30 Oilfield Review

Evolving Technologies: Electrical Submersible Pumps

Chad BremnerNisku, Alberta, Canada

Grant HarrisInverurie, Scotland

Alex KosmalaHouston, Texas, USA

Barry NicholsonSugar Land, Texas

Albert (Chip) Ollre Rosharon, Texas

Marc PearcyOklahoma City, Oklahoma, USA

Chris J. Salmas Edmonton, Alberta

Sandeep C. Solanki EnCana CorporationCalgary, Alberta

For help in preparation of this article, thanks to Marc FournierCarrie, Pyt-Yakh, Russia; Natalie Collins, Cesar Contreras andJim Sams, Oklahoma City; Drew McGinn, Inverurie, Scotland;Micah Schutz, Tyumen, Russia; and Brian Scott, Aberdeen.espWatcher, Hotline, Maximus, Phoenix, ProMotor, REDA andSpeedStar are marks of Schlumberger. Microsoft InternetExplorer is a trademark of Microsoft Corporation.

Innovations in electrical submersible pump technology are paying off for oil

companies, providing greater reliability, performance and endurance in harsh

environments. From manufacturing to monitoring, advanced pump systems are

helping oil companies optimize production while protecting their investments in

downhole lifting technology.

The history of artificial lift is marked byinnovation—often the result of gradual evolutionin a product line, but sometimes the result ofdrastic redesign efforts. These changes have ledto improvements in artificial lift, particularlywith respect to electrical submersible pumps(ESPs).1 New records of performance andendurance are opening up the range of ESPapplications. Advances in design and manufac -turing are making ESPs more resilient in hostiledownhole environments, qualifying them forservice at greater depth, increasing their gas-handling capability and making them moreresistant to solids and abrasives.

ESPs depend on movement of produced fluidsto carry heat away from the motor. Thisrequirement once limited ESPs to internaloperating temperatures around 400°F [204°C];certain pump models are now capable ofoperating at up to 550°F [288°C]. The use ofproduced fluids to cool ESP motors has alsoimpacted the amount of gas that ESPs couldpump before overheating. With advances in gas-handling components, ESPs with axial pumps cannow handle free-gas fractions up to 75%. Otherimprovements in ceramics, metallurgy andelastomers are making ESP systems moreresistant to abrasion caused by sand production.By extending the range of operating tempera -tures, gas handling and abrasive resistance ofmodern ESP systems, these advanced pumps cannow be installed in wells that were onceconsidered beyond the realm of ESP applications.

To get the most out of their pumps whileprotecting their investment in artificial lift, oilcompanies monitor ESP performance. With

advances in sensor technology, operators areable to fine-tune the performance of the pump,the well and the reservoir. In Oklahoma City,downhole sensor readings are monitored andanalyzed around the clock by a multidisciplinaryteam of specialists working at the SchlumbergerProduction Center of Excellence. At this facility,pump surveillance and reservoir-productionengineers work in concert with operators toevaluate trends in pump and field performance.These trends alert ESP experts to downhole orsurface problems early on, usually in time to takecorrective measures. Even more, by monitoringdownhole data during pump shutdowns orstartups, reservoir-production engineers canprovide pressure-transient analysis, to assistoperators in evaluating reservoir performance.

This article describes advances in ESPdesign, surface and downhole instrumentation,and centralized monitoring that are helpingoperators optimize pump and field performance.Examples from Canada and the North Seahighlight the growing range of successfulapplications for which electrical submersiblepumps are being installed.

Improving Pump DesignOne of the oldest axioms in the oil field is thatcritical operations invariably take place onweekends or holidays, in the middle of the nightand during bad weather. While it is hard onpersonnel to install pumps in a driving rainstorm,blowing sand, or the wind, cold and snow of ablizzard, these surface conditions can also betough on the pumps themselves. However, a newline of pumps was developed to meet these

1. For more on artificial lift: Fleshman R, Harryson andLekic O: “Artificial Lift for High-Volume Production,”Oilfield Review 11, no. 1 (Spring 1999): 48–63.

Winter 2006/2007 31

Electricalpower cable

Wellhead

Pump

Intake

Protector

ESP motor

Pumpmonitoring

unit

Head

Pump efficiency

Horsepower

conditions. Originally designed for installation inhostile environments exemplified by harshRussian winter conditions, the REDA Maximuselectrical submersible pump can handle extremesin surface and downhole temperatures that usedto wreak havoc on pump installation and evencause early pump mortality (left).

Rather than evolving through a series of smalldesign improvements, the REDA Maximus ESPwas developed as a modular system engineered toenhance reliability and increase service efficiencyand performance of downhole ESP systems. TheMaximus system consists of integrated compo nentsusing fewer and simpler mechanical connectionsthan previous models. This system offers a rangeof configuration options. Operators who want astandard system in each well can install theProMotor integral motor, protector and sensorunit. For installations that require moreflexibility and custom application design, theMaximus motor and Maximus protector permitthe operator to select application-specificprotector types that will best function incombination with the motor horsepower andvoltage required for a particular well.

Electrical power connections, as well as theconnections between oil-filled components, havebeen engineered for greater integrity. Maximusmotors use a new ESP motor connector-plugdesign that eliminates taping of electricalconnections normally performed at the wellsite(below left). Oil-filled components that areconnected at the wellsite, such as the motor andprotector, use special ESP flange connections toprevent these components from trapping airbubbles while making up connections in the field.

The Maximus design also removes certaincritical installation operations from the wellsite.Before delivery to the field, Maximus motors,protectors or integrated ProMotor units are filledwith oil, and the protectors are shimmed to ensureproper shaft spacing. Formerly carried out at thewellsite, these procedures are now performedindoors, in the controlled environ ment of a REDAservice facility, eliminating the risk of improperfilling or shimming under difficult field conditions(next page). This process reduces exposure of thedielectric oil to wellsite contamination byprecipitation, sand or dust.2 These improvementsin service quality also helped to simplify theinstallation process of the Maximus unit, resultingin a significant reduction in rig time compared toprevious ESP technologies.

32 Oilfield Review

> New electrical power connection. A redesigned connector (left) eliminates the practice of tapingelectrical connections at the wellsite (right), thus reducing the chance for tool contamination orhuman error.

Power cable

Power connectionsocket

> Siberian winter in a Russian oil field. To survive such conditions, pump components must be designedto withstand drastic changes in temperature. After the pump is made up, it is lowered into the depthsof the wellbore, taking it from subfreezing surface temperatures to the extreme heat imposed by thegeothermal gradient.

