Oil and Gas Well CompletionsWPS - Kellyville Training Center

Completion DefinitionDefinition: The methodology and technology required to produce recoverable reserves (reservoir to surface).

Process:The design, selection and installation of tubulars, tools and equipment, located in the wellbore, for the purpose of conveying, pumping or controlling production (or injection) fluids.

Fundamental RequirementsA completion system must provide a means of oil or gas production which is:Safe e.g., well security, environmentEfficient e.g., production objectivesEconomic e.g., cost vs. revenue

Completion History/Evolution1300 Marco Polo wells dug at Caspian Sea1814 First naturally flowing oil well 475 ft1822 Rudimentary art of drilling established1905 Casing cemented1911 First gas lift device1913 First dual completion1926 First electric submersible pump1933 First gun perforation job1969 Commercial coiled tubing services introduced

Completion System DesignGross production rateWell depth and reservoir pressureFormation propertiesFluid propertiesWell locationOpenhole orCased HoleEruptive orPumpedSingle orMultiple Zone

Openhole Completions (Barefoot)Conductor with openholeNo ground water protectionCasing string with openholeProvides top-hole stabilityLiner with openholeCross-flow protectionReservoirCap RockOpenholeCompletionGravel PackCompletion

Perforated CompletionsCasing or linerWithout production tubingCasing or liner with production tubingProduction through tubing or annulusCasing or liner with tubing and packerProduction through tubing, enables flow controlReservoirCap RockCementedcasingCementedliner

Modern Completion ConfigurationFour zone selective production systemDual production stringsCommingled or alternate production controlled by sliding sleevesSystem contains 28 major downhole components

Factors Affecting Well Performance

1 Reservoir boundaryCan be estimated2 Reservoir propertiesCan be measured3 CompletionCan be controlled

Vertical Wellbore ProfileVertical wellboreNo great productivity benefitMay catch unwanted water or gasPreferred for fracturing

Deviated Wellbore ProfileCap rockBasementDeviated wellboreIncreased productivity especially in thin reservoirsExtends reach within reservoir

Horizontal Wellbore ProfileHorizontal wellboreSignificant increase in productivityReduced influence of skinReduced influence on coningCap rockWater zone

Oil and Gas Well CompletionsCompletionDesign and Engineering

Multiphase Fluid FlowPrincipal multiphase flow regimes recognised in oil and gas wells:Bubble flowSlug flowTransition or churn flowAnnular or mist flow

Bubble FlowBubble flow characterized by:Small evenly distributed gas bubblesContinuous liquid phaseFurther categorized as:Bubbly flowDispersed bubble flowSmall gas bubbles evenly distributed throughout liquid phase

Slug FlowSlug flow characterized by:Series of gas pockets between slugs of liquidContinuous liquid phaseTaylor bubblesBubbles of varying size unevenly distributed throughout liquid phase

Annular/MistAnnular/mist flow characterized by:Continuous gas phaseEntrained liquid in gas flow (mist)Annular liquid film ContinuousgasphaseAnnularfluidfilm

Transition/Churn FlowTransition flow characterized by:Chaotic flow patternNeither phase is continuousLiquid appears to move both up and down the conduitChaotic flow pattern

Evaluating Pressure LossesGasLiquidSeparatorNodeSurface chokeReservoir Node(boundary)Wellhead NodeWellbore NodeReservoir Node(near wellbore)SSSVDownholerestriction

Tubing String SpecificationTubing strings specified by the following:Size and dimensionsODWeight and wall thicknessCoupling ODMaterial gradeMinimum yield strengthConstructionSeamless/electric welded pipeTool jointNonupset/UpsetPremium thread

Tubing Connections - CollarNon-upset(8 round) ConnectionExternal Upset Connection

Tubing Connections - IntegralEUE Integral ConnectionHydril Integral Connection

String Design FactorsCriteria for string selection/design include:Pressure and tension< 80% of tubing yield strengthburst and collapse pressure limitationsProduction rateflowrate should be compatible with flow areaWellbore environmentfluid properties, e.g., corrosion, wellbore depositsTubular connections and geometrye.g., tool joints and annular clearanceForce and stressthroughout the life of the completion

Tubing ForcesForces and stresses on the completion can be effected by:Temperaturetemperature changesPressurepressure changesWeight of componentsFluid density and gradientsFrictionespecially in deviated wellbores

Tubing Movement- PackersLimited motionNo motionFree motion

Buoyancy1Open tubing4Plugged string3Tapered string2Tapered stringACBDACBA

Length and Force ChangesLength and forces changes should be assessed to enable:Selection of an appropriate packerAssessment of potential tubing damageAccurate space out and landing of the completionFour principal causes of length and force changes:Piston effectBuckling effectBallooning effectTemperature effect

Buckling EffectRadial clearanceBowed tubingCompression bucklingNeutral pointRCasing wall contact

Pressure BucklingTubing deflectionacts to increase tensionHigh pressureLow pressure

Ballooning EffectHigh pressureLow pressureActs toshorten the stringincreasing tension

Reverse BallooningHigh pressureLow pressureActs tolengthen the stringreducingtension

Temperature EffectNeutral (As installed)Cooling increases tensionHeating reduces tensionICEHEAT

Tubing Stress CalculationsCompletion fluid1Installation3Treatment2ProductionCompletion fluidMid stroke settingProduced fluidCompletion fluidSeal assembly on down-strokeTreatment fluidCompletion fluidSeal assembly on up-stroke

Material SelectionFactors influencing material selection criteria typically include:Mechanical propertiese.g., material strengthOperating environmente.g., sour or corrosive serviceEase of manufactureCostAvailabilitye.g., in required dimensions

CorrosionFailure mechanisms associated with corrosion:Stress corrosion crackingHydrogen embrittlement, stress crackingMaterial weight lossCO2 corrosion, oxidization, treatment fluidsPitting or localised lossRequires three conditionsCorrosive media, e.g., oxygenElectrolyte, e.g., moistureHeat or pressure

Elastomers and PlasticsGeneral definition:An elastomer can be stretched to at least twice its original length and will quickly return to approximately its original length on release. Plastics cannot withstand such strain without permanent damage.

Primary applications:Sealing components for:pressurefluids (liquids and gas)heat

Elastomer and Plastic LimitationsElastomers and plastics should be selected on compatibility with:Corrosive fluids or environmente.g., reservoir or completion fluidsChemical compatibilitye.g., stimulation fluidsOperating temperatureincluding range and fluctuationOperating pressureincluding range and fluctuationDimensione.g., ability to function with extrusion gap

PerforatingThe process of creating a clear channel of communication between the reservoir and wellbore.

