44 Oileld Review

The Pressures On: Innovations in Gas Lift

Maharon Bin JadidPETRONAS Carigali Sdn BhdKuala Lumpur, Malaysia

Arne LyngholmMorten OpsalStatoil ASAStavanger, Norway

Adam VasperThomas M. WhiteRosharon, Texas, USA

For help in preparation of this article, thanks to Gayatri Kartoatmodjo, Kuala Lumpur; Ian Raw, Stavanger; Eli Tenold,Norsk Hydro, Oslo, Norway; and Samuel Zewe, Rosharon. NODAL, NOVA, PIPESIM and XLift are marks of Schlumberger.

Low-cost gas lift systems have traditionally been the preferred method of articial

lift in offshore production environments. Innovations in high-performance and high-

reliability gas lift systems have increased the capabilities for enhanced production

and safety in modern high-pressure deepwater and subsea installations.

Introduced in the mid 1800s, gas lift is one of theoldest artificial lift methods in the oil industry.1

However, traditional gas lift technologies, most ofwhich have been developed since the 1950s, donot meet all of the high-pressure, high-performanceand safety needs of todays deepwater and subseacompletions. These gaps are being filled by new equipment that overcomes traditionaldesign limitations.

The new equipment is sorely needed. Theworlds energy demand is expected to increasenearly 1.9% annually to the year 2030.2 At least90% of that demand will be met by hydrocarbons,which translates into an additional 11 millionbbl/d [1.7 million m3/d] of oil by the year 2010.Taking into account an annual reservoir declinerate of 5%, the need for oil will grow to nearly 44million bbl/d [7 million m3/d] by 2010. This need fuels concerns about uncertain futurereserves. However, many industry experts believe that 50 to 75% of the oil needed for thenext 20 years will come from mature assets, andare convinced that much of the demand can bemet with fit-for-purpose artificial lift tech -nolo gies that increase long-term potential production capabilities.3

Currently, there are nearly 1,000,000 produc -ing oil wells in the world.4 More than 90% of theseare on some form of artificial lift for enhancedproduction. Reservoir pressure in these wells istypically inadequate for raising oil to the surface,so operators must supplement natural reservoirdrive to boost gross fluid production. Althoughgas lift is used in only approximately 30,000wells, it is the most widely employed andeconomic artificial lift method used for matureoffshore oil wells.

The gas lift process involves injecting naturalgas through the tubing-casing annulus in aproducing well. Injected gas creates bubbles inthe produced fluid contained in the tubing,making the fluid less dense. This makes itpossible for formation pressure to lift the columnof fluid in the tubing and increases the amount offluid produced from the wellbore.

Unfortunately, traditional gas lift technolo -gies have design limitations, such as limits on the gas-injection rate for stable tubing andcasing fluid flow, low maximum operatingpressure and unreliable backpressure systems.These constraints prevent conventional gas liftmethods from meeting the safety requirementsin high-pressure operations, and preclude theiruse in a significant number of todays deepwaterand subsea completions. Because of theselimitations, many deepwater and subsea installa -tions are not fitted with gas lift systems, butcould benefit from them.

Design innovations, such as the use ofventuri-flow geometry in gas lift valves, canreduce flow instabilities in tubing and casing.Coupled with high-pressure bellows systems,these improvements have significantly extendedthe maximum pressure limitation of gas liftsystems from 2,500 psi to 5,000 psi [17.2 to34.5 MPa]. In addition, the recent introduction ofsurface-controlled gas lift flow-control valves hasincreased the range of applications and theflexibility of gas lift systems. These new gas lift capabilities are addressing the growing needs of current and future deep wells andsubsea completions.

1. The first gas lift patent, the Brear Oil Injector, was issuedin 1865, and more than 70 gas lift patents and applicationswere developed between 1865 and 1953. For more on thehistory of gas lift: Brown KE: Gas Lift Theory andPractice, Including a Review of Petroleum EngineeringFundamentals. Englewood Cliffs, New Jersey, USA:Prentice-Hall (1967): 181197.

2. International Energy Outlook 2006, DOE/EIA-0484 (2006)published by the U.S. Government Energy InformationAdministration, http://eia.doe.gov/oiat/ieo/world.html(accessed November 24, 2006).