Winter 2006/2007 33

By eliminating sensitive and critical assemblyoperations required during conventional ESPinstallations, Maximus technology reducesexposure to potential environmental problemsand human errors. In applications where early,short-run pump failures are often attributed toinstallation problems or human error, MaximusESP systems have demonstrated a significantreduction in operational and equipmentproblems, especially short-run failures.3

Another problem that shortens the life of ESPmotors and protectors is caused by wear on theradial bearings. These bearings become worn asthe ESP motor oil degrades over time. To extendthe life of Maximus ESPs, all radial bearings havehardened shaft sleeves that run in self-lubricating bushings.

Vibration also plays a significant role inreducing pump life. When the motor shaftvibrates, it increases wear on the seals aroundthe shaft, eventually permitting fluids producedfrom the well to leak into the protector. From theprotector, wellbore fluids can seep past the shaftseals and into the motor itself, where theycontaminate the motor oil and change its dielec -tric, hydraulic and lubricating properties,ultimately causing failure of the pump motor. Theprotector-head bearing, which is affected byvibration from the pump intake and abrasives inthe produced fluid, uses an abrasion-resistantzirconia bearing.

Oil companies can guard against pumpvibration damage by monitoring ESP perfor -mance indicators and changing ESP motor speed.Maximus motors offer a gauge-ready base thatallows direct connection of the Phoenix artificiallift downhole-monitoring system so that operatorscan track ESP and reservoir performance.

Downhole Monitoring By monitoring ESP performance, operators canrecognize problems as they develop. In manycases, pump performance declines gradually,leaving operators with time to proactivelyintervene if they are aware of the problem.Phoenix sensors provide a steady stream of real-time pump measurements. By tracking downholepump characteristics, operators can recognizedeviations from established trends and then takeaction to extend pump life and improve produc -tion. These pump measurements are alsoimportant for evaluating reservoir behavior,providing valuable information used in pressure-transient analysis, inflow-performance monitor -ing and productivity trending.4

Phoenix sensors provide a variety ofdownhole measurements and response options.Sensors include the following:• Current-leakage sensor: protects the electrical

system from excessive pump heat, breakdownof electrical motor winding insulation andphase-to-ground insulation loss.

• Discharge-pressure sensor: protects the pumpfrom high pressure caused by closed-valveshut-ins and heavy fluid slugs.

• Intake-pressure sensor: protects the pumpfrom low pressure caused by low fluid level,pumpoff caused by blocked intakes, and gas locking.

• Intake-temperature sensor: protects the pumpfrom overheating caused by high-temperatureintake recirculation and elevated production-fluid temperature.

• Motor-oil or winding-temperature sensor: pro-tects the motor from high temperature causedby low-flow conditions, high motor load andpoor cooling due to scale buildup.

• Motor- and pump-vibration sensor: protects the pump from vibration and mechanical damagecaused by extensive solids production andexcessive mechanical wear.

Each of these measured parameters can beprogrammed to trip an electrical switch at agiven threshold, immediately shutting down themotor to protect it from further damage. In manyinstallations, the operator can remotely adjustpump parameters to correct a problem. Thus, ifan alarm is tripped, the operator may be able totransmit adjustments to pump speed to reducevibration, or increase pump speed to move morecooling fluid past the motor, or apply back -pressure to move solids out of the system.

2. Dielectric oil is an insulating oil used in electricalequipment. A poor conductor of electricity while beingan efficient supporter of electrostatic fields, dielectric oil resists breakdown under high voltages and is used in ESPs to protect electrical components from corrosiveelements in the wellbore.

3. ESP short-runs are failures that occur within the first90 days of operation.

4. For more on downhole monitoring technology: Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,Cosad C, Fitzgerald J, Ingham J, Navarro J, Gabb A,Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.

> Assembly in a controlled environment. Modular bolt-on componentsallow critical assembly procedures to be carried out at the shop,rather than the wellsite. Personal protective equipment shown isaccording to local risk-based plan and Schlumberger standard; glovesare not used in this process to avoid contamination by cotton fibers.

Surface ControlsESPs are driven by induction three-phase elec -trical motors, powered by a surface electricalsupply. This power supply can be regulated to fine-tune pump performance as reservoir condi-tions change. By matching pump performance tochanging well conditions, operators can improveESP system efficiency and run life.

The SpeedStar variable speed drive is asurface control unit that allows operators toremotely adjust the electrical power sentdownhole (right). This variable-speed drive(VSD) is an electronic device that synthesizes athree-phase variable-voltage, variable-frequencypower supply for induction motors. Its outputfilter produces a nearly sinusoidal output voltageand current that prevent pump vibration andincrease motor efficiency. It is also equippedwith a transient-voltage surge suppressor toprotect against electrical utility-fed power surgesor lightning strikes on the system.

The SpeedStar VSD lets the operator controlESP motor speed and performance by adjustingfrequency, which thereby adjusts voltage,transmitted to the motor.5 The VSD providesconstant torque through the entire speed range,enabling the ESP to produce a wider range of fluidvolumes than would be possible at a fixed motorspeed. As well conditions change, the capability tomake fine adjustments to motor speed and torquecan forestall the need to resize the pump,reducing downtime and production costs.

In some wells, operators can change themotor operating frequency in one-hertz incre -ments to reduce pump vibration. By varyingpump speed in a new or reworked well, a VSD canhelp determine the optimal flow rate of the well to avoid pumpoff and cycling problems. Toprovide a soft start during critical startupoperations, the VSD is used to reduce voltage tothe motor and ease strain that would otherwiseresult from starting the motor under full load at full speed. These measures help to extendpump life, especially in wells that are prone tofrequent shutdowns.6

Expanding the Realm of Applications A prime example of an ESP application thatpushes the boundaries of traditional installationsis the REDA Hotline high-temperature electricalsubmersible pump system. This ESP system wasdesigned for wells with high bottomholetemperatures (BHTs), or wells with high oil cut,low fluid velocity and emulsified or gaseousfluids. These conditions are hard on systemcomponents, which rely on produced fluidsflowing past the ESP to carry off heat generatedby the motor.