Technique selection depends on:Completion type and dimensionsReservoir conditions, e.g., stability/consolidationLocal experience and preference

Perforation History

Perforation Program DesignPrincipal design considerations include:Location of the perforated intervalShot densityPerforation phasingPenetrationPerforating debrisGun conveyance methodGun recoverabilityBottom hole perforating pressure

Perforating Gun ComponentsPrincipal perforation gun/system components:Charge carrierrecoverable, disposable Detonatorelectrical or percussion (dependent on conveyance)Detonating cordprovides link between chargesShaped chargegenerates high pressure jet

Perforation ChargeCharge components

Perforation ProcessPerforation sequenceCrushed zonePerforation debrisClean, stable perforation tunnelExtremely high-pressure jet

Perforating Gun SystemsPerforating gun or system options include:Gun conveyance methodwireline, TCP or coiled tubingThru-tubing gun systemssmall OD systemsCasing gun systemslarge OD systemsTubing conveyed gun systemsrecovered or droppedsuitable for long intervalsno verification

Perforation PhasingEffects of perforation phasing

Perforation PhasingPerforation phasing describes the angle between shots. Key considerations include:Five common configurations - 0o, 60o, 90o, 120o, 180ophased guns require decentralizingNear wellbore flow characteristics effected by phasingOriented phasing may be desirable, e.g., hydraulic fracturing treatments

Penetration, Stand Off and DebrisPenetration - effective length of perforation channelShould bypass damaged zoneEffected by stand-offStand Off - distance between gun and casing/linerCharge efficiency diminishes with distanceEffects accentuated at high pressuresPerforation size effected by stand offPerforation debris - left in place after perforatingSome debris inevitable - dependent on gun/charge typeShould be removed by back flush after/during perforating

Bottomhole Perforation PressureTwo basic bottom hole pressure conditions associated with perforating:Overbalanced - perforating with kill weight fluid column in wellboreSurge following perforation acts to compact debrisRequires less complex equipment and techniquesUnderbalancedRemoves perforation debris at time of perforationReduces likelihood of near-wellbore damageRequires special equipment and techniquesA third Pressure condition is being used in the last years:Extreme Overbalanced Perforation ( EOB ); The wellbore pressure in the wellbore is higher than the Frac Gradient.

Oil and Gas Well Completions Types of Completion

Completion Design FactorsPrincipal completion design factor include:Casing protectione.g., protection against erosion, corrosionTubing string removale.g., for replacement or workoverSafety or contingencye.g., requirements for safety valves and well killProduction controle.g., components providing flexibility and control of production (nipples, profiles and sliding sleeves

Basic Production ConfigurationsMajority of completions are based on the following completion configurationsReservoir interfaceOpenholeCasing productionLiner productionGravel pack wellboreProduction conduitSuspended tubingBasic packer Packer and tailpipePacker with additional safety and production devices

Open Hole ProductionKey pointsNo downhole flow control or isolationProducing formation is unsupportedCasing provides isolation between shallower formations

Casing ProductionKey pointsNo downhole flow control or isolationCasing provides isolation between shallower formations with potential for remedial work to isolate sections of perforated interval

Liner ProductionKey pointsSimilar to casing production but with smaller (and shorter) tubulars set through the reservoir

Gravel Pack WellboreKey pointsSpecial application - requirement determined by formation typeMay require special operation (underreaming) during well construction phase

Simple Tubing CompletionKey featuresCirculation capability (well kill or kick-off)Improves hydraulic performanceLimited protection for casing

Basic Packer CompletionKey featuresCirculation capability (determined by design and setting of packer)Casing string protected from fluid and pressure effects

Packer with TailpipeKey featuresAdditional flexibility for downhole production (flow)control, e.g., plugsFacility for downhole instruments (gauges)

Enhanced Packer InstallationKey featuresImproved flexibility for downhole production control, e.g., plugs above or below packerCirculation capability independent of packerSafety facility (SSSV)

Completion ExamplesThe following completion examples are extracted from design files for:Single zone completionsMultiple zone completionsLiner completionsSpecial completionsSand controlInhibitor injectionWaterfloodThermalRemedial (scab liner)

Single Zone Retrievable PackerKey FeaturesTail-pipe facility for pressure and temperature gaugesFully retrievable completionPacker can be set with well flanged upThru-tubing perforation possible where size permits

Single Zone Seal-Bore PackerKey FeaturesSeal-bore packer set on electric-line or tubingOn-off connector and tubing anchor allows tubing to be retrievedTailpipe plugged and left in wellbore or retrieved with production tubing

Single Zone Packer and TailpipeKey FeaturesTailpipe plugged and left in wellbore when production tubing is retrievedPermits safe thru-tubing perforatingBlock and kill system facilitates the killing of high-pressure, high-flowrate wells

Single Zone Casing Seal ReceptacleKey FeaturesExpansion joint allows for tubing movementTailpipe retrievable (separately)Protective sleeve run in CSR during primary and remedial cementing

Multiple Zones 2 Zones 1 PackerKey FeaturesSeparate or commingled production through single tubing stringBlast joint protection across upper intervalOn-off connector and tubing anchor permits tubing retrieval with lower interval isolated

Multiple Zones 2 Zones 2 PackersKey FeaturesIndependent production through dual tubing stringsBlast joint protection across upper intervalBoth packers retrievableTailpipe instrument facility on both stringsThru-tubing perforation of lower zone possible

Multiple Zones 3 Zones 3 PackersKey FeaturesSeveral zones produced through one tubing stringFlow controlled by wireline retrievable choke/check valvesBy-pass sliding sleeve prevents communication during service workUp to five zones have been produced using this method

Multiple Zones 4 Zones 4 PackersKey FeaturesFour zone selective production systemDual production stringsCommingled or alternate production controlled by sliding sleevesSystem contains 28 major downhole components

Liner CSRKey FeaturesMost simple liner hook-upCSR replaces packerFluid circulation through sliding sleeve above the liner hangerTailpipe retrieved with production tubing

CSR and Seal-Bore PackerKey FeaturesLiner top/lap is permanently isolatedFluid circulation through sliding sleeve above the packerTailpipe can be plugged to allow retrieval of the production tubing

Special Service CompletionsSpecial completion examples include:Sand controlInhibitor injectionWaterfloodTubing/casing repair

Gravel Pack CompletionKey FeaturesTools set and gravel placed using a service tool and tubing workstringGravel squeezed into perforation tunnelsProduction tubing stung-in to production seal-assemblySpecialised service typically involving dedicated service equipment and personnel

Inhibitor InjectionKey FeaturesSide pocket mandrel injection permits protection inside production tubing above the packerInjection nipple and small diameter injection line is suitable for shallow applications

Inhibitor Complete ProtectionKey FeaturesParallel flow tube and seal-bore packer enables inhibitor to be pumped down short stringAll flow-wetted completion components are exposed to inhibitor fluidInhibitor flow controlled at surface

WaterfloodKey FeaturesTwo injection zones treated with both flow control regulators located at surfaceTotally separate injection systems

Waterflood Thick Injection ZoneKey FeaturesInjection efficiency in thick zones is improved by using multiple injection pointsDownhole flow regulation helps prevent premature breakthrough between intra-zonal sections

Thermal Completion Steam InjectionKey FeaturesPacker incorporates an integral expansion/slip joint assemblySPM allows insulation material to be circulated into annulus

Remedial Completion Scab LinerKey FeaturesIsolation of damaged casing/liner or abandonment of a depleted zoneHydraulic set packers at top and bottom of scab linerOn-off connector on lower seal-bore packer allowed installation with the lower perforations isolated throughout the operation

Monbore CompletionKey FeaturesDesigned to meet criteria for:appropriate production ratesflexibility/contingencysafetymonitoring (reservoir management)longevitySafety valvePacker/hangerassemblyLiner

Multi-Zone Completion

Artificial Lift ObjectivesThe primary purpose of installing an artificial lift system is to maintain a reduced bottom hole pressure (drawdown) to enable the desired reservoir fluids to be produced at an acceptable rate.

