Artificial Lift for High-Volume Production

Roy FleshmanBartlesville, Oklahoma, USA

Harryson Obren Lekic Houston, Texas, USA

For help in preparation of this article, thanks to Rick Baileyand Duane Russell, Reda, Bartlesville, Oklahoma, USA;James Garner, Camco Products & Services, Houston, Texas,USA; Peter Schrenkel, Reda, Dallas, Texas; and Dave Bergt,Schlumberger Oilfield Services, Sugar Land, Texas. NODAL is a mark of Schlumberger. AGH (Advanced GasHandler), CDPS (Cable Deployed Pumping System) and HOTLINE are marks of Reda. Camco EOR (EngineeringOptimization Resources) is a mark of Camco Products &Services. Camco Products & Services and Reda areSchlumberger companies.

Rod pumps bring oil to surface in many fields, but for better flow rates more than

100,000 wells use subsurface electric pumps or inject external gas to lighten the

fluid column. Specialized approaches are needed to optimize existing gas-lift or

submersible systems and to design new installations for more complex applications.

Less than a fourth of producing oil wells flow nat-urally. When a reservoir lacks sufficient energyfor oil, gas and water to flow from wells atdesired rates, supplemental production methodscan help. Gas and water injection for pressuresupport or secondary recovery maintain well pro-ductivity, but artificial lift is needed when reser-voir drives do not sustain acceptable rates orcause fluids to flow at all in some cases. Lift pro-cesses transfer energy downhole or decreasefluid density in wellbores to reduce the hydro-static load on formations, so that available reser-voir energy causes inflow, and commercialhydrocarbon volumes can be boosted or displacedto surface. Artificial lift also improves recovery byreducing the bottomhole pressure at which wellsbecome uneconomic and are abandoned.

Because reservoir pressure declines andmore water is produced late in field life, artificiallift is generally associated with mature oil andgas developments. However, driven by activity indeep water and areas that require constructionof complex wells, the mature state of hydrocar-bon exploitation worldwide has increaseddemand for high lifting rates to produce oilquickly and efficiently at low cost. Offshore andin difficult international regions, artificial-lifttechniques accelerate cash flow, generate profitssooner and help operators realize better returns,even in wells that flow naturally.

Rod pump, gas lift and electric submersiblepumps are the most common artificial-liftsystems, but hydraulic and progressing cavitypumps are also used. Each is suited to certainlifting requirements and operational objectives,

1. Brown KE: The Technology of Artificial Lift Methods, vol.2A. Tulsa, Oklahoma, USA: PennWell Books, Inc., 1980.

Spring 1999 49

but there is overlap between systems dependingon subsurface conditions, fluid types, requiredrates, well inclination angles, depths, comple-tion configurations, lift-system hardware andsurface facilities.

Lift optimization to get the most fluid from awell or field at the lowest cost offers opportuni-ties for substantial production gains in new wellsor mature fields. When selecting and designinglift systems, engineers must consider reservoirand well parameters, but field developmentstrategies should be factored in as well.Artificial-lift selection is specialized and oftentedious, but guidelines provide the relative appli-cability of each method (previous page).1

Artificial-lift technology is well established,but new developments continue to play a role insolving problems and meeting production chal-lenges. Recent improvements reduce lifting coststhrough system components that resist hostileenvironments, optimize power usage and improvereliability. Alternative means of deploying liftsystems allow profitable production from previ-ously uneconomic wells or fields. Traditional arti-ficial-lift limits are expanded by using more thanone lift method in the same well, such as gas liftor jet pumps combined with electric submersiblepumps and progressing cavity pumps driven byelectric submersible motors. This article reviewsbasic lift systems, discusses high-volume artifi-cial lift and presents selection, design and opti-mization strategies along with new gas-lift andsubmersible technology.

< Artificial-lift selection. Making artificial-liftdecisions is primarily a process of choosing thelift methods most applicable to expected sur-face, reservoir, production, fluid and operationalconditions. This table provides applicabilityvalues and selection criteria or conditions for the basic forms of artificial lift. To choose amethod that meets production requirements,select the range that applies—good to excellent(1), fair to good (2) and not recommended or poor(3)—for key criteria, tally these values and weighthe results.

Basic System Descriptions The four basic subsurface artificial-lift groupsinclude rod or progressing cavity displacementpumps; jet, piston, turbine or plunger hydraulicpumps; gas lift; and electric submersible cen-trifugal pumps.2

Rod pumps combine a cylinder (barrel) andpiston (plunger) with valves to transfer well fluidsinto the tubing and displace them to surface.These pumps are connected to surface by a metalrod string inside the tubing and operated byreciprocating surface beam units, or pumpingjacks, that are powered by a prime mover—elec-tric or gas motors—(below). There are two typesof linear-displacement rod pumps. Tubing pumpshave a fullbore barrel with standing valve and areattached to the end of the tubing. A plunger, ortraveling valve, is run into this barrel on the rods.Tubing must be pulled to repair or replace tubingpumps. Smaller insert pumps consist of a barrel,intake valve, plunger and discharge valve com-

bined in an integral assembly run inside tubingon rods. Insert pumps can be retrieved andrepaired or replaced without disturbing the pro-duction tubing by just pulling the rods.

Fluids are pulled into pump barrels by close-fitting plungers with check valves to displacefluid into the tubing. Standing, or intake, valvesconsist of a stationary ball-and-seat. The dis-charge, or traveling valve, moves during eachreciprocating pump cycle. Rod pumps are simple,familiar to most operators and used widely.However, rod pump capacity, or volumetric effi-ciency, is limited in wells with high gas/liquidratios, small tubing diameters or deep producingintervals. Other disadvantages are a large surfacefootprint (space requirement), high capital invest-ment and potential wellhead leaks or spills.

Progressing cavity pumps are based on rotaryfluid displacement. This spiral system consists ofa rotor turning eccentrically inside a stationarystator (next page, top left). The rotor is a small-diameter screw with deep round threads andextremely long pitch—distance between threadpeaks. The stator has one more thread and longerpitch than the rotor, which forms cavities thatprogress in a rotating motion to create almostpulsation-free linear flow. Like rod pumps, therotor is generally turned by rods connected to asurface motor. New rodless installations use sub-surface electric motors and a speed-reducinggearbox to turn the rotor.

In most cases, progressing cavity pumps areflexible, reliable, resistant to abrasive solids andvolumetrically efficient. Use of small motorsresults in efficient power usage and low liftingcosts. Compared to rod pumps, progressingcavity pumps last longer and have fewer rod ortubing failures because of slower operatingspeeds. Capital costs are typically less than otherartificial-lift methods. Progressing cavity pumpsproduce up to 1700 B/D [270 m3/d] and are usedto depths of about 4000 ft [1220 m]. Elastomercomponents limit operating temperatures tobetween 212 and 302°F [100 and 150°C] and maynot be compatible with some chemicals or hydro-gen sulfide.

Hydraulic systems transfer energy downholeby pressurizing a special power fluid, usuallylight refined or produced oil, that flows throughwell tubing to a subsurface pump, which trans-mits this potential energy to produced fluids (next page, bottom left). Common pumps consistof jets, also known as venturi and orifice nozzles,reciprocating pistons, or less widely used rotat-ing turbines. A free-floating feature allowspumps to be circulated in and out of wellshydraulically, eliminating slickline or rig opera-tions to replace pumps or pull tubing. Hydraulicpumps are used at depths from 1000 to 18,000 ft

[305 to 5486 m] and produce rates from 100 to10,000 B/D [16 to 1590 m3/d] or more. Manyhydraulic installations produce 150 to 300 B/D[24 to 48 m3/d] from deeper than 12,000 ft[3658 m]. Heavy, viscous crudes are often easierto produce after mixing with lighter power fluids.Because pumps can be circulated out, systemscan be modified for changing conditions.