3. Pike B: Importance of Mature Assets Development forFuture Energy Supplies, keynote presentation at theHart Energy Conference, Brownfields: OptimizingMature Assets, Denver, October 31November 1, 2006.

4. Abraham K: High Prices, Instability Keep Activity High,World Oil 227, no. 9 (September 2006), http://www.worldoil.com (accessed December 20, 2006).

5. Fleshman R, Harryson and Lekic O: Artificial Lift forHigh-Volume Production, Oilfield Review 11, no. 1(Spring 1999): 4863.

6. Donnelly R: Artificial Lift: Oil and Gas Production. Austin,Texas: PETEX, 1985.

Winter 2006/2007 45

Advanced gas lift technologies are helpingoperators enhance oil production and improveoil-reserve recovery. This article expands on the basic principles of gas lift and describes how innovative methods are helping operatorsmeet critical oil-production requirements indeepwater and subsea environments. Casestudies from offshore Malaysia, the NorwegianSea and the North Sea demonstrate how thesetechnologies are being used in a variety ofproducing environments.

Principles of Gas LiftOver the producing lifetime of an oil well, thebottomhole pressure that sustains naturalproduction will eventually drop so low that thewell will either stop flowing or fail to produce at

an economic oil rate. When this occurs,significant volumes of oil may be left behind. Torecover this oil and improve field productivity, a number of artificial lift solutions can beimplemented. They involve either pumping theoil to the surface or changing the properties ofthe well fluid, allowing the available reservoirpressure to produce the oil to the surface.5

Gas lift is an artificial lift technique thatutilizes relatively high-pressure gas injected fromthe surface into the wellbore, typically betweenthe casing and production tubing, through avalve placed at a strategic depth in the well(above).6 The injected gas enters the valve andmixes with the existing fluid in the productiontubing. This mixing decreases the density of the

> Gas lift. Gas lift increases oil flow by reducing the hydrostatic head of the fluid column in the well (right).In a gas lift well, the downhole tubing pressure is a function of the amount of gas injected, fluidproperties, flow rates, and well and reservoir parameters. The oil-production rate that can be achievedfrom an individual well is a function of the surface gas-injection flow rate (left inset). Increasing the gas-injection rate will in turn increase the amount of oil produced from the well to a point where producedgas volume replaces produced oil, yielding a maximum oil production rate (A). In typical operations,the cost of gas lifting the well must be considered as part of the overall system economics. Some ofthe lift-cost factors include natural gas costs, gas compression and fuel costs, and nonhydro carbon(produced water) liquid-disposal costs versus the current price for a barrel of oil. In many cases, theoptimal injection rate (B) and associated oil-production rate are more economical and offer a betterrate of return than the maximum injection and oil rate (A), which have a much higher lift cost per barrel.

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liquid, allowing the bottomhole reservoirpressure to produce oil to the surface. Bymaintaining a constant rate of gas injection fromthe surface and a constant ratio of injected gas tothe wellbore fluid, the well will flow oil at aconstant rate.

Since gas is the energy source for a gas-liftedsystem and is usually injected continuously, it isnecessary to have an ample supply. In themajority of cases, gas is obtained from adjacentproducing gas wells and is compressed anddistributed through a surface-piping network toindividual oil wells. Once a gas-lifted well isproducing oil or associated well fluids, theinjected gas is recovered at the surface,recompressed and reinjected into the same field.

To design an optimal and efficient gas liftsystem, application engineers must build asystem model for each well, utilizing specificsoftware and nodal analysis techniques providedby programs like PIPESIM production systemanalysis software. This software tool provides anaccurate representation of the productionpotential of individual wells in the productionnetwork. Based on the available gas-injectionpressure and gas volumes provided to wellswithin the production network, oil rates and gaslift allocations can be computed for each well(above). By computing system-flow potential, themodeling process aids in the proper selection ofdownhole gas lift equipment.

This integrated-systems approach is a mar-riage of each producing wells oil-flow potential,or inflow performance relationship (IPR), andthe production tubing flow capacity, or outflow,to the surface network of production facilitiesand pipelines. The entire oil-production system,which consists of individual wells tied into thesurface production infrastructure, must bedesigned and finely tuned to allow for optimaland stable oil production from the gas lift system.

