Section 1 -introduction 1-1

Section 1 -INTRODUCTION

SECTION1: Introduction 1.1 Drilling and Completion History SECTION2: Well Productivity – Fundamentals 2.1 Well productivity – Fundamentals of Petroleum reservoir 2.2 Formation damage – Control/Prevention 2.3 Sand Control 2.4 Pressure losses SECTION3: Casing and Tubing 3.1 Pipe characteristics SECTION4: Completion Equipment 4.1.Blast joint 4.2 Sliding Sleeves 4.3 Crossover connections 4.4 Double Pin Subs 4.5 Couplings 4.6 Flow Couplings 4.7 FlowTubes 4.8 Pup Joints 4.9 Seal Rings 4.10 Safety subsurface equipment 4.11 Mule Shoes 4.12 Landing Nipples 4.13 BULL PLUGS/BULL CAPS AND OTHERS 4.14 GAS LIFT EQUIPMENT 4.15 Telescopic Subs 4.16 Packers SECTION5: Surface Equipment 5.1 XMAS tree SECTION6: Artificial Lift 6.1 GasLift 6.2 Rod Lift System 6.3 PCP 6.4 ESP 6.5 Plunger Lift

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Well Completion

SECTION 1 INTRODUCTION

Section 1 -INTRODUCTION

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SECTION 1 - INTRODUCTION 1.1. Why a Completion Since the early days of the oil industry, techniques and knowledge have continuously evolved thanks to a better reservoir understanding and a more adapted engineering. Progressively the oil industry became a science rather a matter of feeling. In the early days of the oil industry, reach deep reservoirs was almost impossible due to the lack of technology, missing of harder materials, lack of knowledge about the reservoir, Etc. But at that time, also, there was no need to do so because of low oil demand. First oil producers were not much concerned about Safety and Environment or reservoir damage. Wells where bored where the oil spilled by itself and the technique used to bore and produce oil wells was similar to the one used for water wells. Wells were made by bailing and pilling until an initial blowout, driving to fast reservoir gas depletion. The production was gathered by spill pits around the well. Once the reservoir pressure, dropped, below the hydrostatic pressure it was needed a production method by the means of artificial lifting techniques (This explain partially why most old oil wells were equipped at an early stage with beam pumps). As the demand on the oil market growth, the development of oil industry increased, at this moment, it was realized that preserving from a fast gas cap pressure draw down was an efficient, cheap way of keeping a well flowing efficiently. Casing and tubing concept were introduced for this purpose allowing then to produce wells under pressure. In the beginning the development of new techniques was slow, but as scientific research provided new concepts it was possible to develop several tools and methods to understand what was going on down hole and how to enhance desired or avoid undesirable behavior on wells. The word Completion is the term which designs the action of equipping a well with the adapted tubular, isolations, and flow control equipment to achieve the most efficient way of producing it for long term.

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Well Completion

1.1. DRILLING AND COMPLETION HISTORY The following dates, sequences of progress and other numbers are approximations 1859

First open hole eruptive well driven to 24 meters (Bailing & Piling). Fast drop of reservoir pressure Install the first Xmas tree to allow swabbing Possibility to divert the produced fluid into a storage tank Install first sucker rod pumping system (Steam driven) Found that concept of single casing is not suitable for long term. Install first tubing string as a wear sleeve Forced to develop wellhead and tubing hanger system Need to develop junction threads. Wooden derrick (Drak's yoke) handling capacity still limited the well T.D. Around a maximum of 100 meters

1900

Beginning of rotary drilling Draw work allowed casing and tubing handling at more than 300 meters Mud pump and B.O.P. development allowed lifting the cuttings and balancing the well while drilling Cement slurry displaced between casing and hole, allowed better sealing and decreased risk of water invasions. A second or third casing in smaller diameter allowed reaching deeper reservoirs below 1000 meters Cased hole and open hole compression packers with circulation valve allow to test a open hole section prior to run the completion. (First drill stems testing).

1910

First open hole gravel pack in open hole unconsolidated reservoirs. Use of slotted liner associated with liner hanger (Baker oil tools, Brown oil tools)

1920

First electric line logging with G.R. and C.C.L. allowed to identify more than one producing zone. Electric line technique allowed running, correlating and firing explosive charges to put again the reservoir in communication with production casing. To avoid cross flow between two o r more reservoirs, mechanical tubing set packer were developed.

1923

Invention of the rubber seal type "O'Ring"

1924

First P.C.E; equipment was built by Bowen oil tool to allow Wire line under pressure Flow control equipment such as Sliding sleeves, plugs, was developed by many service companies, so that a given zone can be isolated, or produced commingling or independently.

Section 1 -INTRODUCTION

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1925

GRC company develop the first mechanical down hole recorder

1926

First hydraulic packer tubing set

1927

First hydraulic packer dual.

1928

Improvement in the thread design and sealing capacity (Hydrill, Buttress)

1930

Development of snubbing stimulation and well start up.

1935

First Water injector wells and dump flood injector wells Development of permanent packer with PBR (seal bore)

1940

Development of electrical submersible Pumps. (Reda)

1950

First commercial gas wells are completed. Camco put on the market the first side pocket valve system for gas lift applications.

1955

First sour gas field is put in production (Pau France) Vallourec develop the VAM thread for this purpose (First M. to M premium thread)

1960

First offshore wells to be operated from a platform Development of hydraulic safety valves, remote controlled Selective and multi zone gravel pack. Selective and multi zone oil and gas wells First hydrostatic packer for deep wells and where it is necessary to decrease the piston or ballonning effect

1970

Centrilift introduce the electric pumps with variable frequency First subsea wells. (Abudhabi, Congo, North Sea)

1975

First semi permanent packer able to be retrieved with a retrieving tool

1980

Beginning of horizontal well drilling.

1985

First Sour gas injectors

1990

Beginning of multi lateral well drilling

1992

First multi zone Sour gas injectors

1995

First cemented mono bore well where the tubing is also the production casing. (Mainly suitable when the reservoirs to produce are marginal)

equipment

allowing

sand

washing,

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Well Completion

1997

well head splitter with partition plates

1998

Development of the intelligent type completion. (Only suitable for wells with a production that justifies it).

2000

Development of many other types of equipment is in progress.

Figure N° 1-1 Downhole completion examples

Section 1 -INTRODUCTION

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Notes

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

SECTION 2 WELL PRODUCTIVITY FUNDAMENTALS

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Well Completion

SECTION2 – WELL PRODUCTIVITY FUNDAMENTALS 2.1. WELL PRODUCTIVITY, FUNDAMENTALS OF PETROLEUM RESERVOIR The well productivity is determined by several factors that affect the reservoir first of all are the reservoir characteristics, rock permeability, GLR, fluid properties, type of formation, different oil layers. Then are the well characteristics, the type of completion, damage made to the reservoir during drilling, undesired effects on the tubing or casing, skin factor, perforation depth, and several others. The drilling and completion process must be carefully designed to fit the needs of a given reservoir, taking into count all the characteristics that will determine the life of your well, all along the time you expect to produce, there are several types of completion, but those are just guidelines, because each well requires personalizing according to its own characteristics. Also when selecting down-hole equipment, it’s very important to do it following a brainstorming process involving all the team. Thinking ahead in time its very important because as the well produces all those parameters will change and a good completion must be able to be adapted to new flow conditions with as few as possible modifications, the completion design must take into count the different services that a well will require in time, and must ensure that those services can be done in the best way, and that will be possible to install, service or retrieve with a suitable mean all down-hole equipment (ex: well deviations with more than 70 degrees will create potential wire line operation difficulties, so a well with this deviation must be designed for coiled tubing service), Modern tools, monobore technology and geochemical fingerprint, now allow better measurement and control of multiple zones in the same wellbore (Commingled flow) Also, directional drilling technology allows to obtain a larger drainage than classical vertical wells (at the same time it makes the well more expensive and risky to drill and complete)