Gas lift uses additional high-pressure gas tosupplement formation gas. Produced fluids arelifted by reducing fluid density in wellbores tolighten the hydrostatic column, or backpressure,load on formations. Primary criteria for thismethod are gas availability and compressioncosts. Most gas-lift wells produce by continuousinjection, which is the only lift method that fullyutilizes formation gas energy (next page, topright). External gas, injected into special gas-liftvalves at specific design depths, mixes with pro-duced fluids and decreases the pressure gradientfrom the point of injection to surface. Bottomholepressure is reduced to provide a differential, orpressure drawdown, for required flow rates. Ifdrawdown is insufficient, instantaneous high-volume injection, or intermittent gas lift, can beused to displace slugs of liquid to surface. Theon-off nature of this option causes surface gas-handling problems as well as surges downholethat may result in sand production.

Gas lift is flexible and adjustable. Slickline-retrievable gas-lift valves can be pulled andreplaced without disturbing tubing if designs orsystem performance need to be changed. Costsvary depending on gas source and pressure, butcan be high if additional surface compressorsand processing facilities are needed. Gas-liftinstallations handle abrasive materials like sandand can be used in low-productivity, high gas/oilratio (GOR) wells or deviated wellbores. Naturalgas shortages limit or prevent gas-lift use.Freezing and gas hydrates are problematic, as isslickline valve retrieval in high-angle wells.Scale, corrosion and paraffin increase systemfriction or backpressure and reduce lift efficiency.Tubing size and long flowlines also limit systempressure and restrict efficiency. The main disad-vantage of gas lift is difficulty depleting low-pressure, low-productivity wells completely. Insome gas-lift wells, a change in lift method maybe required before abandonment.

Electric submersible systems use multiplecentrifugal pump stages mounted in series withina housing, mated closely to a submersible elec-tric motor on the end of tubing and connected tosurface controls and electric power by an armor-protected cable (next page, bottom right).

50 Oilfield Review

Insert pump

Rods

Tubingpump

Tubing

Casing

Prime mover Beam pumping unit

Perforations

Producedfluids

Plunger

Fullbore barrel

Traveling valve

Standing valve

> Reciprocating displacement rod pumps.2. Bradley HB (ed): Petroleum Engineering Handbook, First

Printing. Richardson, Texas, USA: Society of PetroleumEngineers, 1987.

Spring 1999 51

Electric motor

Rods

Tubing

Casing

Stator

Rotor

> Progressing cavity displacement pumps.

Power-fluidstorage

High-pressurepump

Perforations

Tubing

Power fluid

Casing

Jet, piston or turbinedownhole pump

Producedfluids

> Hydraulic-lift pumping systems.

Perforations

Produced oil and gas,and injection gas

Producedoil and gas

Injection gas

Gas-liftedproduced

fluids

Flowingproducedfluids

Side-pocketmandrels

Gas-liftvalves

> Injection gas lift.

Electric drives and controllers protectsystems by shutting off power if normaloperating limits are not maintained. A variable-speed driveadjusts pump outputby varying motor speed.

Producedfluids

Gas separators segregate some free gas fromproduced fluids into the tubing-casing annulusby fluid reversal or rotary centrifuge beforegas enters the pump.

Submersible motors are two-pole,three-phase induction motors.

Pump intakes allow fluids to enter thepump and may be part of the gas separator.

Electric transformersconvert source voltageto required downhole

motor voltage.

Motor protectors connect pumps to motors;isolate motors from well fluids; serve as a

motor-oil reserve and equalize pressurebetween wellbore and motor; and allow

expansion or contraction of motor oil.

Pump housings contain multistage rotatingimpellers and stationary diffusers. The

number of centrifugal stages determinesrate, pressure and required power.

Power cables supply electricity to submersiblemotors through armor-protected, insulatedconductors. Cables are round except for a flatsection along pumps and motor protectorswhere space is limited.

Downhole monitoring tools incorporatepressure and temperature sensing instruments

that send signals through the power cable toa surface readout unit.

Perforations

Gas

> Electric submersible centrifugal pump systems.

Submersible systems have a wide perfor-mance range and are one of the more versatilelift methods. Standard surface electric drivespower outputs from 100 to 30,000 B/D [16 to4770 m3/d] and variable-speed drives add pump-rate flexibility. High GOR fluids can be handled,but large gas volumes can lock up and destroypumps. Corrosive fluids are handled by using spe-cial materials and coatings. Modified equipmentand procedures allow sand and abrasive particlesto be pumped without adverse effects. Operatingsubmersible pumps at temperatures above 350°F[177°C] requires special high-temperature motorsand cables.

Historically, electric submersible pumps wereused in high-water, low-oil producers that per-form like water wells. A submersible pump canoperate in high-angle and horizontal wells, butshould be placed in a straight or vertical section.Subsurface submersible equipment may be sev-eral hundred feet long, so bending reduces runlife by causing internal wear on motor and pumpbearings. Wells deeper than 12,000 ft can be pro-duced efficiently with electric submersible sys-tems and these pumps can be used in casing assmall as 4.5-in. outside diameter (OD). At 20 to70% efficiency, electric submersible pumps areperhaps the most efficient and economical liftmethod on a cost-per-barrel basis, but depth andhigh GOR restrict capacity and efficiency.

Another disadvantage is the need for expen-sive rig interventions to pull tubing for pumprepairs or replacement. In addition, individualinstallations have limited production ranges dic-tated by the number of pump stages. Alternativedeployment methods and variable-speed surfacedrives address these limitations.

Current ApplicationsBecause hydrocarbon developments worldwideare in various stages of maturity, producing wellscan be grouped into categories (below). At oneend of this spectrum, which includes subseacompletions and wells requiring advanced con-struction methods or new equipment technolo-gies, there is a limited but growing number ofcomplex, high-cost wells that produce at highrates. Sizable installation and operating costs,combined with technology or equipment con-straints, limit use of artificial lift in these wells.

In general, this sector is not very active, but isundoubtedly the direction of future hydrocarbondevelopment. Offshore, because of reliability andflexibility, robust gas-lift and electric submersiblesystems are now used almost exclusively whenartificial lift is required. Exploitation of deep-water reserves requires improved technology.Alternative deployment methods and combinedlift systems for subsea wells in conjunction withpermanent downhole monitoring allow efficient,economic artificial lift and process control.

At the other extreme, stripper and develop-ment, or harvest, wells produce limited rates andvolumes. Incremental production due to artificiallift is small. Rod, progressing cavity or hydraulic

pumps are often applied in these wells. Althoughwell numbers are high, activity in this sector islimited to low-cost new installations and systemsalvage or replacement.

Between these categories are many medium-volume wells, often in secondary recovery fields,that produce significant rates and oil volumes.Incremental gains in these wells representimportant potential production. These wells drivea majority of engineering and technologicaldevelopments, generate cash flow, and representthe most active and high-value artificial-lift sec-tor. Medium- to high-volume lift methods, likegas lift or electric submersible pumps, areapplied in these wells. Ease of installation andoperational simplicity make these two systemspreferred and popular among operators.

Selection of artificial-lift methods and systemdesigns are best accomplished by studying fieldsas a whole, including reservoirs, wells, surfacefacility infrastructure and overall project eco-nomics. Service companies play an importantrole by providing installation, operation, trouble-shooting and optimization services in addition toartificial-lift technology, equipment and designsfor specific applications.

52 Oilfield Review

Number of wells

Prod

uctio

n ra

te

Subsea

High-rate wells

Stripper wells

Harvest fields and infill wells

Complex completions

Remote environments

Secondary recovery fields

> Artificial-lift applications. Across the spectrumof producing wells, artificial lift is applicable from simple, low-cost stripper wells where low-volume sucker-rod, progressing cavity andhydraulic lift are used most often to high-costsubsea developments. In between, there arelarge numbers of development, infill and sec-ondary recovery wells that produce significantvolumes of gas and oil, primarily by gas lift and electric submersible pumps. Increasingly,artificial-lift methods are being combined toovercome single-system limitations in thesecomplex, high-volume wells.