The ideal operating system for gas-lifted wellsis one that allows for a continuous and stable gas-injection rate at the deepest point possible in thewellbore. A stable injection rate at a constantinjection pressure will foster a stable liquid flowrate from the reservoir, minimizing the potentialfor undesirable pressure fluctuations at thesandface, and allowing maximum oil productionwith continuous gas lift.

Gas Lift Well-Flow Stability Operating efficiency in a continuous flow gas-lifted well depends on stable productionpressures and flow rates. System stabilityrequires that the gas lift operation be properlydesigned so that the downhole gas lift valve isinjecting gas at the calculated critical flow rate.7

Critical flow occurs when the fluid velocitythrough the orifice in a gas lift valve has reachedthe speed of sound. The critical gas-flow rate isregulated by the upstream and downstreampressures across the gas lift valve orifice. In aconventional square-edged orifice gas lift valvedesign, critical flow typically occurs when thereis a 40 to 60% reduction between the upstreaminjection pressure and the downstream flowingpressure (next page, left).

In a subcritical regime, small changes indownstream pressures tend to induce instabilitiesin the upstream tubing-casing annulus.8 Smallchanges in pressure can cause large changes inthe flow rate. In some situations, this may causepositive feedback that results in unwantedoscillations in pressure and production rates,called a heading phenomenon. However, at orabove the critical flow rate, the feedback loop isbroken, and pressure variations downstreamcannot propagate back to the upstream side tocall for more gas. Heading instabilities in thecasing and tubing can also occur when themaximum pressure of the surface compressorsystem cannot sustain the differential pressureneeded to maintain critical flow for adequate gas lift.

46 Oileld Review

7. Alhanati FJS, Schmidt Z, Doty DR and Lagerief DD:Continuous Gas-Lift Instability: Diagnosis, Criteria, andSolutions, paper SPE 26554, presented at the SPEAnnual Technical Conference and Exhibition, Houston,October 36, 1993.

8. Poblano E, Camacho R and Fairuzov YV: Stability Analysisof Continuous-Flow Gas Lift Wells, paper SPE 77732,presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29October 2, 2002.

9. Faustinelli J, Bermdez G and Cuauro A: A Solution toInstability Problems in Continuous Gas lift Wells OffshoreLake Maracaibo, paper SPE 53959, presented at theSPE Latin American and Caribbean PetroleumEngineering Conference, Caracas, April 2123, 1999.

10. Tokar T, Schmidt Z and Tuckness C: New Gas Lift ValveDesign Stablizes Injection Rates: Case Studies, paperSPE 36597, presented at the SPE Annual TechnicalConference and Exhibition, Denver, October 69, 1996.

> Gas lift evaluation. To install an efficient gas lift system, all the factors thataffect well performance must be investigated. This includes the analysis ofthe sensitivities (production-line pressures, formation properties and others)that will influence gas lift well performance. From these evaluations, the gaslift application engineer can assess and determine the best design installationalternative based on technical, commercial, risk and overall system factors.

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Winter 2006/2007 47

To determine if flow instabilities are a resultof the operation of the downhole gas lift system,the production engineer can use current wellproduction-test data and gas lift operatingparameters with NODAL production systemmodeling software to analyze the system. Bymodeling existing flow rates and pressures, theengineer can determine whether the gas-injection rate at the gas lift valve depth is ineither critical or subcritical flow and whether a

sufficient differential pressure exists betweenthe upstream and downstream pressures topromote stable production rates.

Unfortunately, the vast majority of gas liftvalves contain the traditional square-edgedorifice. These traditional gas lift valves arefrequently installed at depths where gas-injection flow rates cannot reach critical flowvelocities, giving rise to unstable oil flow.However, alternative modern gas lift technolo -gies now can address and eliminate these flow

instabilities. For example, Petrleos deVenezuela, S.A. is successfully using theSchlumberger NOVA gas lift valve to eliminateproduction instabilities in its Lake Maracaibowells.9 The innovative mechanical design of theNOVA valves orifice uses a nozzle-venturi insert,which is a converging-diverging aperture, tocontrol the flow of gas through the valve(below).10 The nozzle-venturi insert causescritical gas flow to occur once the downstream

> Conventional orifice gas lift valve and gas-flow performance plot.Gas enters the valve through inlet ports and flows through a square-edged orifice chosen to provide a controlled rate of gas flow. Theflow-performance rate curve (right) through a conventional gas liftsquare-edged orifice valve can be modeled using the Thornhill-Craver equation. This equation uses the casing pressure upstream ofthe valve, Pup, and the tubing pressure downstream of the valve,Pdown, the choke flow area, the empirical discharge coefficients andgas properties to determine the flow rate through the valve.(Adapted from Vasper, reference 13.)