Insufficient cooling adversely affects the oilinside the motor and invariably leads to mal -functions and premature failures of the system.While temperature ratings of standard ESPstrings have climbed from 250°F [121°C] to400°F [204°C], key components of the originalHotline system, especially its motor, powercables, pump and oil-filled motor protector

are rated to 475°F [246°C]. This system hasdemonstrated substantial increases of run lifewhen compared with conventional ESPs in high-temperature applications.

The need for high-temperature ESP systemsis growing as the oil industry matures (nextpage). With most of the world’s oil resourcesconcentrated in heavy and extra-heavy oil andbitumen, oil companies are searching for ways toprofitably extract these viscous reserves.7 Someare turning to steam-assisted gravity drainage(SAGD) wells. The SAGD approach utilizes a pairof horizontal wells drilled parallel to each other,and separated vertically by a distance of about5 m [16 ft]. Steam injected through the upper -most well penetrates the surrounding formation,heating the heavy-oil sands and creating a high-temperature region above the injector known asa steam chamber. Heat transferred to the oilsand reduces its oil and bitumen viscosity.

34 Oilfield Review

5. In these ESP systems, frequency is directly proportionalto speed. By changing frequency, the operator alsochanges pump speed.

6. Bates R, Cosad C, Fielder L, Kosmala A, Hudson S,Romero G and Shanmugam V: “Taking the Pulse ofProducing Wells—ESP Surveillance,” Oilfield Review 16,no. 2 (Summer 2004): 16–25.

7. For more on heavy-oil extraction: Alboudwarej H, Felix J,Taylor S, Badry R, Bremner C, Brough B, Skeates C,Baker A, Palmer D, Pattison K, Beshry M, Krawchuk P,Brown G, Calvo R, Cañas Triana JA, Hathcock R,

Koerner K, Hughes T, Kundu D, López de Cárdenas J and West C: “Highlighting Heavy Oil,” Oilfield Review 18,no. 2 (Summer 2006): 34–53.

8. The SOR is a measure of the volume of steam required to produce one unit volume of oil. In SAGD wells, typicalSOR values range from 2 to 5. The lower the SOR, themore efficiently the steam is utilized. Efficiency impactsthe economics of the project because of fuel costsrequired to generate the steam.

9. Solanki S, Karpuk B, Bowman R and Rowatt D: “SteamAssisted Gravity Drainage with Electric SubmersiblePumping Systems,” presented at the 2005 SPE GulfCoast Section Electrical Submersible Pump Workshop,The Woodlands, Texas, April 27–29, 2005.

10. For more on developing remote fields: Amin A, Riding M,Shepler R, Smedstad E and Ratulowski J: “SubseaDevelopment from Pore to Process,” Oilfield Review 17,no. 1 (Spring 2005): 4–17.

> Variable-speed drives (VSDs). These surface units regulate and condition electrical current forfive wells in Canada. Using electricity generated by the local electric utility or from dedicatedgenerating stations, the VSD transmits power downhole to the ESP. The VSD is key to remotelycontrolling pump performance.

Winter 2006/2007 35

Gravity forces the oil, bitumen and condensedsteam downward, where these fluids, consistingof about 25% to 40% water, are produced into thelower well.

Initially, gas lift was used to pump the fluidsto surface in these high-temperature wells (see“The Pressure’s On: Innovations in Gas Lift,”page 44). With advances in ESP technology, manyoperators are replacing their gas lift systemswith ESPs. The shift toward ESPs promptedfurther modifications to the Hotline system. Thisled to development of the Hotline 550 ESPsystem, which was built to serve in high-temperature wells produced by steamflood. Inlight of the fact that ESPs were formerlyconstrained by operating temperature, their usein SAGD wells may be considered revolutionary.

The Hotline 550 design accounts for variableexpansion and contraction rates of differentmaterials used in the pump, and components arerated for internal operating temperatures of550°F [288°C]. The operating temperaturerepresents the internal temperature of thesystem components, which is generally higherthan the temperature of the produced fluids,owing to heat generated through mechanical andelectrical losses at the pump, motor, intake andprotector. Like other ESP designs, heat in thispump is carried off by produced fluids.

The Hotline 550 pump motor is protected by aspecial metal bellows system and shaft-sealmechanism that create a barrier between hotwell fluids and internal motor oil—featuresnever used in previous ESPs. The metal bellows

compensate for expansion of the oil inside thepump motor. Other ESP designs—which rely onelastomer bag- or labyrinth-type protectors—canleak, allowing produced wellbore fluids to seepinto the motor and contaminate the oil containedinside (see “ESP Protectors,” next page).

Other components, such as the power cable,bearings, shaft seals, winding insulation andmotor oil, have been redesigned or constructedfrom special materials to withstand hightemperatures and improve system reliability.

The Hotline system has been used extensivelyin Canada. In three fields in western Canada,EnCana Oil & Gas Partnership uses SAGDtechnology to recover 10.5° to 13°API bitumen andheavy oil. Wells in the Foster Creek, Christina Lakeand Senlac fields produce from unconsolidatedsands and have bottomhole pressures of 2 to 3 MPa [290 to 435 psi] and bottomhole producingtemperatures of 180°C to 209°C [356°F to 408°F].In 2002, EnCana began testing ESP systems as analternative to gas lift methods.

In SAGD wells, economics are greatlyimpacted by the cost of steam generation andrecovery. Steam accounts for 35% to 55% of thetotal extraction cost, which can reach severalmillion dollars yearly for each well. These costsare proportional to the operating steam/oil ratio(SOR), so SAGD operators try to optimizereservoir pressure to achieve low SOR and highproduction rates.8

Lower SORs can be achieved by lowering theformation pressure in a reservoir. Low reservoirpressure enables the steam to carry higher latent

heat into the formation where the heat canmobilize the oil. However, reducing reservoirpressure can also reduce the efficiency of gas liftto an extent that makes gas lift impractical. Atlower pressures, pumps must be used to lift thefluids to surface.

EnCana successfully field-tested HotlineESPs in two wells in Foster Creek field, achieving645 days and 309 days of run life, respectively.9

Temperatures of 209°C and numerous shutdownsdemonstrated that Hotline systems could handleupsets and thermal cycling. Following these fieldtests, EnCana replaced gas lift systems withHotline 550 ESPs in 11 wells in Foster Creekfield, three wells at Senlac field and one atChristina Lake field. The company also choseHotline ESPs for initial installation in five wellsat Foster Creek field and three wells at Senlac field.

