cover at least the distance between 150 feet above the KOP down to 100 feet below the KOP with one same cement plug such as to obtain uniform cement plug homogeneity.
•
While waiting on cement, run in hole with milltooth bit and dress TOC to 30 feet above the KOP and circulate hole clean.
•
Test the hardness of the cement by applying 50,000 lbs WOB without rotating the pipe but with a maximum of pumping rate. If no penetration is obtained in such condition, the cement is probably hard enough. If any penetration, WOC a further 8 hours and repeat the cement hardness test.
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•
In both cases, when the cement is hard enough, drill the remaining cement to the KOP required, circulate hole clean, and take a survey with bit as close to bottom as possible and pull out of hole.
Note: In case directional control is required during the sidetracking, RIH enough non-MAG DCs to allow taking a survey prior to POH for sidetracking.
•
RIH the following sidetrack assembly: 1. Tricone bit. 2. Mud motor. 3. Bent Sub (1.1/2° to 2.1/2° depending on hole size). 4. Orienting Sub (In case directional control is required) 5. 1 or 2 non-mag drill collar (In case directional control is requiredLength NMDC' Model depends on angle of hole and direction) 6. Enough HWDP to allow a maximum of 20,000 lbs WOB.
S.G. Rev-00/09
•
Run in hole last 30 feet with low circulation and RPM (Adjust the string length such as to have a full kelly above the RT with the bit on bottom).
•
If directional control is required, orient the tool face in the required direction and start sidetracking.
•
If the well is already a deviated hole the easiest optimum direction for the sidetrack would be on the "Low side" of the hole.
•
If no directional control is required, lock the rotary table and do not allow the string to rotate any more until the kick off is completed.
•
With the rotary table locked and marked, and constant circulation pressure, drill the first 15 feet in 12 hours time at a rate of 1 inch each 4 minutes. Check percentage of cement and formation on the shale shaker.
•
Drill the next 15 feet in 6 hours time at a rate of 1 inch each 2 minutes. Check percentage of cement and formation on the shale shaker.
•
Make the connection carefully ensuring that the string is not rotating. Readjust the pump rates as for above.
•
Continue sidetracking another 30 feet in 6 hours at a rate of 1 inch per minute. Check the percentage of cement and formation on the shale shaker. As soon as 100% of formation is obtained on the shale shaker, increase the WOB to normal drilling condition.
•
Make another connection as previously and drill the next 30 feet normally.
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KOP to TOF = Min 100 ft
Shoe to KOP = Min 60 ft
Volume-2/Chapter-2: Workover Operations
Cement Plug
Fish
Figure 2- 6: Openhole sidetracking cement Plug
Note: The KOP where the first foot of sidetracked hole is drilled is the depth which must be considered for lost hole calculation.
•
Take a survey after a total of 90 feet are sidetracked and compare this survey with the survey taken previously.
•
Continue sidetracking until a total of 5° change of hole angle is obtained, or a total departure from the original hole of 5 feet, whichever comes first. Take a final survey and continue drilling sidetrack hole as per plan.
Note: It is important to ensure always the same pump pressure during the sidetrack operation in order to have always the same "reactive torque" on the drill string. The rotary table being locked during the sidetrack would allow the tool face of the bit to change every time the circulation pressure changes.
•
S.G. Rev-00/09
In case of a vertical hole where the direction of the sidetrack is not critical, RIH with the standard pendulum BHA and drill ahead in normal condition, taking a survey every 90 ft. at the beginning to ensure the hole angle is dropping off. Thereafter only normal surveys are required.
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•
In case the sidetracked hole direction is critical, or in case of deviated sidetracked wells, the required BHA for continuing drilling must be selected according to the hole conditions and the target position.
Note: Remember that a conventional rotary drilling assembly has normally a "righthand roll off" tendency during drilling (tendency to turn the well direction to the right) while turbo-drilling has a "left-hand roll off". This can be considered to help in reaching the target of the deviated hole.
1.2
Openhole Whipstock (Cement Whipstock Method) 1.2.1 General Notes
•
The Cement Type Whipstock although set in open hole conditions, should be set on some type of bottom (i.e., formation, fish, etc.) to prevent it from moving downhole when setting.
•
If required, the cement type whipstock can be oriented to a specific direction.
•
Enough cement is pumped and applied generously around the whipstock and at least 100 feet above the whipstock.
1.2.2 Bottom Hole Assembly
•
Cement Type Whipstock
•
Setting Tool
•
Universal Bottom Hole Orientation Sub (UBHO)
•
Drill pipe joint
•
Pup joints (for space-out if necessary)
Note: The UBHO Sub is required only when orientation is necessary.
1.2.3 Procedure
S.G. Rev-00/09
•
Pick up a single joint of drill pipe and make up the whipstock Setting Tool to the bottom connection.
•
If required, make up the UBHO sub to the top of the drill pipe.
•
Make up the Setting Tool to the whipstock concave by sliding the Setting Tool’s tube over the cementing tube extending through the whipstock’s concave.
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•
Run the whipstock into the hole at a slow, steady rate, 2 to 3 minutes per stand. Fill the drill string every 10 to 15 stands to ensure that the tubes on the whipstock do not plug. Caution: Do not include drill collars in the drill pipe string when setting a cement type whipstock. The small ID of drill collars may cause “flash” setting of the cement.
•
Circulate through the drill pipe string.
•
At 10 ft from bottom, run survey tools on wireline to the UBHO sub, take survey readings and correct direction of whipstock.