>

Spring 1999 53

System Evaluation and Selection Various approaches are used to develop oil andgas assets, add value or simply to reduce thecosts associated with potential prospects, newfields and late-life strategies for existing devel-opments. Choosing the best methods involveshydraulic, mechanical and electrical engineeringconsiderations. Ideally, artificial-lift evaluationsincorporate production system parameters fromreservoir boundaries to process plants.

Equipment requirements, the size and com-plexity of production systems and the powerrequired to lift well fluids make high-volume arti-ficial lift expensive to install and operate.Selecting the most suitable methods and equip-ment is important, because one artificial-liftinstallation may produce more oil than the pro-duction of some small mature fields. Selectingthe right system or combination of methods iseven more critical when evaluated in terms offailure, downtime and intervention costs.

Engineering teams review technical, eco-nomic and risk factors, generate options andmake recommendations. The best approach is aniterative total systems evaluation, whetherapplied a short time after discovery when morereservoir information is known, following initialdevelopment at a stage before further drilling orwhen reviewing late-life strategies (right).Artificial-lift strategies should maximize optionsthat are available over the life of a field.

Initial evaluation might indicate an artificial-lift method like electric submersible pump toobtain higher production rates, but later analysismay reveal that gas lift is best. Conversely, gaslift might be considered suitable initially becauseof poor submersible pump economics and equip-ment performance, but a review might show sub-mersible systems to be the right approach aslong as proper design, installation and operationare carried out. In some cases, electric sub-mersible pumps are installed and operated, butwhen sand, scale or emulsion problems developand actual production is reevaluated, gas lift orprogressing cavity pumps might be better.

For example, a field in North Africa withdeclining pressure and increasing water ratesappeared to be a candidate for electric sub-mersible pumps. The reservoir has a strongwaterdrive, and pressure declines about 100 psi[690 kPa] per year. No water injection is planned.The wells flow to field-gathering manifolds thatconnect with a pipeline linked to a distant pro-cessing plant. Increased water rates led to ces-sation of natural flow in some wells, indicatingthat artificial lift or pressure support was needed.This field appeared to be a candidate for electricsubmersible pump installations.

Three members of the Camco EOR Engineer-ing Optimization Resources group conducted anartificial-lift evaluation. Flowing gradient surveyshelped select the best vertical-flow correlation.Field flowline network and export pipeline pres-sures and rates were recorded to select a hori-zontal flow correlation. Water rates at whichnatural flow ceased were predicted and matchedby NODAL techniques and well performance

models.3 Reservoir pressure and water produc-tion forecasts were used to project when thefield would require artificial lift to produce highwater-cut wells.

Electric submersible pump evaluation deter-mined rates that could be achieved given reser-voir and well limitations. Pump designs weregenerated and production benefits were quanti-fied. Also estimated were the expected pump runlife and power requirements for developing thefield with submersible technology. Gas lift wasevaluated for a range of well conditions over thelife of the field. Injection pressure, gas-lift rateand tubing size were calculated to maximize production under existing processing facility con-straints. Compressor requirements were deter-mined from solution gas and lift-gas usage.Pipeline pressure and capacity with lift gasadded to the production stream were analyzed.Gas-lift designs were generated and 20 to 40%production increases were estimated.

Team evaluationof artificial-lift

methods

Commercialanalysis

Riskanalysis

Generateoptions

Makerecommendations

Installartificial lift

Evaluate resultsand review options

Technical inputfrom equipmentproviders and

service companies

Installationinfrastructure

Environmentalconsiderations

Reservoirconsiderations

Drillingconsiderations

Interventionconsiderations

Top-side processconsiderations

Wellboreconsiderations

System dataconsiderations

Technologypresent and future

Safetyconsiderations

> Artificial-lift evaluation. Because there are many strategies for developing oilfields, artificial-lift alternatives need to be identified and evaluated based ontechnical, commercial, risk and overall system factors. Engineering teams recom-mend development strategies and artificial-lift methods from the options generatedby these evaluations. When additional reservoir, well and facility information orperformance data are available, perhaps after initial field development or laterduring mature stages of production, these techniques are used to cycle throughthe process loop again to assess performance, investigate late-life strategies orreevaluate and change artificial-lift methods.

3. Bartz S, Mach JM, Saeedi J, Haskell J, Manrique J,Mukherjee H, Olsen T, Opsal S, Proano E, SemmelbeckM, Spalding G and Spath J: “Let’s Get the Most Out ofExisting Wells,” Oilfield Review 9, no. 4 (Winter 1997): 2-21.

Reservoir constraints like water and gas con-ing, sand production and gas breakout at perfo-rations were identified. Gas-lift and submersiblepump performance were compared, and down-time was estimated based on electric pump runlife and required gas-lift valve changes.Operational capability and safety issues wereidentified and costs were estimated. A compari-son clearly identified gas lift as the optimal arti-ficial-lift method. Intervention and pumpreplacements made electric submersible pumpsuneconomic even though production could beincreased by 30 to 40% initially. The EOR teamrecommended gas-lift implementation to avoidlost production. This evaluation was completedin one month.

Another example shows the complexity of liftselection. Petrobras-operated Ceara offshoreproduction area in Brazil consists of nine plat-forms producing four fields—Atum, Curima,Espada and Xareu. Production from these fieldswas 10,550 B/D [1680 m3/d]. As a result of lowreservoir pressures, all but 6 of 63 wells requireartificial lift. Because of poor pump performanceand scale-related failures, a proposal was madeto switch from electric submersible pumps to gaslift in all four fields.

The objective was to reduce expenses andincrease production by recompleting wells withsingle producing intervals to dual-zone produc-ers. In general, commingling zones was restrictedby wide pressure differentials. Gas lift was pro-posed as a solution that allowed dual zones to beproduced. However, large capital expenditureswere needed to convert from current electric sub-mersible systems.

Dual submersible pump systems also allowsimultaneous production of two isolated zonesand are an alternative to dual gas-lift comple-tions. Using dual submersible pumps in eachwell achieves the same production rates, andinvestment is limited to new completions foronly 26 proposed dual wells. Forecast oil-rateincreases of 725 m3/d [4560 B/D] to 1190 m3/d[7485 B/D] from dual zones can be achieved withgas lift or electric submersible pumps. Existingsubmersible installations and optional solutionswere reviewed, and gas-lift viability as a replace-ment for submersible pumps was assessed.

Based on a flow correlation verified by flow-ing pressure-gradient surveys in a trial gas-liftwell and NODAL analysis, field economics over-all are not affected by switching from electricsubmersible pump to gas lift in existing wells.Scale problems are not alleviated. Gas-lift valvesmust be placed at depths where scale builds up,so chemical injection is still required to ensurethat wells remain productive and serviceable.Gas lift does not draw reservoir pressure downas much as submersible pumps, which results in lower production rates. However, this loss of output is balanced by less downtime for gas-lift completions.

Several wells produce at low rates, particu-larly in the Xareu field, and flow would not be sta-ble under continuous gas lift. In the Cearaproduction area, gas lift is not the ideal artificial-lift method for every well, since some wellswould not continue to produce. Intermittent gaslift or progressing cavity pumps may be neededfor low-rate wells. A subsea completion with lowreservoir pressure that was fitted with gas-liftvalves would not flow naturally. A stand-alonecompressor was proposed to get this well on line.

Significant efficiency and oil output could begained by addressing submersible pump perfor-mance. A better chemical inhibition program wasneeded to reduce failures due to scale andimprove pump operations. Increasing run lifefrom 16 months to 24 months reduces the num-ber of workovers. Better designs could eliminateinefficiency, and installing two submersible pumpsystems per completion would cut workover fre-quency by half. When one pump fails, the othercan be used without pulling tubing and comple-tion equipment. Increasing submersible pump runlife and improving efficiency reduce expenses.After evaluation, submersible systems stillappear to be best, but reliability and life-cyclecosts need to improve.

