2011 ESP Workshop

2011 26th ESP WorkshopSummary of Presentations

Woodlands Waterway Marriott HotelWednesday, April 27 – Friday, April 29, 2011

Prepared byCleon Dunham, Oilfield Automation Consulting

May 6, 2011

Paper Author(s) Summary of Discussion

Purpose of this DocumentPurpose of this Document

Cleon Dun-hamOilfield Automa-tion Consulting

The purpose of this document is to summarize the main points of the technical presentations at the 2011 ESP Workshop. If you wish to learn more, please review the actual papers. The papers are included in the Workshop Notebook and on the Workshop CD. If you didn’t attend the Workshop, you can pur-chase a CD from the ESP Workshop Committee.

These summaries are based on my notes. If anything is pre-sented incorrectly, the fault is mine, not the authors and/or pre-senters of the papers. The lead author (of the author who pre-sented the paper) is shown in bold color with each paper.

Attendance at this year’s workshop:

This is the 26th ESP Workshop.

The first one had 60 people.

A total of more than 500 people are expected to attend this Workshop.

They will come from 26 separate countries.

They will represent 90 different organizations.

Opening CommentsWorkshop Co-Chairs:

Chairman: Rafael Lastra - OccidentalVice Chairman: John Patterson - ConocoPhillips

Opening Com-ments

Rafael LastraOccidental Pe-troleum

Rafael Lastra, the 2011 ESP Workshop Chair, welcomed all at-tendees.

He asked a representative of the Marriott Hotel to give a safety briefing.

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He announced that on Monday and Tuesday, there were three Continuing Education classes.

On Wednesday – Friday, there will be Technical Presenta-tions, Breakout Sessions, and Exhibits in the Exhibit Hall.

He introduced the Keynote Speaker, Mr. Mohan Chawla of Kuwait Oil Company.

Keynote Address

Keynote Ad-dress

Mohan ChawlaKOC

Mr. Mohan Chawla of Kuwait Oil Company (KOC) gave the Keynote Address. He received his Petroleum Engineering de-gree in India. He represented the role of SPE in Kuwait.

Global Petroleum Outlooko Kuwait is part of OPEC.o There is room for oil and gas, nuclear energy, and re-

newables.o There are enough reserves to last for another century.o The Industry will meet the demand caused by growth in

demand.o The U.S.A. represents 25% of the world’s demand.o Concerning the concept of peak energy, there are opti-

mists and pessimists. Reserves have increased 33% in the last two

decades.o There has been much turmoil in the price since 2008.

Price has ranged from $33 - $147 per bbl. Now price is $75 - $80 per bbl. and headed to

$120/bbl. Saudi Arabia will increase production to address

demand. The Japanese crisis has increased the price of oil. Is there a reason for fear of market fluctuations? The 2011 fluctuation is being driven by fear. But we do have spare capacity of 5.19 MM Bbl/

Day. 68.8% of the spare is due to Saudi Arabia. There is 4.1 MM Bbl, if this is needed.

o So, is all well? The answer is “No.” More transparency is needed in the industry. Demand will be 99 MM Bbl/Day by 2035. Uncertainty in the Middle East will cause higher

prices this year. OPEC doesn’t want to disrupt countries and cause

a recession. The IEA encourages OPEC to increase production

to avoid price upsets. They think a fair price is between $75 - $100 per

Bbl.

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IEA expects the price to be about $100 per Bbl this year.

Overview of the Kuwait Oil Industryo Kuwait has 7,000 square miles.o 3.5 MM people.o One third are nationals, the others are internationals.o It has 7.5% of the world’s oil reserves.o Kuwait Oil Company was founded in 1934.o Burgan is the 2nd largest field in the world.o The first well is still flowing.o Kuwait Petroleum Corp. is an umbrella company with

ten subsidiaries.o KOC is the 5th largest OPEC producer.o Iraq destroyed 730 oil wells in the 1st Gulf War.o They destroyed 80% of the processing facilities.o All well fires were put out in 10 months, even though

the initial estimate was that it would take 10 years.o There are still dried “oil lakes” to be seen.o Kuwait has a shortage of gas.o Now produce 130 MM SCFD of non-associated gas

and one BCF associated gas.o 95% of Kuwait’s revenues come from oil.o They are staring some thermal recovery projects.o They are working with four companies to develop new

technologies.o They have a large hiring program.o They are looking to implement automation.

Role of ESP’s in KOC.o KOC didn’t need artificial lift until the early 1980’s.o Now they are using ESP’s.o They started needing them in the early 1990’s.o In 1990 they had 26 ESP’s.o Now they have 550 ESP’s, producing 500,000 B/Day.o Still 75% of their wells are flowing.o The demand for artificial lift will rise in the future.o ESP’s will be used on high rate wells.o They expect to need 1,500 ESP’s by 2015/16.o They are investing in ESP technology.

Summary:o KOC has a bright future.o Will have oil reserves for another century.o They need stable oil prices.o ESP’s are the preferred method of artificial lift for most

KOC wells.

Q. What oil price do you use to evaluate project profitability?A. We use $65 - $85 per barrel.

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Q. How much does the value of the U.S. Dollar affect the world price of oil?

A. OPEC would like to get away from depending on the value of the U.S. dollar.

Q. Do you use water injection?A. Yes. We produce high water cut wells with ESP’s. We currently produce about 200,000 Bbl/Day water.

Session ISurveillance, Modeling, and Testing

Session Co-Chairs:Rafael LastraRoger Brown

It’s coming! Update on the new Interna-tional Stan-dard for ESPs (ISO 15551-1)

Shauna Noonan(ConocoPhillips)

David McCalvinISO Liaison

Shauna Noonan of ConocoPhillips gave an update on the sta-tus of ISO 1555-1 for Electrical Submersible Pumping.

Large-Scale Experimental Investigation of ESP Perfor-mance with High ViscosityFluids and Gas

Lissett Bar-rios(Shell)

Charles DeuelDavid KnowlesSandeep PatniStuart ScottShell E&P

Ketan ShethBaker Hughes

Lissett Barrios gave this presentation about ESP performance with high viscosity fluids and gas.

Introductiono ESP performance decreases due to high viscosity and

multiphase flow that can cause gas locking.o This was studied for the Perdido Booster System where

an ESP caisson is used. This is a 15,000 – 25,000 B/D caisson. It is in 8,000 feet water depth. The separation is not highly efficient. This is based on experience in Brazil. All gas must be passed by the ESP.

o Common ESP System. The burst pressure is greater than 2,000 psi. It uses 1,600 Horse Power.

o Testing in the Gasmer Facility in Houston. The test facility was built in 2006 and became func-

tional in 2007. It can handle 10,000 – 30,000 B/D. It can test from 1.0 – 400 cP oil. It can handle from 0.5 – 50 MMSCF/D gas. It can handle intake pressures of 250 – 1,000 psi. It can have temperatures from 70 – 150 0F. It uses a micro-motion meter to measure flow rate.

o The test system: 1,500 HP motor. 725 series pump.

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Light, medium, and heavy oil. A VSD that can go up to 70 Hz. Determine pump performance degradation with an

increase in viscosity.o Two phase flow test results:

The performance with low gas volume fraction (GVF) is OK.

As the GVF is increased, the performance de-creases.

With more GVF, the BHP decreases. At low GVF, there is no impact on pressure. As the pressure is increased, the performance im-

proves. As the viscosity is increased, the gas handling ca-

pacity decreases.o ESP manufactures should recommend or define the ef-

fect on performance of viscosity and GVF.

Q. Can you test at different speeds? A Yes. As speed increases, performance improves.

Q. What is the definition of degradation?A. It is degradation from the “standard” head curve.

Q. Can “standard” degradation models be used? E.g. Turpin and Dunbar?

A. They are only general models. Actual testing is needed.

Q. What are the downhole temperatures and viscosities at Per-dido?

A. Perdido has about 10 cP. Temperature is not too high.

Q. How did this compare with the Autograph program?A. We matched with correlations, not with Autograph.

Q. Did you do any stage-by-stage analysis?A. We could only measure for the total system. We could model on a stage-by-stage basis.

Q. Is slugging a problem?A. We were dealing with a mixture. It isn’thomogeneous.

Q. You said that as speed increased, the performance im-proved. Is this due to heat?

A. This will be studied in the future.

Q. Why does the pump perform better at high viscosity?A. The gas is still in small bubbles so there is less gas effect.

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Q. At high viscosity with no gas the pump performance is poorer?