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2.1.1. NATURAL FORCE OF THE RESERVOIR During the first stages of operation, the natural force in the reservoir is used to lift the oil to surface; there are three basic types of drive mechanism, depending of the type of reservoir this force comes from: Water driven reservoir: In water drive reservoirs oil is pushed up, and being replaced by encroaching water, declination on pressure is comparatively small as the productive reservoir volume is decreased. Gas in reservoir: Solution Gas driven Reservoir: Those are constant volume reservoir. The production is the result of the volumetric expansion of solution gas. Pressure declines are characteristics of this type of reservoir, since drive is not achieved by water encroachment or gas cap expansion. In addition excessive drawdown can actually decrease oil production under some given conditions. Gas Cap expansion driven reservoir: In this type of reservoir, the oil zone is overlaid by a gas cap. The drive mechanism is a function of the expansion in the gas as oil is produced.

Figure N° 2-1 Reservoir examples

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Well Completion

2.1.2. RESERVOIR CHARACTERISTS The characteristics of reservoir rock determined by core analysis and well logging play a key role in the selection of completion type and equipment:

Figure N° 2-2 Porosity •

Porosity: is the percentual relation, between the number of pores in a rock sample and the total amount of rock in the sample, it usually decreases as depth increases.

Figure N° 2-3 Darcy’s law •

Permeability: is the capacity of a reservoir rock to transmit fluids, it is expressed in millidarcy, because darcy’s law is used to make the calculations, it takes in account the cross section, the length, fluid’s dynamic viscosity, upstream pressure, and downstream pressure, and finally the permeability coefficient to calculate the flow rate through the rock.

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

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•

Saturations: basically is the percentual amount of each phase of a multiphase fluid that is present in a given pore volume

•

Oil properties: several characteristics that can modify the behavior of flow o Specific Gravity: is a comparison of fluid density to that of water. o Viscosity: Is the resistance to flow of a fluid o Bubble point: The temperature and pressure at which gas, held in solution in crude oil, breaks out as free gas from the solution. o Oil formation volume factor: this is the ratio of the liquid volume at stock tank (standard conditions), this ratio is used to convert reservoir barrels to stock barrels

Figure N° 2-4 Hydrocarbon composition •

Water properties o Viscosity: in water the viscosity is primarily a function of temperature, however salinity has a slight influence on it. o Water formation volume factor: it’s a function of temperature, and slightly influenced by pressure, the calculation is done by using a correlation o Water Compressibility: its an estimated value calculated through Meehan correlation.

•

Gas properties o Gas formation Volume Factor: Z, under typical conditions hydrocarbon gases will deviate from the ideal gas law, thus requiring a correction factor, this is determined from laboratory measurement, but it’s a common use to determine it using the Camco chart o Gas Viscosity: in natural gas is a proportional function of pressure, as it decreases, gas viscosity decreases, natural gas viscosity varies from a range between 0.01 and 0.04 cp

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2.1.3. RESERVOIR CONSIDERATIONS There are some reservoir considerations that must be taken in count at the moment of completion, because they affect the ability of your well to produce: • •

• • • •

•

Partial penetration effect: this is when only a fractional percentage of the total productive section is open to the wellbore, this can impact in the following ways the well production: Conning effect: Excessive drawdown when producing a well can create water or gas cone around the pay zone. This cone eventually will reach the perforations and affect the oil production by giving priority to water or gas production. Reduced producing rate effect: this refers to the relation between the potential length of the payzone and the actually perforated interval. Reduced bottom hole pressure effect: the bottomhole pressure on a partially penetrated well is less than would be available under totally penetrating conditions. Skin damage effect: this is defined as a thin layer of impaired permeability occurring immediately around the well bore and extending vertically over the entire productive interval penetrated by the well. The selection of tubing size is given by the required flowing bottomhole pressure at various flow rates, depending on the depth of the well. Also there are certain reservoir variables which must be at least closely approximated in order to accurately perform tubing sizing calculation: o Gas Liquid ratio (GLR): the higher the GLR is, the lower the density of the produced fluid is, thus lower will be the required flowing bottom-hole pressure. o Liquid Density: the fluid density has the same effect as GLR, only this refers to the density on the liquid phase of the fluid. o Liquid Viscosity: the higher the viscosity the higher that the required bottomhole flowing pressure will be. o Liquid surface tension increased the bottomhole required flowing pressure will be higher. o Kinetic energy effect will become important in small diameter tubing with high GLR and low pressure levels Surface equipment, the influence of surface equipment in the production capacity of a well, is given by the pressure losses created by the surface equipment in order to deliver the production to the separation and storage facilities, production choke size, Flowline size, production header pressure, separator pressure, interaction of the network in the header.

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

Figure N° 2-5 Temperature Gradient

Figure N° 2-6 Fluid changes from Downhole to surface

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Well Completion

2.1.4. RESERVOIR STAGES & RECOVERY STRATEGICS Although during the first stages the natural force of the reservoir is used to deliver the production to surface, this is not always possible (extra heavy oil, very low GLR) and also as time passes the force in the reservoir starts to decrease until it finally depletes, this doesn’t mean that also the reservoir is depleted of oil. To overcome this several techniques have been developed, including artificial lift systems, Gas lift, ESP, beam pumps, which are covered later on this document. Also techniques to maintain the reservoir in shape are now of common use, not only to keep natural lift longer, but also to avoid reservoir collapse, for late production stages there are three levels of recovery: Primary stage: This is mainly made by producing an eruptive well, in natural conditions through a choke. Secondary stage: producing a depleted well by using a wide range of technologies meant to replace the natural force in the reservoir by generating and artificial lifting force, for this porpose several methods; such as beam pumping, gas lifting, ESP, screw pumps have become standards in the industry. (The most common of them are covered later in this document) Tertiary stage: Its purpose is to recreate the natural force in the reservoir by modifying its natural conditions, doing so eruptive production can be achieved again. For this several techniques have been developed some of them are: • • •

Injecting water in the reservoir to repressurize it. For this water injection wells are drilled and compressed water is forced inside the reservoir. Injecting gas, air, nitrogen, steam in the reservoir (is different from gas lift) for this several injection wells are drilled and the fluids ares forced inside the formation. Creating a water drive from several water injection wells around the producing well, by this is intended to displace the oil in the reservoir to the payzone in the producing well.

Its important to note that this is only a classification, that varies from company to company following certain guidelines, and according to internal policies of the operating companies those stages are applied some times combining two or more of the thecniques the enhance the production, and the common denominator here is that no management will wait to reach full depletion before starting an alternate recovering plan.