•
Pull the wireline from the drill pipe string and lower the whipstock assembly until it rests on the bottom.
•
Connect the cementing line to the drill string. Note: The cementing tube is rated to 3,500 psi. Pump cement at no more than 2 bpm to prevent bursting the tube.
•
Pump the cement to a level approximately 100 feet above the whipstock (see Figure 2-8).
•
Disconnect the cementing line immediately after the cementing procedure is complete.
•
Pick up to the string weight.
•
Pick up 5 to 10 feet and then quickly lower back to the bottom to shear loose from the concave.
•
Once shearing has been verified, pick up the drill pipe string 10 stands (see Figure 2-9).
•
Pull out of the hole, circulating on the way out.
•
Wait on cement to set.
•
Use a drill bit to drill through the cement, above the whipstock down the whipstock’s concave and into the new formation (see Figure 2-10).
•
This run should include a flexible assembly as follows (from top to bottom): 1. Drill pipe string 2. One joint drill pipe
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3. Bit Sub (Minimum length, bored for the float assembly)
4. Drill Bit (Usually PDC or short tooth rotary bit) Caution: Do not rotate stabilizers on the whipstock's concave; this action could cause damage to the whipstock orientation.
Figure 2- 7: Cementing O.H. Whipstock
2.
Figure 2- 8: Releasing Whipstock
Figure 2- 9: Sidetracking
Sidetracking Inside Casing For sidetracking inside casing, two different methods are available:
• S.G. Rev-00/09
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•
To set a Whipstock assembly inside the casing and cut a window in the side of the casing through which the sidetrack is made.
Both the above methods are efficient but the final selection of which to use must be made on the hole condition, as described hereunder.
2.1
Sidetracking through a cut section of casing This method of sidetracking should be used when the casing across the KOP is in poor cemented and/or mechanical conditions, which would not permit the setting of a Whipstock in safe condition.
2.1.1 Standard measures
•
As for sidetracking in open hole, the optimum formation behind the casing should be selected for better chance of success.
•
The very minimum distance of casing to be cut is 60 ft, from which the top 40 feet are reserved for "getting out" of the old hole.
•
The optimum length of cut casing is 75 feet.
•
Distance between the top of fish and the bottom of the cut section of casing is minimum 50 ft.
2.1.2 Section mill description The section mill cuts through casing with three cutter blades working like single-point tools and then mills the casing with six blades at a speed of up to 8 ft/hr. The mill features is a piston actuated cam that locks the cutting blades open during operation and automatically closes them when pump pressure is removed. When cut out is complete, annular flow through the tool is more than doubled resulting in a pressure drop of about 200 psi and a noticeable increase in pump strokes.
2.1.3 Cutting section (window) in casing
S.G. Rev-00/09
•
Run in hole with section mill to the desired depth, filling string every 10 stands.
•
Rig up slickline.
•
RIH with 1.11/16" GR/CCL and correlate driller depth.
•
Pull out of hole and rig down slickline.
•
Rotate section mill at 60 RPM without pump pressure.
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S.G. Rev-00/09
•
Turn pump on and build up pressure to 1500-2000 psi. Record pressure and pump speed and hold pressure as even as possible during cut out.
•
Cut the distance of casing required. During this operation, as casing joints are normally 40 feet long, a maximum of 1 casing collar is to be cut. POOH.
•
When the cut out is completed, a pressure drop of about 200-250 psi will be noticed and the pump speed will increase.
•
After the cut out is made, allow the tool to rotate for about 10 minutes to clean up the cut.
•
Increase RPM to 100-125.
•
Gradually apply 4000-8000 lb/ft weight.
•
Maintain an even weight while milling rather than allowing the weight to "drill off" before adding more weight.
•
After casing has been milled, reduce weight to 2000 lb/ft.
•
Turn the pump off.
•
Rotate 2 to 5 minutes and stop rotation.
•
Pull into casing slowly and continue POOH.
•
RIH with 600 feet of 2 ⅞" or 3 ½" open ended tubing on 3 ½” DP down to at least 30 feet below the base of the cut casing section. The ideal would be to set the base of the cement plug right at the top of the fish.
•
Set a balanced cement plug.
•
Clean out to top of cement as; the KOP will be 10 feet below the upper section of the casing cut.
•
For controlled azimuth side tracks the survey to be taken will require a single shot Gyro tool or continues Gyro tool due to the magnetic interference from the casing string.
•
Proceed with the same sequences as described above in “Cement Plug Method” including all notes and remarks.
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ADCO DRILLING MANUAL
Cut window = 75 ft Optimum (60 ft minimum)
Volume-2/Chapter-2: Workover Operations
Bottom of window to TOF = 50 ft
Cut Window
Fish
Figure 2-10: Cut window in casing with section mill
2.1.4 Mud conditioning for milling
•
Minimum annular velocity of 120 ft/min.
•
Turbulent flow is required to clear the cuttings and avoid the chance to "bird nest" in the wrong place such as above DCs.
•
If well conditions permit, use water based drilling fluid.
•
Increase the yield point of the mud with a moderate increase in viscosity.
•
Keep a minimum of 60-70 cp viscosity.
2.1.5 Removal of cuttings
•
S.G. Rev-00/09
Make sure that all tubulars run with the section mill are full bore because restrictions can cause fluid volumes problems preventing cutting removal and could affect the hydraulically operated section mill.
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2.2
•
Additional nozzles may be installed, pointing up the hole, directly above the section mill.
•
Have a magnet on the flow line.
•
Surface arrangement should be available for flushing flow line to avoid plugging.