Reasons for Artificial LiftCompensate for declining reservoir pressurei.e., maintain an acceptable production rateOffsetting the effect of increasing water productionOvercome high friction pressures associated with the production of viscous or waxy crudesKick-off high gas-liquid ratio wells that die when shut inReduce the effect of flowline back pressureMaintaining a production rate which reduces wax or scale deposition

Artificial Lift SelectionThe selection of an appropriate (optimal) artificial lift system is dependent on:Inflow performance of the well/reservoirCapacity and operation of the artificial lift system(s)Capital costOperating costServicing frequency (maintenance cost)

Artificial Lift TPC

Artificial Lift MethodsCommonly used artificial lift methods include:Rod pumpGas liftElectric submersible pumpPiston pumpJet pumpPlunger liftOther specialist or adapted systems

Rod PumpRod pumps account for approximately 60% of onshore artificial lift completionsIndustry acceptedEconomic in ideal fieldNot gas dependentLimited efficiencyMaintenance intensiveVertical wellboresRodsProduction tubingRod pumpTubinganchor

Rod Pump - Surface Equipment

Gas LiftGas lift accounts for approximately 90% of offshore artificial lift completionsSystem may be designed to suit most wellsWireline serviceableFew mechanical partsSand and fill tolerantProduction tubingProduction tubingGas lift valve installed inside pocket mandrelRetrievable packer No-go seating nippleWireline entry guide

Electric Submersible PumpExtremely high liquid production capabilityHigh installation and operating costSuitable for low gas-to-oil ratio applications onlyElectrical components easily damaged

Hydraulic Systems Hydraulic pumping systems - two main categoriesPiston pumpclose coupled engine/pump assembly with positive displacement pumpperformance determined by the pump/engine sizeHydraulic jet pumpimparts energy to the production fluidrelatively tolerant of lower quality power fluid or produced fluids

Hydraulic Pumping SystemsPiston pumpsystemJet pumpsystem

Plunger LiftSuited to high GLR wells (low liquid production)Efficiency decreases with depth and PIEfficiency increase in larger tubing sizes (where liquid slippage is more prevalent)Other SystemsScrew pumpoperates on same principle as PDMTurbine pumpsimilar to ESP installations

Plunger Lift SystemPlunger (with liquid loadTubing stopStanding valveTubing stopInjection gasProductionPlungercatcherIntermitteror controllerSurface EquipmentDownhole Equipment

Introduction to Oil and Gas Well Completions

After a well has been drilled, it must be properly completed before it can be put into production. A complex technology has evolved around the techniques and equipment developed for this purpose.

This presentation sequence has evolved, and as a living document will continue to evolve, with the objective of providing a sound introduction to completion technologies. Additional detail and emphasis is placed on areas associated with the services and products provided by Schlumberger Technology Corporation and its alliance partners.

Definition

The well completion process extends far beyond the common perception of installing the wellbore tubulars and completion equipment.

By referring to methodology and technology we imply a process.

The definition and process thereby includes installing and cementing the production casing or liner, as well as logging perforating and testing are part of the completion process. In addition, complex wellhead, processing or storage requirements effect the production of a well so it may have some bearing on the design and configuration of the completion.

Completion Requirements

There are three basic requirements of any completion (in common with every oilfield product or service).A completion system must provide an (i) efficient, (ii) safe and (iii) economic means of producing petroleum products. Current industry conditions may force operators to place undue emphasis on the economic requirement of completions. However, a non-optimized completion system may compromise long-term company objectives. For example, if the company objective is to maximize the recoverable reserves of a reservoir or field, a poor or inappropriate completion design can seriously jeopardize achievement of the objective as the reservoir becomes depleted.To summarise, it is the technical efficiency of the entire completion system, viewed alongside the specific company objectives, which ultimately determines the completions configurations and equipment used.Completion Technology Evolution

The first openhole wells were drilled in very shallow reservoirs which were sufficiently consolidated to prevent caving. As deeper wells were drilled, the problems associated with surface water prompted the use of a casing or conductor to isolate water and prevent sloughing. Development of this process led to fully cased wellbores in which the interval of interest is selectively perforated.

Completion System Design

The initial approach to the completion design will depend on:(i) the basic classification optionsand(ii) reservoir, fluid and location issuesBarefoot Completions

Only feasible in reservoirs with sufficient formation strength to prevent caving or sloughing. In such completions there are no means of selectively producing or isolating intervals within the reservoir. This completion technique is now almost entirely abandoned except for a few low pressure formations and in highly specialised conditions such as the external gravel pack shown.

Perforated Completions

The evolution and development of efficient and reliable perforating tools and logging services has enabled complex completions to be designed with a high degree of efficiency and confidence. This, combined with efficient reservoir interpretation and appraisal techniques, ensures the successful completion and production of modern-day oil and gas wells.

Modern Completions

Multiple zone completions are often used in reservoirs with complex structures and production characteristics. The ability to select and control the production (or injection) of individual zones is often the key to ensuring the most efficient production regime for the field or reservoir. Consequently, modern multiple completions tend to be more complex to maintain a high degree of flexibility and control of production.

Factors Affecting Well Performance

The factors affecting well, field or reservoir performance can be classified as shown. Since the completion is the only area which can be controlled there is an obvious need for the completion design and installation process to be carefully conducted. The shape of the curve illustrated is determined by a combination of all three factors.The management of certain reservoir properties is the basis of sound reservoir management.Vertical Wellbore Profile

The wellbore profile can have significant bearing on the production characteristics of a well/reservoir. Most wellbores can be described as being vertical, deviated or horizontal. Each category has associated advantages and disadvantages. However, in the majority of reservoirs currently being developed, horizontal wells provide significant benefits and are becoming a preferred option in many cases.

Vertical wellbore - provides limited intersection of the reservoir, especially on thin reservoirs. However, this configuration provides improved predictability/control on reservoirs which are to be stimulated by hydraulic fracturing.Deviated Wellbore Profile

Deviated wellbore - extends the reach of the well to access outlying reserves and improves productivity by increasing reservoir contact, especially in thin reservoirs.In wellbores deviated greater than 45, significant productivity gains can be realized.Horizontal Wellbore Profile

Horizontal wellbore - significant increase in productivity, especially in thin reservoirs. Reduced influence of skin and reduced susceptibility to water and gas coning.Completion Design and Engineering

The design of an efficient, safe and economic completion system is dependent on the acquisition of accurate data. Previous experience and knowledge of potential problem areas help identify data areas which must be closely assessed.In general, deeper wells, multiple zones and extremes of temperature or pressure (i.e., costly completions) require a more careful design and selection process.