The Camco EOR group recommended thatsubmersible pumps be retained as a primary arti-ficial-lift method and that alternatives for reduc-ing cost and increasing production be reviewed.One option was to use more than one artificial-lift method. By using redesigned submersiblepumps and better operating practices in theAtum, Xareu and Espada fields, and convertingthe Curima field to gas lift, production andexpense targets were achieved at reduced capitalexpenditure for facilities. This approach addressesthe field with highest lifting costs due to short sub-mersible pump run life and allows installation ofdual gas-lift completions in the Curima field,which has the best production potential.

Expertise is required to select, install andoperate high-rate artificial lift. Aside from techni-cal evaluation, system designs must be depend-able to realize optimal value in the face ofprobable commercial and risk scenarios. To mini-mize technical and financial risks, and addressspecialized applications, outsourcing and results-based contracts are becoming standard practiceamong operators for procuring equipment andimplementing artificial lift through systemsdesign and engineering services (see ”Artificial-Lift and Field Optimization,“ page 61).

54 Oilfield Review

Nitrogen-filledbellows

Casing ports

Tubing ports

> Subsurface gas-lift valves. The choice ofvalve and operating principle depends on wellparameters and well intervention costs. Con-ventional gas-lift valves and mandrels are runas part of the production tubing string. Retriev-able valves in side-pocket mandrels that areoffset from the centerline of the tubing areused offshore and in remote locations whererig interventions are expensive. Closing forcefor pressure-operated valves is provided by a spring, nitrogen-charged bellows, or both.Using a surface test rack, valves are preset toopen at the required operating pressure for awell. Smaller miniature values are available forlimited clearance and slimhole applications.

Spring 1999 55

High-Rate Gas-Lift SystemsAlthough trailing electric submersible pump useworldwide, gas lift—generally the most eco-nomical artificial-lift method if a cost-effectivegas supply is available—is common in NorthAmerica, the US Gulf Coast and offshore. Unlikesubmersible systems, gas lift does not addenergy, or lifting power. Reservoir pressure, sup-plemented by gas injected into tubing valves atspecific depths to lighten the fluid column, stilldrives fluid inflow and outflow. There are manytypes of gas-lift valves that use a variety ofoperating principles (previous page). Productionengineers choose the valves that fit well andfield conditions.

In gas-lift systems, downhole equipment andsurface facilities are closely related. Becausewell parameters and conditions like reservoirpressure are dynamic, producing operations

change over time. By using sophisticated soft-ware to link wellbore, surface facilities and pre-dicted reservoir response in a single model,integrated engineering teams can balance sur-face and subsurface considerations. Reservoirparameters are productivity, changes in perfor-mance with time and specific problems like sandor water influx. Well factors include tubing andcasing size as well as depth, completion configu-ration—packers, perforations and sand-controlscreens—type of gas-lift valve, wellborehydraulics and fluid-flow regimes. Surface facili-ties involve compressors, separators, manifolds,field flowlines and export pipelines (below).

Compressor discharge pressure impactsinjection valve setup and operation, and is thefirst gas-lift design consideration. Available pres-sure at the wellhead establishes gas injectiondepth, which determines lift efficiency. The

deeper gas is injected, the higher the productionrate. The cost of injecting deeper is related toadditional compression, plant upgrades andoperating expenses, as well as factors related toother surface facilities, like separator perfor-mance and pressures. There are, however, solu-tions that balance compression cost with theproduction rates that can be achieved.

It is important to ensure dependable gas pres-sure and volumes through mechanical reliabilityand operating procedures. Trained operators andproperly installed and maintained compressionequipment are crucial to gas injection. In somefields, gas lift is limited by existing infrastructure.Like gas-lift valves, compressors can also bechanged. Skid-mounted, portable compressionfacilities can be modified for use in other loca-tions or applications to improve outflow andminimize costs.

Oil storage

Productionmanifold

Compressorstation

Gas exportpipeline

Producedgas

Injection gasmanifold

Meteringand control

Producingwells

Producedfluids

Gas and oilseparator

Waterdisposal

well

Oil exportpipeline

Producedwater

Producedoil

Wellheadtubing and

casingpressure

Injectiongas

> Gas-lift networks and facilities. On the surface,gas-lift infrastructure includes compressors,separators, manifolds, field flowlines and exportpipelines, which are closely related to subsur-face equipment operation and performance.Changes in facility or reservoir performance influ-ence both systems. Often, there is not enough gasto lift every well at maximum efficiency. Produc-tion can be enhanced by optimizing gas injectionwithin existing field networks. If gas lift is limitedby existing surface infrastructure, skid-mounted,portable compression facilities can be used toimprove field output. [Adapted from Book 6 of theAmerican Petroleum Institute (API) Vocational TrainingSeries: Gas Lift. Dallas, Texas, USA: API, 1984.]

Surface gas compressors and subsurfacevalves need to operate in a stable manner, butchanges in facility or reservoir performance influ-ence both systems. Most of the time there is notenough gas to lift every well at maximum effi-ciency. Required injection rates often cannot beachieved because of gas source, equipment,pressure, economic or other limitations. Productionoutput can be enhanced by effective and efficientinjection gas distribution within existing fieldnetworks.

Many criteria are considered when choosingthe best injection rate. For example, wells withhigh productivity or low injectivity need more gas volume or higher gas-injection pressure.

Sensitivity analyses determine how wells affecteach other and define injection rates that resultin optimal production. Gas-lift valve port, or ori-fice, size can be calculated and adjusted forrequired gas injection. Subsurface gauges supplydata for subsequent evaluations. Surface andfinancial constraints often restrict gas throughputand need to be addressed using an integratedsystems approach.4 In such cases, field outputinstead of single-well rates are optimized. Forthis purpose, field-wide models are built basedon production system data such as compressors,separators, flowlines and chokes. Along withwell performance curves, data are gathered intoa field-wide NODAL analysis program.

Maximizing gas-lift performance one well at a time was standard in the past. Today, ongoingproduction optimization and management on asystem-wide basis, which includes compressors,increase revenue, enhance profitability and pro-vide long-term value more effectively. This sys-tems approach is made possible by improvementsand advances in computing, downhole monitor-ing, data-collection and information technologies.

Camco, now a Schlumberger company, manu-factures surface and subsurface flow-controldevices, side-pocket tubing mandrels and gas-liftvalves, latches, running and kickover tools forgas-lift systems (left). New technology, like elec-tric gas-lift valves, are also being developed.Conventional valves have one port size with thecapability to open and close. Simple orificevalves have no open-close mechanism. Electricvalves allow port size to be adjusted remotelyfrom surface over a range of fully open to closed.This provides better control when unloading flu-ids during well startup, real-time gas-lift opti-mization and the option of changing gas injectionpoints without well intervention. This flexibilitywill help meet future oil and gas exploitationchallenges by reducing gas-lift costs for deep-water and subsea wells.

In future optimization efforts, valves will berun with gauges to read casing and tubing pres-sure. Combined with information currently avail-able, such as well tests and surface pressuremeasurements, these readings will validate mod-els and forecasts, and be used to establish opti-mum gas-injection rates. Based on requiredrates, port size will then be adjusted remotely.The resulting effect on casing and tubing pres-sure is monitored and then used as feedback forthe next generation of closed-loop automatedcontrol systems.

High-Rate Electric Submersible SystemsWith liquid-lifting capacities up to 30,000 B/D[4770 m3/d], depending on electric power limita-tions, oilfield submersible pumps are used pri-marily for medium- and high-volume production.Within this artificial-lift sector are several typesof applications and configurations, includingstandard installations, booster or injection ser-vice, bottom intake or discharge, shroudedinstallations, offshore platforms and surfacehorizontal systems (next page). Design andinstallation of submersible systems combinehydraulic, mechanical and electrical componentsin a complex subsurface environment, so relia-bility is a key to success. If run life is short,retrieving an electric submersible pump thatfails prematurely is expensive and detrimental toproject economics.