Sidetracking in casing with Conventional Whipstock This method of sidetracking should be used when the casing across the KOP is in good cemented and mechanical conditions (only 20 to 30 feet of good casing are required to allow a safe setting of the Whipstock).
2.2.1 Standard measures
•
The optimum formation behind the casing should be selected for better chances of success.
•
The minimum distance required "to get out of the old hole" is 30 feet.
•
There is no need for a special distance between the top of fish (TOF) and the setting depth of the bridge plug.
•
This sidetrack CAN NOT GO WRONG, even if the sidetrack is made through two strings of casing (which is not always the case in open hole technique sidetracks).
2.2.2 Whipstock mills
•
Starting Mill: Used to lower the whipstock into the setting position and to cut the initial window.
•
Watermelon Mills: Typically run above the window Mill and drill pipe to assist in opening the window.
•
Window Mill: Used for cutting windows as a follow-up to the Starting Mill.
•
String Mills: Used on the final run above the Window Mill on a drill collar.
•
Tapered Mill: Used when problems (such as flattened, split, or bent casing) are encountered; not used to cut the formation.
2.2.3 Procedure
• S.G. Rev-00/09
Make a round trip with scraper across the packer setting area.
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•
In case of directional holes which require azimuth control of the side track, the Whipstock packer has to be set on DP to allow orientation of the Whipstock by means of an orienting tool.
•
In this case the BHA would be:
•
•
O
Permanent Bridge Plug (with aligning pins for the Whipstock).
O
Hydraulic setting tool (with ball installed on the seat as the ball will not pass the orienting sub above it).
O
Orienting sub (with mule shoe guide).
O
HWDP and DP.
The setting procedure will be as follows: O
Run in hole with above BHA to packer setting depth.
O
Fill string every 10 stands.
O
Orient the packer into the required direction using single shot gyro instrument.
O
Set the permanent packer by applying pressure.
O
Release the setting tool by pull shearing the release pin.
O
Pull out of hole.
In wells where directional control of the well is not required, the packer can be set on DP as said above, but without having to orient the string, or can be set on electric wireline.
Note: It is advisable to set the packer about 10 feet above a casing collar such as having the Whipstock (the later window) in smooth casing.
•
With the permanent packer set, run in hole with Whipstock assembly # 1 as follows: 1. Casing Whipstock with its latching device assembly at bottom. 2. Starting mill shear pinned to the Whipstock.
•
S.G. Rev-00/09
3. HWDP and DP. Fill the string every 10 stands.
•
When this assembly is on top of the permanent packer, the Whipstock is latched/secured automatically onto the packer. In case of required directional control, the Whipstock is automatically oriented by means of the aligning key which is in the permanent packer, prior to being latched / secured. DO NOT ROTATE THE PIPE in any attempt to help the alignment.
•
The shear pin connecting the nose of the "starting mill" is then sheared-off by applying weight (normally 12,000 lbs).
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•
Cutting the window is made by normal rotation of the mill and slacking-off the string at a rate of one inch every 15 minutes over a distance of 2 to 3 feet (observe the RT torque carefully). The tapered shape of the "starting mill" by "sliding down the slope of the Whipstock, is pushing the cutting edge of the mill against the casing wall. Cutting will progress until the bottom nose of the starting mill touches the wall of the casing. The string is pulled out when the starting mill begins to take weight. Note: A magnet should be installed in the mud ditch such as to collect steel cuttings and evaluate the volume of casing wall cut-off. Check also for cement and formation cuttings.
•
The BHA # 2 to be as follows: 1. Diamond mill. 2. Watermelon mill. 3. 15 joints of HWDP.
Note: The reason for the 5" HWDP is because a flexible BHA is required.
•
At the top of the Whipstock, start reaming at approximately 90 RPM. Ream the "starting cut" made previously maintaining smooth cutting and acceptable Rotary torque. When the torque has disappeared the diamond mill starts to cut its own window. Increase RPM to 130 and adjust WOB for smooth torque until 10 to 15 feet of formation is drilled. POOH.
•
Run in hole the following reaming assembly # 3: 1. Taper mill 2. String mill. 3. Watermelon mill. 4. Normal size DCs (use non-mag in case of directional control).
S.G. Rev-00/09
•
Continue drilling until 5° inclination is obtained or 5 to 10 feet departure from the old hole is obtained, whichever comes first, and POOH.
•
RIH building-up assembly consisting of Rock bit, N.B. stabilizer, and DC's.
•
Drill 70-100 ft. Take survey and if 5° inclination is achieved POH, otherwise drill more to get 5° inclination or + 10 ft departure from old hole. POOH.
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2.3
•
RIH with drop off assembly consisting of rock bit and string stab at 60 ft above bit and resume normal drilling operation.
•
In case of azimuth control, remember that magnetic interferences of the string of casing (and the fish) will require the use of the single shot gyro surveying instrument until approximately 40 feet distance is reached.
Sidetracking in casing with Single-Trip Whipstock The single-trip whipstock is hydraulically set in the casing, eliminating the need for a false bottom. This system enables setting, orienting the whipstock, detach the milling assembly, mill a full-size window, and drill a pilot hole all in a single trip.
2.3.1 Milling fluids
•
Utilize the mud which will be used to drill the next hole section. The fluid properties planned for the next section are usually adequate for hole cleaning during milling.
•
Consider the fracture gradient at the previous shoe if there is a risk of milling into an un-cemented annulus.
2.3.2 Wellbore preparation
S.G. Rev-00/09
•
Make a round trip with scraper and full gauge, rough outer diameter string mill to ensure that the wellbore is clean/free of debris.