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2.2. FORMATION DAMAGE CONTROL / PREVENTION 2.2.1. RESERVOIR DAMAGE The most common causes of formation damage are: • Drilling mud solids or mud invasion into the formation • Cement filtrate invasion • Incompatibility between drilling, completion, perforation and packer fluid • Inadequate perforations, in size, number or penetration • Solids from completion or workover fluids into the formation or plugging perforations • Plugging of formation with native clays (clays swelling) • Asphalthene, paraffin or scale precipitation in the formation or perforations • Sand fill in the wellbore • Excessive drawdown which may cause fines movement, compatation of weak formation or influx of water production This kind of damage can be the result of inappropriate procedures during the process of drilling, completion and even during normal operation, to avoid this at each stage the team must develop procedures that are adequate to the type of formation / completion in question

2.2.1.1. DRILLING RELATED DAMAGE During drilling, some preventive procedures can be applied to minimize the risk of formation damage, like using wide particle size in mud, high bit weight and low rpm, minimizing barite, mud conditioning, use of low invasion fluids, minimizing drilling time, low overbalance, matching salinity of formation, among others.

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2.2.1.2. PERFORATION RELATED DAMAGE Perforation related damage: While perforating; usually around the perforation a small damaged zone is found, where the permeability and the porosity of the rock have been modified by the shoot, the goal is to minimize those changes, by selecting appropriate shape of charge, level of differential pressure when shooting, and optimum clean up process. Also the penetration and density of perforations are very important factors to take in account, in the early days perforation guns were able to penetrate up to 1 feet in the formation, while today’s guns can reach up to 2,5 feet whit the same amount of charge, the penetration is very important when there is already formation damage previous to the perforation, because there the goal must be to penetrate deeper than the maximum area of damaged zone around the wellbore, this is a common approach to overcome formation damage due to drilling. Also in completions with drilling and perforation damage, a few deeply penetrating perforations are more effective than many shallow perforations. A common used thecnique is to start with medium penetrations, so given the case later on formation damage get deeper, then reperforation can be done with more penetration to overcome it. Figure N° 2-8 Perforating gun assembly

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

2.2.1.2.1.

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Importance of positioning the Perforating Guns

Perforating guns have evolved as well as the quality of explosives and firing techniques, but this evolution its been around the same old principle of a metal gun with the explosives distributed along it, connected with prima cord, a firing head and a remote mean of firing, that can be radio or, electrical signal, which is ran downhole to the selected firing depth by wireline. There are some important things to remember about perforation guns, Some times there are liquids in the completion, since liquids are not compressible, if the charges are fired while a part of the gun is submersed, the force generated by the gas expansion of the explosion, could deform the gun and it could stuck downhole, creating a problem which is quite expensive to solve. The firing head shall be put in the bottom of the gun, as the firing head will not work while in liquid, this will prevent the charges to fire and corrective actions can be taken. Reperforation technique is found to be useful as a remedy to blocked perforations because the detonation of the gun has a loosening effect on the blocking materials in the formation adjacent to the well and in the previous perforations.

Figure N° 2-9 Sequence of firing a perforation gun

Figure N° 2-10

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Well Completion

2.2.1.3. COMPLETION RELATED DAMAGE Completion fluids related damage: The completion fluids must be selected according to the type of formation; those fluids are used for weight control and for prevention of clay problems, in the case of salts. There are several types of salt but the most used are: Sodium chloride (NaCl), which can reach a maximum density of 1.26 SI, the problem with NaCl is that it has some effects on clay that reduces its permeability, the other type of salt is Potassium Chloride (KCl) reaching a maximum density of 1.16, KCl doesn’t affects permeability on clays so its use is preferable in clay reservoirs. When higher density is required then is mandatory to use other type of salt, because NaCL and KCl when mixed at higher density form crystals. While surfactant agents are meant to change the surface tension of fluids and to affect the wettability of rock, there are two types of surfactant agents used: Cationic and Anionic and should not be used together because they are not compatible with each other.

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2.3. SAND CONTROL Most Oil and gas wells produce through sandstone formations, this is not a problem unless the sand is not consolidated or partially consolidated with soft clay or silt, Miocene and younger sands are usually weak formations that may not restrain grain movement, when producing at high flow rates. Sand production can produce erosion on both surface and downhole equipment, flowline deposits can create undesired chokes, and deposits in tanks or separators can render them to un-operational The objective of all sand exclusion techniques is to avoid the migration of the formation sand into the production stream trough the well to the surface.

2.3.1. FLOW RESTRICTION: By restraining production rate of the well, drag forces on the sand grains are reduced. This is not a efficient approach and its usually used when there’s no sand control technique on the completion design, but while simple this approach is uneconomical. Using this technique at the moment of starting the well, by opening slowly the production choke, and letting the flow stabilize for long periods, contributes to decrease the initial drawdown of the wellbore and thus Natural sand consolidation is achieved. This is very important to remember because doing so increases the chances of long term clean producing wells.

2.3.2. CHEMICAL AND MECHANICAL CONTROL A widely used method is to control the sand through gravel, this can be done by chemical treatments to consolidate the gravel around the perforations or a physical screen installed down hole, or in some types of gravel pack the screen is installed along with resin coated gravel, there are several types but basically can be divided as follows: Resine coated RESINE + GRAVEL

Gravel Pack SCREEN + GRAVEL

Short term

Medium to long term

Expandable screen The screen is the casing tubular, that is expanded (bursted) to come in contact with formation creating a consolidation around the perforations. Long term

Each method has its own advantages and applications, as they have inconvenients too, resine coated for example, tends to become unefficient under high water conditions, because it gets washed from the gravel, losing its controlling properties.

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2.3.2.1. GRAVEL PACKING: As this is perhaps the oldest, simplest, and widely used sand control technique, it has been applied onshore and offshore for several years and its efficacy it’s proven, it becomes important to explain. Gravel packs have the avantage that can be used both in vertical or horizontal wells. It’s important to state that it is not a filter, filter screens trend to get clogged after a while decreasing the production of the well. The ideal gravel pack will consist of: • • • • •

Replacing formation sand by gravel to a distance of 1ft or more radial from wellbore Sharp gravel to sand interface and prevent invasion of formation sand into the gravel Gravel being thightly packed in the annulus, perforations and cavities behind the casing A screen stopping the gravel with all slots or wire spacing open to flow Not polluted gravel. Fluid and pumping system must be clean.

Figure N° 2-11 Different methods of sand control

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

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Also the design must be made a way that all the fluid going through the perforations is in laminar flow. Some reservoir characteristics play and important role at the moment of selecting the sand control method: • • • • •

Interval length Sand Quality Reservoir Temperature Reservoir pressure Reservoir fluid

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2.3.2.1.1. SCREENS: Other important part of the gravel packing method is the screen. Its function is to retain the gravel in an annular region within the wellbore. There are three types of screen available. a) Slotted liners: usually have vertical slots spaced uniformly about the casing. The width od the slots can vary from 0.002” (0.5mm) to as large as desired, depending on the gravel size and the particular situation, their use is typically confined to long completion intervals or low productivity wells b) Wire screens: available in three basic constructions a. Welded 1: the wire is resistance welded to longitudinal rods and a lathe-type machine. The screen is manufactured separately, then placed over a drilled pipe base and welded into position. Welded 2: it’s a variation or the previous, in this case the screen is wrapped and the resistance welded Figure N° 2-13 directly on the pipe base, with the longitudinal rods as the only separation. b. Wire wrapped: (also known as Pipe base) the wire is wrapped directly on the pipe base which maybe drilled slotted and grooved. This type is highly recommended because it can be rerun in the hole, as it is less fragile than the welded or rod base, and its cost is not much higher than the others. c. Rod base: these screens are similar to the jackets on welded construction screens but contain no pipe base. c) Prepacked screens: These screens are made by filling the annulus between two concentric wire screens with properly sized resin coated gravel. The gravel pack is actually installed and consolidated at surface and then is lowered into the well. The sand control technique must be designed according to the geometric factors and completion requirements of a particular well. Gravel packing offers an economical method of controlling sand, interval of 6 to 200 mts are common, and treatment covering more than 150 mts have been successfully performed. But they offer some disadvantages; if the screen fails it will require remedial treatment, involving expensive fishing job.