56 Oilfield Review

Side-pocketmandrel

Gas-liftvalve

Slicklinekickover

tool

> Retrievable gas-lift valves. Slickline-retrievable valves can be installed or removed withoutpulling tubing. Kickover tools are designed to selectively locate side-pocket mandrels.

Spring 1999 57

Well stimulation or chemical injection areoften required, so it is important to ensure com-patibility between chemicals and downholeequipment. Treatment fluids can damage coat-ings and elastomer components like cable, motor,pump and motor-protector seals. Improveddesigns and advanced construction materials,including new metal alloys and elastomers forhanding corrosive fluids and harsh subsurfaceconditions such as extreme temperatures or high-ratio gas producers, are continuing to be devel-oped. These new technologies, coupled withalternative methods of deploying electric sub-mersible pumps, are expanding the range ofapplications for this versatile artificial-lift form.

High temperatures—For many years, electricsubmersible pumps were used in the Wilmingtonoil field, which consists of about 600 wells drilledfrom man-made islands in the harbor of LongBeach, California, USA, near San Diego. A subsetof these wells includes low-rate, high-oil-cut pro-ducers with 9 5⁄8-in. casing. The THUMS LongBeach Company operation had problems withmotors that failed prematurely in about 20 ofthese installations.5 Pumps were subjected totemperatures above 400˚F [205˚C] because oflimited oil rates and low water production thatdid not cool motors adequately. Pumps ran foronly 30 to 60 days.

An advanced design, HOTLINE motor serieswith capability to run continuously at up to 550˚F[228˚C] was developed by Reda, also aSchlumberger company. High-temperature ther-moplastic motor-winding insulation initiallydeveloped and patented for geothermal andsteamflood wells was applied. This successfulnew technology resulted in average runs inexcess of 1000 days and annual savings of over$200,000 per well, including fewer well interven-tions, less equipment repair and reduced

> Submersible pump configurations. In booster service, a standard pump, protector and motor unit are used to lift fluid from flowlines or other sources and simultaneously provide injection for waterflood, pipeline or other applications. In bottom-intake configurations, fluid enters the pump through a stingerin a permanent packer. Pump and motor are inverted from conventional installations. This setup is used when casing clearance limits production becauseof tubing friction loss or pump diameter interference. A bottom-intake configuration pump and motor can also be suspended by small diameter, high-strength cables, conventional tubing or coiled tubing to improve output. The bottom-discharge pump is used to inject water from shallow aquifers intodeeper producing zones. A shrouded configuration directs fluid past the motor for cooling or allows free gas to separate from fluids ahead of the intake and allows pumps to be set below perforations or producing zones. To save space on platforms and in other surface operations, submersiblepump surface units are used for mixing mud, washing down and fire protection, sump and water supply pumps and off-loading oil from storage.

4. Lekic O and Watt GW: “‘System Approach’ OptimizesGas Lift,” The American Oil & Gas Reporter 41, no. 6(June 1998): 124-128.

5. The THUMS (Texaco, Humble—now Exxon, Unocal,Mobil and Shell) Long Beach Company name wasderived from the first letter of the five companies thatjoined together to bid successfully for the rights todevelop and produce oil from under the city and harborof Long Beach, California.

Bottom Intake

Bottom Discharge Shrouded

Booster Service

Pump

Intake

Cable

Motor

Pump

Intake

Motor protector

Motor

Cable

Motor

Motor protector

Pump discharge

Pump

Packer

Motor

Motor protector

Intake

Pump

Packer

Cable

Cable

Motor protector

deferred-production cost. A life-cycle cost com-parison before and after introduction of this tech-nology shows a significantly expanded range ofsubmersible applications (above). These motorsare used in conventional submersible pumps forbetter reliability, even at low temperatures.6

High gas volumes—Like any artificial-liftmethod, submersible pumps reduce flowing bot-tomhole pressure to obtain better inflow. In gassywells, however, more vapor evolves from crudeoil at lower pressures. At higher vapor/liquid

ratios, pump performance begins to deteriorate.If a critical vapor-liquid limit is reached, pumpoperation becomes unstable, surging, cavitatingor stopping as gas blocks liquid flow insidepumps. Centrifugal force does not acceleratelow-density vapor. In fact, gas tends to lagbehind liquids and separate further, accumulat-ing in low-pressure, low-velocity areas of pumpimpellers and diffusers. Vapor restricts flowthrough these components, causing poor lift per-formance. Depending on fluid types, well charac-

teristics and hydraulic design of individualpumps, vapor can completely block flow into andthrough submersible pumps. Catastrophic fail-ures result if pumps are not protected from thisgas-lock condition (left).

The traditional solutions to gas problemswere shrouded, or tailpipe configurations, androtary separators to remove vapor ahead of pumpinlets. Production rate could also be limited, sothat inlet pressure is high enough to avoid detri-mental vapor/liquid ratios inside pumps. None ofthese solutions are optimal. Gas separatorsintroduce other limitations and mechanical com-plications while robbing the system of energy inthe form of gas, which lightens fluid density inthe tubing just as it does in gas-lift installations.However, keeping inlet pressure high limits pro-duction and may make artificial lift uneconomic.

Field experience shows that, depending onhydraulic design and fluid characteristics, cen-trifugal pumps tolerate vapor concentrations ofonly about 10 to 20% at moderate inlet pres-sures. New multiphase fluid-conditioning deviceslike the AGH Advanced Gas Handler componentprovide a way to produce at higher rates andlower flowing bottomhole pressures with greaterreliability and less wasted energy. The AGHmodule homogenizes liquid and gas entering the pump to reduce separation and accumulationin the first few pump stages, allowing sub-mersible systems to tolerate vapor concentra-tions greater than 50%.7

Field testing performed by Intevep S.A., theresearch branch of Petroléos de Venezuela S. A.(PDVSA), confirmed that the AGH component canallow stable pump operation with 48% vaporentering the pump. In Lake Maracaibo, Venezuela,where AGH technology was directly applicable inproduction operations previously restricted bygas-lift limitations or gas interference withsubmersible pumps, Intevep estimated thevalue of this capability to be at least 75,000 B/D[11,920 m3/d] of incremental oil productionfrom 250 wells.8 The AGH module can be usedalone or with a traditional rotary gas separator.

Alternative deployment—Techniques for run-ning electric submersible pumps in subsea com-pletions and on cable or coiled tubing expandartificial-lift applications and increase productionflexibility for offshore systems, remote locationswith limited rig availability and high-costworkover areas (next page).

A cable-deployed submersible-lift alternativelike the Reda CDPS Cable Deployed PumpingSystem technology reduces intervention costs byeliminating dependence on workover rigs. Thesystem is lowered into wells with a power cable

58 Oilfield Review

HOTLINE insulation

455°F[235°C]

Standard insulation

Subm

ersib

le sy

stem

life

500°F[260°C]

> High-temperature electric submersible pump performance. Through advanced materials, sub-mersible technology has developed to the point that operating temperatures greater than 400°F are possible, but many factors, including design and installation, must be addressed. Critical among these are cable type, equipment sizing, cable bands and elastomers. Each component ofthe HOTLINE production system is modified to operate up to 550°F [288°C], which expands sub-mersible lift use to steamfloods, geothermal applications and wells with poor cooling conditions.

Gasinterference

Gas lock

Pump impellers

AGHAdvanced

GasHandler

Rotarygas

separator

> Submersible pump performance in high gas/liquid ratio wells. When gas is present in producedfluids, lift efficiency deteriorates as gas takes up space inside pump stages and interferes with per-formance. Eventually, the system becomes gas-locked and stops producing or fails catastrophically.Traditionally, high gas volumes are handled by rotary gas separators that segregate gas into thetubing-casing annulus. Research and dynamic modeling prove that fluids can be homogenized byreducing pressure differentials within the pump. The AGH Advanced Gas Handler module conditionsfluid to behave as a single phase before it enters pumps.