It is easier to gas lock with lighter oil than with heavy oil.

Prediction Of The Transi-tions In Two-Phase Perfor-mance Of An ElectricalSubmersible Pump

Jose Gamboa(Multiphase Sys-tem Integration)

Mauricio PradoThe University of Tulsa

Jose Gamboa gave this presentation on two-phase perfor-mance of an ESP.

Introductiono Gas causes a decrease in the pump head curve.o This can be servere if there is slugging.o Slugging leads to more gas interference.o Prediction of the effect is a two-step process:

Determine the impact on the pump impeller. Determine the impact of this on the pump head.

o Two phase flow can be determined with the TUALP model.

Evaluation of two-phase performance.o Need to look at performance of each stage of the ESP.o Test with flow rate of 10,000 B/D, 300 MCF/Day.

Test results:o Constant gas flow rate.o Constant liquid flow rate.o At constant gas rate and decreased liquid rate, the per-

formance decreases.o With constant liquid flow rate:

Get different performance regimes. Get some mild reversals. Obtain a pump performance region map of liquid

vs. gas flow rates. A question evaluated: is performance decline re-

lated to impeller design? Can this be predicted?

o Models developed: Homogenous flow performance:

- Small bubbles. Mild degradation. Severe degradation. Developed surge correlations. Compare with Turpin and Dunbar.

- This new model is a better model.o Conclusion

An improved correlation has been developed.

Q. Would using a vertical vs. a horizontal pump for the tests give better results?

A. There should be no effect. T he tests used abooster pump to “charge” the flow into the ESP.

Q. What is the effect of pressure?A. At higher pressure, the gas bubble size isdecreased, and the performance is improved.

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Q. Is the performance related to the density of the liquid and gas?

A. There is a pressure grid on the impellers. This needs to be studied further.

Q. What is more important: density or bubble size?A. Bubble size is more important.

Q. What is the impact of using a redial stage?A. This needs to be studied in the future.

Viscous and Gas effects on the Perfor-mance of Multi-stage Centrifugal Pumps

Lyle Wilson(Baker Hughes)

Ketan ShethDonn BrownMichael FoxBaker Hughes Incorporated

Lyle Wilson presented the effects of gas on the performance of multi-stage centrifugal pumps.

How ESP’s differ from “normal” pumps.o There are in-line differences.o There are multi-stage pumps.o They are long – may be up to 60 m. long.o Fluid properties affect pump performance.o Viscosity affects pump performance.

Performance decreases as viscosity increases Can get less throughput at lower temperature. HP does not increase with change in pump speed. The pumps must be tested to understand their per-

formance.o Pump speed.

Performance is related to the speed of the pump. Pump efficiency decreases a speed decreases.

o Volume changes. Pump head decreases as gas volume fraction in-

creases.o Fluid is compressed as it moves through the pump.o Intake pressure increases allow more gas to be han-

dled per stage.o Why does the pressure increase with an increase in

gas flow rate?o Because it’s harder to compress the gas at higher pres-

sures.o Improved gas handling pump stages give better pump

performance – better than turbines.o Can improve gas handling by changing the boundary of

instability. Conclusions

o Higher viscosity helps drive gas through the pump.o Gas handling performs better than with standard ESP

pumps.

Q. Do you see the effects of emulsion?A. Emulsion is a problem. More testing is needed.

Q. Do you test radial flow pumps?

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A. Radial pumps are better for middle to higher flow rates.

Q. Can we use different control algorithms to operate gassy wells?

A. Yes. We are doing better to detect the onset of gas locking. We can react to onset of gas locking. We are looking at approaches. It may be better toincrease pump speed to work through a gas locksituation.

Q. What about use of tapered pumps?A. We do consider use of tapered pumps.

Production Al-location Using ESP in the Peregrino Field

Ketan Sheth(Baker Hughes)

Helge OlsenStatoil Brazil

Rui PessoaRisa OkitaAlex CrossleBaker Hughes Incorporated

Ketan Sheth reported on work the Statoil in offshore Brazil.

Introductiono There are 30 wells on two offshore platforms.o There are two manifolds.o The issue is how to determine the oil flow rate for each

well.o There are no flow meters.o “Measurement” is done by modeling the flow through

each ESP.o A venturi flow meter was used to calibrate the ESP

“flow” model.o The wells were tested in a test loop at Centrilift.o The performance of each type of pump was deter-

mined.o As viscosity increases, HP increases, efficiency de-

creases, and BEP decreases.o The accuracy of the flow rate estimates is +/- 3%, and

+/- 1% at low viscosity. Allocation principles:

o Measured pressure, fluid properties, RPM, HP, and BHP.

o This is used to calculate (estimate) the flow rate. Scenarios evaluated:

o Changes in water cut.o Changes in gas production rate.o Changes in pump performance.o Tests were conducted and validated with comparison

with venturi meter measurements. Conclusions:

o Accuracies within 3% were realized.o ESP performance models can be successfully devel-

oped.

Q. There are viscosities up to 20,000 cP. How is this mod-eled? How does it work?

A. The models were tested up to 360 cP.

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Q. What is the allocation algorithm? Do you look at RPM?A. The model was developed by Statoil. It isproprietary.

Q. Is the flow rate a function of the viscosity?A. It is only a function of the flow rates of water and oil, not of the gas.

Q. Do you have to test each pump?A. The model is not generic. It is necessary to test and model each pump.

Model-Derived Flow Monitor-ing in an Elec-tric Sub-mersible Pump (ESP)Application

Tommy Den-ney(Baker Hughes)

Alex CrossleyBaker Hughes Incorporated

This was a standby paper. It was not presented.

Session IIDismantle, Inspection, and Failure Analysis

Session Co-ChairsAtika al Bimani

Tom van Akkeren

A Holistic Ap-proach to Im-proving ESP Run Life in the Forties Field, UKCS.

Jeff Dwiggins(Dwiggins Con-sulting)

Cledwyn T. HughesPaul L NicollApache North Sea Ltd.

Jeff Dwiggins gave a presentation on the Forties Field.

Introduction:o There are five platforms in the Forties Fieldo Two of them have ESP’s. three others use a mixture of

ESP and gas-lift.o All 82 wells use artificial lift.o More than 50% use ESP’s. 60% of the production is by

ESP.o There are two active drilling rigs and one “gorilla” rig.

The goal is to increase the ESP run life.o Most ESP failures are evaluated with tear downs.

The top four causes of failure (16 failures per year):o 33% are caused by sand, both in and above the ESP’s.o Other reasons are: high water production, poor reser-

voir inflow, installation problems, and manifold prob-lems.

Sand Control:o Use open-hole gravel packs.o Use sand screens.o Upgraded ESP’s with Ni-Resist, silicon carbide bear-

ings.o Use downhole check valves.

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o Many failures occur at start-up. Start-up.

o They are developing better start-up procedures.o The Operators like the new start-up procedures.o They have an “auto flow” start-up function.o They use VSD’s to bring the wells on slowly.o The goal is to improve run life to greater than 2 years.

Q. What type of check valves are used? What are the prob-lems with them?

A. Use poppet valves. Have a problem with them when we do a scale squeeze. The check valves help with sand fallback.

Q. Are you doing any work to minimize the number of shut-downs? A. We are trying to keep the platforms on line to

minimize the number of shutdowns.

Improving Electric Sub-mersible Pump (ESP) Performance with Root Cause FailureAnalysis

Sebastiano Lapi(ExxonMobil)

Mark JohnsonExxonMobil Pro-duction Com-pany

Scott McDowellWood Group

Sabastiano Lapi gave a presentation on the ExxonMobil ESP experience in Chad, Central Africa.

Introduction:o Produce 125 MBO/Day, 700 MBW/Day.o Wells are 3,000 – 6,000 feet deep.o The pay zone is 200 – 350 feet thick.o The wells all have sand control.o There are 763 wells.o There are 672 producers; 470 with ESP’s, 202 with

PCP’s.o There are 60 injection wells and 7 gas wells.o There are two workover rigs and two drilling rigs.o The wells have 9-5/8” casing and 4.5” tubing.o The ESP’s are produced with VSD’s.o They have “Y” tools.o They uses shrouded intakes to help with motor cooling.o They use downhole gauges.o Run life has been improving since 2006.o Problems include emulsions and reductions in produc-

tivity index. Root Cause of Failure Analysis (RCFA)

o Each failure has a cause.o They analyze each failure.