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

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Overpressurized reservoirs cannot be controlled with calcium chloride brine; a special gravel pack fluid is required. Productivity can be impaired by perforation tunnels being filled with sand or invasion of the gravel pack by formation fines. (This problem is especially severe in small casing where small screen must be used)

Figure N° 2-14 Gravel packing process

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Well Completion

2.3.2.2. CONSOLIDATION THROUGH CHEMICAL TREATMENTS The objective is to treat the formation in the immediate vicinity of the wellbore with a material that will bond the sand grains together at their points of contact, the treatment must be made outside all perforations, and the consolidated sand mass must remain permeable to well fluids. With this technique future workovers are simplified because there’s no mechanical equipment left in the wellbore, production decline associated with the migration of fine particles toward the wellbore does not occur because the flow velocities are reduced at a treatment radius of 0.9 to 1.2 mt from the well. Along all this advantages, problems will arise from injecting insufficient resin into low permeability zones of highly stratified reservoirs. Also consolidation success is reduced in long perforated intervals (more than 5mt) and the cost is really high (around 5000 $ per foot of perforated interval) Resin coated Gravel: this consists in consolidating the gravel placed inside and immediately surrounding the perforation. The gravel is coated with a resin at the surface and then pumped into the well as slurry. This slurry is then squeezed through the perforations to fill a region behind the casing. After hardening, the consolidated gravel prevents formation sand from entering the wellbore. All excess are removed from inside the casing either drilling or washing. This method is 25% to 50% cheaper than conventional consolidation treatments or gravel pack, but in despite it has a relative short lifetime.

Section 2 –WELL PRODUCTIVITY FUNDAMENTALS

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2.4. PRESSURE LOSSES Any fluid flowing in a pipe loses part of its energy, which is absorbed by dissipation in friction process. This friction can be the result either internal (the fluid viscosity) or external (the pipe roughness) and even both, also changes in diameter create pressure losses, and when the change is a restriction to avoid the creation of turbulences a specially polished piece shall be used immediately after the restriction, those pieces are called “Flow Coupling” and come in sizes from 2 feet up to 6 feet, FC has a extremely low roughness 1/1000mm. Pressure losses are expressed by the difference in the pressure of the fluid between two points of the pipe. And are modified according to the type of flow laminar or turbulent. The type of flow is determined by the Reynolds number Re, which is them compared to a critical value ReC Reynolds number is a function of: (Velocity of fluid (m/s) * inner diameter of pipe (inches) * density of fluid (kg/m3)) Dynamic viscosity (pa.s) Laminar flow is the ideal condition for production, and to determine if this condition is met, the velocity of flow must be less of equal to critical velocity, which is the flow velocity at the critical Reynolds number. So, pressure losses, are determined by several factors, but they can be calculated, from: critical velocity, critical flow rate, length of the pipe, inner diameter, circulation velocity, flow rate, dynamic viscosity and the density of fluid.

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Notes

Section 3 –CASING & TUBING

3-1

SECTION 3 CASING AND TUBING

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SECTION3 - CASING AND TUBING (PRESSURE LOSSES, BURST, COLLAPSE, TENSILE STRENGTH, METALURGY) Casing and Tubing are key elements on a completion, carefully selection of pipe properties, according to the characteristic of the well must be done, the basic need of a casing is to keep the drilled hole in shape, so erosion due to flow doesn’t collapse the well, in the early days there was only the conductor, that acted as casing, production casing, tubing, all I one, later when the importance of reservoir gas was realized, the need to put a production tubing aroused, to act as a velocity string, as a solution to gas slugging, and also to protect the production casing from erosion due to flow, the actual process of drilling a well and completion, includes a wide range of carefully engineering and products to optimize the live of wells in time and efficiency. Please refer to Well Production Practical handbook for tables (on this section only)

3.1. PIPE CHARACTERISTICS API and ISO, normalized standards for oil/gas tubing and casing, tubing there is defined as pipe with nominal diameters from 1.050 to 7.0 inches (ISO 11 960), while casing sizes range from 4 ½ to 20 inches. Geometrical characteristic of casings: are the dimensions, masses and capacities commonly used in completions Dimensions and masses of tubing: are the set of geometrical characteristics in relation with grade and nominal weight of tubing from 1.050 to 7 inches according to ISO 11 960 standard Casing and tubing are classified according to 5 properties • • • • •

Steel Grade Length range Wall thickness Manner of manufacture Type of joints

Section 3 –CASING & TUBING

3-3

3.1.1. STEEL GRADE AND TENSILE STRENGHT In a well the materials are exposed to extreme conditions, it could lead to: Burst in the pipe if it is not capable of withstanding the pressures applied from the inside or to Collapse, given the annulus pressure is higher that the pressure inside the pipe, or the weight of the string is excessive high. Basically what is taken in account for preventing those problems are the tensile requirements and Steel grade: The grade refers to the yield minimal strength of the steel, is expressed in thousands of PSI, this means, the amount of tensile stress required to produce extension under load, so, the higher the grade the higher the force coming from the weight of the tubing string that the tubing can withstand. And the Tensile strength: which is the maximun amount of tensile stress required to produce breakdown of a pipe under load.

3.1.1.1. ELONGATION AND BALLOONING EFFECTS The effect of elongation or ballooning in a pipe due to load or pressure is very important to take in account, because if the elongation is too much in the tubing string, it could deform and create mayor problems. Also the ballooning effect could create mayor problems, because it not only shortens the pipe string, but also makes it wider, which in the case of cementing casings could create a small space in between the pipe and the cement which is know as microannulus that in the future will create leak problems in between the casings and/or packers, there are several techniques to face those problems, as using centralizing adaptors between tubing and casing.

Figure N°3-1 Ballooning effect

Ballooning is more common in big diameter pipe, while elongation tends to appear in small diameter ones. In the drilling world tubing of 3 ½ “ is know as magic pipe, because it seems not to suffer elongation neither ballooning, unfortunately not all wells could be fit with this diameter of tubing. The type of steel used plays a big role in a completion, it could be: Carbon steel, stainless steel, titanium, iconel. Each type of steel has a specific application and special tolerance to certain effects coming from the well or reservoir characteristics.

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Well Completion

3.1.1.2. Hardness The hardness of a pipe its measured either using the; Rockwell hardness testing which is an indentation testing method. An indenter is impressed into the test sample at a prescribed load to measure the material's resistance to deformation. A Rockwell hardness number is calculated from the depth of permanent deformation of the sample after application and removal of the test load. Various indenter shapes and sizes combined with a range of test loads form a matrix of Rockwell hardness scales that are applicable to a wide variety of materials. Also there is the Brinell Hardness Test this common standard method of measuring the hardness of materials is done by subjecting to indentation by a hardened steel ball under pressure the smooth surface of the metal. The diameter of the indentation, in the material surface, is then measured by a microscope and the hardness value is read from a chart or determined by a prescribed formula.

3.1.1.3. HOW FLUID COMPOSITION CAN AFFECT THE SELECTION OF PIPE There is a range of problems associated to the presence of H2S in the reservoir that affect directly on the selection of materials to be used, there’s the galling effect which affects Stainless steel in the presence of H2S, the sulfide stress cracking caused by the small atom of sulfur entering the composition of carbon steel and weakening it, creating small crevices. Also CO2 presence carries out some problems in the presence of water and low-pressure conditions. To overcome those effects now are available in the market different types of pipe, with specific coatings, which minimize problems, but coatings tend to be worn out in the presence of high temperature and high gas velocity, so it isn’t a definitive solution.