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> Nozzle-venturi orifice NOVA gas lift valve and gas-flow performanceplot. The performance plot (right) shows that critical flow (blue) isachieved through the converging-diverging aperture in the nozzle-venturi valve with a 10% pressure drop or less. By contrast,conventional square-edged orifice valves (red) require between 40%and 60% pressure drop to achieve critical flow. In most cases, it isnot practical to operate with this much loss.

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pressure is reduced to between 90 and 95% of theupstream pressure. In all cases, critical flowexists with differential pressures equal to 10% ofthe upstream pressure.

This valve is unique because it prevents flowinstabilities without the attendant losses inproduction associated with conventional valves.Stabilization of the flowing bottomhole pressurein a well will generally increase the overallproduction from that well. This benefit isparticularly important in dual-well completionswhere two independent gas lift systems areoperating in a single-well annulus (above). Inthese gas lift installations, a single source of gas

injection must be utilized to control the gasinjection and flow stability of two independentproducing wells. Stabilizing the injectionpressure can also reduce maintenance costs.

Another benefit of the NOVA valve is theimproved control it offers in gas lift fields thathave computer-controlled optimization schemes.11

Until recently, unstable wells have been excludedfrom controlled optimization operations becauseof their destabilizing effects on the feedbackcontrols in such a system. With the NOVA gas liftvalve, even if well production is slightly tubingunstable, the injected-gas rate will remainconstant and, hence, injection-gas pressure,which is the control parameter for these systems,will remain stable. This makes it possible toinclude even more wells in optimization schemes.

Gas Lift Optimization A recent example in Malaysia shows the benefitsof switching from traditional gas lift valves tonozzle-venturi gas lift valves in a field-wide gaslift optimization campaign. The Bokor field,operated by PETRONAS Carigali Sdn Bhd(PCSB), comprises three platforms with 77 gas-lifted producing oil strings (below). Several ofthese strings are completed as common-annulusdual producers.

A nearby field supplies injection gas for Bokorfield, and the compression facilities are on theBokor platforms. However, with aging compres sorsand fluctuations in gas availability, it is critical todistribute lift gas to the most prolific producers.Key to optimizing field productivity is maintaining

48 Oileld Review

> Dual gas lift completion. Dual gas lift or common-annulus dual gas lift installations are typicallydesigned for offshore production environments.The concept allows two producing zones or twowells to be independently produced from a singlewellbore. The producing zones are isolated by a dual-production packer that allows fluidproduction into the individual tubing strings. Gas injected into the common annulus can beindependently distributed through the gas liftvalves for each producing string. This conceptallows an offshore operator to produce multiplezones from each wellbore, thereby doubling thenumber of wells that can be produced from asingle offshore platform.

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> Bokor field. PETRONAS Carigali Sdn Bhd operates three platforms in the Bokor field located 45 km[28 mi] offshore Miri, Sarawak, East Malaysia.

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Winter 2006/2007 49

lift-gas delivery to wells with unreliable gas supply,which are the ones that create significantinstability in the field production.

As part of an overall production strategy forthe Bokor field, PCSB and the SchlumbergerBokor alliance team implemented a gas liftsystem-optimization campaign to stabilizeproduction flow rates. Well productivity would besignificantly improved by minimizing the severeheading that is introduced by fluctuations inthe casing gas-injection pressure and injectionflow rate.