Spring 1999 59

banded to a torque-balanced tension cable, andseated in a profile landing nipple of 5- or 7-in. tub-ing. A customized drawworks, which can be trans-ported by helicopter to offshore platforms andremote or environmentally sensitive areas withlimited access, is used to run and pull submersiblesystems.9 The CDPS lift system is inverted. Unliketypical submersible installations, running themotor on top and pump on bottom allows largerdiameter, higher volume pumps to be used sincethere is no need for a flat motor cable and guard torun beside the pump and motor protector. Blowoutpreventers are available to seal around the cables.

The economics that make coiled tubingattractive for other oilfield applications in high-cost workover areas also apply for artificial-liftsystem deployment. Electric submersible pumpson coiled tubing pump fluids conventionallythrough the coiled tubing or can be inverted toproduce fluids up the annulus. Power cables maybe installed inside coiled tubing or banded to theoutside. Internal cables are protected frommechanical damage, chemicals and well fluids.

In the Middle East, ARCO Qatar used coiledtubing with internal power cables to deploy sub-mersible pumps and produce fluids up the annu-lus inside 7-in. production tubing.10 In Brunei,Shell converted a well from gas lift to high-rateelectric submersible pump with a riglessworkover made possible by a coiled tubingdeployed system.11 Offshore, coiled tubingexpands submersible pump applications whenthrough-tubing installation is feasible, reducingthe need for conventional rig workovers and min-imizing downtime as well as deferred production.This unique, flexible technique has potential insmall or marginal offshore fields where no gas-lift infrastructure exists.

Subsea completions—Flow from subsea wellsis driven by reservoir pressure supplemented withgas injection when necessary. However, if wellsare far from host platforms, gas lift is inefficientbecause of long flowlines. Well-to-platformdistance is limited by the capacity of gas-liftinjection and reservoir pressure, which declinesas fields are depleted and water cut increases, to drive outflow. Distances greater than 8 miles[13 km] are considered uneconomic.12

Compared with gas lift, submersible pumpsare not as adversely affected by well-to-platformdistances and offer increased flow rates. Subseasubmersible installations were not feasible untilrecent advances in wet mateable connections.These connectors allow seafloor electrical tie-insand eliminate the need for dry connections to bemade at the surface. Offshore reservoirs that areuneconomic to operate by conventional means

Electricsubmersible

pump system

Electricsubmersiblepump system

Coiled tubingdeployed

Cable deployed

Packer

Cable bands

Armoredpowercable

Perforations

Torque-balancedwire rope

> Alternative deployment techniques. Cable-deployed and coiled tubing submersible pump systemsare designed to reduce expenses and production downtime associated with remote or high-costwells and offshore platforms where space and rig availability are limited.

6. Fuller D, Fickes B and Dowdy R: “Electric SubmersiblePumping Systems Applied in High-TemperatureEnvironments,” presented at the SPE ElectricalSubmergible Pump Workshop, Houston, Texas, USA,April 27-29, 1994.

7. Kallas, P and Way K: “An Electrical SubmergiblePumping System for High GOR Wells,” presented at theSPE Electrical Submergible Pump Workshop, Houston,Texas, USA, April 26-28, 1995.

8. Castro M, Pessoa R and Kallas P: “Successful Test ofNew ESP Technology for Lake Maracaibo Gassy OilWells,” presented at the SPE Electrical SubmergiblePump Workshop, Houston, Texas, USA, April 28-30, 1999.

9. Toubar M, Bahaa H and Guindi R: “Cable DeployedPumping System Case Study,” presented at the SPEElectrical Submergible Pump Workshop, Houston, Texas,USA, April 28–30, 1999.

10. Patterson JC, Stamey RC, Penny R and Dwiggins JL:“Coiled Tubing and Electrical Submersible PumpTechnology Improve Field Evaluation Cost,” presented at the SPE Electrical Submergible Pump Workshop,Houston, Texas, USA, April 30-May 2, 1997.

11. Pastor G, Knoppe R and Shepler R: “South China SeaGas Lifted Well Conversion Utilizing Coil Tubing ElectricalSubmersible Pumping Systems,” presented at the SPEElectrical Submergible Pump Workshop, Houston, Texas,USA, April 28-30, 1999.

12. Al-Mashgari A, Breit S, Christmas D, Leslie D and Smith J: “Subsea Electrical Submersible Pumps at Large Step-Out Distances,” paper SPE 38537, presentedat the 1997 SPE Offshore Europe Conference, Aberdeen,Scotland, September 9-12, 1997.

can now be produced with submersible lift.Operating satellite wells at greater distancesmeans that fewer platforms are needed; hostplatforms can be in shallow water; and marginalfields can be produced without platforms, whichreduces initial costs and operating expenses.

Electric submersible pumps offer many bene-fits over other artificial-lift methods in subseaapplications. The capability to operate wells far-ther from host platforms is the most important,but other benefits include improved well perfor-mance, reduced capital costs and lead times,improved energy efficiency and less environmen-tal impact. The first subsea submersible pumpwas installed in Brazil for Petrobras in 1994.13 Tomaximize recovery over a five-year production

contract, the BP Amoco plc Liuhua field in theSouth China Sea employs 24 of 29 subsea sub-mersible pumps in operation today, all installedby Reda (above).14

For electric submersible pump systems, Redamanufactures and supplies multistage centrifugalpumps, motors, protectors, gas-handling equip-ment, power cables, surface variable-speed drives(VSD) and controllers, and other accessories. In future submersible systems, vital operatingstatistics from fields or wells can be gathered bysurface instrumentation and reliable permanentdownhole gauges to be transmitted by SupervisoryControl and Data Acquisition (SCADA) systems tooffices where data are processed.

Pump inlet and outlet pressures, well andmotor temperatures, insulation resistance, sys-tem vibration and power supply can be inter-preted using software to make decisions, identifyor prevent pump problems and premature fail-ures, monitor performance and evaluate operat-ing options. Then, before actions are taken,NODAL analysis is used to simulate new systemconditions and validate motor frequency. Ifresults look good, executable commands aretransmitted to the well or field. Advanced vari-able-speed drives will be able to change operat-ing speeds automatically based on downholemeasurements and estimated torque to avoidelectric current fluctuations in motors.

Design, Installation and OperationArtificial-lift methods work well if systems aredesigned and installed properly. Changing reser-voir and well conditions need to be anticipatedso that proper equipment is selected andinstalled to ensure flexibility. Availability of datais important to achieve good designs that workeffectively in the field. In gas-lift design forexample, well data, completion diagrams, welldeviation, gas-lift equipment, surface productionsystem information, and reservoir and fluid char-acteristics are basic requirements. Good pres-sure-volume-temperature (PVT) data with flowingpressure and temperature surveys improvedesigns. The less uncertainty, the more economi-cal the design.

This principle also applies to other artificial-lift designs. In electric submersible designs, over-sized or undersized pumps and motors, whichcause inefficient energy consumption and shorterpump life, are often the result of limited or poordata. Variable speed drives can avoid these prob-lems, but may add to project capital expenditures.

Good data may have been available in thepast, but those designing artificial-lift systemsdid not always have access to this informationdue to inadequate communication within operat-ing companies or with pump manufacturing andservice companies. Reorganized and realignedbusiness units focus information and experiencelocally rather than company-wide. This trendrequires more openness between operators andservice provides to share nonconfidential infor-mation. Companies and operating areas need toshare knowledge and data efficiently to benefitfully from isolated pockets of industry expertiseand experience.