3.1.2. PIPE RANGES The Length range of pipe, API normalized 3 length ranges: R1 are pipes from 7 mt up to 8.5 mt R2 are pipes from 8.5 mt up to 9.5 mt R3 are pipes from 9.5 mt up to 12.5 mt It’s important to try to keep subassemblies within the range of pipe used normally, to fit the derrick size and the length of the stand of pipe been used.

3.1.3. PIPE THICKNESS The wall thickness is the schedule of the pipe, it determines the internal diameter, and is also inherently related to the strength of the pipe.

Section 3 –CASING & TUBING

3-5

3.1.4. PIPE METALLURGICS Metallurgic plays a very important role in oil industry; actual techniques allow the creation of Seamless pipe: which is a pipe that does not contain any line junctures (metallurgical welds) resulting from the method of manufacture. This product may be produced by extruding or by drawing, using either die-and-mandrel or hot-piercer processes. (Typically used for fluid-carrying applications under pressure.) Pipe, Drawn: Pipe brought to the final dimensions by drawing through a die. Pipe, Extruded: Pipe formed by hot extruding. Piercer: A fixed mandrel, attached to the press stem, used on either cored or hollow billets to produce seamless tubular product. This techniques relay on the principle of Plastic Deformation, which is a distortion that remains after removal of the load that caused it. And depends of the ability of a material to be deformed extensively without rupture.

3.1.5. CONNECTIONS As new completion techniques demanded stronger steel to reach deeper wells several types of thread connections were developed to meet the higher requirements. Now the most common types of tread used for completions are:

3.1.5.1. STANDARD API COUPLING CONNECTIONS: API couplings were the very fisrt type of trhead used in oil industry; nowadays upset connections are still widely used because they are unexpensive and still relailable. UE: API non upset connection is a 10 round thread form cut on the body of the pipe, it’s not recommended because the joint has less strength than the body. EUE: API External upset connection, it’s an 8 round thread and the thread area is wider in the outside to make the joint as stronger as the pipe body is. Also is found for high pressure service a special long thread form which is 50% longer than the standard effective thread

3-6

Well Completion

3.1.5.2. OTHER TYPES OF CONNECTIONS: Vam:

Buttress Buttress threads are square-cut, a screw thread having one flank that is vertical while the other is inclined, and a flat top and bottom. This creates a hydraulic seal through the interference fit of the mating threads; this type of thread is designed to withstand heavy thrust in one direction. The shape of the thread, requires no effort at the beginning, but as the thread go together it will require more force to continue screwing until at a given point the torque required will be so high that the metal will deform creating a seal of the two pieces. (Plastic effect).

Figure N°3-2

Section 3 –CASING & TUBING

3-7

Figure N°3-3 Non Upset, Upset & Vam Threads

3-8

Well Completion

Premium Thread (hydrill) A class of high-performance thread type that is commonly used in modern oil well and gas well completions. Premium threads are available in a number of configurations and are typically designed to provide superior hydraulic sealing, improved tensile capacity and ease of make-up. Unlike conventional threads, the sealing areas in premium thread connections are independent of the thread profile and are included as two or three areas within the tool joint, thereby providing some redundancy. Premium thread. Premium threads provide high mechanical and hydraulic performance. The multiple sealing areas are particularly efficient in moderate- to high-pressure gas well applications.

Althought it seems to be very reliable, the use of this type of thread is not common, because there is no way to determine for sure that all the junction points are togheter.

Figure N°3-4 Hydrill thread

Section 3 –CASING & TUBING

3-9

Notes

Section 4 –COMPLETION EQUIPMENT

SECTION 4 COMPLETION EQUIPMENT

4-1

4-2

Well Completion

SECTION4 – WELL COMPLETION EQUIPMENT There is a wide variety of equipment that is used in completions in order to achieve long-term results or to allow future intervention of the well, among several, here we list the most important of them and therefore the most common used:

4.1. BLAST JOINT: Designed to be installed in the tubing, in front of the perforations, to absorb the jetting impact of fluids under pressure, it is a piece of very hard and resistant steel that protects the tubing from erosion in front of the jetting fluid.

Figure N° 4-1

4.2. SLIDING SLEEVES: They are completion devices that can be operated to provide a flow path between the production conductor and the annulus. Sliding sleeves incorporate a system of ports that can be opened or closed by a sliding component that is generally controlled and operated by slickline tool string.

Figure N° 4-2 Sliding sleeve

Section 4 –COMPLETION EQUIPMENT

4-3

4.3. CROSSOVER CONNECTIONS: Are short lengths of casing or tubing used to change the size, weight or connection type at a certain point in a string, the selection must be done carefully specialy when working on deviated wells, because of the angle on the reduction, if it is narrow, ex: 45º reduction angle on a deviation of 45º will become a 90º which will make impossible to run tools Figure N° 4-4

4.4. DOUBLE PIN

4.5. COUPLINGS:

SUBS: Are furnished in a pinby-pin configuration. These subs are short lengths of casing or tubing used to connect downhole tools. The subs can be manufactured to any length with OD and ID defined by string criteria.

Figure N° 4-4

Are used to connect two joints of pipe together. The couplings are short lengths of heavy wall pipe with identical box threads at each end which mate with the pin ends of the Figure N° 4-5 joint. Combo Couplings are couplings with non-matching ends, thereby changing thread types, weights or sizes. Both types of couplings are available with API or proprietary connections

4.6. FLOW COUPLINGS: Are heavy-wall connectors made up in tubing strings above or below subs where turbulent flow problems are apt to occur. These couplings resist erosion caused by production fluids and gases. The ID size is usually the same at the pin ID. As mentioned above at the beginning of this manual, flow coupling are used to overcome the turbulences caused by changes in diameter along the tubing. The internal surface of the coupling is highly polished and this is what makes them suitable to reduce the turbulences. Figure N° 4-6

4-4

Well Completion

4.7. FLOWTUBES: Are an alternative to conventional Flow Couplings and pup joints. When compared to standard, FlowTubes can save from additional components, as shown in accompanying illustration. Moreover, FlowTubes require fewer connection make-ups. Like Flow Couplings, FlowTubes are used above and below a control device to minimize turbulence in the tubing bore.

4.8. PUP JOINTS: Are short lengths of casing and tubing that are used to adjust the depths of strings or downhole tools. These pups can be manufactured to any length, described in Table 26 of API 5CT as 2,3,4,6,8,10 or 12 feet, with OD and ID as defined by string criteria. Having sets at the well site is an added precaution in the event the depth of strings or downhole tools needs to be adjusted. Threads may be specified for either API or proprietary connections. During the completion period, the derrick uses standard range predefined pipe, to adjust various equipment in the tubing to this pipe size, a subassembly is created, this is not more than the equipment, lets say a subsurface valve, perhaps a flow coupling and then two pieces of pipe to complete the full length of Figure N° 4-8 the range been used.