Historically, traditional square-edged orificegas lift valves had been installed in the Bokorwells. For example, one well was originallydesigned for a gas-injection rate of 500 Mcf/d[14,200 m3/d] at an injection pressure of 630 psi[4.3 MPa]. However, the production system wasactually operating with a much lower injection-gas-flow rate of 120 Mcf/d [3,398 m3/d] at a450-psi [3.1-MPa] injection pressure, becausethe square-edged orifice prevented attainment ofthe critical gas flow rate in the well, resulting intubing flow instabilities. By switching to a NOVAnozzle-venturi gas lift valve, the operator wasable to increase the gas-injection flow rate in thewell enough to reach the critical flow rate andstabilize production. The well eventuallyattained its originally designed gas-injection flowrate, and the average oil production increased by80 bbl/d [12.7 m3/d].

Over a nine-month period, the gas liftoptimization campaign in the Bokor fieldconverted all three platforms to the NOVAvalve systems. Measured production readingsindicated that stable injection rates andpressures were achieved in wells fitted with theNOVA gas lift valves. The gas lift optimizationcampaign for Bokor field increased oilproductivity by more than 2,000 bbl/d [318 m3/d]over what had been produced before the NOVAinstallation (right).

High-Pressure and High-PerformanceGas Lift SystemsGas lift systems have long been the preferredmethod of artificial lift in offshore productionenvironments. Among the reasons for this are therelatively low cost of the initial hardwareinstalled during the completion of the well, thegeneral availability of gas and compressionequipment, and the systems ability to adapt tochanging reservoir conditions. Also, the relativeease of slickline intervention to service downholegas lift equipment gives the operator theflexibility to change or repair the system without

having to pull the entire well installation, whileat the same time minimizing the amount ofdowntime during this intervention process.Finally, because of their relatively low cost andlong-term reliability, gas lift systems are oftendeployed in deep subsea wells as a backupsystem for other artificial lift technologies, suchas electrical submersible pumps (ESPs) (seeEvolving Technologies: Electrical SubmersiblePumps, page 30).

As the number of deepwater and subseadevelopments continues to increase worldwide,so has the need to develop new downhole gas liftsystems to maximize oil recovery. As reservoirpressures decline and water cuts increase,

operators are challenged with installing systemsthat address the high-performance and sustained-reliability requirements of their deep operatingenvironments, while limiting or eliminating theneed for costly interventions. Also, increasedpressures in deeper wells and more stringentregulatory requirements, combined with therisks associated with floating production struc-tures, have elevated the importance of wellboreintegrity in gas lift systems for subsea applications.

11. Jansen B, Dalsmo M, Nkleberg L, Havre K,Kristiansen V and Lemetayer P: Automatic Control ofUnstable Gas Lifted Wells, paper SPE 56832, presentedat the SPE Annual Technical Conference and Exhibition,Houston, October 36, 1999.

> Bokor field gas lift optimization. Individual well performance rates are compared before and aftergas lift optimization (top). Gross production, including oil and water, from all gas lift wells increased byapproximately 60% during more than a year of operation (bottom). Net oil production increased byabout 35%.

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Operators considering gas lift for deepwaterand subsea wells typically struggle to work withinthe limits of standard gas lift equipment. In mostcases, this means that the greatest depth for gasinjection is limited by the valves gas-injectionpressure range. In many instances, wellperformance analysis shows that with higher gas-injection pressures, the depth of injection couldbe increased significantly enough to allow thewell to produce much higher volumes of oil.

Conventional gas lift systems can operate upto a maximum injection pressure limit of2,500 psi. This maximum operating pressure issufficient only in traditional land-based wellsand typical offshore shelf wells where reservoirdepths are shallow and lower productionpressures occur. However, in deeper water andsubsea environments, gas lift equipment must beable to operate at gas-injection pressures up to5,000 psi and at gas lift injection flow ratesexceeding 10 MMcf/d [283,000 m3/d]. These arenontradi tional applications, and they must beaccom plished while maintaining criticalpressure integrity during the life of the well.Conventional gas lift valves are not capable ofperforming at these extreme operating levels and therefore do not offer adequate reliability.This has typically limited the use of gas liftsystems in subsea wells requiring high gas-injection pressures.

The XLift high-pressure gas lift system wasrecently developed as a fit-for-purpose solution to address the demanding requirements ofdeepwater and subsea environments (left). Thishigh-pressure gas lift system extends the capabilityof existing systems by increasing the operatingpressure range to 2,000 psi to 5,000 psi [13.8 MPa to34.5 MPa]. The XLift systems higher maximuminjection-pressure limit allows operators tocomplete gas lift wells with deeper injection pointsto increase overall well performance.