•
In deviated holes or in special drift casing strings, scraper plus two full gauge mills spaced out with short DC is recommended.
•
Pump viscous pill and work scraper at the whipstock setting depth. If there is a lot of cement to be drilled, consider using adequate scraper. Check the string mill gauge when out of the hole, if there is evidence of junk in hole when this assembly is pulled, an additional cleanout run including junk basket is recommended.
•
Be sure that casing across whipstock’s setting depth is in good cemented and mechanical conditions (only 20 to 30 feet of good casing are required to allow a safe setting of the Whipstock).
•
The whipstock should be positioned so that the window is milled through the wall of the casing joint, and not across a casing collar. This milling practice will help avoid the possibility of parting the casing string if the cement behind the casing is poorly set and unconsolidated, if a CBL is available, avoid centralizers.
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•
The optimum formation behind the casing should be selected for better chances of success.
•
There is no need for a special distance between the top of fish (if any) and the whipstock setting depth. However all precautions should be made to get as far from the original hole as possible.
2.3.3 Bottom hole assembly
•
Lead mill.
•
Full gauge string mill.
•
One joint of drill pipe
•
Orienting sub or MWD.
•
Drill collar or HWDP.
•
Concave.
•
Hydraulic Anchor and Hydraulic Packer (packer is optional).
2.3.4 Running in hole
S.G. Rev-00/09
•
The whipstock engineer must be on rig floor while making up and running the system in hole.
•
Make certain that the hole is full of fluid prior to tripping.
•
Slowly lower the system into the hole ensuring that whipstock and milling BHA do not hang up on the Blowout Preventer or casing top.
•
Run in hole slowly. The maximum speed for running in the hole with the system is two minutes per stand.
•
Fill the string every 10 stands while RIH.
•
Use back-up tongs properly while making up the drillstring. If the drillstring turns sharply below the drill floor, this can fatigue the shear screws resulting in premature shear between the milling BHA and the whipstock.
•
Set down and pick up easy on the slips, any jolting pipe movement will fatigue the shear attachment bolt.
•
Should circulation need to be established at any time while running in hole, monitor the flow rate as not to accidentally set the Whipstock (whipstock engineer must be on rig floor)
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•
Run in hole slowly until approximately 30 feet of setting depth.
•
Move the drillstring up and down 5 to 20 feet, recording accurate string weights and removing torque from the drillstring.
•
Place the Whipstock at setting depth.
2.3.5 Orienting
•
The Directional Driller should be on rig floor during the entire process.
•
Determine orientation of the whipstock by wireline conveyed Gyro or flowing through the MWD.
•
The whipstock may be oriented using MWD in inclined holes (greater than ~ 5 degrees), or using a surface readout gyro in near-vertical holes.
2.3.6 Setting the whipstock
•
The whipstock engineer must be on rig floor during the entire process.
•
Slowly increase the pump flow rate and set whipstock as by manufacturer’s instructions.
•
Turn off the pumps and slack off the drillstring. The drillstring weight will decrease indicating the whipstock is set.
•
With the whipstock set, move the drillstring down applying WOB to shear the milling BHA from the whipstock. Weight in excess of the shear value may be required to shear the attachment bolt in deviated wells.
•
Once the milling BHA shears from the whipstock, apply an additional weight (~15,000 lbs) above the recorded shear WOB to ensure the whipstock is set.
•
Lift the drillstring 10 feet above the top of the whipstock in preparation for milling.
2.3.7 Milling procedures
S.G. Rev-00/09
•
Do not commence milling while displacing to a different mud system. The variations in standpipe pressure can make it difficult to monitor and control the milling operation.
•
Install ditch magnets (two to four magnets) to catch metal junk.
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S.G. Rev-00/09
•
Begin rotating the string slowly; increase the RPM to appropriate milling speed (50 to 70 RPM).
•
Reciprocate the string up and down, recording the pick-up and slack-off string weights, free rotary torque, and pump pressure.
•
Lower the string to commence milling. Once the Lead Mill reaches the top of the whipstock, there will be an immediate increase in rotary torque.
•
Begin milling with approximately 1,000 Ibs WOB down on the Lead Mill for the first 6 inches of milling depth.
•
Slowly bring the RPM up to the recommended range.
•
Slowly increase the WOB until a rate of penetration of one to six feet per hour is achieved. After the Lead Mill passes the bottom of the concave, a significant increase in ROP should be observed.
•
Continue to mill with enough weight to maintain a minimum ROP of 1 ft/hr. The optimum ROP from this point on is 2 to 4 ft per hour.
•
Check the fluid returns frequently for the presence of cement and/or formation.
•
When the casing window has been milled and the Lead Mill is out into the formation, increase the WOB as necessary to drill the formation. The optimum milling distance is to mill formation beyond the end of the concave.
•
Make sure that the string mill has completely passed through the window.
•
Once the total milling depth has been reached, the WOB has been milled off, and "bottoms up" circulation has been achieved, reduce the pump flow, RPM, and start reaming the window.
•
Continue reaming up and down through window, recording torque and string weights, until torque does not increase while reaming.
•
Pump Hi-Vis pill as required and circulate wellbore clean.
•
Drill 1 – 1.5 ft extra rat hole to ensure bottom is free of junk.
•
Stop pumps and rotary and slowly slide the BHA through the milled window; there should be no decrease in string weight.
•
Pull the Milling BHA out of the hole and gauge mills to verify window’s condition is acceptable.