Figure N° 4-7

Section 4 –COMPLETION EQUIPMENT

4-5

4.9. SEAL RINGS: Are used to prevent leakage due to internal or external pressures. These rings are manufactured of a non-metallic material, usually Teflon®. The ring fits in a groove cut into the box end of a connection and is compressed to form a seal when the connection is made up power tight. Seal Rings are available for API and proprietary connections

Figure N° 4-9

Figure N° 4-9Bis

4.10. SAFETY SUBSURFACE EQUIPMENT: There are several types of valves, developed to act under significative flow variations, to avoid environmental damage from broken pipes or personnel risks, usually those valves act with a flapper which is held in position by hydraulic pressure and this pressure is released to let the flapper close in case of a pressure build up or decrease in sensors installed in the flow line, even there are some that are subsurface actuated and those what senses is the changes in bottom hole pressure.

Figure N°4-10 Safety valve

4-6

Well Completion

4.11. MULE SHOES: They are used to facilitate the passage of tools or instruments into the bore of another tool, such as a packer. The shoe is run on the bottom of a tubing string and lands inside the bore after the shoe insures the centralizing of the string. A Re-entry Guide is used to facilitate the return of wire line tools back into the tubing when being brought back up the well bore. Its purpose is to keep the wire line tool lined up to the center so as not to hang up when entering the tubing. Figure N°4-11

4.12. LANDING NIPPLES: Along with Lock Mandrels are run into the well on completion tubing to provide a specific landing location for subsurface flow control equipment. Landing nipples are universal due to their common internal profile. Landing Nipples are used on standard weight tubing; and under special specification are used for heavy weight tubing. NO-GO Landing Nipples are designed for use in single nipple installations or as the bottom nipple in a series of landing nipples, from manufacturer to manufacturer it varies and you find models with top NO-GO or bottom NO-GO. Applications: •

Plugging under pressure

•

Unlimited locations for setting and locking subsurface flow controls

Figure N°4-12 Landing Nipple

Section 4 –COMPLETION EQUIPMENT

4-7

4.13. BULL PLUGS/BULL CAPS AND OTHERS: Are used to cap off pipe or parts to provide pressure integrity. These plugs and caps are short solid pieces with the closed end rounded and the other end threaded with either pin or box threads. Available in API or proprietary connections. Single Joint Handling Plugs provide a positive grip by elevators when lifting a single joint of drill pipe, drill collar, casing or tubing Lift Plugs are used to handle multiple joints during the running of tubulars. The plug provides a positive grip for Figure N°4-13.1 the elevators. These plugs support the weight of an entire string. Consequently, it is important that the lift plug be designed by the same company that designed the connection it is made up to. Stabbing Guides are used to protect pin and box threads (as well as seals and internal coating if present) when tubulars are Figure N°4-13.2 being run into or out of a well. The guides are constructed of lightweight, rigid aluminum outer frames with durable polyethylene inserts. Latches and hinge pins are stainless steel ensuring long-lasting service. Maintenance is simple and inserts can be changed to accommodate different size connections.

4-8

Well Completion

4.14. GAS LIFT EQUIPMENT 4.14.1.

SIDE POCKET MANDREL:

Those are adaptors to place gas lift valves, the spacing between each SPM, is very important and it is defined by calculations done determined by the static and dynamic gradient of the well, and the characteristics of fluids. Gas lift valves are set in place using wireline, with a Sidekick Tool.

Figure N°4-14.1.1 Kick off tool

Figure N°4-14.1.2 Side Pocket Mandrel

Section 4 –COMPLETION EQUIPMENT

4.14.2.

4-9

UNLOADING VALVES:

Those are live (opening / closing) valves used at the moment of starting up a gas lift well to displace the liquids accumulated in the annulus (completion fluids, packer fluids…) they can be injection operated valves and production operated, later here is a section dedicated to GL where its explicated in more detail.

4.14.3.

OPERATING POINT:

This is an orifice installed usually in the last (deepest SPM) which is the one that must inject the gas in a gas lift well functioning ideally.

4.15. TELESCOPIC SUBS: The swivel features makes it possible to connect both long and short string tailpipe to the lower end of the packer even if the tailpipes are strapped together; it also makes it possible to leave the weight of the tubing hanging in the slips while making up the connection between tubing and packer. The Telescoping Swivel Sub may also be used to make up tailpipe between two dual packers or between a dual and a triple packer, since it telescopes to compensate for inaccuracies in measurement and to relieve the strain on the threads as they are made up.

Figure N° 4-15

Figure N°4-14.3 Unloading valve

4-10

Well Completion

4.16. PACKERS: There are several types of packer developed to fit different needs, but essentially them all serve the same basic purpose, create isolation between the tubing and the production casing so production fluids arrive to surface through the tubing to avoid gas slugging and don’t loose pressure and velocity because of casing wider diameters. The rubber in a packer is the real sealing element, and it should be selected according to the fluid, well and completion characteristics. Rubber comes in different Although the rubber is what makes the seal, packers are classified according to the installation method and own characteristics, and today they are so technified that you could thing that the rubber seal is not important at all. Initially packers had one single rubber element, now it is usually three of them stacked, the one in the center usually the softer one is the actual seal, the ones on the extremes are made of a harder rubber and act as backups of the center one and also help keeping this in place and untouched by fluids (this makes it last longer) setting packers is a job that must be carefully carried out, and after the setting, a test must be made to ensure there is no leaks, basically a packer is held in place by a metal cone which compresses the rubber seal and a set of slips acting against the cone and the casing, this principle applies for almost all kind of packers and comes from the compression packer design, almost all the other types of packer vary in the way of setting and the internal equipment used to hold them in place and made possible retrieving. The selection of the type of packer to be installed, is done according to the well characteristics, the depth, the deviation, the fluids, ETC. the following are the most commonly used packers in completions:

4.16.1.

COMPRESSION PACKER

They are set slacking off the string (applying weight on it) so the cone displaces the slips and create a hold to compress the rubber. Now they are rarely used. Tension packers heve exactly the same desing but upside down and intead of slacking are set by pulling; to set them, the tubing string is pulled to create tension and hold the slips in place, normally those packers are used in steam injection wells

Figure N°4-16.1.1 Compression / Tension Packer

Section 4 –COMPLETION EQUIPMENT

4.16.2.

4-11

HYDRAULIC & HYDROSTATIC

Both types uses the same principle, to set them, a force is applied from a fluid, they have the advantage that don’t require rotation to be set, but in the other hand, they are not very reliable, because is difficult to determine if were set correctly, also both are subjected to ballooning and piston effects. They also are not meant to be used in gas wells, because the hold down pins contains Orings, which suffer a lot under gas presence. Hydraulic packers do not have good performance in deep wells, while hydrostatic are better for that application.

Figure N°4-16.2 Hydrolic Packer

4-12

4.16.3.

Well Completion

PERMANENT PACKER

Really simple and reliable, they have breakable slips, which under compression break apart holding the rubber in place; the inconvenient is that to retrieve you must mill the packer and washout. The permanent packers can have a combination of technologies to be set, can be hydrolics, compression, mechanical, but they are not retrivables.

Figure N°4-16.3 Permanent Packer

Section 4 –COMPLETION EQUIPMENT

4.16.4.

4-13

MECHANICAL PACKER

They have rings between the rubber elements, and are set applying torque on the string, the rotation screws the center piece, which compresses the rubber and makes it fill the gaps in the rings, this type of packer is suitable for DST, but while you avoid putting weight on the string to set, you put a lot of torque in the string which is not good for deviated wells because is very difficult to drive the torque through the deviations without creating damage to the string.