Following a reduction in reservoir pressurebelow levels required for gas lift, the operator’sproduction data showed that SOR decreased byapproximately 20%. This enabled EnCana totransfer steam to newer wells and improveoverall production in their fields. Across Canada,Schlumberger has installed over 60 Hotline ESPsystems in SAGD wells, and all are operating atBHTs in excess of 204°C [400°F]. The longest-running Hotline unit, installed in February 2004,is still running as of January 2007, in excess of1,070 days; the longest-running Hotline 550 pump was installed in June 2004, and hascontinued to run more than 940 days.

Subsea Applications With improvements in reliability, ESPs aremaking significant contributions to production inoffshore fields. Some of these offshore fields areincapable of supporting their own dedicatedproduction infrastructure because of meagerreserves or remote locations. To be developed,such reservoirs must be tied back to existinginfrastructure.10 ESPs are playing an importantrole in recovering these stranded reserves.

Following the 1973 discovery of Gannet fieldin the UK North Sea, several satellite reservoirswere tied to the Gannet facility by Shell Expro,UK, operator of this joint venture between ShellUK Ltd. and Esso Exploration & Production UKLtd. The field lies 180 km [112 mi] east ofAberdeen, in 95 m [311 ft] of water. Subseasatellites produce the Gannet B, C, D, E, F and Greservoirs from turbidite sands of Tertiary age,

> ESP temperature-rating time line. New ESP applications are gradually pushing the temperatureenvelope. Temperature ratings have steadily climbed since the 1950s, with significant gains achievedsince the early 1990s.

Circa1950

250°F121°C

Circa1960

300°F149°C

Circa1980

350°F177°C

Circa1990

475°F246°C

Era

Temperaturerating

Circa2000

550°F288°C

36 Oilfield Review

In an ESP string, the protector lies betweenthe pump and motor. It has numerousfunctions:• Carrying upthrust or downthrust developed

by the pump: These forces are distributedover the large area of the protector thrustbearing. The bearings must therefore berated higher than the maximum thrust thatthe pump will generate.

• Coupling torque developed by the motor to the pump: The protector shaft must becapable of delivering full torque withoutexceeding its yield strength, which couldresult in a broken shaft.

• Keeping well fluids out of the motor: Theprotector transfers pressure between themotor oil and the produced fluid in theannulus without allowing any mixture of the two fluids.

• Providing a reservoir of fluid to accommo-date thermal expansion of motor oil: Pumpinstallation subjects an ESP to increases intemperature between surface and settingdepth. During operation, internal heatingraises the temperature even further. Thetemperature increases cause the dielectricmotor oil to expand. The protectoraccommodates this expansion, allowing the excess expanded volume of oil to movefrom the motor to the protector, displacingan equal amount of wellbore fluid from theprotector and into the wellbore. When amotor shuts down, the motor oil contractsas the motor cools, and the protectorprovides a reservoir of clean motor oil toflow back into the motor while keeping thewellbore fluids separated. If the motor wereto shut down without benefit of a protector,the motor oil would contract as the motorcools, creating a vacuum that would then befilled with wellbore fluids. Protectors generally fall into three

categories: the labyrinth, the bag and thebellows designs (above right). The labyrinthdesign uses the difference in the specificgravity of the well fluid and the motor oil to

keep them separate, even though they are indirect contact. For this design to work, thewell fluid has to be heavier than the motoroil, and the unit must be installed verticallyor nearly vertical in the well. In wells withhigh gas/oil ratios, the specific gravity of wellfluid may be lower than that of the motor oil.

In deviated wells, the bag-type protectormay be more suitable. This design uses ahigh-temperature, high-performanceelastomer bag to separate the well fluids onthe outside from the clean motor oil inside.The bag flexes to accommodate thermalvolume changes in motor oil. However, it israted to only 400°F, and as with all elastomerseals, the bag is susceptible to abrasives andcan be breached if exposed downhole tochemically incompatible liquids or gases suchas hydrogen sulfide [H2S]. Exposure to

elevated temperatures can also harden thebag and seals, causing a loss in elasticity thatis eventually followed by failure.

The elastomer bag and labyrinth protectorsusually perform adequately in the downholeconditions for which they are rated. Thebellows-type protector is better suited forhostile downhole conditions, where protectorsare subjected to high temperatures, abrasives,harsh well-treatment chemicals, carbon dioxide[CO2] or H2S. It is filled with an oil that retainsviscosity at high temperatures and uses a metalbellows to accommodate thermal expansionand contraction of the oil. Using materialsselected to minimize thermal stresses, it israted up to 475°F internal oil temperature. The bellows are also rated for 30% H2Sconcentration, depending on temperature.

ESP Protectors

< Evolving protectordesign. ESP protectorsare critical for preserv-ing the integrity of thepump’s electric motor.Positive-seal elastomerbags are used in manyapplications, but do nothave sufficient tensilestrength or temperaturetolerance for SAGDwells. Labyrinth-styleprotectors use a tortuouspath to limit wellborefluid entry, but are notsuited for horizontalinstallations typical ofSAGD wells. The posi-tive-pressure, metalbellows allows for pres-sure equalization andexpansion of the dielec-tric oil in the motor.

Motoroil

Wellfluid

BellowsElastomer bag Labyrinth

Winter 2006/2007 37

found at depths ranging from 1,768 m to 2,728 m[5,800 ft to 8,950 ft]. These satellites are tiedback to the centrally located Gannet Aproduction platform (above).

The Gannet E field uses ESPs to produce oiland gas to the Gannet A platform.11 This field lies14 km [8.7 mi] away from the Gannet A platform.Discovered in 1982, it was originally designatedas the Guillemot C field, slated for developmentfrom the Guillemot complex. When the GuillemotA reservoir was later integrated into the develop -ment plan of a nearby field, Guillemot C and Dreservoirs became stranded. In 1994, productionfrom these fields was relegated to the Gannetplatform and they were renamed Gannet E and F, respectively.

Gannet E field produces a thick, 20°APIheavy crude with a reservoir viscosity of 17 cP[0.017 Pa.s] and a gas/oil ratio of 110 ft3/bbl[19.8 m3/m3]. Initial reserves were estimated at132 million barrels stock tank oil in place[20 million m3], with a recovery factor of 43%.The field was developed in two phases. At peakproduction, the field produced at a rate of14,000 bbl/d [2,225 m3/d]. The transport andhandling characteristics of this heavy andviscous crude, combined with low reservoirpressure, made artificial lift necessary forstarting the well and producing its fluids back tothe Gannet A platform.