RCFA Processo Perform surveillance and data collection.o Pull and dismantle each failed system.o Perform failure analysis on each failure.o Plan corrective actions.

Personnelo Wood Groupo ExxonMobil staff

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o Send some units to a Service Center to be tested.o There is an incentive to improve run life.o They conduct a weekly conference between Chad,

Houston, and Oklahoma City.o They use an RCFA Flow Chart.o They use a “Work Book” to track the process.o In the Work Book, they keep data on each stage of the

operation from design, operation, pull, and teardown.o They are tracking Key Performance Indicators (KPI’s).o They are working to improve alarm settings.

Conclusions:o Run time has improved by 70% since 2006.o Wood Group and ExxonMobil management are commit-

ted to the RCFA process.o They are focusing on “why” a failure has occurred,

rather than “what” failed.

Q. Why did run life decrease in May, 2010?A. Had gravel pack failures and field power upsets. We are now back to a good improvement trend on run life.

Q. How do you calculate run life?A. Total number of failures divided by total number of active wells.

Q. Are you looking at reliability gathering analysis?A. We are considering this, but aren’t there yet.

Q. Do you re-run the same system after a failure or do you wait for evaluation of the cause of the failure?

A. We usually have up to 10 days to respond to afailure, so we use the results of the RCFA.

Effect of Near Wellbore Con-dition on Elec-trical Sub-mersible Pump Design - Part 2

Mohamed N. Noui-Mehidi(Aramco)

J. XiaoNabeel S. Al-HabibEXPEC Ad-vanced Re-search Center Saudi Aramco

Mohamed N. Noui-Mehidi gave a presentation on the effect of near wellbore conditions on the performance of ESP’s.

Introductiono They are looking at skin effects.o ESP’s are used more than other forms of artificial lift in

Saudi Aramco.o They are concerned with system reliability.o They perform system analysis and system optimization.o They use VSD’s to better match the ESP output to the

PI’s of the wells.o They perform well testing to determine:

Flow rate, skin, and reservoir kh.o They model the effects of the skin.

They determine the degree of damage near the wellbore.

If necessary, they perform acid jobs. They use the Darcy equation to evaluate the skin

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effects. They then relate the amount of skin to the number

of ESP stages needed to produce the well.

Q. Do you try to increase the drawdown to reduce the amount of skin:

A. This may help to reduce the amount of skin but may damage the reservoir.

Q. Do you install the ESP when the well is drilled?A. We run tests to “right size” the ESP for each well.

Q. Do you use underbalanced drilling to avoid skin?A. Don’t know.

Q. Are there ways to anticipate how much skin there will be?A. We need well testing to answer the question of how much skin there is.

Declining ESP Runlife - M Field Study

Iqbal Sipra(Petroleum De-velopment Oman)

Saud Al-NaabiAtika BimaniPetroleum De-velopment Oman

Ghadani Adnan Centrilift ESP, Muscat

Ibal Sipra discussed declining run life in a field in Petroleum Development Oman.

Introduction:o This is about the PDO “M” Field.o It has 84 ESP’s.o The average run life is 652 days, but the target run life

is 800 days.o They use surface pumps to transport the production to

the facilities.o They use VSD’s.o They have problems with corrosion, solids.o The oil is 28 oAPI.o Bubble point pressure is 1,030 psi.o They use in-line separators to handle the fluid produc-

tion.o The wells flow to high pressure separators.o There are problems with foaming, CO2 and NaMetasili-

cate scales.o Solids are 10 – 40 ppm.o As ESP performance increase, the number of failures

increase. Failures:

o Tubing leaks 17%.o Solids 25%.o Corrosion 17%.o They perform tear downs and take photos of each fail-

ure.o For tubing corrosion. They use GRE lining.o They follow a risk and mitigation process.

VSD’s are not used on wells where the well’s pro-duction rate is known.

Old ESP’s are replaced if the efficiency has de-

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creased.

Q. What is the basis of the 800 run life target?A. This is based on historical performance.

Q. Is this needed to make the wells economical?A. It is based on experience.

Q. When are tubing failure occurring? What material is used?A. Normally the failures are right above the pump. We are using carbon steel.

Q. When the CO2 increases do you get a high BHP and higher partial pressure of CO2? Have you considered rising the setting depth of the ESP?

A. Good suggestion. We will consider it.

Q. Where is the sand coming from?A. The reservoir is carbonate. We sometimes drill into a shale zone. We get production of solids; it’s not sand.

Q. Why don’t you use VSD’s on all the wells?A. Normally we only run the wells at 50 Hz. We don’t need VSD’s on many of the wells.

Q. Do you used chemical injection?A. We do some batch injection.

Q. How does the ADU help?A. It helps to have the solids bypass the pump.

Typical Corro-sion Patterns in ESP Equip-ment

Ignacio Mar-tinez(Baker Hughes)

Rui PessoaBaker Hughes Incorporated

Ignacio Martinez of Baker Hughes Centrilift gave a presenta-tion on corrosion.

Introduction:o Types of corrosion: CO2, H2S, O2, Bacteria, Galvanic,

Chlorides, Water, Sulfide Stress Corrosion Cracking. Need to evaluate:

o Gas qualityo Watero pHo Partial pressureso Temperatureo Velocity and pattern of flowo Fluid type

Corrosion inhibitiono O2 scavengingo H2S scavenging

Chloride corrosiono Pittingo Creviceso Sulfide Stress Cracking

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o Fractureso Water cuto pHo Temperatureo Metallurgy

PREN is a factor. Recommended materials.

o Use 300 Stainless Steelo Use no Copper

Corrosion processo CO2 + H2O = H2CO3 + Iron = Iron Carbonateo Scale penetrates into ESP housing.o High pH scale is stable.o High partial pressure increases corrosion.

Paint is good. If have sulfide stress corrosion cracking, recommend

o NACE MR 0175-97 O2 corrosion

o Don’t usually have in downhole conditions.o May get if inject water with O2 in it.o In this case, use an O2 scavenger.

Microbiological induced corrosion.o If have this, use biocides.

Q. What about a galvanic corrosion.A. This is not covered in this presentation.

Q. Water will wet the steel at 14% H2O. or when have a water external system.

A. True.

Q. When does O2 corrosion occur?A. When water is stored in a tank. Can get O2

corrosion with water injection. Need to use an oxygen scavenger or a gas blanket.

Q. At what temperature do we get more corrosion?A. At 195 – 205 oF.

Q. Can corrosion occur with erosion?A. Corrosion can be more severe with erosion and the opposite can occur.

Q. How about Barium Sulfate?A. You will see this when you pull the well.

Breakout Sessions#1 – ISO

#2 – Producing Deviated Slugging Wells

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Producing Devi-ated Slugging Wells

Coordinators:Bill BowlinLyle Wilson

Bill Bowlin and Lyle Wilson coordinated this breakout ses-sion.

Typical wellso Typically these wells are pressure depleting, below the

bubble point.o Normally they have 7 – 7.5” casing.o Normally they are 8,000 feet deep or deeper.o Normally the horizontal section is 5,000 feet or longer.o Often the wells are frac’ed.

Artificial lift options:o Gas-lift

Wells are slugging which is a problem.o Sucker rod pumping

Pumps don’t like gas. They don’t work well through curved well sections.

o Jet pumping Limited applications

o ESP’s Can gas lock There are problems if there is more than 20% free

gas All testing of ESP’s is conducted in steady state

conditions But here the production is pulsating.

Options for using ESP’so Drill a “rat” hole

It can be straight or slanted A shroud can be used to cool the motor Can use a recirculating pump to cool the motor Can use a gas separator below the pump intake

o Complete without a “rat” hole Use a rotary gas separator

- This won’t work is the well is slugging and there are periods of no liquid.

Use a separator with holes in the bottom of the pump casing

Use a dip tube Use a tail pipe – gas in the tail pipe goes into the

pump intake Use an inverted shroud

- A path is provided for the gas to flow up past the pump

- Can slow the pump speed to 20 Hz if get an in-dication the pump is staring to gas lock

- Need a 7” hole and a 5.5:” shroud Use a recirculating pump Monitor the pump to control its speed, or use an

open/close recirculating valve Run a long tail pipe in the horizontal section to in-

crease the flow velocity of the liquid in the section Place an auger in the horizontal section to induce

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flow turbulence Drill a 2nd vertical well to intersect the toe of the hor-

izontal well- Produce the gas through the horizontal and

pump the liquid up the vertical well

Session IIIAlternative DeployedSession Co-Chairs

William MilneRobert Lannom

Cost Efficient Alternative Deployed ESPs for Deep Water GoM

Jørn Andre Carlsen(Statoil)

Alexey Pi-vavarskiStatoil,

Jorn Andre Carlsen of Statoil presented plans that are being developed for deploying ESP’s in deep Gulf of Mexico wells.