Figure N°4-16.4 Mechanical Packer

4-14

Well Completion

Figure N°4-16.5 Retrivable packer setup / retrieve

Section 4 –COMPLETION EQUIPMENT

4-15

Notes

Section 5 –SURFACE EQUIPMENT

SECTION 5 SURFACE EQUIPMENT

5-1

5-2

Well Completion

SECTION5 - SURFACE EQUIPMENT 5.1. XMAS TREE For Xmas tree is known the arrange of surface valves and equipment found at surface level in a well, this name comes from its shape similarity to the decorated pine what is usually found in most places during December. This arrangement is very important in the completion, because here is the surcafe control of a well, normally a Xmas tree is conformed of:

Figure N° 5-1 Wellhead

5.1.1. TUBING HEAD ADAPTER: It holds the tubing hanger inside and provides a flanged connection for the master valves and so on the rest of wellhead equipment.

5.1.2. TUBING HANGER: this piece of equipment has the function of support the tubing at surface level, it holds all the weigth of the tubing string.

Section 5 –SURFACE EQUIPMENT

5-3

5.1.3. MASTER VALVE: can be one single or two of them, their function is to provide a mean of isolating the well, at surface level, in modern completions, one of them is manual and the other is pneumatic pressure operated.

5.1.4. TEE SECTION Then just above the master valves, the tee section is found, which provides a three way pass, the upper one to accommodate the swabbing valve, and the two laterals for the wing valves.

5.1.5. SWABBING VALVE: just on top of the well, provides a mean to isolate the top connector section.

5.1.6. TOP CONNECTOR SECTION:

Figure N° 5-2 Hanger

this is the very last part of the wellhead, provides a threaded connection for wireline or coil tubing adapters, so is a sort of service port for the well, normally the thread wears a plug where is a gauge port or measuring the WHP.

5.1.7. WING VALVES, FLOWLINE VALVES & EQUIPMENT On the lateral side of the tee, two wings valves are found, those valves allow to isolate the well to the production facilities, and still be able to run tools bottomhole, in not too high production wells, normally one od the valves ends in plugged, and the other holds the production choke, and so the flowline.

5.1.7.1. PRODUCTION CHOKE: it is a surface flow control device which enables to restrict the flow of the well, at startup and during production, to avoid overcoming the production facilities pressure or flow handling limitations. There are two types of production chokes, the adjustable choke, which is a sort of valve with a special design which has a graduated, hand actuator, that indicates how much open or closed it is. And the positive or fixed choke, which is a housing were a calibrated choke bean is inserted and creates a fixed diameter restriction to the flow.

5-4

Well Completion

After the choke comes the flowline, which is the pipe that delivers the production of the well to the separation facilities. Also has a flow line valve normally. All the equipment after the choke, usually has a lower pressure specifications than the Xmas tree equipment. All along the Xmas tree, are measuring points and sampling points, for taking pressure, temperature and samples of the production.

Section 5 –SURFACE EQUIPMENT

5-5

Notes

Section 6 –ARTIFICIAL LIFT SYSTEMS

SECTION 6 ARTIFICIAL LIFT SYSTEMS & EQUIPMENT

6-1

6-2

Well Completion

SECTION6 - ARTIFICIAL LIFT When the natural force of the reservoir is depleted, there is still oil downhole, just that the bottomhole pressure is less than the weight created by the hydrostatic column and there is not impulse to lift the oil to surface, to overcome this several methods has been developed along the history of oil industry, basically all those techniques, look after recreating by artificial means a force to lighten the hydrostatic column so the fluids could change from static to flowing status. This change is achieved by careful calculations done by specialized teams, and based on the results of the calculations and analisys a method is selected, in all this is taken into account the suitability of the actual completion, the status of the reservoir, characteristics of the well during its normal production period, the productivity declination curves among several others. There is not artificial method better than the other, all the ones menctioned here, have been used in the industry since what we could call the early days, and have suffered modifications and optimizations, sometime to make them more efficient, some times to reduce costs associated to them. We can say each well has its own personality and what suit the needs in one case is not necessary the solution for a well just aside. Normally given the oil characteristics and the reservoir, a method is selected and applied for several wells in the same field/reservoir, but in this case each well need that the detailed conditions are selected and adapted to fits its behaivor and achieves the best benefits. In this manual the more common methods are summarized and briefly explained, but to get into the real thing a single book or a whole encyclopaedia will be required, here is explained the principle of how those methods work, and Gas Lift receives certain preffrence, because perhaps is the oldest and more common thecnique, and also the less understood of them all.

Section 6 –ARTIFICIAL LIFT SYSTEMS

6-3

6.1. GAS LIFT This is one of the oldest techniques of artificial lift, which has proven its efficiency and fidelity during many years, has many advantages of them the main ones are its cost efficiency (it is relatively cheap given the completion was designed to fit it, and there is compressed gas available) and the other is that it always works, perhaps not in the most efficient or optimal way, but always products benefits. Gas is injected through the casing and enters the tubing in to lift the fluid column. The completion must be designed spacing the upper valves (unloading valves) which are used at the moment of start up to discharge fluids contained inside the casing, and lighten the fluid column in the tubing, if the completion was made according to the well characteristics, the unloading valves which are live valves (open/close) should remain closed after unloading phase is done, there are two types of unloading valves, injection operated (IPO) and Production Operated (PPO). The principle: In a typical gas lift system, compressed gas is injected through gas lift mandrels and valves into the production string. The injected gas lowers the hydrostatic pressure in the production string to reestablish the required pressure differential between the reservoir and wellbore, thus causing the formation fluids to flow to the surface.

Figure N° 6-1 Tipical Gas lift System The final consideration is that the injection should be made through the lowest point. There are two GL techniques, Continuous and intermittent, continuous is used at the early stages of reservoir natural force depletion, while intermittent is normally the option when continuous is no longer producing benefits.

6-4

Well Completion

Continuous GL: The technique is based in the principle of lightening the fluid column along the tubing to drive the fluids to surface, through gas injection inside it. This is achieved by a fixed orifice, installed in a side pocket mandrel at the deepest possible level (the closer to the packer the better). Intermittent GL: in this case, there is a lapse of time, between the action of the lowest valve (which is a live valve) this lapse, allows fluids to enter from the formation and create a liquid “plug” in the tubing which is the amount of liquid to be lifted.

INTERMITTENT Gas Lift

CLOSED

OPEN

t i : INFLUX

OPEN

CLOSED

CLOSED

CLOSED

t t : TRAVEL

t e : ESTABILIZATION

Tc = CYCLE TIME = t i + t t + t e

Figure N° 6-2 Intermitent Gas Lift (Standar & Idealized)

Section 6 –ARTIFICIAL LIFT SYSTEMS

6-5

6.2. ROD LIFT SYSTEM OVERVIEW Also known as Beam Pumps, a typical reciprocating rod lift system consists of a surface-pumping unit powered by an electric or gas prime mover, a rod string, and a positive displacement pump. Fluid is brought to the surface by the reciprocating pumping action of the surface unit attached to the rod string, which in turn, moves a traveling valve on the rod pump, loading it on the downstroke and lifting fluid to the surface on the upstroke. The operation of reciprocating rod lift systems has a history of proven reliability while giving operators the flexibility to reuse various components in different well applications. Weatherford offers a complete package and full range of reciprocating rod lift equipment for all your application requirements.