60 Oilfield Review

Power cable

9 5/8-in. casing

Packer

7-in. liner oropen hole

Bypass tubing

4 1/2-in. tubing

Y-tool bypass

Electric submersible pump

30-in. casing

Subsea wellhead

Subsurface safety valve

13 3/8-in. casing

Wet-mateable connector

> Subsea electric submersible installations. Under certain conditions, submer-sible pumping systems may offer advantages over other forms of artificial lift in subsea applications, including improved well performance, reduced capitalcost and lead time, improved energy efficiency, reduced environmental impactand more efficient operations at longer distances from host platforms.

Spring 1999 61

Once installed, artificial-lift systems must beoperated and managed. In gas-lift systems, sta-ble gas-injection pressure and rate are importantto prevent gas from being injected into multiplevalves or short circuiting above the operating-valve design depth. Effective monitoring providesearly indication of submersible pump problems,so preventive steps can be taken or future wellinterventions can be scheduled. If artificial liftfails, these data can be used in failure analysisand contribute to a process of continuous improve-ment. Teamwork among production, reservoir,completion and artificial-lift engineers, relateddisciplines, equipment providers and service sup-pliers is a key to production optimization.

Artificial-Lift and Field Optimization Maximizing field value is an important, but diffi-cult and often neglected task. Optimizing produc-tion well by well is one way to improve fieldoutput, but this approach is limited by constraintsfrom other wells and facilities. Another approachis to look at entire production systems—wells,reservoirs over time and surface networks. In thisway, constraints can be identified and elimi-nated. On an individual-well basis, optimizationis carried out using single-rate and multirate welltest results. When a group of wells is addressed,more involved methods from spreadsheets tofield models may be needed.

The value of production optimization may bedifficult to quantify and varies from case to case.Incremental production above baseline declinecurves through focused production managementand continuous optimization is the objective (right). The area under production curvesbetween optimized and baseline rates representscumulative incremental production and ulti-mately additional reserve recovery, particularlywhen ultimate abandonment pressure can bereduced. Added value can be significant, espe-cially in large fields. Experience shows that 3 to25% incremental production can be achievedwith production optimization. This percentagevaries, depending on the degree of optimizationthat has already been achieved and the quality orage of the original production system.

A modest 1% improvement in productionrates may deliver millions of dollars in addedvalue. Three to 25% increases equate to tens ofmillions of dollars per year in added revenue.Moreover, value is delivered not just fromincreased production, but also by better gas orpower usage, reduced operating costs and lowercapital expenditures. For example, after existingwells are optimized, fewer new or infill develop-ment wells may be required. Whatever the levelof production performance—from basic dataacquisition, system control and communicationto the actual optimization process—more isachieved with a systemized plan implementedand followed in a disciplined, structured approach.

When optimization is considered, often thefirst thought is in relation to gas-lift oil fields.Today, however, the approach and tools toachieve optimization allow all producing sys-tems—natural flow, gas lift, electric submersiblepump and gas wells—to be considered.Moreover, this process lends itself to performingshort studies to assess commercial and technicalimpacts of alternative development scenariosand provide important data for decision-makingand field management. Before optimizationbegins or strategic, economic and design choicesare made, it is necessary to evaluate productionsystems. This includes topside compressors,flowlines, manifolds and separators; wellboresubmersible pump or gas-lift design and opera-tion, fluid hydraulics and completion designs;reservoir productivity and changes with time,sand or water problems; and operating environ-ments from geographic location to type of instal-lation and export method.

Computer models aid in production systemoptimization. It is essential to have simulationsthat match reality by adjusting well and surfaceparameters—formation damage, tubing, flowlinecompressors, separators, manifolds, pipelinesand a flow correlation—in models. Often simula-tions that match measured, or known, cases areused as a predictive tool. Therefore, regularlyscheduled well tests are an important componentof modeling and optimization. As predictive tools,models are used to perform “what-if” scenariosand sensitivity analyses on different parametersto evaluate options. Continuous monitoring ofcompressor pressures, gas-injection rates orelectrical amp charts in submersible systems isneeded. These data are used to update modelsregularly and match actual well tests so that fieldconditions are represented accurately.

By studying oil and gas operations as com-plete systems, the most economic developmentstrategies are identified. Surface equipment andfacilities, well completion configurations, reser-voirs and operating environments are all takeninto consideration. Over the productive life of afield, optimization includes well modeling andmonitoring, liaison between field and officepersonnel, reconciling model predictions withmeasured data, updating recommendations peri-odically, training, data management and regularreporting of actual performance against targets.How far this process is taken depends on exist-ing conditions and limitations. In some cases,drilling new wells might cost less than optimiza-tion work. Therefore, a comprehensive study isneeded before making decisions.

Economic limit

Well life

Naturalflow

Gaslift

Electricsubmersible

pump

Prod

uctio

n ra

te

> Unlocking value: area under the curve. Incremental production value may be difficult to definebecause it varies from case to case, but output above a baseline decline is the target of artificial-liftoptimization. The difference between initial output and enhanced production is cumulative additionalproduction, or reserve recovery. Artificial lift increases the area under decline curves by improvingproduction rate, extending well life and reducing ultimate abandonment pressure. Changing from oneartificial-lift method to another may be necessary to further reduce flowing bottomhole pressure andmaximize reserve recovery.

13. Mendonca JE, Hodge RC, Izetti R, Nicholson A, DwigginsJL, Morrison D, Cia M and Alfano PP: “First Installationof an Electrical Submersible Pump in a Subsea Well,”presented at the SPE Electrical Submergible PumpWorkshop, Houston, Texas, USA, April 26-28, 1995.

14. Baillie AR and Chen Jing Hue: “Liuhua 11-1 FieldDevelopment: An Innovative Application of Technology,”presented at the SPE Electrical Submergible PumpWorkshop, Houston, Texas, USA, April 29-May 1, 1992.

Forties field is a decade-long example ofongoing artificial-lift optimization in a harsh off-shore environment where both gas lift and elec-tric submersible pumps are utilized. This NorthSea development consists of four main platformsproduced predominantly by gas lift and a smallerplatform lifted exclusively by electric sub-mersible pumps. Within the main field platforms,submersible systems have been used strategi-cally for tasks ranging from starting up platformsto proving new technologies. Submersible pumpoperations began in the late 1980s and gas liftwas initiated in the early 1990s. Incrementalgains from gas-lift optimization continue toincrease, and electric submersible pump reliabil-ity as well as run life have increased steadilywith improvements in operating techniques. Avalue-pricing arrangement led to $50 million inproject savings over five years.

Initially, a gas-lift group focused on supportingmore than 40 gas-lifted wells through studies,designs, monitoring, performance analysis, train-ing and trouble-shooting problems. Over time, astructured management process evolved thatincluded gas lift, reservoir surveillance and pro-duction engineers and encompassed all aspects ofproviding gas lift to the fields. Another team con-centrated on a systems approach to electric sub-mersible pump installation and operation with thegoal of improving run life and establishing anagreement between operating and service compa-nies that shared the financial risk of pump failuresas well as the benefits of prolonged production.

Team members are involved directly in analyz-ing and selecting artificial-lift methods bestsuited to meet short- and long-term field devel-opment goals. This approach brings new tech-nologies forward to address a variety of issuesfrom reservoir constraints to cost reduction.Combining gas-lift and electric submersible pump

expertise helps to better define and manage pro-duction. Today, an integrated team is modelingthe field, and networking all the wells and asso-ciated infrastructure. This will allow strategic andeconomic decisions to be made that take intoaccount a variety of constraints from platformelectricity generation, gas compression, flow-lines, separators, gas availability and water han-dling to subsurface pump performance, motorpower, pump stages, pressure drawdown limitsand well geometry.15 This asset is in decline, butsubstantial recoverable oil remains.

The next technological step is for optimiza-tion to be performed in real time with automatedclosed-loop systems. Automation can be appliedat different levels, from semi-automatic—stillinvolving field personnel to gather data or adjustvalves and engineers to make decisions—to fullyautomatic computerized systems. Automationcan be done using simple proportional-integral-differential (PID) or complicated fuzzy-logic con-trol systems.