Introductiono Statoil has 20,000 employees.o It works in 34 countries.o It produces 80% of the oil and gas in Norway.o It’s the 3rd largest crude oil seller in the world.o It’s the 4th largest lease holder in the Gulf of Mexico.

Challenges in deep water Gulf of Mexicoo Greater than 7,000 feet water depth.o Greater than 30,000 feet deep reservoir depth.o Reservoirs are sub-salt.o Wells cost more than $250 MM.o Reservoir pressure is greater than 25,000 psi.

Solutiono Use ESP’s, with sub-sea boosting.o This can increase production rates by 15% and in-

crease recovery. Booster pump

o The well is 22 km from the host platformo The booster can increase drawdown by 6,000 psi.

In-well ESP’so Used to increase production, extend the life of the well.

Conventional ESPo Tubing deployedo Longer MTBFo Very high workover costs in range of $50 - $70 MM.o Estimated MTBF 3 years.

Alternative deployment methods

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o Wirelineo Coiled tubingo Cost $12 - $20 MMo Statoil is working on thiso Need a holistic approach

Optionso Coiled tubing deployed ESP.o Install with an external cable.o Wireline deployed ESP.

There is little experience with this, less than 15 in-stallations.

o Coiled tubing deployed – more than 100 installations. Choice

o Use internal power cable.o Work on wellhead design – need 15,000 psi pressure

rating.o Completion

Use control choke. Use a downhole safety valve. Use downhole gauges.

Surface vessels.o Floating vesselso Hold the coiled tubing unit and reelo Use standard configurationo BOPo Downhole safety valve

Internal power cable.o Motor on top of the ESP.o Pump on bottom.o ESP – 400 or 500 series.o Use 500 series with 7” tubing.o Shut-in pressure 15,000 psi, 22,000 psi max.o Need to extend run life to greater than 5 years.

Designo Optimize the load range and minimize up and down

thrust.o Minimize vibrationo Design to tolerate operator mistakes

Downhole monitoringo Pressure up to 27,000 psi.o Temperature up to 300 oF, 145 oC.o Surveillance – try to predict ESP failures.o Need to decide to communicate on power line or sepa-

rate communication cable Variable speed drive.

o This doesn’t exist for this condition.o Need a JIP to develop it.o The ESP must work in conjunction with sub-sea boost-

ing. Timing

o 2010 – Design

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o 2012 – Coiled tubing designo 2014 – Coiled tubing used sub-seao 2016 – System operational

Q. Is this the Statoil “wish list?”A. Statoil plans to make this happen.

Q. 5- year run life – what needs to be done to make it happen?A. Enhanced motor, seal section, cable.Minimum influence of Operator, highlyautomated.

Q. What size coiled tubing? What materials?A. This may not actually be conventional coiled tubing. We’re looking at materials. The size depends on the size of the power cable.

ESP Chal-lenges in Ul-tra-Deep Wa-ter Wells - Lower Tertiary Reservoir in the Gulf of Mexico

Carlos Lopez(Baker Hughes)

Andres CardonaRaymond O’Quinn Baker Hughes Incorpo-rated

Carlos Lopez of Baker Hughes Centrilift discussed the chal-lenges associated with ultra-deep Gulf of Mexico wells in the Lower Tertiary Reservoirs.

Introductiono The Lower Tertiary reservoir in the Gulf of Mexico is

400 x 800 miles in size.o Reservoir depth is 12,000 to 20,000 feet in the West.o Reservoir depth is 24,000 – 35,000 feet in the East.o Water depth is 6,000 – 10,000 feet.o Reservoir pressure is 20,000 – 23,000 psi.o Bubble point is 1,200 to 1,300 psi.

Design methodologyo Use Nodal Analysiso Use “Autograph” for ESP analysis.

Planned approacho Use sub-sea boosting.o Add ESP’s in the well for artificial lift.o Limit drawdown to 5,000 psi.o Add pressure with the sub-sea booster and the ESP’s.

ESP options.o Deploy with tubing – need 7 – 10 year run life.o Deploy with coiled tubing – reduce workover time to 20

days. Challenges

o Need large casing – 11.75”o Use ESP CAN.o Need new tubing hanger.

Two ESP cables. Wellhead penetrator to 15,000 psi. CAN to 10,000 to 15,000 psi. Power penetration

o Need auto diverter valve – to bypass ESP initially.o ESP must have high production range.

3,000 – 15,000 B/D

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Need valve below ESP to isolate reservoir.o Coiled tubing design challenges.

7” tubing hanger. Dual crown plug. ESP power penetrator. Coiled tubing large enough for power cable. Coiled tubing at least 2-7/8”.

Summaryo Recovery will be increased by 30% by adding an ESP.

Q. What is the assumption for sub-sea boosting?A. The sub-sea booster will boost pressure by 1,200 psi. It will have greater than 2,000 psioutlet pressure.

Q. What is the depth limit of the coiled tubing?A. There will be 10,000 feet of C.T. Total length will be 12,000 feet.

Q. Can you use 11-3/4” casing at this depth?A. This is being studied.

Q. What voltage is needed for 1,200 HP ESP?A. 5,000 – 6,000 volts.

Q. What is the back-up plan if the barrier valve fails?A. Baker Hughes is studying the possiblecontingencies.

Q. Does the well design depend on the well’s PI?A. Yes.

Q. Does the casing size depend on it too?A. We are planning on 11-3/4” casing. We could possibly use 10-3/4” casing with coiled tubingdeployment.

Geared Cen-trifugal Pump - Project Up-date

Bruce Mor-row(Harrier Tech-nologies)

John C. Patter-son Cono-coPhillips Com-pany

Michael R. Berry Mike Berry Con-sulting LLC

Bruce Morrow of Harrier Technologies gave an update on the geared centrifugal pump project.

What is a geared centrifugal pump?o It uses a PCP drive head.o An ESP pump downhole.o A 7:1 gear box downhole to convert PCP rod ration

speed to ESP speed.o No downhole electrical components.

Components from bottom to top.o Intake stinger.o ESP pump.o Lower seal section.o Transmission.o Upper seal section and compensator.

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o Receiver.o Tubing with the PCP rod string.o PCP drive head.

Unique technologyo Bottom-latch pump – good for gas handling.o Load carried by tubing, not the rods.o Transmission

Paired helical gears. Production flows past the transmission and up the

tubing. Forced oil circulation prevents overheating Helps work through gas locking.

Field installationo Installed in Texas in May, 2010.

4,600 feet. 1,550 B/D Ran greater than 11 months.

o Installed in New Mexico in Jan. 2011 4,600 feet. 1,400 B/D Efficiency greater than 50%. No installation problems. Took two hours longer than normal PCP installa-

tion. No re-start problems.

Rod string test stand.o Test RPM, tension, inclination.o Use 1” rods, 3.5” tubing.o Have a window to see the rods in the test stand.o 1,000 tests have been run.o 500 PRMo 3 stabilized flow rates.o Well inclination not a problem.

Target is to use this in SAGD wells at high temperature.o Designed for high temperature operation.o Will test in May, 2011 in the teat loop.

Advantages of the Geared Centrifugal Pumpo Better gas handling.o ESP rates at lower cost and higher efficiency.o Eliminate high cost ESP componentso Use in high temperature applications.o Thanks to John Patterson and ConocoPhillips.

Q. Are there depth limits?A. 10,000 feet.

Q. What is the “sweet” spot?A. Anywhere between surface and 10,000 feet.

Q. What is the transmission:A. 7:1 speed increase.

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Q. What is the maximum O.D.?A. 5-inch.

Q. Can it handle dog legs?A. Same as an ESP.

Q. How about intake back pressure?A. Can use a gas intake. Can use a gas anchor (separator) if it is installed above the perforations.