11. MacFarlane JS: “Gannet E: The World’s Longest Subsea ESP Tie-Back,” paper SPE 38534, presented at the SPE Offshore Europe Conference, Aberdeen,September 9–12, 1997.

12. Harris G, Lowe P and Holweg P: “Technical Challengesand Solutions for Subsea ESPs in the North Sea: TwoWells Tied Back 15 km to the Shell Gannet Platform with Flow Commingled into a Single Flowline,” paperpresented at the SPE Gulf Coast Section’s 19th AnnualESP Workshop, Houston, April 25–27, 2001.

> Gannet field layout. Two wells from the subsea Gannet E field are produced by ESPs. Heavy oil produced fromeach well is commingled, and production from this field is tied back to the Gannet A platform. Power suppliedthrough variable-speed drives on the Gannet A platform is transmitted via underwater electrical umbilicals to thesubsea ESPs. (Adapted from Harris et al, reference 12.)

ESP packer with cable and chemical line feed-through

Y-tool assembly

ESP pumps

Sand screen

Perforated joints

Bypass tubing

Demulsifier injectionline

Permanent downholegauge

Gannet E2

Gannet E1 Gannet F

Gannet C

Gannet B

Gannet Aplatform

Gannet D

Export line

p

Ganne

p

GanneGannGannGanGanGaGaG

ESPs were preferred over other methods ofartificial lift because they could produce athigher volumes and handle fluids better thanother systems. However, the operator wasconcerned that short run-life problems commonto many ESPs would adversely affect projecteconomics. Shell Expro wanted an ESP thatcould run two years before replacement. Testingwas conducted to evaluate the subsea cableneeded to conduct electrical power to the ESP,resulting in the development of a simulation toolto predict system stability over various lengths ofcable (see “ESP Power Modeling for ImprovedRun Life,” next page). The operator also wanteda pump capable of handling reservoir and fluidchanges that could occur over the service life ofthe pump. After a fluid sample was obtainedduring Phase 1, with the drilling of a 2,800-ft[853-m] horizontal well, a production test wascarried out and the pump design was finalized.

The first Gannet E well was completed with aprepacked screen and an ESP, becoming the firstsubsea development on the UK continental shelfof the North Sea to use ESP technology, and atthe same time setting a record for the longestsubsea tieback of an ESP.12 The pump wassuspended from a “Y” tool that would allow awireline bypass for setting a plug below the pumpin the event the pump needed to be removed. A

Phoenix downhole gauge was used to monitorpump-inlet conditions. These conditions aremonitored on the platform, and data aretransmitted to Shell in Aberdeen and toSchlumberger in Inverurie, Scotland. Thisarrangement allows ESP specialists to monitorpump performance in real time, and to requestchanges in pump settings in response tochanging conditions downhole.

First oil was produced from the Phase 1 wellin January 1998. The ESP operated for 17 monthsbefore a workover was required due to problemsbetween the tail pipe and polished borereceptacle. The flow rate was 19,000 bbl/d[3,019 m3/d] with 900 hp required for the pump.

Experience gained from installation,operation and workover of the first well wasincorporated into planning and execution of thenext well, which was drilled and completed in

(continued on page 40)

In an effort to improve run life, SchlumbergerESP engineers have developed an electrical-simulation model to evaluate electricalfailures under a variety of downholeconditions. The model was tested in a well byspecialists from the Schlumberger Assembly,Repair and Test (ART) Center in Inverurie,Scotland, where almost 20 km [12 mi] ofcable was connected between a surfacevariable-speed drive (VSD) and a downholeESP motor.

This model showed that a common mode of failure among ESP motors is the electricalshort, a condition often caused by breakdown of insulation around wiring used in electricalmotor windings, cables and penetrators. Suchinsulation breakdown can occur throughseveral different mechanisms:• Contamination of the pump’s insulating

motor oil by fluids produced from thewellbore

• High motor temperature, a function ofambient temperature, motor load, fluidcomposition and fluid velocity past themotor

• Voltage stress caused by harmonics in theelectrical power transmitted between the VSD and the ESP. Electricity flows insinusoidal waves as it is transmitted alongthe length of electric cable. These wavescan be reflected as they travel back andforth along the cable, moving from the VSDto the ESP and back again to the VSD. Likeocean waves, the sinusoidal electrical wavescan build upon each other to createamplified waves that exceed the electricalrating of the downhole motor, cable orpenetrator. Such amplified waves can easilypeak in excess of three times the ratedvoltage output of the VSD. This amplifiedvoltage can degrade insulation that coversthe electrical wiring used in the ESP,eventually causing a short in the system.

Contamination by produced fluids and highmotor temperatures are problems that can be resolved by selecting the correct type ofprotector, or by changing the load on the lineand the motor. However, the problem ofharmonics requires a thorough understanding of the downhole system. Every VSD producessome degree of output harmonics, and thelength of most ESP power cables exacerbatesthis problem. The magnitude of outputharmonics depends on the entire electricalsystem: the ESP motor, the downhole cable and the wellhead penetrator; in subsea wells,the wet-mate connection, submarine cableand transformers are also involved. If onecomponent in this system is changed, thenthe harmonics will change as well.

Based on testing of ESP systemcomponents, Schlumberger engineers inInverurie developed a model to calculateperformance of an ESP electrical circuit.Working closely with their colleagues inInverurie, power-system engineers at theSchlumberger Edmonton Product Center(EPC) in Alberta, Canada, developedmodeling software that can display overallharmonics for both current and voltage,creating a harmonics signature for the entiresystem (next page). The particular ESPapplication and operating conditions willaffect the level of harmonics permissible forthat specific system. Sensitivities to changingcomponents can also be simulated in themodel, with the model predictingconsequences of corrective action, such asadding electrical filters, varying the carrierfrequency of the VSD or changing the type ofVSD used.

Another important reason for modeling theESP electrical system is to determine theamount of power required to start the ESPmotor, along with any limitations inherent inthe system. ESP startup can be jeopardized byinsufficient power to the motor. Because most

wells require several thousand feet of powercable to transmit power from the surface VSDto the downhole ESP, they typicallyexperience a large voltage drop across thelength of cable. The effects of this voltagedrop must therefore be factored into thedesign and operation of the ESP system.