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2.3.8 Drilling ahead
S.G. Rev-00/09
•
Run in hole with drilling bottom hole assembly.
•
The driller must always be aware of whipstock top and bottom depths and orientation. Post this information clearly.
•
Always orient the bit towards window opening when tripping in/out with directional BHA. Enter the window slowly, watching weight indicator.
•
DO NOT ROTATE BIT (particularly PDC bits) OR STABILIZERS ACROSS THE WHIPSTOCK FACE. Know the positions of these items with respect to the whipstock at all times.
•
DO NOT CIRCULATE THROUGH MOTOR WHEN BIT IS ACROSS THE CASING WINDOW.
•
Be particularly aware of items in the drill string above the bottom hole assembly (especially reamers), which are sometimes forgotten. None of these items should be rotated over the whipstock, and caution should be used when POOH these items through the window.
•
The Directional Driller must be on site every time these items are tripped through the window.
•
If the bit could not pass easily through the window, run in hole with dressing assembly.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 6 REMEDIAL CEMENTATIONS Remedial cementation during workover operations may be required in the following cases.
•
Repair primary cement job.
•
Plug back old/watered out holes.
•
Well abandonment.
•
Directional requirements/sidetracking.
•
Casing leaks.
•
Abandon non productive or depleted zones.
•
Seal off lost circulation zones.
The remedial cementing techniques typically used during workover operations are:
•
Balance Plug cementing.
•
Cement through EZSV.
•
Cementing through coiled tubing.
•
Macaroni Tube.
The matrix below presents the different technique that might be used for each application: Table 2- 6: Techniques used for different remedial applications
Technique Purpose
Balanced Plug
Squeeze with EZSV
Coiled Tubing
Macaroni Tube
Repair primary cement job-channels
X
√
X
X
Cement Top Job
X
X
X
√
Well abandonment
√
√
√
X
For directional requirements and sidetracking
√
X
X
X
Casing leaks.
√
√
X
X
Abandon non productive or depleted zones
√
√
√
X
Selective Shut-Off for Water Injection
X
√
√
X
Shut-off fluid migration into production zone.
X
√
√
X
Plug back existing perforations
√
√
√
X
S.G. Rev-00/09
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1.
Balanced Cement Plugs 1.1
S.G. Rev-00/09
General Notes
•
Plugs are set by “spotting” cement through tubing tail pipe with a ported side outlet sub on bottom. Length of tubing tail pipe should be equal to the plug length plus 30 %.
•
2 ⅞" tubing is used in slim holes of 8½” diameter or smaller. 3½” tubing is used in larger holes. Coupling OD’s of the tubing must be minimized.
•
If no tubing is available, 3½” drillpipe may be considered. The tail length should be equal to the plug length plus 30%.
•
Caution should be taken not to plug the cementing string while RIH.
•
The minimum thickening time should be the job time plus 1-2 hours safety margin.
•
Cement slurry should be mixed in a batch mixer. If cement is mixed using a re-circulating jet mixer, dump the slurry until the correct slurry density is achieved.
•
If a hole is badly washed out, it is better to set 2 short plugs over the washed-out interval rather than to try to cover the interval in one go with a large amount of cement. Gauge hole sections are preferred for cement plugs.
•
When setting abandonment plugs in potential loss zones it is better to set a cement plug in two stages, i.e. first a small one, which acts as a carrier for the next plug.
•
Balance Plug length should not exceed 700 ft.
•
Pull the pipe back to at least 500 ft above theoretical top of plug before commencing reverse circulation. This does not apply if a series of plugs are to be set continuously. O
Always calculate the loss in hydrostatic pressure before using water or base oil ahead of a cement plug. Consider gauge hole for calculations.
O
Never stab the cement string back into the plug following displacement.
O
Always use spacers ahead and behind the slurry. Use spacer volumes to give at least 100 ft. linear height in the tubing and annulus.
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1.2
S.G. Rev-00/09
Spotting Procedure
•
Make up and run cement string to the bottom of the plug depth and circulate hole clean.
•
Pump a low viscous pill, of the same weight as the mud.
•
Pump weighted spacer ahead. The quantity of the spacer depends on hole size.
•
Pump the mixed cement slurry.
•
Pump sufficient spacer behind the cement to balance pre-flush.
•
Displace with mud to balanced position where level of cement slurry and spacer inside tubing are the same as annulus. O
Do not over displace.
O
Do not reciprocate the pipe during cement displacement.
•
Pull back slowly (20 ft/minute) to at least 500 ft above theoretical top of the plug. Pulled out stands shall be hammered, cleaned and drifted after lay-down on racks.
•
Reverse circulate 2 times string capacity to clean the cement string (except if tail pipe bottom is below Nahr Umr), Drop two 6” Foam balls (with minimum 15 bbls of mud spacing) and circulate through string with maximum allowable pumping rate for 1-1/2 string volume.
•
In case if tail pipe bottom is below Nahr Umr, POOH above top of cement (at least 500 ft), drop two 6” Foam balls (with minimum 15 bbls of mud spacing) and circulate through string with maximum allowable pumping rate for two cycles. O
Reverse circulation is not permitted across Nahr Umr to avoid string plugging by shale cuttings/cavings.
O
Reverse circulation may induce losses, or cause differential sticking of the cementing string.
O
6” foam ball is applicable for all sizes of Drill pipes or Tubing between 2-7/8” to 5-7/8”.
•
Close pipe ram and squeeze cement at a maximum of 0.65 psi/ft, hold pressure for 6 hours. This step is applicable only if mentioned in the program.