6.2.1. ROD LIFT APPLICATIONS • • • • •

SYSTEM

Virtually all applications, including sandy, gaseous, and high viscosity Wide range of fluid levels from near surface to seating nipple depth Low to medium volume lift capabilities All types of wells, including horizontal, slant, directional and vertical reservoirs Industry standard for land and remote applications

Figure N° 6-3 ROD Lift

6-6

Well Completion

6.2.2. ROD LIFT SYSTEM ADVANTAGES • • • • • • •

High system efficiency Optimization controls available Economical to repair and service Positive displacement/strong drawdown Upgraded materials reduce corrosion concerns Flexibility -- adjust production through stroke length and speed High salvage value for surface and downhole equipment

Figure N° 6-4 Typical beampump

Section 6 –ARTIFICIAL LIFT SYSTEMS

6-7

6.3. PCP SYSTEM OVERVIEW Progressing Cavity Pumping (PCP) Systems typically consist of a surface drive, drive string and downhole PC pump. The PC pump is comprised of a single helical-shaped rotor that turns inside a double helical elastomer-lined stator. The stator is attached to the production tubing string and remains stationary during pumping. In most cases the rotor is attached to a sucker rod string, which is suspended and rotated by the surface drive. As the rotor turns eccentrically in the stator, a series of sealed cavities form and progress from the inlet to the discharge end of the pump. The result is a non-pulsating positive displacement flow with a discharge rate proportional to the size of the cavity, rotational speed of the rotor and the differential pressure across the pump.

6.3.1. PCP SYSTEM APPLICATIONS • • • • • • • •

Sand-laden heavy crude oil and bitumen Medium crude oil with limits on H2S and CO2 Light sweet crude oil with limits on aromatic content High water cuts Dewatering gas wells such as coalbed methane projects Mature waterfloods Visual and/or height sensitive areas All type wells, including horizontal, slant, directional and vertical reservoirs

Figure N° 6-5 PCP Lift

6-8

Well Completion

6.3.2. PCP SYSTEM ADVANTAGES • • • • • • • • •

Low capital investment High system efficiency Low power consumption Pumps oils and waters with solids No internal valves to clog or gas lock Quiet operation Simple installation with minimal maintenance costs Portable, lightweight surface equipment Low surface profile for visual and height sensitive areas

6.3.3. DIRECT GEARBOX SURFACE DRIVES Offering the flexibility to be used with either a gas or electric prime mover, Direct Gearbox Drives provide an efficient and economical method to transmit power through the drive string to the downhole Progressing Cavity (PC) pump. These drives can be applied where a lower pumping speed is required or where electric power is not readily available.

Figure N° 6-6 PCP System

Section 6 –ARTIFICIAL LIFT SYSTEMS

Figure N° 6-7 PCP Completion

6-9

6-10

Well Completion

6.3.4. DIRECT ELECTRIC SURFACE DRIVES Direct Electric Surface Drives from Weatherford provide an efficient and economical method to transmit power through the drive string to the downhole Progressing Cavity (PC) pump. The electric motor is mounted to the wellhead drive and transmits torque through belts and sheaves to the drive string. Most Weatherford surface drives have the patented hollow shaft design allowing simple installation, operation and maintenance of both the wellhead drive and downhole PC pump.

Figure N° 6-8 PCP Drive

6.3.5. HYDRAULIC DRIVES FOR PCP Weatherford Hydraulic Surface Drives have been used in Progressing Cavity Pumping (PCP) applications for more than two decades. These systems are ideal for applications requiring precise torque control and adjustable wellhead speed. Of the two components making up the drive system, the wellhead drive houses the hydraulic motor, supplies power, suspends and rotates the drive string that, in turn, rotates the bottomhole pump. The Power Transmission System houses the prime mover (gas or electric), hydraulic pump and hydraulic oil reservoir.

6.3.6. PC PUMPS There are two basic elements that make up the downhole Progressing Cavity (PC) Pump – a single helical alloy-steel rotor connected to a rod string and a double helical elastomer-lined stator attached to the tubing string. Using the latest manufacturing technology, rotors are kept to tight

Figure N° 6-9 PCP Pump

Section 6 –ARTIFICIAL LIFT SYSTEMS

6-11

tolerances and treated with chemical and abrasion-resistance coating, typically hard chrome. Stators are comprised of a steel tube with an elastomer molded inside to provide the internal geometry. Each combination of rotor/stator is matched to downhole conditions to provide highly efficient operation and optimum production enhancement. The heart of the PC Pump is the stator elastomer itself.

Figure N° 6-10 Elastometer

Figure N° 6-11 PCP Pump

6-12

Well Completion

6.4. ESP OVERVIEW Electric Submersible Pumping (ESP) Systems incorporate an electric motor and centrifugal pump unit run on a production string and connected back to the surface control mechanism and transformer via an electric power cable. The downhole components are suspended from the production tubing above the wells' perforations. In most cases the motor is located on the bottom of the work string. Above the motor is the seal section, the intake or gas separator, and the pump. The power cable is banded to the tubing and plugs into the top of the motor. As the fluid comes into the well it must pass by the motor and into the pump. This fluid will flow past the motor aids in the cooling of the motor. The fluid then enters the intake and is taken into the pump. Each stage (impeller/diffuser combination) adds pressure or head to the fluid at a given rate. The fluid will build up enough pressure as it reaches the top of the pump to lift it to the surface and into the separator or flowline.

6.4.1. ESP APPLICATIONS • • • • • • • • • • • • • • •

High volume lift requirements (>300 BPD) A variety of well types including highly deviated or non-vertical wellbores Waterfloods or high water-cut wells With proper trim, can handle small quantities of H2S, CO2, and abrasives Well testing operations Mature waterfloods Abrasive, gassy, viscous fluids Electric Submersible Pumping Advantages High volume and depth capacity High efficiency over 1,000 BPD Low maintenance Minimal surface equipment requirements High resistance to corrosive downhole environments Use in deviated wells and vertical wells with doglegs Adaptable to wells with 4 1/2" casing or large Figure N° 6-12 ESP lift

Section 6 –ARTIFICIAL LIFT SYSTEMS

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6.5. PLUNGER LIFT OVERVIEW Plunger Lift Systems consist of a plunger, often referred to as a piston, two bumper springs, a lubricator to sense and stop the plunger as it arrives at the surface, and a surface controller of which several types are available. Various ancillary and accessory components are used to complement and support various application needs. In a typical plunger lift operation, the plunger cycles between the lower bumper spring located in the bottom section of the production tubing string and the upper bumper spring located in the surface lubricator on top of the wellhead. In some applications, the lower bumper spring is placed above a gas lift mandrel. As the plunger travels to the surface, it creates a solid interface between the lifted gas below and produced fluid above to maximize lifting energy. The plunger travels from the bottom of the well to the surface lubricator on the wellhead when the force of the lifting gas energy below the plunger is greater than the liquid load above the plunger. Any gas that bypasses the plunger during the lifting cycle flows up the production tubing and sweeps the area to minimize liquid fallback. The incrementation of the travel cycle is controlled by a surface controller and may be repeated as often as needed.

6.6. PLUNGER LIFT SYSTEM APPLICATIONS • • • • •

Unload wells that continue to load up with produced wellbore fluids Reduce fallback of fluids in flowing wells Increase production in wells with emulsion problems Clean the tubing ID in wells experiencing paraffin or other tubing deposit problems Eliminates need for soap

6.7. PLUNGER LIFT SYSTEM ADVANTAGES • • • • • • • • •

Dewatering gas wells Requires no outside energy source – uses well's energy to lift Easy maintenance Keeps well cleaned of paraffin deposits Low cost artificial lift method Excellent for small field or one well leases Handles gassy wells Good in deviated wells Can produce well to depletion Figure N° 6-13 Plunger Lift

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Well Completion

Notes