Power-system engineers at the EPC haveused the same modeling software to simulateESP motor startups. This simulation packagehelps EPC engineers to determine the voltagedrop across the cable. Then they cancalculate the required motor terminal voltageand compare it with the voltage limit of thesystem to achieve a successful motor start.The starting frequency of the drive andvoltage boost settings can also be determined.This simulation helps ESP specialists toevaluate the capacity of the VSD and determinewhether it is large enough to support, not justthe routine pumping operations, but also thesystem startup.

ESP Power Modeling for Improved Run Life

38 Oilfield Review

Winter 2006/2007 39

> Voltage, current and harmonics. Simulation software charts typical output voltage and current waveforms of adownhole motor to show the effects of noise spikes superimposed on the waveform as a result of transient voltageharmonics (top). Peak harmonics levels are present at approximately 2.2 kHz and multiples thereof; thus they are seen at4.4, 6.6 and 8.8 kHz as well. These peaks coincide with the carrier frequency of the variable-speed drive. Followinganalysis by EPC personnel, a load filter was recommended to save the system from potential damage caused byharmonics. After a load filter was applied, most of the noise was removed, producing a much smoother sine waveaccompanied by a significant reduction in harmonics (bottom).

0

12,000

–12,00020 40

Time, ms60 80 1000

Volts

1,500

3,000

02 4

Frequency, kHz6 8 100

Volts

0

250

–25020 40

Time, ms60 80 1000

Ampe

res

0

12,000

–12,00020 40

Time, ms60 80 1000

Volts

0

250

–25020 40

Time, ms60 800

Ampe

res

100

1,500

3,000

02 4

Frequency, kHz6 8 100

Volts

Voltage Waveform at Motor

Without Filtering

With Filtering

Current Waveform at Motor

Voltage Harmonics Root-Mean Sum

Voltage Waveform at Motor

Current Waveform at Motor

Voltage Harmonics Root-Mean Sum

Phase 2 of the development. The second welldesign closely mirrored the original, and the wellwas completed in January 2001. Flow from bothwells was commingled into a single flowlinethrough a subsea manifold, producing30,000 bbl/d [4,767 m3/d]. ESPs in this fieldaverage 2.3 years of run life, with the longest runlife being 1,390 days.

Experience from this record-setting ESPtieback will help Shell Expro to expandopportunities for long-distance pumping fromremote fields to existing infrastructure in theNorth Sea and elsewhere. This knowledge willhelp to extend the life of existing facilities andinfluence strategies for producing a number ofreservoirs previously deemed uneconomical.

Improving Well Performance Pump and reservoir performance invariablychange over the years. Upon installation of an ESP,critical parameters such as pump speed orelectric-power frequency (Hz) are set to optimizepump performance under the reservoir conditionsthat exist at the time. However, over time, the gas-or water cut may increase, reservoir pressure maydecline, or other conditions may change, thuscausing the lifting system to operate inefficiently.Not only will these factors adversely impact pumpperformance, some of these changes may actuallydamage ESPs.

Therefore, as a reservoir is produced, pumpsettings should be monitored and adjusted toensure that the lifting system is operating asefficiently as possible. Most operators strive tomonitor their pumps, as evidenced by stacks ofpump and production records that can quicklyoverwhelm a desktop. Sometimes these data canoverwhelm the operator as well. Most operatorsdon’t have time or resources to keep watch onthe pump activity of every well in their fields.

From an operator’s perspective, the goal maynot be to constantly monitor all pumps, butrather to determine what their optimal settingsare, which settings to change, and when tochange them. This is where the advanced ESP

lifting services provided by the SchlumbergerProduction Center of Excellence (PCoE) canhelp operators improve efficiency in the pumpand the field. PCoE surveillance and diagnosticengineers evaluate the entire ESP system tooptimize production. Every component of thelifting system can be fine-tuned, from the pumpto the wellbore and out to the reservoir.

The espWatcher surveillance and controlsystem for electrical submersible pumpsprovides valuable information used by ESP andreservoir-diagnostics experts at the PCoE. Basedon the data transmitted from the well, theseexperts make recommendations that can helpoperators boost production. The espWatchersoftware has the ability to monitor pump andwell performance once every minute, 24 hours aday.13 Just as important, its algorithms allow it tofilter and prioritize the pump data it receives.Using this information, it can rate the status ofeach well as either green, yellow or red,depending on whether a well is operating withina specified performance range, operating outsideof the range, or is shut down.

This Web-based system helps operators andthe PCoE staff to remotely monitor the status of wells (above). When this semi-automatedsurveillance system detects parameters that fall

40 Oilfield Review

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> Remotely monitoring field performance. Secure Web access to the espWatcher system allowsclients and PCoE engineers to monitor the status of a pump or field at any time. The espWatchersystem can monitor numerous parameters on each particular pump (left). The map display on theWeb interface (right) uses a color-coded system to quickly identify problem wells in a field. Greenindicates wells that are operating within acceptable limits. Yellow shows wells that are still operating,but with some particular measurement that has deviated from acceptable limits. Red indicates wellsthat are shut down. ESP and reservoir engineers will usually concentrate on the yellow indicators.

Oil gravity15°API

Flow rate2,199 bbl/d

Total GOR600 ft3/bbl

Casing pressure100 psi

Free gas at intake0%

Pump flow rate2313.43 bbl/d

Operating frequency45 Hz

BHFP760 psi

Productivity index3.5 bbl/d/psi

Oil rate1,320 bbl/d

Water rate879 bbl/d 2,200 bbl/d

Motor temperature167°F

Water cut40%

Wellhead pressure165 psi

Wellhead temperature120°F

Water density1.02

Discharge pressure1,400 psi

Intake pressure525 psi

Discharge temperature175°F

Intake temperature165°F

Motor current39.5 A

Motor volts2,305 V

Motor vibration0.05 gn

Reservoirpressure

1,350 psi

Reservoirtemperature

Total rate

170°F

Winter 2006/2007 41

outside of the range specified by the operator, itsets off a yellow alarm. This alerts the PCoE staffto take a closer look at that particular well andallows personnel to focus more attention onthose wells that are not performing optimally.

Instrumented wells are capable of producingconstant streams of real-time data from down -hole sensors and surface monitors. Much of thedata are routine, and provide valuable trendinginformation. Other data are exceptional, andpoint to immediate changes in parameters thatwarrant closer scrutiny. And some data, thoughtransient, provide valuable snapshots of reservoir behavior.