The XLift gas lift system features a nozzle-venturi orifice flow configuration, similar to thatof the NOVA gas lift valve, for more efficient andstable gas throughput. In addition, it has apositive-sealing check valve that eliminatespotential leak paths to the casing-tubing annulusduring nonproducing periods. The XLift valve hasa patented, edge-welded bellows assembly thatreduces the internal gas charge while increasingthe operating pressure. A larger, 134-in. [4.4-cm]outside diameter valve was designed to improvethe working geometry. The valve has demon -strated improved performance and reliabilitycompared with standard gas lift valves. XLifthigh-pressure systems provide flexible operatingranges for multiple-well scenarios requiring high

50 Oileld Review

> XLift system for deepwater and subsea applications. The XLift gas valveextends the capability of conventional gas lift systems by increasing themaximum operating pressure limit to 5,000 psi. XLift valves have a positive-sealing check-valve system that prevents potential leak paths to the tubing-casing annulus. This potential leak path is present in gas lift valves withconventional check-valve systems.

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Winter 2006/2007 51

gas-injection pressure. The development of thesystem components included a series of qualifi -cation flow tests to measure the effect of liquidflow erosion, and high-volume gas-flow andpressure-integrity tests to validate the reliabilityof the system.

XLift Operations in the Norwegian SeaStatoil is using the XLift systems in criticalsubsea wells in the Norwegian Sea. For example,the Norne satellite fields Svale and Str, locatednorthwest of Norway, have three susbseainstallations that tie back to the Norne floatingproduction storage and offloading vessel(FPSO)(above). Within these installations thereare five producing oil wells and three water-injection wells. The deepest reservoir depth is8,150 ft [2,484 m] true vertical depth from meansea level (MSL). The sea is about 1,245 ft [379.5 m]deep at this location. High-performance gas liftvalve systems are needed in the wells to lift a

high volume of produced oil and to satisfypressure-integrity requirements. These gas liftsystems require surface gas-injection pressuresof approximately 3,335 psi [23 MPa] and gas-injection flow rates of 8 MMcf/d [226,500 m3/d]to facilitate production exceeding 20,000 bbl/d[3,180 m3/d] of oil per well.

Statoil chose the XLift system to satisfy thehigh-performance, reliability and environmentalrequirements for these subsea gas liftinstallations. Working with Statoil to meet rigidregulatory test requirements, Schlumbergerengineers subjected the gas lift valves to a seriesof high-volume and dynamic, liquid- and gas-flowand pressure-integrity tests. Under Statoilsguidance, the gas-flow tests were performed atStatoils Karsto Metering and TechnologyLaboratory (K-Lab), and the liquid flow testswere performed by the International ResearchInstitute of Stavanger (IRIS). The specificobjectives of the testing were to qualify thedynamic performance of the XLift valve system

and to verify its use as a pressure barrier. Theresult of the testing and collaboration withStatoil was a valve design capable of meetinghighly stringent operational criteria. XLiftsystems have been installed and are successfullyhelping to produce oil in these five Norne wells.

Natural, or Auto, Gas LiftThe introduction of surface-controlled downholeflow-control valves in 1997 led to a newtechnique of gas-lifting wells called natural, orauto, gas lift.12 Natural gas lift uses gas from adownhole gas reservoir or gas cap penetrated bythe same well to increase oil production througha specially designed hydraulically or electricallycontrolled flow-control valve with adjustableports (above). Using gas directly from a sub-terranean sourcerather than pumping it downthe tubing-casing annulus from surfacemeansthat a gas compressor, transportation pipelines

12. Betancourt S, Dahlberg K, Hovde and Jalali Y: NaturalGas-Lift: Theory and Practice, paper SPE 74391,presented at the SPE International PetroleumConference and Exhibition in Mexico, Villahermosa,Mexico, February 1012, 2002.

> Statoils Norne floating production storage and offloading vessel (FPSO). The Norne satellite fields,Svale and Str, and their three subsea installations are shown.