Q. What is the maximum rate?A. There is a 200 HP limit.

Q. With the “D” channels, can you handle high oil cuts in heavy oil fields?

A. There is a low differential pressure across the “D” channels. There is no problem with bitumendeposition.

Q. If the pump is stopped, is there a problem with back spin?A. There is a back-spin brake in the PC drive head.

Q. Is efficiency related to pump depth?A. There is very little impact on efficiency at depth.

Q. How does it work with water production?A. The efficiency is a little less than 50% when pumping water.

Q. Could you use coiled tubing or wireline deployment?A. This should be possible.

Electrical Sub-mersible Pump With In-tegral Pod In-take System

Kristopher Snyder(Baker Hughes)

Lyle WilsonJames FlemingJohn Mack, SPE, Matt Wis-newskiBaker HughesIncorporated

Mark RooksSaudi Aramco

Kristopher Snyder with Baker Hughes Centrilift presented an ESP with an integral POD intake system.

Introductiono Working with Saudi Aramco.o Have 753 ESP’s since 2002.o Have sour gas, high GOR.o All use sub-surface packers.o No artificial lift other than ESP’s.

ESP program; for it they use:o No field splices.o No POT heads.o Shrouded intakes.o 513 seals.o Lower tandem motors.o Special penetrators.o Motor lead extensions (MLE)o POD hangers with four intake holes.o They get no gas breakout.o They use swage lock fittings.

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o Motor adapters.o 562 high volume pumps.o They stab into barrier valves.o They operate at 5,000 psi working pressure.o Working temperature is 280 oF.

Validation testing:o Test at 1850 psi for four hours.o 73,000 lb. pull test.o Air test.o Spin test.

All gas enters the pump.o They use typical pumps.o There is no fluid over the pump.o They use slow start-up.o The installation depth limit is 5,000 feet.o These will be installed in 2011.o Will report results at 2013 ESP Workshop.

Q. Do you have much H2S? What materials so you use?A. Use Monel, 416 Stainless Steel, 9 Chrome. We have 3 – 4 % H2S.

Q. Do you use H2S scavenging?A. We will look into this.

Q. What are your termination limits?A. We use 238 HP motors, 60 amps, up to 280 oF.

Q. Why use Stainless Steel, and not Monel and Lead?A. We’ll look into this.

New Develop-ments in Through Tub-ing Conveyed Technology in the Rocky Mountains

David L. Ol-son(Baker Hughes)

Nicholas J. Bei-dasJoshua T. PratherBaker Hughes

Peter OyewoleBP Exploration

David Olson of Baker Hughes Centrilift presented new devel-opments for through-tubing deployed technology in the Rocky Mountains.

Introductiono This is working with coal bed methane production.o There are erratic production rates.o High rig costs.o The fields are in pasture areas.

The wells:o The wells are deviated, “S” shaped, horizontal.o There are long perforated intervals.

Objectiveo Improve run life.o Improve use of power.o Monitor the VSD’s.o Need real-time data to be proactive.

Use ESPCP’s.o Greater efficiency.o Lower power.

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o Better to handle solids and gas.o Operate with a VSD.o Use gear reducer from 3500 RPM with 11.5/1 reducer

to 300 RPM for the PCP.o The PCP’s are conveyed through tubing with a GS tool.o There is a packer above the pump.o The tubing stabs into the packer.o Can also use a mechanical lock.o Can use slick line or co-rods.

Field experience:o Installed in Nov. 2005.o 3.5” tubing.o 907 days run time.o Motor failed due to erosion.o Downhole monitoring:

Inlet Temperature, Motor Temp. Pressure. Set below the pump. No shroud is used. Monitor PIP, PDP, Motor T. Vibration. VSD is used to maintain constant fluid head above

the pump. Analysis.

o Need good power.o Need good motor run time.o Through-tubing installation is reliable.o Need 7” casing.

Value proposition.o Reduced intervention costs from $97,500 to $15,000.o Save up to $300,000 over all.o Have low surface profile.

Q. What happens if the sensors fail?A. Can operate by using fluid level shots.

Q. What percent of the cost is the measurement system?A. 10 – 15%.

Q. Do you use a downhole de-sander?A. Sand is separated and injected through the tail pipe.

Q. How is the motor cooled?A. Have dielectric oil to protect the motor.

Q. How do you pull the equipment out of the hole?A. Scale deposits inside the tubing, so can pull it OK.

Q. Do you use a check valve?A. No.

Q. What is the “void factor” on PCP to reduce run life?A. Don’t know.

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World's Deep-est Thru Tub-ing Conveyed ESP's

Jennifer Ju-lian(BP)

J. C. PattersonConocoPhillips Company

B. E. YingstW. R. DinkinsBaker Hughes Centrilift

This paper wasn’t presented.

Alternate De-ployment Method for ESPs in the Cliff Head Off-shore Devel-opment

John Mack(Baker Hughes)

Simon DanielRoc Oil Co. Ltd.

Travis JamesBaker Hughes

John Mack of Baker Hughes Centrilift presented this alternate paper as a back-up to the above paper.

Introductiono This project is in Cliff Head offshore development in the

Perth Basin, offshore from Perth, Australia.o It is a beautiful area, seven miles offshore.o The onshore plant is two miles from the beach, to keep

the beach pristine for people to use.o Oil is exported from the plant by truck.o This is in a National Park area. No leaks are allowed.o The platforms are un-manned.

ESP’s are installed by coiled tubing.o The cable is internal in the coiled tubing.o Every anchor is x-rayed to be sure it is OK.o The pump is installed on bottom, below the motor.o A hydraulic release is used by pressuring up on the tub-

ing. This has been tested and works OK.o There is the motor, a seal, the pump, and an intake

pressure gauge.o The intake is screened.

Run life.o Run life has been greater than 2,000 days for two of the

wells.o There have been some scale problems.o There were early transformer issues.

Sparking. Burn spots. Needed better insulation.

Conclusions:o Good reliability.o Total MTBF 2,351 days.o There have been no discharges, no spills.o 10,000,000 bbls. of oil have been produced.

Q. What is the fluid condition, the temperature?A. Low temperature.

Q. How do you get such long run times?

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A. Pay close attention to the system. Place the cable in the coiled tubing.

Q. You use dimples. Are there any “cap stand” effects?A. We x-rayed all anchors. There are dimples on both sides of the anchors.

Q. One of the run times was only 35 days, Why?A. We had a transformer issue?

Q. Do you run concurrently with live and dead wells?A We place a barrier valve on both strings. We don’t use a lubricator.

Q. Do you use both an isolation valve and a barrier valve?A. We rely on one valve.

Q. Do you have any corrosion issues?A. No.

Q. Have you considered downsizing from 7” to 5.5”?A. Use of 7” was a choice so we could run cable in the coiled tubing.

Session IVOn the HOT Seat

Session Co-ChairsBud Missel

Tommy Vineyard

A Tale of Two Operating Companies, One ESP Man-ufacturer and a Very Hot FlowLoop

Leon Waldner(Nexen)

Shauna Noonan ConocoPhillips

Wayne KlaczekC-FER Tech-nologies

Kelvin WonitoyBaker Hughes

Leon Waldner of Nexen presented a nice story about coopera-tion on testing for a SAGD project.

Introductiono SAGD – Steam Augmented Gravity Drainage.o This is a very challenging environment.o There are two horizontal wells, one above the other.o Steam is injected in the top well to heat the steam

chamber.o Oil flows down to the lower well where it is produced.o Validation of equipment is required.o The project involves ConocoPhillips and Baker Hughes.o They invited Nexen to participate in the project.o The testing was done at C-FER’s high temperature flow

loop in Edmonton, Alberta, Canada. SAGD wells in Canada

o There are 750 SAGD wells in Canada.o The number will double in 5 years.

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o The temperatures are up to 270 oC.o The vertical depth of the wells is shallow.o Some of the wells are drilled in a slant from the surface.o The deviation is greater than 1o per 100 feet.

Operating conditionso Greater than 240 oC.o Temperatures vary more than 100 oC.o The fluid is very high viscosity, greater than 1 MM cP.o There are GOR issues due to the steam.o There is water cut variability.o The downhole pressure fluctuates a lot.o There are thermal cycling challenges.o Downhole pressure can be controlled.o Young SAGD wells have low temperature.

Monitoringo Need special equipment.o Need special control logic.o Must control internal temperatures to not exceed limits.

Cost issueso High CAPEX.o High OPEX.o Downtime a problem.

Validation program.o Objectives

Test Baker equipment at 250 oC. Provide realistic test environment.

o Contracts Define roles and responsibilities Base on existing contracts to leverage.

o Test in C-FER High Temp. test loop. Simulate typical SAGD wells. Hold constant T and P. Run pump start-up tests. Run pump performance tests. Run reliability tests over time. Run electrical degradation tests. Run thermal injection tests.

o Why use collaboration? More can be done and better by working together. Keys to success:

- Cost sharing.- Common goals and objectives.- Strong relationships.- Financial stake in the results.- Technical resources.- Understanding costs.- Obtaining measureable results.- Ownership of results.