Multiphase Fluid Flow

There are several flow regimes associated with the upward flow of multiphase fluids in vertical, or slightly deviated wellbores. Four conditions are generally recognized when describing flow in oil and/or gas wells.Bubble Flow

Characterized by a uniformly distributed gas phase as discrete bubbles in a continuous liquid phase. Further classified into bubbly and dispersed bubble flows, based on the presence or absence of slippage between the liquid and gas phases.In a bubbly flow regime, fewer and larger bubbles move faster than the liquid phase due to slippage. In dispersed bubble flow numerous tiny bubbles are transported by the liquid phase, resulting in little relative motion between the two phases. Dispersed bubble flow is sometimes known as froth flow.Slug Flow

Characterized by a series of slugs, comprising a gas pocket called a Taylor bubble, a plug of liquid (slug) and a film of liquid around the Taylor bubble flowing downwards. For vertical flow, the Taylor bubble is an axially symmetrical bullet-shaped gas pocket that occupies almost the entire cross-sectional area of the pipe. The liquid slug, containing smaller gas bubbles, bridges the tubing thereby separating the Taylor bubbles.Annular/Mist Flow

Characterized by a continuous gas phase core with the liquid flowing upwards as thin film on the tubing wall. Some investigators have called this flow pattern mist flow, since small liquid drops are continuously being broken from, and reabsorbed by the annular film. The interfacial shear stress acting at the core-film interface and the amount of entrained liquid in the core are important parameters.Transition or Churn Flow

A chaotic flow of gas and liquid in which both the Taylor bubbles and liquid slugs become distorted. Neither phase appears to be continuous and the liquid phase appears to move both up and down (oscillate) the tubular. Churn flow is considered a transition region between slug flow and mist flow.Evaluating Pressure Loss

For NODAL analysis, the producing system is considered in four components, (i) the separator, (ii) horizontal flow line, (iii) tubing/completion string, and (iv) the reservoir. Each component is analysed separately and then as a group to evaluate the performance of the complete system.Tubing String SpecificationTubing generally provides the primary conduit from the producing interval to the wellhead production facilities. Therefore, the proper selection, design and installation of tubing is very important part of any completion system.Size/dimensions - the tubing must be sized to enable efficient production.Grade - the string should be designed to prevent failure from tensile forces, internal and external pressures and the corrosive nature of the wellbore environment.Assembly - the components of the string must be installed undamaged to provide a pressure tight seal.

Tubing grades criteria are specified by API:Standard API gradesJ-55, C-75, C-95, N-80, P-105Special gradese.g., C-75 and C-95 for H2S serviceHigh strength gradesGrades having a yield strength above 80,000 psiMore sensitive to defects or damagemanufacturing defectshandling or transport damagehydrogen embrittlementTubing Connections

Collar type connections are the most common but have limitations of service and pressure.Tubing Connections - Integral

Integral tubing connections have been developed for high pressure and more demanding applications.String Design Factors

Key string design and selection factors are shown.Tubing Forces

Factors effecting forces on the completion are shown.Tubing Movement

Choice of packers and tubing components not only must meet minimum stress requirements, but they themselves contribute directly to these stress calculations.The tubing/packer relationship (motion) must be considered.(i) strung through packers (sealbore) - unlimited motionNote: unlimited refers to the direction of motion (up/down) not the extent or distance of travel.(ii) landed packer provides for movement upward only.(iii) latched packers allow no motionBuoyancy

Archimedes Principle which deals with buoyancy, states: A body (pipe) wholly or partially submerged in a fluid, experiences an upward force equal to the weight of the fluid displaced.For example, consider the hydrostatic pressure acting on the cross-sectional area of the tubing. The buoyancy of a tube is the same in any position, but in the vertical position the entire force is concentrated on the lower end, ie in the horizontal position the entire force is distributed evenly over the length.

The four examples shown illustrate the principal effect/factors associated with completion string buoyancy.(i) open ended non-tapered tubing string(ii) tapered tubing string (iii) tapered tubing string with significant fluid/pressure differentials(iv) plugged stringLength and Force Changes

The piston effect, buckling effect and ballooning effect result from pressure changes in the system.The temperature effect is related only to temperature change and is not effected by pressure changes. While some effects are related to each other, each must be calculated individually. Each calculated effect will have a magnitude and direction. Once each effect is know, they are combined to obtain the total effect. The decision to add or subtract when combining is based on the direction that each effect (resultant force) acts.Forces on the completion string are generally expressed in very large numbers. Consequently, if a force direction is added to the string weight instead of being subtracted, a 50,000 lbf error is entered into the calculations.

Bowed tubing - Temporary and Permanent Buckling

In temporary buckling, forces have been generated great enough to cause buckling within the elastic limit of the tubing material. These forces have not exceeded the yield strength of the tubing and when buckling forces are released the tubing will return to its original shape. In permanent buckling, buckling forces have exceeded the yield strength (elastic limit) of the tubing and the tubing will remain buckled even when buckling forces are released.Neutral Point BucklingNeutral point buckling will not occur until a point is reached (neutral point) that forces are not strong enough to cause buckling. From this point to the surface, the tubing is relatively straight. The amount of severity of buckling is dependent upon the forces placed on the tubing, the size of the tubing, and the r value.Compression BucklingIs the result of the weight or force being applied on the tubing end. The force applied results in bowing of the tubing. Compression buckling is one of the greater contributing forces and can be the result of many combined forces (eg in a latched packer system, an increase in temperature will cause expansion of the tubing resulting in buckling and possibly corkscrewing).Pressure Buckling

Is an unequal force distribution caused by a large internal tubing pressure differential. Minor variations in the wall thickness of tubular goods will initiate pressure buckling. Pressure buckling only occurs with a high internal differential tubing pressure and contributes very little to tubing length contractionBallooning Effect

When pressure is applied to the inside of a tubing string, the pressure differential from the inside of the tubing to the outside of the tubing creates a force that will attempt to burst the tubing. These burst forces cause the tubing to swell (balloon). Reverse Ballooning

When pressure is applied to the outside of a tubing string, the pressure differential creates a force that will attempt to collapse the tubing. These forces cause the tubing to reverse balloon.Temperature Effect

The temperature effect is the only one of the four basic effects which is not pressure related. The length and force changes due to temperature effect are a function of the change in average temperature throughout the tubing string.When the average temperature is decreased, eg by injecting cool fluids, the string will shorten in length if the tubing is free to move. If the tubing is restrained from moving, a tension force will be applied to the packer. When the average tubing temperature is increased, either by injecting or producing hot fluids, it will cause the tubing to elongate if it is free to move. If the tubing is restrained from moving, a compressive force will be applied to the packer.In many packer installations the temperature effect will be the largest of the four effects. To find the average temperature of the tubing string, both the surface and bottom hole temperature must be known.Two important points should be kept in mind when the equipment is installed downhole:(i) The temperature effect is not immediate. It may require several minutes to several hours for the temperature effect to be seen. However, it is normally assumed that the temperature effect occurs immediately. This assumption allows the temperature effect to be added to the pressure effects so that all factors can be considered at one time.(ii) In injection applications, the temperature of the injected fluid will vary with time as a result of climatic changes. When an installation is planned where the injection temperatures will vary, average temperature calculations should be based on worst case injection temperature.Tubing Stress Calculations

The final completion calculation check is to determine the forces acting on the tubing and whether or not tubing failure will occur. In a situation where tubing is being stressed higher than the recommended 80% safety factor, a heavier grade of tubing, further application of mechanically applied force, or applied pressure may be needed to meet operational requirements.