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> Natural gas lift. This technique uses gas from asubterranean formation to lift produced fluids inthe well. A specialized surface-adjustable, flow-control valve is used to control the flow ofinjected gas. Typically, well production isoptimized by setting the valve position from thesurface through a small hydraulic control line.

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and other injection-related equipment are notrequired for these wells. This reduces platformload requirements and capital costs for offshorefacilities or subsea installations. It also has thebenefit of producing gas without recompletingthe well, and eliminates the need for futureinterventions for resizing or replacingconventional gas lift equipment.13

Natural gas lift requires a gas cap or aseparate gas reservoir that can be completed todeliver gas at sufficient rates for gas injection.The gas reservoir must be sufficiently large thatthe pressure remains high enough to allow gas tobe injected into tubing throughout the wellsproducing lifetime. The flow-control valvesprovided by Schlumberger for natural gas liftapplications have several special features. Thesevalves have a range of positions that can controlthe gas-flow rate needed to optimize productionacross the anticipated range of well conditions.The gas-flow rate can be adjusted from thesurfaceeither discretely or continuously

through hydraulic or electric control of the valveopening position, which in turn enablesoptimized oil production. The gas rates flowingthrough the valves can be predicted withnumerical modeling, which ensures that thevalve is properly sized for the well conditions.

The valves can be opened or closed and theflow-rate position changed while subjected tosignificant pressure differentials, and they canwithstand the erosive effects of abrasive fluids.The valves contain check valves to prevent fluidflow from the tubing to the annulus. This allowsthe production tubing to be pressure-tested andprevents damage to the gas-producing zone.

The use of downhole flow-control valves alongwith permanent-monitoring equipment alsomeans that natural gas lift wells are consideredintelligent wells. The increased value of anatural, gas-lifted, intelligently completed well is relatively easy to calculate since the costs can be compared with those of a conventionalgas lift system.

Since 1998, Norsk Hydro has installed35 natural gas lift subsea completions in 16 wellsin the North Sea using Schlumberger flow-control valves. Of these, the first 31 installationshave been on the Troll and Troll West fields.Norsk Hydro decided early in the development toutilize the large gas cap overlying the Troll oil rimto optimize oil recovery using natural gas lift.Using these valves for natural gas lift has helpedNorsk Hydro reduce development costs byeliminating expensive surface compressors andsupport infrastructure for gas injection.

Single-Trip Natural Gas LiftFollowing the successful installation of the first31 natural gas lift completions in the Troll fields,Norsk Hydro presented Schlumberger with a newchallenge: optimizing oil production in NorskHydros marginal Fram Vest field by installingnatural gas lift systems at the lowest possiblecost. Gas lift in the Fram Vest field was notrequired for the traditional reasons of water cutor low reservoir pressure, because the produc -tion wells in this field were capable of flowingwithout any artificial lift. Instead, the require -ment was to maximize the wellhead pressuresand production in four subsea wells to flowthrough a 20-km [12-mi] pipeline back to theproduction platform.

The solution would be field-wide develop -ment optimization. The goal was to maximize oilproduction from each well, while maintainingsimilar wellhead pressures to keep theproduction rates of the four wells balanced. Thesolution for the production system also had toaccount for flow in long subsea flowlines. Hydrohad a tight four-month schedule to complete the installations.

The customary natural gas lift installation inthe Troll field required three trips in the well.The first was to perforate the well in the gas cap,another was to run sand screens on anintermediate tubing string, and a third to run theflow-control valve with the production packerand tubing to the surface.14 This long, sequentialinstallation process leaves the gas-cap perfora -tions exposed for an extended time period,risking formation damage to the gas cap andposing well-control safety concerns. In addition,to minimize well-control concerns, a kill pill ofheavyweight mud had to be placed in the wellwhere the gas cap would be perforated. This inturn leads to potential reservoir damage, cleanupissues and the need to dispose of the kill pill.

To address Norsk Hydros goals to reducecompletion costs in the Fram Vest field, protectthe environment, and maximize safety and well

52 Oileld Review

13. Vasper A: Auto, Natural or In-Situ Gas-Lift SystemsExplained, paper SPE 104202, presented at the SPEInternational Oil and Gas Conference and Exhibition,Beijing, December 57, 2006.