Summaryo Need to understand reliability.o Testing is expensive.

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Q. Can you use “ESP Vision” to evaluate the wells?A. Need lots of understanding and monitoring. Need a good system for evaluation.

Q. Can you optimize the performance of the wells?A. We try to understand how to optimize SAGD wells.

Q. Why are ConocoPhillips and Nexen testing and not just de-pending on the Manufacturer?

A. To deal with the specific requirements ofConocoPhillips and Nexen.

Q. Are you open to having other partners join the project?A. Couldn’t answer at this time.

Q. Do you plan to test with live steam?A. Don’t know.

Developing a High Tempera-ture Field with 3.75” Pump Systems

Ricardo Maz-zola(Pan American Energy)

Miguel CollaMariano CiapparelliPan-Energy Company

Daniel SantosJuan Carlos SegniniRicardo Hector TevesWood GroupGE Oil and Gas

Ricaardo Mazzola of Pan American Energy presented a story about developing a high temperature field in the South of Ar-gentina with a 3.75” pump.

Introductiono The field is in the South of Argentina.o It is 1,200 miles south of Buenos Aires.o There are 2,800 producing wells.o 480 injection wells.o Produce 95,000 BOPD.o All wells are vertical.o There are 15 – 30 productive layers per well.o They have 5.5” casing.o They are 9,000 feet deep.o They have 2,500 feet of perforated interval.

ESP’so The pumps are installed below the perforations.o They use 375 series pumps.o They measure downhole pressure.o They use shrouded systems.o 170 HP motors.o High temperature downhole sensors.o De-sanders.o Three tandem seals.o 880 of the wells (90%) use 375 pumps.o Average depth 6,400 – 7,000 feet.o Temperature about 180 oC (360 oF).o There are some scale and sand problems.o Production from 630 – 1,200 B/D per well.

Key Performance Indicators (KPI’s)o Failure index 0.19o Run life 5 years.

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o MTBF 1.5 years.o Use HP isolation.o MLE greater than 200 oC.o Use hardness.o De-sanders.o High temperature sensors, up to 410 oF.o Automation

Resultso 900,000 B/D, mostly by ESP.o 375 series motor is OK.o Good teamwork between the Operator and Supplier.o Use teardown and inspection.

Q. Root cause of failure analysis process?A. Tear down, data base, historical data, evaluate causes of failures.

Q. Do you use stage coatings?A. We use a chemical process for this.

Q. What type of scale do you have?A. CACO3.

Q. How do you deal with scale and sand?A. We use a scale inhibitor.

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High Tempera-ture ESP Ap-plications in Surmont Field

Esteban Oliva(ConocoPhillips)

Jeff DwigginsDwiggins Con-sulting LLC

Colin DreverLaolu AdekoyaSchlumberger Canada Ltd.

Esteban Oliva with ConocoPhillips presented high temperature ESP applications in the Surmont Field in Canada.

Introductiono This is about SAGD operations in the Surmont Field in

Alberta, Canada.o The extent of the field is 80 x 50 miles.o The crude oil is highly viscous.o It is necessary to add heat to reduce the viscosity so

the crude can be produced. SAGD (Steam Augmented Gravity Drainage) was invented

in 1978.o Steam is injected in an upper wellbore.o Production is from a lower parallel well bore.o The steam pressure declines over time.o ESP’s are used to produce the wells.

Project designo The wells are 550 meters deep.o The pressure is 1,500 kPa.o The production rate is 250 – 520 M3/Day.o The injection temperature is 210 – 250 0C.o The bottom hole pressure is 2,700 – 3,500 kPa.

Challengeso High temperatureo High dogleg severityo Temperature monitoring

Wellso Originally drilled to be gas-lifted.o Wellbore deviation 130 per 30 meters.o Pumps are set in a deviated run of 5o per 30 meters.

Instrumentationo Motor Temperatureo Pressure at the bubble tubeo Use new high temperature downhole gauges made by

Schlumberger and other companies.o Goal is to optimize growth of the steam chamber.

Wellheado Use VSD’s for control and DCS’s to monitor.o Store wellhead parameters in the DCS units.

Resultso Seven units installed in 2010.o First three were evaluated and then four more installed.o Real time monitoring used via the VSD’s and DCS

units.o Used inflow measurements.o High temperature rise – up to 270 oC.o The first three wells were evaluated and then the de-

sign was changed for the next four wells.o Better results were obtained with the next four wells.o Temperature rise up to 240 oC.

Future

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o Don’t design for gas-lift.o Only use ESP’s.

Q. How is the motor temperature working with the motor oil?A. Good.

Q. You do weekly analysis. Do you use the SCADA datayourself or is it done by a contactor?

A. Initially it was done by Schlumberger. Now it is done by ConocoPhillips. We use pressure and temperature optimization and analysis.

Q. How are the motor loads?A. They are not more than expected.

Q. How about bottom-hole pressure?A. The GOR is less than expected.

Q. How about bottom-hole temperature?A. Some are at 210 oC, some at 170 oC.

Q. Are you using any closed-loop control?A. No closed loop control yet. Only manual control via the DCS and VSD units.

Q. You are producing 1,500 – 3,000 Bbl/Day. Why use ESP in-stead of PCP?

A. We are looking at the possibility of an all metal PCP with a metal stator. We are planning field trials of this.

Q. You would use an all metal PCP with such high tempera-tures?

A. We plan to try this. It has been used by others with good success.

Q. Are there benefits of using a 250 oC ESP vs. a 220 oC unit?A. We have decided to settle on the 250 oC units. The performance of the two is similar.

Use of Failure Analysis Techniques to Improve Mate-rial Selection andPerformance in SAGD Wells

Haining Pan(Schlumberger)

J. CaridadSchlumberger

S.G. NoonanConocoPhillips

Haining Pan of Schlumberger gave a presentation on failure analysis to improve material selection for SAGD wells.

Material selectiono Schlumberger runs ESP’s in SAGD wells at tempera-

tures above 250 oC.o They use high temperature motors, and normal ESP

pumps.o They have a “hot loop” test well.

There was a crack in a bearing sleeve.o They were using a compression pump.o There were issues in the impeller stack.o They evaluated the cause of the crack in the bearing

sleeve.

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o They performed root cause analysis; the process they used: Repeated the cause of the failure. Analyzed the failure. Developed a model to predict the failure. Recommended solutions.

o Tests conducted in Singapore’s lab in Singapore. The crack occurred at 220 oC. Caused by a compression load. It was a radial fracture. The increased temperature increased the axial

load. The stress was not due to compression, but ten-

sion. The crack occurred at a notch. Used finite element analysis to evaluate the cause. They could see a concentration of hoop tensile

stress due to fatigue in the radial.o A correction was implemented based on the model.

Used finite element analysis to define the correc-tion.

Used a 3D model. Predicted a failure at 225 oC with the model. Redesigned the system to increase the failure tem-

perature up to 280 oC. Future

o Evaluate the new model.o Choose new materials.o Improve the long-term system reliability for SAGD wells.

Q. Have you experienced similar cracking? Could there be other causes?

A. Torque is not a cause of the failure.

Enhanced ESP Motor Cooling - De-sign, Testing & Field Trial

Ketan Sheth(BakerHughes)

Yamila Orrego Kenneth Car-monChevron

Roshani O’BryanBruce Brook-bankJohn BeardenBaker Hughes

Ketan Sheth of Baker Hughes gave this presentation on en-hanced ESP motor cooling.

Introductiono This work was done for Chevron.o Heat is generated during operation of the ESP motors.o Get a high temperature inside the motor housing.o Chevron operates more than 5,000 wells with ESP’s.o Some operate above 350 oF.o They worked with the Los Alamos lab to develop a

model. Benefits:

o Reduce motor failures.o Double run life due better handling of high temperature.o Enhance use in SAGD projects.o Reduce scale deposition.o Get better use with heated fluid.

Thermal model:

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o Calculate temperature at each end of the motor. Design

o Base on motor temp. and fluid temp.o Well and ESP configuration.o Operating conditions.o Motor characteristics,o Fluid properties.

Numerical description.o Reynolds Number.o Laminar flow – no mixing.o Turbulent flow – convection and conduction heat trans-

fer. Internal factors that affect motor heating.

o Finned surfaces.o Optimum number of fins – 36 axial fins.o Conducted computational studies.