NOTE THE MOVEMENT OF THE END OF THE TUBING IN THE DIFFERENT SITUATIONS.Material Selection

In general, oil and gas wells are hostile environments and some consideration must be given to the materials from which completion components are manufactured or machined. A wide variety of materials, with a range of physicals properties, have been developed specifically for use in downhole completion components. In severe cases, it may be necessary, or cost effective, to incorporate a system which neutralises, or at least reduces, the harmful effects of agents present in the wellbore or reservoir fluid. Proper selection of completion materials is a key factor in ensuring completion longevity.

Corrosion

Corrosion is generally viewed as the factor having the greatest detrimental effect on the life and integrity of completion equipment and components. In severe environments, components will fail extremely rapidly often with spectacular results and requiring expensive fishing or retrieving operations.There are three principal failure mechanisms associated with corrosion. Although two related to material loss, the cause and effect of each are significantly different. Material loss uniform loss of material Pitting or localized loss Stress corrosion crackingIn material loss corrosion, the base metal reacts to form a compound which lacks the structural strength or form of the original material. This can occur as oxidation (rusting) or closely related oxidation by sulfur attack from H 2 S.Essential conditions for corrosion include: Corrosive media (e.g., oxygen) An electrolyte (e.g., moisture) Heat or pressureIn general terms, all forms of corrosion encountered in oilfield tubulars require the presence of moisture. The moisture may be present in very small quantities, but is an essential part of the corrosion process.

Elastomers and Plastics

The primary applications of elastomers and plastics in completion components are in sealing applications to isolate pressures, liquids, gases, or heat. As a general rule, elastomers are used for the seal material with plastics being used in support or backup functions to prevent distortion, extrusion and eventual failure of the seal. The elasticity of an elastomer, enables an efficient seal to be achieved as the material deforms against the sealing surface. Being incompressible, the elastomer can maintain this seal across a range of pressures providing the material is constrained, e.g., an O-ring groove with appropriate extrusion gap(s)Elastomer and Plastic Limitations

Although elastomers generally function well in most wellbore environments, there can be significant limitations within the areas shown

Ironically, seals are generally the least expensive part or component in a tool assembly, but often impose the greatest limitations in tools performance or operating range. Consequently, the correct selection of elastomers and plastics for downhole application is an important process which should be undertaken by an engineer with a thorough understanding of the materials available and the specific conditions of the intended installation..Perforating

Perforating is the process of creating a clear channel of communication between the wellbore and the reservoir. This should be achieved without damaging the inflow ability of the surrounding formation to ensure that the perforations do not form a restriction on the production capability of the completion system.There are generally several perforating options available for most completion applications. Selection of the most appropriate technique will consider specifications of the completion (e.g., dimensions), reservoir conditions (e.g., consolidation compatible with under/over balanced perforating) and local experience.Perforating Program Design

The principal considerations for design of a perforating program are outlined. In many cases, local field experience and the availability of specific perforating services will determine the preferred program.Perforating Gun Components

The principal components of any perforating gun or system include:Charge carrierThe charge carrier is the housing within which the gun components are placed and connected. A number of carrier configurations are commonly used depending on the conveyance method selected. DetonatorDetonators are used to initiate the ballistic sequence at time of perforation. Safety systems to allow perforating guns to be assembled and deployed safely are typically linked with the detonator or detonation system. Such safety systems and procedures are an essential and integral part of all perforating operations.Detonating CordThe detonating cord provides the link between the detonator and each of the shaped charges contained in the gun assembly. The cord passes in close proximity to the primer section of the shaped charge which initiates the main explosive charge.Shaped chargeA shaped perforating charge contains four principal components each of which are critically engineered to provide the desired perforation characteristics and charge performance.Perforation Charge

Modern perforating operations rely on the accurate placement and reliable detonation of a shaped explosive charge. When detonated, the shaped charge creates a jet of extremely high pressure (15 million psi) travelling at high speed (21,000 ft/sec). This action causes the casing/liner, cement and formation to flow away from the jet tip and thereby create the perforation, i.e., it is a high pressure process rather than a burning process which creates the perforation tunnel.

Perforation Process

A key objective of perforating is to establish a clean, stable channel between the wellbore and the reservoir. Perforation clean-up should be considered part of the perforating operation.Perforating Gun Systems

Conveyance MethodWireline - Conventional perforating operations are completed using wireline conveyance.Tubing conveyed perforating (TCP) - Tubing conveyed perforating typically utilizes casing guns run on a tubing string which, since there are no electrical conductors available, incorporates a mechanical or hydraulic detonation or firing system.Coiled tubing - CT conveyed perforating operations can utilize gun systems designed for wireline or TCP applications depending on whether a wireline is installed in the CT string.Casing gun systemsCasing guns systems were designed for perforating operations which are undertaken before the well is completed. However, with the increased use of tubing conveyed perforating, (including coiled tubing) some casing gun systems or components are used in thru-tubing and TCP applications.Tubing conveyed gun systemsTubing conveyed perforating systems are run on a tubing string, typically on the tailpipe below a packer, allowing the packer to be set before perforating. Since the guns deployed by this method are typically larger than through tubing guns, the resulting perforations are typically larger and deeper.Perforation Phasing

There are five common gun configurations, 0, 60, 90, 120, 180. The phasing options are limited by the type of gun, or gun conveyance system being used. Note the effect of stand-off and small gun, large casingPerforation Phasing

Perforation phasing describes the angle between the perforation tunnels. There are five common gun configurations 0, 60, 90, 120 and 180. The phasing options are limited by the type of gun, or gun conveyance system, being used. In general, small diameter guns (e.g., thru-tubing guns) enable fewer options due to the limited space available.Zero degree phase guns contain charges aligned in a row. This gun configuration differs from others in that is desirable to decentralize the gun to minimize the stand off. A magnetic positioning system is generally used to ensure the charges are properly located against the casing/liner wall. Zero degree phased perforating carries two principal disadvantages.At high shot densities (>16 SPF), 0 phasing significantly weakens the casing or liner. This may cause some distortion which restricts access below the perforated interval. Note: High shot density using 0 phased perforating guns is achieved through multiple gun runs (typically 6 SPF is the maximum shot density per run).The near wellbore flow characteristics for 0 phased perforations presents a restriction to production and can limit the efficiency of stimulation treatments. For ex-ample, the efficiency of a fracturing operation is significantly increased if the perforations are aligned with the plane on which the fracture wings will form.Penetration Stand Off and Debris