•
Bleed off (if there is any pressure) & POOH. During POOH Hammer every stand. Lay down, clean & drift if any joint is not cleaned by foam balls. Inspect, clean & drift all the x-overs used in cement string.
•
Wait on Cement as required.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
1.3
Balanced Cement Plugs for Kick-off Following are general notes for setting balanced cement plugs for kick-off purpose;
1.4
•
In soft formation e.g. Zone A or B, use 125 pcf normal G cement as kickoff plug.
•
For kick-off plugs in hard or medium hard formations, Sand cement slurry with 142 pcf weight or Metallic ribbon reinforced slurry (e.g. Durastone) with 147 pcf weight shall be used.
•
Cement slurry should be mixed properly in the Batch mixer to get the designed uniform slurry weight.
•
In all types of kick-off plugs, a weighted spacer of 90 pcf shall be used ahead and after of cement and volume shall be calculated as per balance plug calculations.
•
If the plug length is more than 600 ft, cement slurry of 125 pcf shall be spotted below it as a carrier / foundation for the kick off plug.
•
The cement string to be circulated clean by using 2 foam balls spaced by mud as mentioned in clause 1.2 above.
•
For kick-off plugs, cement shall be tagged and dressed as per program.
Balanced Cement Plug in Deviated Wellbore A successful cement plugs in a deviated (30º-75º) wellbore require the following conditions to be met.
S.G. Rev-00/09
•
Reduce the density differential between the drilling fluid and cement.
•
Increase the yield point or gel strength of the drilling fluid below the cement plug.
•
Place high viscous pill or stable reactive spacer pill between the cement and the drilling fluid.
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
2.
Squeeze Cementing 2.1
Cementing through EZSV Cement squeeze through retainer may be used when circulating cement behind casing, between two sets of perforations is required.
2.1.1 Cement Squeeze through retainer for high injectivity.
•
Rig up W/L BOP on 7" shooting nipple and test to 1000 psi.
•
Set EZ-Drill cement retainer between the two sets of perforations with W/L (avoid setting cement retainer against casing collar or the final production packer setting depth).
•
RIH EZ stinger with 1000 ft. of 2 ⅞" tubing on Drill pipe.
•
Sting into EZ cement retainer. Check circulation through retainer, by repeating volumetric communication test for 15 minutes each way. If communication is not established as before, inform town.
•
Keep stinger in retainer if injection rate is more than 2 BPM at 0.65 psi/ft or 1500 psi surface pressure.
•
R/U circulating head and test cement lines to 3000 psi for 15 minutes.
•
Mix and pump the designed cement volume and additives as per cement recipe.
•
Circulate ½ volume of cement through retainer at maximum 0.65 psi/ft. (do not squeeze for more than 15 minutes if unable to circulate the above cement volume).
•
Sting out and spot the rest of cement as balanced plug on top of EZ-Drill retainer. Check for losses during job.
•
POH 10 stands or to 50' below top of liner (above all perforations) whichever is the case. Reverse out at a maximum pressure of 0.65 psi/ft or 1500 psi whichever is less recording any losses. POH one more stand.
•
Close rams and squeeze cement at 0.65 psi/ft or 1500 psi whichever is less until lock up pressure is reached then increase pressure to 0.75 psi/ft. or 2000 psi whichever is less. Hold pressure for 6 hours.
Note: If lock up pressure is not achieved, release pressure, check for back flow and POH. S.G. Rev-00/09
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•
Release pressure, check and record back-flow, open rams, POH.
•
RIH with appropriate bit and two junk subs, tag top of cement, clean out to 50 ft. above top perforations.
•
After total 24 hours WOC, drill out cement, cement retainer, cement and RIH to PBTD. Circulated hole clean, POH.
Note: If cement is still soft after 24 hours, stop DOC, circulate one cycle and W.O.C. to complete 30 hours prior to clean out to PBTD.
•
Trip with bit and scraper to PBTD. Circulate hole clean and displace with new clean fluid.
•
Repeat the communication test.
2.1.2 Cement squeeze through retainer for low Injectivity Formation To be made when communication rate is established at more than 0.5 BPM and less than 2 BPM at 0.65 psi/ft or 1500 psi surface pressure.
S.G. Rev-00/09
•
Rig up W/L BOP on 7" shooting nipple and test to 1000 psi.
•
Set cement retainer.
•
RIH with stinger and 1000 ft. of 2 ⅞" tubing on DP.
•
Circulate at 10 ft. above retainer for 15 minutes. Record circulation rate and pressure. Sting into retainer and establish injection rate at 0.65 psi/ft or 1500 psi whichever is less. Record rate of injection for 15 minutes.
•
Sting out of retainer, circulate for 15 minutes.
•
R/U circulating head and test cement lines to 3000 psi.
•
Mix cement and pump down D/P the following: O
5 Bbls 15% HCL with additives (this should be done in case of iniectivity less than 0.5 BPM, otherwise acid is not necessary).
O
5 Bbls fresh water
O
Cement with additives as per cement recipe
O
5 Bbls fresh water.
O
Displace cement to 5 Bbls inside DP above the drillpipe to minimize U-tube prior to sting in (use choke manifold if required to control U-tube effect).
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3.
•
Sting into retainer, bullhead by pumping down D/P at 0.65 psi/ft. or 1500 psi whichever is less for a maximum duration of 15 minutes or 1/2 the cement volume or lock up pressure whichever comes first.
•
Increase surface pressure gradually until reaching to 0.75 psi/ft. if necessary.