Fins give better cooling. This is on a 562 series motor. Get an 80 oF reduction in internal temperature with

fins. Conclusions:

o Finned motors are cooler.o They are more reliable.

Q. What is the sensitivity of gas on the cooling?A. We looked at the effects of gas.

Q. What are the effects of gas?A. Gas increases turbulence and increase heattransfer.

Q. What is the Reynolds Number associated with the flow of fluid?

A. Get poorer heat transfer with laminar flow.

Q. What is the comparison with motor size? Are you compar-ing apples to apples?

A. We are looking at the effect of different HP’s in our testing.

Q. Is there an effect of a centralized motor vs. an offset motor?A. There doesn’t appear to be much effect whether the motor is centralized of offset in the casing.

Q. What are the effects of the fluid?A. We tested with Oil, Water, and Gas. We compared with the same Reynolds Numbers.

Q. Did you consider the effect of friction loss due to the flow past the motor?

A. There is a minimum effect of the small loss past the

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motor due to friction.

ESP Recircu-lation System Solves Pro-duction Issue in Granite Wash Gas Well

Leslie C. Reid(Baker Hughes)

L. M. IrishXTO Energy Inc,

N. G. HollandT. L. HowardBaker Hughes Inc

This alternate paper was not presented.

Breakout Sessions#1 – Surveillance

#2 – POWER – What are the Problems (Regulatory to Harmonics to Supply)?

Surveillance Coordinators:Jeff DwigginsGreg Stephen-sonEsteban

This was a breakout session to discuss ESP surveillance.

What is surveillance? How is it used? What difference does it make?o Use it to make intelligent decisions.o Service Companies have surveillance systems they use

themselves and use to provide information to Opera-tors.

o Information is power.o Have more influence.o Better use of resources, people.o ConocoPhillips uses LOWIS.o Manage by Exception.o Evaluate gas effects vs. viscosity effects.

What will happen in the future?o Use automation systems for automatic control.o Nexen is willing to share data with others.o Apache places their data in a PI system.o Baker Hughes uses trend analysis.

Bottom line: everyone should use enhanced surveillance systems.

Session VField Studies

Session Co-ChairsJohn Patterson

Craig Stair

First Electrical Submersible Progressive

Ernesto Bar-ragán(Andes Petro-

Ernesto Barragan with Andes Petroleum Ecuador Ltd. gave a presentation on use of ESPCP systems in Ecuador.

Background

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Cavity Pump (ESPCP) Run In EcuadorOpens New Opportunities For Heavy Oil Production

leum Ecuador Ltd.)

Angel BurgosAndes Petro-leum Ecuador Ltd.

Vladimir CoelloJuan Sem-pertegui, Baker Hughes

o This is in the Terapac Block.o A first well was completed in 2006.o The field produces 50,000 BOPD.o The reservoir is sandstone.

13 oAPI. 17,000 Bbl/Day in the ESPCP wells. 266 cP. Sand production. Bottom water drive. Wells produce with 90% water cut. Wells are 8,000 feet deep. Reservoir pressure is 2,644 psi. 200 oF. 255 md permeability.

Introduction:o Originally used ESP’s.o Failed in 48 days.o Installed ESPCP in 2007.o Initial run life 130 days.o Installed upgraded ESPCP in 2009.o Used a stronger gear reducer.o Had run life of 599 days.

Challenges:o Heavy oil.o Short ESP run life.o High viscosity.o Sand productiono Deviated wells.o Ran PVT analysis and elastomer analysis to choose the

pump metallurgy.o Conducted tests on a test bench.

Solution:o Use ESPCP’s.

Use a simple design. High volumetric efficiency. Handle solids and high viscosity. Ne emulsions, no gas problems.

o Disadvantages Heat Aromatics Had gear reducer failure – was replaced with a

stronger reducer. Have produced 187,000 bbls. oil extra vs. ESP’s.

Conclusions:o Increased run life.o Added reserves.o Produce 13 oAPI oil.o Perform satellite monitoring of the wells from Quito,

Ecuador.o Handle unconsolidated sand.o Will use more ESPCP’s.

Future:

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o Will add more wells.o Have reserves of 5 MM Bbl.

Q. What is your Horsepower? What is the influence of VSD?A. We use 110 HP. 2150 volts. Produce 300 B/D per well. We use VSD’s. We use downhole sensors.

Q. Do you have an issue with motor cooling?A. It is OK. We use a high temperature motor.

Q. What is the comparison between the ESP motor and the ESPCP motor:

A. We were using a 152 HP ESP motor. ESPCPmotor is 110 HP, high temperature.

Q. How did the gear reducer fail?A. We use a series 575 9/1 reducer or a series 53811/1 reducer. A screw broke and caused the failure.

Q. Do you inject chemical to reduce the viscosity?A. Yes. But sand production is a big problem.

Q. Is sand production related to production rate?A. We get 30 lbs. of sand per 1000 bbls. of production.

Q. How do you handle the sand at the surface?A. We have a 3 km. long flow line. We have PAD wells. Fluid flows from the PAD’s to the Facility. We clean the sand out of the separators.

Review of Dual ESP Sys-tem Applica-tions Follow-ing 100 Instal-lations

Brian Scott(Schlumberger)

E. JamiesonSchlumberger

Brian Scott of Schlumberger gave a review of dual ESP appli-cations.

Introduction:o The first systems were installed in 1996.o Now there are over 100 dual ESP systems in operation

in the world.o They are used as back-up systems, one to back up the

other in case it fails.o They are also used to produce multiple zones in a well

where the zones must be produced separately.o The dual systems consist of two ESP’s in the same

wellbore.o 95% of the systems are installed as back-ups.o They produce high rates.o They have high horsepower.

Back-up systems:o Goal is to minimize downtime.o They have dual by-pass systems.o They use by-pass tubing.o Either unit can be operated.o It is possible to by-pass both units for reservoir logging.

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o They are run in 9-5/8:” casing.o They use a “Y” tool with a plug.o Use slick line to run/pull the plugs.

An “auto” “Y” tool was developed in 1998.o Don’t need slick line to run/pull the tool.o No intervention is required.

Dual POD system:o The production casing is isolated from reservoir fluid.o Uses an “auto” flapper valve.

Economics:o Reduce downtime when an ESP fails.o Avoid negative income due to downtime.

Back-up system growth:o 33 wells in primary installationso 8 wells in secondary installations.

Multi-zone ESP systems:o Pressure differences in different zones.o Need to test the zones separately.o Use dual ESP’s to produce the zones separately.

Two tubing strings – one inside the other. No commingling. Can run the ESP’s simultaneously or separately.

Summary:o 100 wells with dual ESP’s in the world.o Provide back-up for one another.o Can produce multiple zones are same time.

Q. What is the probability that the 2nd ESP will start?A. If there is infant mortality, there may be a problem. If the 1st unit is OK, the 2nd until us usually OK too.

Q. What is the percentage of failed units?A. There have not been enough failures to havestatistics. Experience has been very good.

Q. What is the run life of the 2nd system?A. If the 1st unit is OK, the 2nd is normally OK. For the 2nd unit, we expect +/- 75% of the run life of the 1st unit.

Q. Do you use a traditional “Y” tool?A. Some are different.

Q. Is the thermal energy different for the upper and lower ESP’s?

A. This hasn’t been a problem.

Q. Do you run the 1st unit to failure before switching to the back-up unit?

A. Normally run the lower ESP to failure and then run the upper one.

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Use of Multi-stage Cen-trifugal Sur-face Pumping Systems to Optimize CO2 EOR inMature Fields

Neil Ferrier(Wood Group ESP)

Tim McGowanWood Group ESP

Neil Ferrier of Wood Group (ESP) (GE Oil and Gas) gave this presentation on multi-stage surface pumping systems for CO2 fields.

Introduction:o Using ESP’s on the surface.o Gulf of Mexico – Denbury Reservoir

Background:o These fields are in the top 5 in the lower 48 U.S. states.o Use CO2 enhanced oil recovery.o Used in 13 fields.o CO2 is produced in the Jackson Dome, in Mississippi.o The Field was developed by Shell in the 1980’s.o Was re-developed in 2000’s.

Requirements:o Need to boost CO2 pressure in the pipeline to 1,400 psi.o The CO2 critical point is at 1070 psi at 80 oF.o The CO2 properties change rapidly as temperature

changes.o The pump design is complicated by the pumping condi-

tions. Pilot test:

o Conduct a 24/7 operation with no standby.o Must be flexible to adapt to seasonal changes.o Must have minimum maintenance, minimum downtime.