The length (or penetration) of the perforation can be a critical factor in achieving the desired production response. An essential objective in any perforating operation is to connect the reservoir to the wellbore. This involves penetrating through the drilling damage zone to access the reservoir.The following factors should be considered in regard to perforation penetration.The performance and penetration of a perforation charge is greatly influenced by gun stand off.Maximizing the perforation penetration is a common objective. However, in some applications (e.g., gravel pack completions), perforation diameter is more crucial than perforation length.Gun stand off is the distance from the exterior surface of the gun and the target surface for the perforation. The efficiency of a perforating charge diminishes with distance, consequently minimizing gun stand off is beneficial. However, due to the geometry of the wellbore and gun system, some stand off is inevitable..A small quantity of debris is inevitable from any perforating operation. Debris can be left from the charge, the gun body and the crushed rock. However, some guns systems leave more debris than others, e.g., strip guns may leave relatively large pieces of debris downhole. Smaller debris and crushed rock should be backflushed from the perforation tunnel. A cleanup flow period may be necessary to achieve this, especially in critical applications such as gravel packing.Bottomhole Perforation Pressure

There are two basic bottomhole pressure conditions during perforating, under or overbalance, ie. the wellbore pressure is less, or greater, than of the reservoir to be perforated.Overbalanced - perforating with a kill weight fluid column in the wellbore. After the perforation is created, the pressure within the wellbore acts to compact the perforating debris in the damaged zone surrounding the perforation tunnel. This may cause lasting damage to the perforation (and surrounding zone) conductivity, or if severe plug the perforation.Underbalanced - generally regarded as the preferred method of creating perforations which are clear of debris or damage. The pressure differential applied during underbalanced perforating causes the reservoir fluid to flush out debris and loosened formation immediately after the charge is fired. The benefits of underbalanced perforating are well accepted and documented.Extreme Overbalanced Perforation ( EOB ); The wellbore pressure in the wellbore is higher than the Frac Gradient. Normally the gradient pressure applied is 1.4 psi/ft or greater and the fluid in the tubing is mainly nitrogen. When the guns fires the formation is suddenly expose to the wellbore pressure, wich is greater than the frac pressure, the fluid rushing into the perforations generate multiple small fracs that will reamin open after the operation.

1Types of Completion

Note: This section does not include artificial lift examples. Artificial lift completions, by their nature, require special consideration of several detailed design factors. A description of artificial lift systems (including wellbore configuration examples) is covered in a later manual section/presentation sequence.

Completion designs vary greatly, and can be categorised in many ways. The underlying requirement is, as always, that the completion be safe, efficient and economical.

2Completion Design Factors

Completion design processes has evolved as the complexity of components and the overall completion design has increased. However, the principal factors shown are considered basic and have a role to play in almost all completion design processes.

Basic Production Configurations

This slide sequence almost describes the evolution of completion design. However, some of the more simple configurations may still be appropriate for some special applications (or locations) Open Hole

No protection against formation movement and minimal control of production (surface only). Wellbore tubulars (casing) exposed to production fluids.Cased Hole

Protection against formation movement and minimal control of production (surface only). Wellbore tubulars (casing) exposed to production fluids.

The perforated producing interval can enable remedial work (cement squeeze) to control excess water or gas production.Liner Production

Protection against formation movement and minimal control of production (surface only). Wellbore tubulars (casing) exposed to production fluids.

Reduced cost associated with liner (less tubulars and smaller hole size)Gravel Pack Completion

Special application determined by formation type/behaviour often, requiring greater complexity during the well construction phase. Suspended Tubing

Provides partial protection for casing/liner string by providing a separate flow path. However, casing/liner remains exposed to production fluids.

Provides a circulating capability for well kill (and kick-off) purposes.

Reduced cross sectional area results in more efficient production of all production fluids, I.e., preventing liquid loading or water build-up.Basic Packer Installation

Provides better protection for casing/liner string by providing a separate flow path and enabling a inhibited fluid to be placed in the annulus.

Provides a circulating capability for well kill (and kick-off) purposes, with the additional safety feature of the annulus containing kill fluid. In addition to safety issues, this also reduces the levels of stress to which the casing string is submitted.Packer with Tailpipe

Provides all advantages of the basic packer installation but enables downhole flow control (including plugging) and a facility for downhole gauges.Enhanced Packer Installation

Provides all advantages of the previous basic packer installations but enables greater flexibility in downhole flow control and circulation.

Safety components (SSSV) provide a higher safety factor (typically considered to be a minimum requirement).Completion Examples

The following completion examples are provided to illustrate the range, or diversity, of applications under which an extensive selection of completion components can be used.3Single Zone - Retrievable PackerThe majority of single zone completions are of a simple configuration, utilizing a retrievable packer conveyed and set by the production tubing. The completion shown is designed to facilitate installation and future workover operations.Recovery/FunctionPrimary recoveryFrequency of UsageCommonOperational Advantages Fully retrievable completion no permanent components. Packer can be set with well flanged up sliding sleeve allows circulation of kick-off or perforating fluids. Thru-tubing perforation possible where size permits. Tail-pipe facility for pressure and temperature gauges located in no-go nipple below perforated spacer. This protects instruments from turbulence during high production rates.Operational Disadvantages

4Single Zone Seal-bore Packer

Seal bore packers are typically utilized in application where dependability and longevity are important issues. Electric line setting enables the packer depth to be accurately correlated in critical applications.

Recovery/FunctionPrimary recoveryFrequency of UsageCommonOperational Advantages Seal-bore packer set on electric line or tubing. On-off connector and tubing anchor allows tubing to be retrieved while leaving the packer and tailpipe in place. Tailpipe can be plugged before the tubing is removed to protect formation from kill fluid or workover fluids. Tailpipe can be retrieved with tubing if required.Operational DisadvantagesCompletion retrieval and replacement may be more complex5Single Zone Seal-bore Packer with Tailpipe

Permanent packer with tailpipe provides flexible option for well kill without endangering the reservoir formation (exposure to kill fluids)

Recovery/FunctionPrimary recoveryFrequency of UsageLess common - more specialisedOperational Advantages Tailpipe permanently attached to packer. Tailpipe plug isolates formation during workover/tubing retrieval. Permits safe thru-tubing perforating. Block and kill system facilitates the killing and control of high-pressure, high volume wells.

Operational Disadvantages

6Single Zone CSR

Uncommon option with limited application

Recovery/FunctionPrimary recoveryFrequency of UsageInfrequentOperational Advantages Tailpipe retrievable separately. Protective sleeve run in CSR during primary and remedial cementing operations Expansion joint allows for tubing movement. Safety valve run and retrieved on wireline. Circulation of well fluid/kill fluid facilitated by sliding sleeve.Operational DisadvantagesRelatively complex installation providing little flexibility of operation7Multiple zone completionsMultiple zone completions can be extremely complex. Key to their success of is the ability to control or service each zone selectively. Sufficient room must obviously be allowed within the production casing or liner strings for multiple tubing strings and the necessary components.