Transient data are produced when pumps shutdown or start up again. These fairly normaloccurrences take place because of pump cycling,well workover or interruptions to the electricalsupply caused by blackouts, brownouts or lightningstrikes. Pressure measurements obtained duringthese transient events can provide useful

information about reservoir behavior.14 Though thepump isn’t running, its sensors may still berecording the ensuing changes in the reservoir.Upon shutdown of a pump, the reservoir pressureincreases, providing timely data that can beanalyzed for reservoir evaluation. When the pumpstarts up again, the sensors obtain drawdowninformation on the reservoir. Transient-pressureanalysis techniques are used to interpret thisbuildup or drawdown data and thereby determinethe ability of the reservoir to produce fluid. Thisanalysis provides information for ascertainingwhat, if anything, can be done to improve thereservoir’s producibility. Additional details aboutthe reservoir’s outer boundary conditions can alsobe obtained from these data, indicating thepresence of sealing faults, interference from offsetproduction or constant pressure boundaries frompressure injection.

Based on PCoE experience, 57% of ESP wellscan benefit from optimization of the liftingsystem, making relatively simple adjustments,such as increasing the speed of the pump tolower intake pressure and increase production.And 50% of wells can benefit from optimizing the reservoir through stimulation to reduce

skin damage or through reperforating. Theseresponses to pump and reservoir behavior canhave an immense impact on well performance;according to results obtained by the PCoE, thesechanges can increase production by nearly 20%.

PCoE remediation recommendations includepredictions regarding how much production willbe increased. These predictions help operatorsevaluate the risk versus reward associated withacting on PCoE recommendations. The predic -tion also helps the PCoE track its own perfor -mance, and aids PCoE management indetermining whether the remedial action waseffective, and if not, what can be done to furtheroptimize the well’s performance (above).

A major challenge for the PCoE is helpingoperators recognize the benefits of remediation inwells that, in some cases, produce only 2 to 8% oil.For example, when the espWatcher softwarealerted the PCoE to increasing intake pressure ina well in Oklahoma, PCoE surveillance personnelinvestigated the problem and alerted the client.Seeing that the well was producing at bottom holepressures of 300 to 400 psi [2.07 to 2.76 MPa], theyrecognized the potential for higher production

13. Bates et al, reference 6.14. For more on using transient data to model changing

reservoir conditions: Corbett C: “Advances in Real-TimeSimulation,” The Leading Edge 23, no. 8 (August 2004):802–803, 807. Also refer to: Bradford RN, Parker M,Corbett C, Proan̆o E, Heim RN, Sonleitner C andPaddock D: “Construction of Geologic Models forAnalysis of Real-Time Incidental Transients in a Full-Field Simulation Model,” presented at the AAPG International Conference and Exhibition, Cancun, Mexico, October 26, 2004.

> Tracking well problems. The evaluation table for a field in Oklahoma shows arange of diagnostics and remedial actions that could improve production orreduce operating expenses. Note that most of the wells in this field requireonly minor adjustments to increase output. By addressing only those wells thatrequire changes of electrical power and pump speed, the operator could boostfield production by several hundred barrels.

WellNumber Diagnostics Suggested Remediation Potential Production

Increase, bbl/d

Well 1

Well 2

Well 3

Well 4

Well 5

Well 6

Well 7

Well 8

Well 9

Well 10

Well 11

Well 12

Well 13

Well 14

Well 15

Within safe range, to the far right

Within safe range, to the left

Within safe range, to the left

Within safe range, to the left

Within safe range, to the left

Far to the left of the safe operating range

Within safe range, to the left

Within safe range, to the right

Within safe range, to the left

Far to the left of the safe operating range

Within safe range, in the middle

Within safe range, to the right

Within safe range, in the middle

Within safe range, to the left

Within safe range, in the middle

Increase Hz from 58 to 59, reduce wellhead pressure (WHP) from 185 to 100 psi

Increase frequency from 50 to 55 Hz

Increase frequency from 50 to 52 Hz

Reduce WHP from 130 to 100 psi

Based on inflow performance relationship (IPR) curve, production potential exists

Downsize pump

Increase frequency and decrease WHP from 270 to 150 psi

Reduce WHP from 213 to 100 psi and place on variable-speed drive; 50 to 59 Hz

Reduce WHP from 156 to 100 psi

Increase frequency from 45 to 48.5 Hz, downsize pump to get operations in a safe range

Place on variable-speed drive, reduce WHP and upsize pump

Increase frequency from 50 to 58 Hz

Increase frequency from 53 to 58.5 Hz

n/a

n/a

44; but 500 after installing a larger pump

250

75

12

740

Save between $1,100 and $1,900 a month in electricity

410

130

12

40

570; but 1,260 after installing a larger pump

90

210

0

0

rates, and suggested an increase in pump speed todraw down the intake pressure and produce morefluids. PCoE engineers recommended a 1-Hz boostin electric frequency to the pump. Although thisincrease resulted in a lower intake pressure, italso resulted in an unexpected decrease inproduction rate (below).

This prompted PCoE personnel to examinethe efficiency of the pump by scrutinizing thepump performance curves, which are generatedindividually for each pump that is installed in

the field (bottom). These curves chart therelationship between pump horsepower, effi -ciency, flow rate and head, relative to the pump’soptimal operating range.15 Since the pump wasalready performing optimally, PCoE expertsrecommended that the operator acquirepressure-buildup data (next page, top). From thebuildup analysis, PCoE reservoir engineersextrapolated reservoir pressure and calculatedan average permeability of 60 mD and a skinfactor of 4.16

Recognizing that skin damage, with its near-wellbore pressure drop and reduced permea -bility, was the problem, PCoE reservoir engineerssought to quantify the impact of increased skinfactor on production. The engineers firstmodeled the relationship between downholepressure and flow rate. Using this model, theywere able to project how production wouldimprove if the skin damage were removed (nextpage, bottom). Their model showed a potentialproduction increase, so the operator pulled thepump, acidized the well, and replaced the pump.From this remediation, the operator increasedfluid production by approximately 350 bbl/d[56 m3], from which an additional 2,550 barrels[405 m3] of oil per year were extracted.

In addition to looking for ways to improveproduction, PCoE engineers seek to extend pumplife and reduce downtime. PCoE engineersevaluate performance data to anticipate problemsthat might shorten run life, and recommendintervention as early as possible to delay onset ofpump failure. Sometimes the challenge is to strikea balance between increased run life andincreased production. The two are not alwayscompatible, and operators must choose whichcourse of action to pursue, depending on thefield’s production economics.