•
Sting out of retainer and spot the remainder of cement as balanced plug of cement above retainer.
Cementing Through Coiled Tubing 3.1
Applications Cementing through coiled tubing has different applications as follows:
3.2
3.3
S.G. Rev-00/09
•
Isolate / Abandon perforations during multi-zone testing.
•
Shut off gas or water production zone.
•
Squeeze- off perforations riglessly prior to rig move.
•
Horizontal hole abandonment
Slurry Design Criteria
•
Low Rheological Values (PV & YP)
•
Laboratory mixing energy = Field mixing energy
•
Good slurry stability
•
Minimum gellation under static downhole condition
•
Safe thickening time (Optimized)
Placement Procedure
•
Run with suitable gauge cutter to reconfirm Coiled Tubing accessibility.
•
R/U and RIH with Coiled Tubing to the desired plug depth.
•
Circulate coiled Tubing while RIH.
•
Perform pull test every 3000 ft.
•
Slow down Coiled Tubing running speed at any restriction.
•
Circulate at the plug setting depth and at the same time observe the well stability.
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4.
•
Pump 5 bbls fresh water followed by 7 bbls weighted spacer ahead of the cement recipe.
•
Pump the designed cement slurry until 2 bbls of cement exit from the coiled tubing nozzles.
•
Pump 5 bbls weighted spacer followed by 5 bbls fresh water.
•
POOH w/ Coiled Tubing at a speed maintaining 2 bbls of cement coverage above C.T nozzle.
•
Continue displacing and spotting cement, POOH to 100 ft above the T.O.C.
•
Circulate above the top of cement.
•
Wash down to the planned T.O.C.
Squeezing Off the Aquifers Sealing off the aquifers (Dammam, UER and Simsima) with cement is normally done prior to running and cementing tie-back casing. The objective of sealing off the aquifers prior to running the tie-back casing is to protect the casing from the corrosive action of aquifer water, and to avoid the erosion resulting from the cross flow between the different aquifer perforations of Dammam, UER and Simsima.
4.1
Procedure
• •
Isolate the reservoir perforation with either cement plug or Bridge Plug.
•
Spot 500 SKS class "G" cement with a light weight cement (+ 95 pcf) as balanced plug. POH 15 stands and flush string with location water.
• •
POH another 10 stands and W.O.C 6 hours.
•
RIH bit and clean out casing down to top of liner or as specified in well programme.
•
DO NOT test the squeezed off perforations. Observe well for losses or flow.
RIH with 1000', 2 ⅞" tbg. tail pipe on 3 ½" DP to 50' below aquifer perforations.
RIH with cementing string with circulation, tag T.O.C and repeat steps above as required.
Note: If losses are more than 15 BPH, another cement plugs should be spotted as above to cure losses. S.G. Rev-00/09
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SECTION 7 SETTING INTERNAL CASING PATCH This technique could be used in some water supply wells to seal off holes in corroded surface casing to prevent sand entry to well. A corrugated pipe 1/8" thick and plated with resin was mechanically expanded and set across the corroded part of casing using special setting tool after the holes being squeezed of with cement to isolate the aquifer water from contact with the patch.
1.
2.
Well Preparation •
RIH with bit and casing scraper. Clean out casing ± 100 ft below expected leak point.
•
Circulate with 54 pcf viscofied emulsion or as specified in well Program and test casing to 500 psi. If leaking, proceeds to next step .
•
Run casing packer and locate leak in casing by selective testing at 500 psi.
•
Cure leak with ± 200 sks cement, (volume of cement will be determined based on injectivity rate). Repeat steps above.
Procedure •
Lay out and prepare the casing patch (Welder to weld sections of patch to obtain the required length).
•
Pick up setting tool, extension bar and safety joint assembly.
•
Pick up patch with tugger and strip onto extension bar.
•
Make up cone, collet, and bullnose assembly, grease liberally.
•
Lower patch into well and apply epoxy to outside of liner.
•
Make up BHA comprising of:
•
1. Casing Patch 2. Setting tool 3. Single drill pipe 4. Impact sub 5. Single drill pipe 6. Drill pipe pup joint (master joint if required) 7. Drill pipe to surface Run in hole with patch (Medium speed whilst running to depth).
S.G. Rev-00/09
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•
Pick up kelly and position patch (Taking up and down string weight).
•
Slowly pressure up drill pipe, to set patch, Tool will stroke at approximately 1000 psi. Continue to pressure to 3000 psi, to assure full stroke.
•
Bleed to zero pressure and leave bleeder open.
•
Pull tool open at string weight. When tool is open, overpull will be encountered. Continue to pull cone and collect through patch and set some. Overpull will be approximately 40 klbs to 70 klbs, dependent on the condition of the casing. Pull out of top of patch.
•
Drop bar and shear out impact sub pin.
•
Pull out, break and lay down tools.
•
Test casing to 500 psi. If OK proceed to well programme.
Important Note: Setting casing patch will result in reducing the casing inside diameter by more than 0.25 inches. (I.e. 13.3/8 csg patch will reduce the ID of 13.3/8, 68 lbs/ft from 12.415 to 12.115 so that 12.1/4 bit will not pass).
S.G. Rev-00/09
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ADCO DRILLING MANUAL Volume-2/Chapter-2: Workover Operations
SECTION 8 SECURING WELL WITH SHALLOW SET CASING PACKER 3.
When to Secure the Well Securing the well with kill string and casing packer hanged at shallow depth is required prior to performing the following operations.
4.