Multiple Zone Seal-bore Packer

A simple approach to multiple zone production. However, the use of the annulus as a production conduit it not always acceptable to the regulatory authorities.

Recovery/FunctionPrimary recoveryFrequency of UsageUncommonOperational Advantages Separate or commingled flow through single production tubing string. Upper zone may be produced through the annulus. Blast joint protects tubular integrity across perforated intervals. On-off connector and tubing anchor allows tubing to be retrieved with lower interval isolated. Seating and polished nipples above and below the blast joint provide for contingency repair in the event of blast joint deterioration. Sliding sleeve or the on-off connector facilitates circulation of well fluids and kill fluid.Operational Disadvantages Upper zone produced through casing. Lack of casing protection.

8Multiple Zone Multiple Packers

An effective option providing a high degree of safety and control for each zone. However, The complexity of dual string packer installations requires careful planning and preparation.

Recovery/FunctionPrimary recoveryFrequency of UsageUncommonOperational Advantages Independent production through two tubing strings. Both packers are fully retrievable. Tailpipe instrument facility in both strings. Thru-tubing perforation possible on bottom zone. Blast joint protectionOperational Disadvantages Complex downhole design and configuration. Multiple packer system retrieval can be difficult to release.9Multiple Zone Multiple Packers

Provides a multiple zone option without the requirement for dual conduits (and packers). However, commingled flow and interconnected zones may not always be feasible due to reservoir management and pressure difficulties.

Recovery/FunctionPrimary recoveryFrequency of UsageUncommonOperational Advantages Several zones produced through one tubing string. Flow controlled by wireline retrievable choke/check valves. By-pass sliding sleeve prevents communication during service work. Up to five zones have been produced using this method.Operational Disadvantages Complex downhole design and configuration. Multiple packer retrieval can be difficult to release. Commingled flow limits reservoir management options.

10Multiple Zone Multiple Packers

Complex and specialised installation requiring extensive engineering and planning effort. However, this illustrates the potential for effective multiple zone production if the economics can be justified.

Recovery/FunctionPrimary recoveryFrequency of UsageUncommonOperational Advantages Four zone selective production system, two at a time, with the lower two zones alternating or commingled through the long string. Upper zone produced through the short string with remaining zone being produced through either the short or long string.Operational Disadvantages Complex downhole design and configuration (System contains 28 major downhole components). Multiple packer retrieval can be difficult to release. Flow capabilities may limit reservoir management options.

11Liner Completion CSR

A relatively simple liner completion which is typically suited to larger completion sizes.

Recovery/FunctionPrimary recoveryFrequency of UsageBecoming more commonOperational Advantages Simplest liner-type hook-up. CSR replaces packer function. Sliding sleeve permits well fluid or kill fluid circulation. Tailpipe retrieved with production tubingOperational Disadvantages

12Liner Completion CSR and Seal-bore Packer

Similar to previous design but with more safety/contingency options included. The ability to remove the tubing string without unseating the packer or exposing the producing interval to kill fluid is an attractive feature of such completions.

Recovery/FunctionPrimary recoveryFrequency of UsageUncommonOperational Advantages Liner lap/top is permanently isolated. Fluid circulation through sliding sleeve. Tailpipe can be plugged to allow retrieval of tubing string with the producing zone isolated.Operational Disadvantages

Special ServiceSpecial service completions, like remedial completions, are typically designed on an individual, or limited number basis.Remedial CompletionsRemedial completions are specially designed and configured for specific or individual applications. Careful review of the reservoir, wellbore and production conditions are required, as well as a careful assessment of the risk and consequences of failure, e.g., economic impact, loss of the well etc.

Gravel Pack Completion

A relatively simple liner completion which is typically suited to larger completion sizes.

Recovery/FunctionSand controlFrequency of UsageCommon - generally within certain regions (dependent on reservoir characteristics)Operational Advantages Tools and equipment placed using a service tool and tubing workstring. Through tubing installation using CT possible in some situations.Production string can generally be removed while leaving the pack in place.Operational DisadvantagesGravel pack equipment and the resulting intervals can constrain subsequent wellbore or reservoir treatments.19Inhibitor Injection

The requirement for inhibitor injection is determined by the reservoir formation and fluid composition, and the presence of injected water break through. These characteristics and the wellbore conditions (temperature and pressure) will determine the level of protection required.

Recovery/FunctionPrimary and secondaryFrequency of UsageUncommon Operational Advantages System comprises conventional componentsOperational Disadvantages Protection at relatively shallow depths only Full protection of producing conduit/tubulars not possible20Inhibitor Injection

Dual strings provide an injection point below the main conduit enabling complete protection

Recovery/FunctionPrimary and secondaryFrequency of UsageUncommon Operational Advantages Complete protection of flow wetted componentsOperational Disadvantages Additional (dedicated) injection string required.

21Waterflood

More common offshore, for obvious reasons, the complexity of waterflood installations is dependent on the current (and required) reservoir parameters, especially pressure!

Recovery/FunctionPrimary and secondaryFrequency of UsageCommon on offshore installations or where adequate quality water is available. May also serve as a disposal well for separated water.Operational Advantages Dual zones can be controlled independentlyOperational Disadvantages Annular injection exposes casing string to pressure and potential corrosion/erosion22Waterflood

Thick zones, or multiple streaked zones may require multiple injection

Recovery/FunctionPrimary and secondaryFrequency of UsageCommon on offshore installations or where adequate quality water is available. May also serve as a disposal well for separated water.Operational Advantages Dual zones can be controlled independentlyOperational Disadvantages Annular injection exposes casing string to pressure and potential corrosion/erosion23Steamflood

More common offshore, for obvious reasons, the complexity of waterflood installations is dependent on the current (and required) reservoir parameters, especially pressure!

Recovery/FunctionSpecial application - heavy crudeFrequency of UsageUncommon - limited applicationOperational Advantages

Operational Disadvantages 24Scab Liner

More common offshore, for obvious reasons, the complexity of waterflood installations is dependent on the current (and required) reservoir parameters, especially pressure!

Recovery/FunctionSpecial application - remedial installation or temporary repairFrequency of UsageUncommon - limited applicationOperational Advantages Rigless intervention Enables continued production from damaged tubing/casing/liner Shuts off selected perforated intervalOperational Disadvantages Monobore Completion

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Recovery/Function?Frequency of Usage?Operational Advantages?Operational Disadvantages?Multizone Completion

Artificial Lift - Objectives

This is the basic objective of any artificial lift system. The objectives for installing the system are many and varied.Reasons for Artificial Lift

An artificial lift system may be desirable for several reasons. Any one, or combination, of the following factors may provide justification, for installation of an artificial lift system.

Artificial lift is generally associated with oil wells. However, there are a number of special applications which, although less common, benefit significantly from the methods installed.