Combining Systems Downhole There is a trend toward artificial-lift method com-binations to yield higher rates at lower cost,under better operating conditions and with moreproduction flexibility than could be expected fromjust one method. These approaches overcomerestrictions and limitations of individual methodssuch as tubing sizes, operating depth, high waterrates and corrosive conditions. Combined lift sys-tems are also more adaptable to changing oper-ational conditions, resulting from reservoirpressure depletion, gas injection for pressuremaintenance and secondary recovery water-floods. Combined lift methods reduce equipmentrequirements and power consumption, and yieldbeneficial results in terms of costs, investmentsand asset value.

For example, combining gas lift and electricsubmersible pumps in the same well offers manyopportunities to enhance production, optimizeflow rates and ensure uninterrupted operation.Gas lift in a combined installation provides abackup in case electric submersible pumps failand can be used prior to pump startup to unloadwells or stabilize wells that produce excessivegas or sand (below). Applications that operateboth systems concurrently include using a sub-mersible system to extend the life of an existinggas-lift installation. The submersible pump actsas a bottomhole pressure booster to increase theflowing pressure at the gas-injection depth. Fromthe standpoint of design, electric submersiblepumps develop greater flowing bottomhole pres-sure differentials than gas lift for a given rate.Simultaneous gas lift and submersible pumpoperation allows smaller pumps and motors to beused. Cost-savings can be utilized to install sys-tems with advanced materials and designs thathandle harsh conditions and extend pump andmotor life.16

62 Oilfield Review

Gas-lift valves

Packer

Injection gas

Electricsubmersible

pump system

Producedliquids

Perforations

> Combining gas lift and electric submersiblepumps. Combined artificial-lift systems performbetter in terms of improved production rates and reduced initial investments or operatingexpenses than can be expected from using onlyone method. Combining submersible pumps withgas lift allows smaller pumps or fewer stages tobe used and wells can continue to produce evenif submersible equipment fails.

15. Lekic O: “Enhancing Production,” Hart’s Oil and Gas World 90, no. 3 (March, 1998): 38-41.

16. Divine DL, Eads PT, Lea JF and Winkler HW: “Com-bination Gas Lift/Electrical Submersible Pump SystemIncreases Flexibility,” World Oil 211, no. 4 (October 1990): 77-82.Borja H and Castano R: “Production by CombinedArtificial Lift Systems and Its Application in TwoColombian Fields,” presented at the 1999 SPE LatinAmerican and Caribbean Petroleum EngineeringConference, Caracas, Venezuela, April 21-23, 1999; andSPE Electrical Submergible Pump Workshop, Houston,Texas, USA, April 28-April 30, 1999.Kahali KK, Deuri B and De SK: “Electrical SubmersiblePump-Gas Lift Combination—A Successful Trial for theFirst Time in ONGC, India,” presented at the SPEElectrical Submergible Pump Workshop, Houston, Texas, USA, April 28-April 30, 1999.

17. Chachula RC and Mann JS: “Selecting the AppropriateRodless Progressing Cavity (PC) Lift System for a HighlyDeviated Wellbore,” presented at the 1999 SPE LatinAmerican and Carribean Petroleum EngineeringConference, Caracas, Venezuela, April 21-23, 1999.Mann J, Ali I and Keller M: “Wireline RetrievableProgressing Cavity Electric Submergible PumpingSystem Updated Field Case Study,” presented at the SPEElectrical Submergible Pump Workshop, Houston, Texas,USA, April 29-May 1, 1998.Haworth CG: “Updated Field Case Studies onApplications & Performance of Bottom DriveProgressing Cavity Pumps,” presented at theSPE Electrical Submergible Pump Workshop,Houston, Texas, USA, April 30-May 2, 1997.

18. Carvalho PM, Podio AL and Sepehrnoori K: “Perform-ance and Design of an Electrical Submersible-Jet PumpSystem for Artificial Lift,” presented at the SPE ElectricalSubmergible Pump Workshop, Houston, Texas, USA,April 28-April 30, 1999.

Spring 1999 63

Progressing cavity pumps are popular for pro-ducing fluids with high-solids content, aromaticcondensates and tight emulsions as well asheavy crudes, especially in high-angle wells. Innonvertical wells, however, conventional sur-face-driven systems experience rod failure andwear-induced tubing leaks. Various rodless sys-tems are being used to solve these problems.One alternative is a bottomdrive configurationthat uses a power cable, submersible motor, pro-tector and flexible gearbox to drive progressingcavity pumps. This eliminates rod breaks, tubingwear and wellhead leaks, which reduces down-time and repair costs. The primary cause of pro-gressing cavity system failure is pump wear.Harsh subsurface conditions reduce pump perfor-mance and efficiency, but electric submersiblepump motors and drive components are usuallyunaffected and can be rerun.17

Deployment alternatives include conventionaltubing or coiled tubing. Using slickline or coiledtubing to replace pumps without pulling the driveassembly offers order-of-magnitude cost-savingsand makes combined systems attractive in high-cost areas if pumps fail frequently (left). Slickline-retrievable, bottomdrive progressing cavitypumps were evaluated originally for the AlaskanNorth Slope of the USA, where conventionalworkovers cost $200,000, but slickline operationscost $20,000. Wireline-retrievable progressingcavity lift systems were recently used in highlydeviated wells in Southeast Asia with sand, scaleor heavy-oil problems and small-diameter tubu-lars. When a failure occurred, the operator wasable to retrieve and replace the pump.

In subsea applications, artificial lift mustoperate effectively with multiphase gas-liquidmixtures since it not practical to use the tubing-casing annulus for downhole separation or ventproduced gas from the casing to an extra flowlinefor each well. Prototype testing proved thathydraulic jet pumps can be operated in combina-tion with electric submersible pumps to allowproduction of high gas/liquid ratio wells in deepwater. A rotary gas separator (RGS) to reduce the

volume of free gas that enters the pump intake,increases pump performance. Placing a jet pumpin the tubing above the electric submersiblepump discharge allows gas segregated into theannulus by rotary separation to be compressedand injected back into the liquid flow stream thatis pumped to surface by the submersible pump(above). The power fluid is the liquid—producedfluids less free gas—pumped by the electric sub-mersible pump. The jet-pump intake fluid is thefree gas that was separated upstream of theelectric submersible pump intake.18

Gas lift and electric submersible pumps havebeen used for decades, but new developmentsare still being introduced. Separating oil and gasdownhole, subsurface dewatering and disposal,and horizontal electric submersible pump sys-tems for surface oil and gas operations are justsome of the future applications for artificial-lifttechnology. Combining production processesdownhole to provide environmentally friendlysolutions that improve profitability blurs the dis-tinctions between various artificial-lift methods,and between subsurface equipment and surfacefacility functions. —MET

Bolt-on head

Progressing cavity pump

Casing

Intake

Cable

Gearbox and flex drive

Motor protector

Motor

Tubing

Slickline fishing head

Tubing-Conveyed

Slickline-Retrievable

> Subsurface-motor-driven progressing cavitypumps. Using progressing cavity pumps is away to lift heavy oil and high-solids content fluids. Rodless, bottomdrive progressing cavitypumps eliminate rod failures, tubing wear, rod torque and back spinning, and surfacewellhead leaks, which are major problems in conventional surface-driven systems.

Discharge

Producedliquids

Suction

Casing

Tubing

Sliding sleeve

Flowline

PlatformPower cable

Electricsubmersiblepump

Jet pump

Perforations

Subseawellhead

Gas

Gas

Producedfluids

> Combining submersible and jet-pump lift systems. Using a jet pump above the discharge of electricsubmersible pumps allows gas segregated into the tubing-casing annulus by a rotary gas separatorto be compressed and injected back into the liquid stream being boosted to surface by the submersiblepump. Prototype testing proved that this combination of artificial-lift methods can be used offshore,especially in deep water, where individual flowlines to vent annulus gas are complex and expensiveto install.