Using PCoE lifting-system diagnosticprograms, ESP specialists can track pumpefficiency and its degradation over time. Thistracking is useful in predicting when the pumpswill eventually fail. By analyzing individual pumpperformance and anticipating failures, PCoEengineers can notify the operator in time toevaluate the well and make the best decision forthe company. In many cases, ESPs are run untilthey fail, at which point the operator replacesthem. In other cases, economics dictate earlyintervention and replacement before failure,thus lessening the impact of reduced production.Tracking pump degradation also lets PCoEengineers monitor declining production, whichhelps operators decide when it would be mosteconomical to intervene proactively. At the veryleast, timely notification by the PCoE enablesoperators to minimize downtime by orderingreplacement pumps and scheduling workoverrigs in advance.

42 Oilfield Review

> Pump operating curves. Pump curves are custom-generated for each pump to chart the pump’sability to displace fluids. Head capacity (blue curve), pump efficiency (green dashed curve) and brake horsepower (red dotted curve) are plotted against flow rate. The most important part of thisperformance graph is the head-capacity curve, which charts the relationship between total dynamichead and flow capacity of a specific pump. A pump can develop only a certain amount of head for agiven flow rate, and vice-versa. The yellow area on the pump curve indicates the most efficientoperating range for this specific pump. In this case, the operating point (red dot) shows that, at 60 Hz ,this 185-stage pump is operating within the optimum range.

00 200 400 600 800 1,000

Flow rate, bbl/d1,200 1,400 1,600 1,800

600

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, ft

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p ef

ficie

ncy,

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epow

er, h

p

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Actual Pump PerformanceREDA 44 Series–185 Stages

3,396.33 rpm at 60 Hz

Pump efficiency

Horsepower

> High intake pressure. A reduction in intake pressure failed to increase production as originally expected.

0

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1,1001,1251,1501,1751,2001,2251,2501,2751,3001,3251,3501,375

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e fre

quen

cy, H

z

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ke p

ress

ure,

psi

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4/06

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9/06

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3/06

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2/06

08/2

7/06

09/1

1/06

09/2

6/06

10/1

1/06

10/2

6/06

11/1

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5/06

12/1

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5/06

01/0

9/07

01/2

4/07

Liqu

id fl

ow ra

te, b

bl/d

Liquid flow rateDrive frequencyIntake pressure

Frequency increase

15. Head, often used interchangeably with pressure, isgenerally considered to be the amount of energyrequired to pump a fluid to a certain height. In pumpsystems, engineers must contend with variations on thisbasic definition, and have to calculate the effects ofelevation or static head, pressure head, velocity headand friction head to improve pump performance.

16. Skin refers to a zone of reduced or enhancedpermeability around a wellbore, often attributed toformation damage and mud-filtrate invasion duringdrilling or perforating, or by well stimulation.

Winter 2006/2007 43

The PCoE in Oklahoma monitors more than500 wells, from Canada and the USA toArgentina, Brazil, Colombia and Ecuador. Othersuch well and reservoir-monitoring centers havebeen created in Beijing and Aberdeen.

Back to the FutureIn 1916, a 23-year-old Russian-born inventornamed Armais Arutunoff created the firstelectric motor capable of operating in water anddriving a pump. By 1921, he had establishedREDA (Russian Electric Dynamo of Arutunoff).After immigrating to the United States in 1923,Arutunoff installed the first electric submersiblepumping system in the oil fields of Oklahoma.

Returning to those early Russian roots, a newgeneration of REDA manufacturing, engineering,field service and repair centers are now beingestablished throughout Russia. The most recentaddition is the REDA Electric Submersible Pumpmanufacturing facility in Tyumen. This 10,000-m2

[107,642-ft2] facility was opened in 2005, and isslated to produce approximately 800 ESP stringsper year.

Since 1916, the REDA line of ESPs hasevolved to handle high volumes of fluid, highgas/oil ratios, high temperatures and abrasivefluids in onshore and offshore applications. Theengineering improvements implemented forincreased reliability and efficient installation inthe harsh conditions of Siberia will inevitablyserve to make the next generation of ESPs even better. —MV

> Predicting increased production. The plot of bottomhole pressure versus surface flow rate (left) shows how much the reservoir can yield at a givenbottomhole flowing pressure. Starting with the current condition with a skin of 4, the red line is used to validate the model and match the measured intakepressure of 100 psi [0.69 MPa] with the measured flow rate of 1,200 bbl/d [191 m3/d]. PCoE engineers can then use this model to predict the production-enhancement potential. The blue curve illustrates how a skin of 0 impacts bottomhole pressure and surface flow rate, known as the inflow performancerelationship (IPR). The model predicted that if the skin is removed completely, the production potentially could be raised to approximately 1,600 bbl/d [254 m3/d], for the same bottomhole flowing pressure. The pressure and flow-rate plot (right) shows that after acidizing, production was increased to 1,550 bbl/d [246 m3/d].

1,000

500

0

2,000

1,500

Pres

sure

, psi

Liquid rate, bbl/d

Bottomhole pressure

Static reservoir pressure

0 250 500 750 1,000 1,250 1,500 1,7500

1,800

1,600

1,400

1,200

1,000

800

600

400

200Intake pressure

Liquid flow rate

Liqu

id fl

ow ra

te, b

bl/d

Inta

ke p

ress

ure,

psi

Date11/04/05 12/14/05 01/23/06 03/04/06

Post-acidproduction increase

04/13/06

Match point

Predicted production

rate

> Transient-pressure diagnostic plot. The PCoE uses this chart to interpret reservoir behavior based onpressure-transient measurements. This log-log plot shows changes in measured reservoir pressure(green points) and the derivative of pressure (red points) over time. The computer-generated derivativesuperimposes changes in flow rate onto the pressure points. The measured and computed points arethen matched against modeled performance curves (solid lines). In this model, the derivative curvetrends downward, eventually flattening as pressure behavior transitions from wellbore storage to aradial-flow regime. The radial-flow portion of this curve is important for determining permeability andskin. The distance between the pressure and pressure-derivative data during radial flow is an indicatorof near-wellbore damage, in which increased separation indicates greater skin damage.

Δ pr

essu

re, p

si

Time, h10.10.01

Modeled pressurederivative

Modeled reservoirpressure

1001010

100

1,000

10,000

Pressure derivativeMeasured pressure