Maintaining a production rate which minimizes wax or scale deposition.Dewatering gas wells or in water production wells.Powered dump-flood operations.Artificial Lift Selection

Maintaining the required (optimal) flowing bottom hole pressure is the design basis for all artificial lift installations, ie. the well system tubing performance curve (TPC) is displaced downward. If the appropriate drawdown can be maintained the future management of the reservoir and completion can be conducted efficiently.

The inflow performance is a function of the reservoir and various production characteristics, eg. the efficiency of the stimulation. Well systems analysis techniques and software are used to compare inflow performance with the expected performance of completions equipped with the artificial lift options under review. The solutions for the various completion and artificial lift option can then be compared graphically (NODAL analysis).Artificial Lift - TPC

Although artificial lift systems may be installed later in the life of a well or reservoir, there are clear benefits in preparing for artificial lift when planning the construction of a well. Relatively small modifications to the well configuration can provide flexibility and enhancements which benefit the long-term production capacity of a well. For example, the following factors may be considered at time of constructing the well and selecting/designing the completion tubulars.Artificial Lift Methods

In the USA, approximately 84% of wells on artificial lift are rod pumped, 12% are on gas lift, 2% use ESPs and the remaining methods (hydraulic piston, jet, plunger and others) combined account for the remaining 2%.

Worldwide the type of lift system varies with region and type of well. Gas lift and flowing wells are most common in new, high production areas/fields, while a variety of artificial lift systems are in use in depleted or low production fields and wells.14Rod PumpRod pumps have traditionally been the secondary completion method for non-flowing oil wells with a low gas-to-oil ratio. With this system it is possible to pump off most of the reservoir in time.NameRod PumpRecovery/FunctionSecondary recoveryFrequency of UsageVery commonOperational Advantages Rod pumps account for approximately 60% of onshore artificial lift completions. Industry accepted, economic in the correct application. Not gas dependent. Operational Disadvantages Limited efficiency, maintenance intensive and require vertical wellbores. Well depth and deviation limitations. Sand sensitive Gas sensitive Wireline access not possible Requires surface power (diesel/electric)Rod Pump - Surface Equipment

Rod pumps are configured with a downhole pump and surface power source connected by a rod string. The reciprocating pump assembly comprises relatively few components. The standing valve remains stationary and allows flow from the wellbore to the pump but stops reverse flow. The traveling valve is attached to the rod string and therefore reciprocates with the string.Upstroke - the traveling valve is closed, forming a low pressure area beneath the plunger and drawing wellbore fluid through the standing valve.Downstroke - the plunger (containing the traveling valve) moves through the liquid that has flowed into the pump. The liquid, trapped by the standing valve, is forced through the traveling valve, into the tubing. The new fluid pushes all the other liquid in the tubing up by the volume of liquid in the pump.All pumps operate with some void space (space between the top of the fluid and the top of the fluid chamber), however, too much void can lead to equipment damage. The void area may result from gas breakout to occur when the pump (plunger) cycles faster than reservoir liquids can flow into the pump. Free gas is generally vented up the annulus.Factors which influence the operation and efficiency of rod pumps include oil viscosity, pump size and speed (vs inflow), restrictions in the equipment surrounding the pump, and dissolved/free gas.Wells producing viscous fluids require pumps equipped with large diameter valves, less restrictive pump openings and slower pump speeds.A test instrument (dynamometer), measures the forces on the rod and is used to optimize the operation of the pump and string. The dynamometer is attached to the polish rod which is the uppermost rod in the string. The polished rod, passes through the stuffing box and is attached by a clamp and cable arrangement to the head of the beam pumping unit.Gas lift provides an highly efficient and flexible means of artificial lift in a wide range of applications. The facilities may be used continually to assist production, intermittently to off load liquid (water), or to initiate production (kick-off) following which the well flows naturally. Gas lift is compatible with deviated wellbores and produced solids. Installation costs are relatively low, running costs are dependent on the supply of gas in sufficient volume and pressure.NameGas LiftRecovery/FunctionPrimary/Secondary recoveryFrequency of UsageVery commonOperational Advantages Gas lift accounts for approximately 90% of offshore artificial lift completions. System may be designed to suit most wells. Wireline serviceable. Few mechanical parts. Sand and fill tolerant. Operational Disadvantages Requires gas source and possibly compression. Gas lift valves require frequent servicing/replacement.

16Electric Submersible Pump

Provide a flexible high-rate artificial lift method. The installation and running costs are relatively high. However, in the right conditions extremely high volumes of fluid can be produced.NameElectric Submersible PumpRecovery/FunctionPrimary/Secondary recoveryFrequency of UsageVery commonOperational Advantages Extremely high liquid production capability Can provide some flexibility of production (control)Operational Disadvantages Requires electricity supply and distribution system Electrical components can be unreliable in some downhole environments Suitable for low gas-to-oil ratio applications only High installation and operating cost

Hydraulic Systems

The piston pump is a positive displacement pump, the performance of which is determined by the pump/engine size (diameter) ratio, ie. a large engine and small pump configuration will provide more dynamic head capacity than a small engine and large pump. Single or double action pumps are available in a range of stroke length (12-24-in. stroke). Pump speed (strokes/minute) is controlled by the supply rate of the power fluid.

The jet pump is relatively tolerant of lower quality power and produced fluids, ie when compared with other hydraulic pumping applications.Hydraulic Pumping Systems

A hydraulic piston pump is a close coupled engine/pump assembly, which is similar in operation to a steam engine. Internal valves and shuttle timing mechanisms control the pump cycles and flow of power fluid through the pump.

A jet pump imparts energy to the production fluid using a power fluid directed through a venturi system. No moving parts are required. The venturi system comprises three components which (in some cases) can be sized/selected to provide the appropriate energy input for each installation.Plunger Lift

Plunger lift is suited to high GLR wells that produce relatively little liquid (500 stb/day).The system requires some capacity for gas storage and high rate supply. In many applications, the tubing/casing annulus is used for storage purposes.

Screw pumps, or progressive cavity pumps operate on the same principle (in reverse) as PDM Moineau motors. A rod string, similar to sucker rods, is used to rotate the pump motor.

Turbine pumps are similar to ESP installations but use a power fluid and turbine to power a downhole centrifugal pump.Plunger Lift System

Gas energy is used to drive a plunger (piston) carrying a small slug of liquid to surface. When the tail gas (power gas) has been produced, the well is shut-in and the plunger allowed to fall to bottom. The cycle is then repeated. Plunger lift efficiency decreases with depth and PI, but can be more effective in larger tubing sizes (where liquid slippage is more prevalent).AdvantagesSystem components can be retrieved/replaced without the requirement for pulling the production tubing.System has no moving parts (other than plunger).Compatible with crooked or deviated wellbores.Unobtrusive in urban locations and is applicable offshore.DisadvantagesSystem may not be capable of producing well to depletion.Applicable on low rate wells only (typically < 200 BPD)Requires engineering/specialist supervision.Danger of surface equipment damage if plunger travels too quickly due to incorrect setting.Communication between tubing and casing required.