14. As a safety measure, sand screens are typically run ineach oil zone and are required in all gas completions.

15. Raw I: One Trip Natural Gas Lift Solution BrightensPicture for Marginal Oil Reserves, Scandinavian Oil-GasMagazine, no. 7/8 (2004): 99101.

16. Scott S: Artificial LiftOverview, Journal of PetroleumTechnology 58, no. 5 (May 2006): 58.

> Fram Vest single-trip natural gas lift installation. Using the one-trip natural gas lift system (left) allowsrunning the gas lift completion, perforating the well and setting the packers with one trip in the well.The map (right) shows the Norsk Hydro subsea Troll and Fram Vest fields.

Packer

Sand screens

Perforations

Packer

Perforations in gas cap

Oil zone

Gascap

Openhole completion with sand screens

Perforating guns

Flow-control valve

Flow tube connectingsand screens to flow-control valve

Flor

MongstadTroll fieldTroll West

Fram field

Fram Vest

Sture

Bergen

N or t h

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Winter 2006/2007 53

productivity, Schlumberger developed a single-trip natural gas lift system (previous page). Thiswas achieved by integrating the hydraulic gas liftvalve and premium sand screens into a singletubing-conveyed assembly. Perforating guns werealso installed on the outside of the completiontubing so that the entire completion could be runin one trip.

For flow control, a modified wireline-retrievable hydraulic flow-control valve allowed

coupling of the gas inlet to the sand screens.When the single-installation trip was completedand the tubing hanger secured in the wellhead,pressure was applied to the annulus and thenbled off to fire the tubing-mounted perforatingguns. After the guns had fired, tubing pressurewas applied to set the production packer.

Four systems were installed and the fourFram Vest production wells were brought onstream successfully. The single-trip natural gas

lift system installations minimized risks offormation damage and well control related to theopen gas-cap exposure. Compared with conven -tional completions in this field, the single-tripcompletions saved Norsk Hydro US$ 2.8 millionrepresenting two days of rig-time reduction perwell. Other savings include reduced costs ofcompletion hardware, and the elimination of the need for a kill pill and environmentaldisposal concerns.15

The success of the Fram Vest single-tripnatural gas lift system convinced Norsk Hydrothat similar single-trip gas lift technology couldbe applied in many other production scenarios.For example, in three wells in their Vestflankenfield, Norsk Hydro used a tubing-retrievable 11-position flow-control valve with sand screens inmultilateral boreholes to allow for future gasproduction at high rates after the oil in these gas lift production wells is depleted (left).Schlumberger designed a surface-controlled,high-rate, flow-control valve with five choke-sizepositions to allow for gas lift control during theoil-production phase of the well. When thedecision is made to switch to gas production, thevalve will be fully opened to provide themaximum flow area required for gas production.

The Horizon for Gas LiftEvery oil well will ultimately need some form ofartificial lift to help operators optimize recovery,and gas lift remains the dominant form ofartificial lift in the offshore environment. In deepwater, ultradeep water and other remote areas,operators are facing a broader definition of gaslift. In some of these environments, flow in longsubsea tiebacks represents an importantcomponent of the production system.16 Applyingartificial lift in these situations requirestechnology advances to assure flow throughthese extended flowlines.

Furthermore, highly reliable gas liftequipment with higher pressure ratings andcapabilities for deeper points of injection will bea critical component for optimizing production inthese demanding environments. New high-pressure and flow-optimized gas lift technologyalong with surface-controlled gas lift flow-controlinnovations have paved the way for successful oilrecovery from the worlds most challenging andcomplex deepwater and subsea oilfields.

As operators continue to explore ways toextend the natural decline of their assets,drilling programs will continue to go deeper. Gas lift remains one of the key applications for the recovery of vast amounts of the worlds oil reserves. RH

> Vestflanken field dual-purpose gas lift installation. Flow-control valvescontrol the liquid flow from each of the oil-producing legs. A third flow-controlvalve controls the gas used for the natural lift. Once the oil zones aredepleted, the upper flow-control valve will be fully opened to allow high-volume gas production from the well.

Oil zone A

Oil zone B

Gaszone

Perforations

Sand screens

Productiontubing

Casing

Flow-controlvalve

Gas flow

Oil