•
Repairing or changing a BOP element which would not allow shutting-in the well in case of a kick.
•
Repairing of the upper casing or tubing spool which would not allow shutting-in the well in case of a kick, even if the repair does not require any welding or torch cuttings.
•
Changing the upper casing or tubing head spool.
•
Any welding or torch cutting on the wellhead, even if the fluid in hole does not contain hydrocarbons, and the well is overbalanced with drilling fluid
•
Any urgent well suspension needs.
Minimum Barriers Requirements It is preferable to carry out the required wellhead repairs immediately after a remedial cement jobs or liner cementing job. Refer to the table bellow for the minimum barriers requirements: Table 2- 6: Techniques used for different remedial applications
Water Injectors (Except Bab Mid Dip Injectors)
Oil Wells (and Bab Mid Dip Injectors)
Gas Wells Producer, Injectors
2 Barriers
3 Barriers
3 Barriers
(1 Mechanical and 1 Hydraulic)
(2 Mechanical & 1 Hydraulic)
(2 Mechanical & 1 Hydraulic)
Cemented casing with non drilled shoe track is a Barrier that can substitute the 2 Mechanical Barriers
5.
Safety Precautions Prior to commencing welding / cutting operations after removing old tubing head spool, the following safety measures must be considered as minimum:
• S.G. Rev-00/09
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6.
•
Clean well cellar and cover with dry sand.
•
Displace the top 5 ft inside casing with foam, circulate through wing valves. Check for any effluents.
•
Safety officer (drilling) to confirm the cellar is free of gas prior to any welding.
•
Issue hot work permit
Securing Well Procedure This operation must be planned to be carried out during a programmed day time trip (bit change or POH / RIH open ended pipe after cement job).
•
Make up the 9 ⅝” casing packer.
•
Make up the SC-SSSV onto the top of casing packer. Ensure that the threaded joint between the seal mandrel and the upper body of the SC-SSSV is only hand tight. Check the rating of the safety plug shear pin if rated to 1500 or 3000 psi, and record same in daily report (Note that the 3.72" size SC-SSSV uses only 1700 psi shear pin).
•
Install the DP rubber wiper plug over the string to avoid dropping of foreign matter on top of the packer and RIH casing packer to approximately 300 feet below rotary table. Break circulation a few minutes. Record the string handling weight with and without circulation.
•
Set the casing packer and pressure test above the packer to 2000 psi. Slack off the total string weight of string below packer, after the pressure test.
•
The casing packer mandrel must have adequate strength to support the weight of drill pipe or tubing string. The 9 ⅝” casing tensile and burst capacity must be strong enough to withstand the addition of the string weight below the packer and the pressure test load above the packer, even if the casing is not cemented behind.
•
As the SC-SSSV is a combination of safety valve and back-off safety joint:
S.G. Rev-00/09
1.
Apply left hand rotation to close the balanced valve inside the SSC tool. At this stage the SC-SSSV being closed will retain any amount of pressure from below the packer AND ONLY 1500 or 3000 psi pressure from above because of limited shear rate capacity of the safety plug inside the SSC tool.
2.
By applying further left hand turns the string will unscrew and release from the safety joint. A total of 20 turns are required to close and unscrew the 3.72" size SC-SSSV while 22 turns are required for the 4.3/4" and 6 ⅛" SC-SSSV.
3.
Pick up one foot and pressure test the annulus above the packer to 1000 psi to ensure the SC-SSSV is closed. Spot clean viscous mud pill above
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ADCO the packer (about 25 bbls in case of 9 ⅝” DRILLING MANUAL exact backed-off string weight and POOH.
casing).
Record the
Volume-2/Chapter-2: Workover Operations
•
Proceed with the required repairs or other work to be carried out after having taking all surface safety precautions, like removing/ cleaning all hydrocarbon fluids from the cellar, issuing Hot Work Permits if welding or torch cutting, etc. are required, or proceed with well abandonment program after closing the BOP, if this is the case. Notes:
Any welding on wellhead or casing has to be done by Production Operations Division's certified welder.
O
All welds on casing must be X-rayed and approved by Production Operations Division before proceeding further with the job.
O
O
Production Operations Division must be notified 24 hours in advance if any welding on casing is required.
O
If any component of the BOP stack or the wellhead has been removed, opened, or changed, each of above element must be re-pressure tested after nippling up.
•
When the repairs are completed, or the temporary abandonment is over; RIH the same backed off string to the top of the SC-SSSV above the casing packer. Pick up the Kelly and break circulation a few minutes. Engage the mandrel inside the SC-SSSV without circulation. Use the drill pipe rubber wiper plug around the string while RIH to prevent dropping of foreign matters down the hole on top of packer. O
Apply same amount of right hand turns as in disconnecting step to reconnect and to open the balanced valve inside the SSC tool and equalize pressure on both sides of the packer.
O
Unset the casing packer and circulate bottom up to ensure the hole is safe.
Notes:
•
O
If unable to unset the casing packer because the SC-SSSV is not opened, so that the pressures above and below the packer are not equalized, pressure up the string to the shear pin capacity and pump out the safety plug then unset the packer Circulate bottoms up to ensure hole is safe.
O
When necessary to perform wireline operations through the SC-SSSV after it is re-opened, the safety plug in the bottom of the valve can be knocked out with a sinker bar, this would provide an unobstructed opening through the tool. It is also possible to pump out this plug when the valve is closed as already said in note above.
POOH casing packer to surface without rotating the string. Lay down SCSSSV and casing packer and proceed with program.
Printed on: 19/08/2008
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