Application:o 900 psi suction pressure, 1,400 psi discharge pressure.o 18 MMSCFD at 65 oF.o 29 stage pumps, special seals.

Pilot results:o Uptime was good.o Seals – had to change the seal type.

Experience since 2003:o More than 100 units installed.o Have re-cycle facilities.o Use a mobile unit for injection in some fields/wells.o Built a new transfer pipeline to Houston.o Now have some industrial clients.o Expanded system and only had two days downtime

during expansion process.o Use VSD’s to accommodate changes in requirements.o Tractor-mounted units:

Use VSD’s. Can increase pressure if needed for a project.

Conclusions:o There are power savings relative to using a compres-

sor.o Save $200,000 per year, $20 MM over life of project.o Reduced maintenance relative to compressors. $2,000

per year vs. $30,000 for compressors.

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o Have been able to standardize on equipment.

Q. Is the intake in liquid form?A. It is always in liquid form. It must be a liquid.

Q. Do you need special bearing lubrication with CO2?A. Yes.

Q. Do you need any change to pumps to handle CO2?A. No.

Q. Do you operate at 60 Hz?A. We use a VSD and operate between 55 and 60 Hz.

Q. Do you have problems with elastomers?A. We have to change the “O” rings.

Q. When do you need to use a booster pump?A. Not sure.

Successful Application of ESP’s In Bo-hai Bay Devel-opment

Ed Sheridan(Baker Hughes)

Dr Zia JanjuaESP Expertise Ltd;

Jim McRaeSanjay Paranji,Michael LongAnadarko Petro-leum Corpora-tion

Ed Sheridan of Baker Hughes Centrilift gave a presentation on use of ESP’s in Bohai Bay, offshore China.

Introduction:o The field in in Bohai Bay, offshore China.o It’s in 25 meter water depth.o Development started in 1999.o First production was on 2004.o Then there were 30 ESP’s, 6 platforms, production

flows to an FPSO.o There are 3 manned platforms.o Now there are 125 ESP’s.o Cumulative production has been 100 MM barrels of oil.o The wells are horizontals.o The crude is 12 – 20 oAPI, 30 – 425 cP.o The water cut is 90%.

ESP applications:o Contract was given to Baker Hughes Centrilift.o Hired a consultant.o The contract has shared risks and rewards.o They use performance monitoring and optimization.o It is essential to measure to be able to optimize.

Challenges:o Production ranges from 2,000 – 9.000 B/D per well.o Have target run life of 3 – 5 years.o Needed lots of front-end planning.o Needed lots of training.o Use VSD and downhole sensors.

Equipment from Baker Hugheso Abrasion resistant technology.o Use reservoir control valves.

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o Use CAN system.o Use intake sensors.o Still using the same system 8 years later.o Have added discharge sensors.o Worked to reduce inventory.o Use 3 designs, 3 ranges.o Use downhole gauge for pressure transient analysis.o Use special start-up procedures.

Change 1 Hz. each 5 minutes up to 3h Hz. Then move to VSD control.

o Work to maximize run life: Maximum speed allowed is 60 Hz. Temperature is 130 oC.

Summary:o For 180 wells, have 3.5 year average run life.o The longest has been 7 years.o Training is on-going.o Plan to continue the same process.o Focus on communication with the partners.

Q. What are the primary failure mechanisms?A. Electronics due to transients. Also had problems with penetrators.

Q. Do you have water/oil emulsions?A. One well had a problem. Used chemical injection to address it. There was no appreciable increase inviscosity due to the emulsion.

Q. Why did you change use of the CAN?A. To reduce cost on request by Anadarko.

Q. Why did the Anadarko wells perform better than the Cono-coPhillips wells in the same field?

A. A better sand control system was used.

Q. Why limit the speed to a maximum of 80 Hz?A. Operating between 35 Hz and 60 Hz gives good performance. There is increased sand production if go above 60 Hz.

Q. Did you notice mobility of the solids?A. There was some production of fines. The sandcontrol stopped the production of sand. Get some skin with the movement of fines. This is a small effect with the limited drawdown.

ESP Optimiza-tion in Natu-rally Fractured Horizontal

Keith Fang-meier(Hess)

William McNabb

Hess Corporation presented this story about innovative use of ESP’s in a North Dakota field.

Introduction:o This field is in North Dakota.

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Wells through the use of ESP Design Tech-nology, High Resolution Data Acquisi-tion, Surface Controls, andInnovative VSD Control Logic

Jeff SmithLogan StonerHESS Corpora-tion

Dana SanderBaker Hughes Centrilift

o There is H2S and CO2 gas with the production.o The field was discovered in April, 1951.o 200 wells were drilled.o A water flood began in 1959 and was stopped in 1971.o In 1998 they started drilling horizontal wells.o They first used gas-lift, but production declined.o Then they decided to try ESP’s.o The initial ESP’s had a 3-year run life.o In 2009 they installed more ESP’s.o Production is more than 200 B/D per well.o They inject batch chemicals to control corrosion.

High resolution SCADA system:o Use 1 minute data sample rate to evaluate well and

pump performance.o Have gas slugging.o Use dynamic control to control the wells.

Use PID control and monitor intake temperature. Need to carefully control the system to respond to

varying inputs. Need upfront protection. Need to improve efficiency.

Looking at another well:o Well is completed toe up and has slugging.o Need high-speed SCADA to monitor and control the

VSD.o Need very close control.

A third well:o It produces differently and needs different control logic.

Summary:o Installed three ESP wells this year.o Each well is (very) different.o Need real-time SCADA on each wall to optimize its

monitoring and control.

Q. Do use you shrouds on the pumps?A. We try to keep the design simple. So we don’t use any shrouds.

Q. You scan data at one-minute intervals?A. SCADA gives us one-minute data. The system gets updates once every 5 seconds. We communicate with the wells using cell phone technology.

Q. Do you control on casing pressure and tubing pressure?A. We are concerned with the motor so we perform real-time control using the VSD.’

Advanced ESP Comple-tion for New Field develop-

Miguel Hi-dalgo(Schlumberger)

This alternative paper was not presented.

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ment

Dual Comple-tion with a Permanent Magnet ES-PCP and a Sucker-Rod Pump

Fedor Galkin(Borets)

R. NavoBorets-Weather-ford

F. KormakovN. LunevPK Borets

This alternative paper was not presented.

Breakout Summary

Four break-out sessions were held – two on Wednesday afternoon and two on Thurs-day afternoon. These are the brief sum-maries of these ses-sions

ISO ESP Docu-mentShauna Noonan

Deviated Slug-ging WellsBill Bowlin

ISO Document for ESP’s.

Deviated Slugging Wells

Optionso Drill a rat hole

Standard or slanted. Use recirculating pump. Use gas separator. Challenging to get it drilled.

o No rat hole Use a rotary gas separator. Use a dip tube. Use a tail pipe. Use an inverted shroud. Install a liner to the toe of the well. Drill a 2nd vertical well to intersect the toe and pro-

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ESP Surveil-lanceJeff Dwiggins

Electrical IssuesSal Grande

duce the liquid. Place an auger in the horizontal to induce turbu-

lence.

ESP Surveillance

40 people attended the session. Discussed benefits of surveillance. It is needed. Newer technology is helping ot make it easier to use. There was good interactive discussion.

Electrical Issues

31 people attended Topics discussed:

o Power.o Lightning and surge protection.o Grounding.o Surface equipment.o Safety.o Power factor.

Closing Comments

2011 ESP Workshop Closing Com-ments

Closing Com-mentsRafael Lastra

Summary of Workshopo Three continuing education courses were offered

ESP 101 ESP 102 VSD’s

o Five Technical Presentation sessions were held 72 Abstracts were received 27 Technical Presentations were given

o Four Breakout Sessions were heldo Thirty Technical Exhibits were offered.

Attendanceo 560 people attended the Workshop – a record.o 60% were from the U.S.A.

18 States represented. Most from Texas, Oklahoma, California

o 40% were from international locations. Central and South America Africa Europe Middle East

Door prizes

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o Excellent door prizes were given before or after each technical session.

o The grand prize, a laptop computer, was given at the end of the closing session.

o Greg Stephenson of ConocoPhillips was the winner.

2011 ESP Workshop

Documents

Transcript of 2011 ESP Workshop