presented by: andrew mabian pecten cameroon company subsidiary of shell e&p int’l prepared by:

1ASME Gas Lift workshop - 2001

PRESENTED BY:

ANDREW MABIAN

PECTEN CAMEROON COMPANY

Subsidiary of SHELL E&P Int’l

PREPARED BY:

ANDREW MABIAN

PECTEN CAMEROON COMPANY

SAM WILDMAN

ALTEC GAS LIFT, INC

ALTECGAS LIFT

ISO 9002 Certified

“A PRACTICAL APPROACH TO OPTIMIZING A MATURING FIELD”

2

MOKOKO ABANA CONCESSION

FIELD LAYOUT

3


FIELD BACKGROUND

*Drilling of the field initiated 1982.

*9 platforms set and drilled 1982-1990.

*12 platforms by 1997.

*11 producing platforms.

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FIELD BACKGROUND

*80 producing wells.

*4 natural flowing wells.

*74 gas lifted wells.

*2 ESP wells.

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FIELD BACKGROUND

Infrastructure upgraded 1997

•Pumps and compressors installed down field on Echo platform to lower production pipeline pressure.

•2 ESP pumps installed 2000.

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PRE-OPTIMIZATION 1/1/2000

INDIVIDUAL WELL TEST INDICATED FIELD CAPABLE OF PRODUCING

•26,000 BOPD.

•63,000 BWPD

•45,510 MCFPD FORMATION

•34,000 MCFPD GAS LIFT INJECTION

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PRE-OPTIMIZATION 1/1/2000

DAILY AVERAGE PRODUCTION

•24,000+ BOPD.

•58,152 BWPD

•42,009 MCFPD FORMATION

•31,385 MCFPD GAS LIFT INJECTION

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PROBLEM DISCUSSION

Gas Lift valves and stock located onshore.

•Setup and calibration performed onshore by vendor.

•2 weeks cycle time from problem identification to remedial action.

Gas lift valve calibration - Cycle time inefficient

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ACTION/RESULTS

•Purchased and installed valve calibration unit offshore.•Moved valve inventory to offshore location.•Altec technician trained Pecten personnel in valve calibration

•Time lapse from identification to implementation cut to few hours.•Valves tested for stem travel.•Check valve integrity tested.•Check valve function ability checked. •Designed for port sizes identified and adhered to.•Valves flexed and aged previous to final calibration.

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PROBLEM DISCUSSION

Appropriate tool to run pressure gauges not existing - common practice was to choke / shut-in well until

gauges were at lowest point, then re-open well.

•Well test taken during survey not representative due to the above.

•Annular fluid levels - not available.

Down hole problem identification - More survey data needed

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ACTION/RESULTS

•Purchased Anti-blowup tools.•Purchased Echometer for annular fluid level identification.•Offshore personnel trained on the use of above mentioned tools.

•More Flowing surveys are being performed.•Test data more accurate.•Annular fluid levels taken on every gas lifted well: 17 wells found not to be lifting at lowest possible point.•Pecten purchasing Shell Line for real time surface readout pressure data gathering and surveillance enhancement.

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PROBLEM DISCUSSIONInjection gas pressure low - Best wells in North field

EXCESS GAS

980# 3,945

MCFPD990# 725

MCFPD

1000#

990# 5,860

MCFPD

980# 4,303

MCFPD

970# 2,546

MCFPD

OIL SALES

930# 2,255

MCFPD

900# 2,590

MCFPD

900# 1,137

MCFPD

890# 3,454

MCFPD

880# 4,641

MCFPD

840# 3,728

MCFPD

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ACTION/RESULTS

•Revised gas lift designs for platforms nearest compression point to preserve pipeline pressure.•Replaced orifice valves with live valves to:1 - Prevent casing bleed down during system upsets2 - Get full benefit of gas lift pressure•Optimized injection gas to each well as per Winglue projection.•Recovery time after system upsets improved. ( eliminated re-pressuring of annular areas )•Reduced injection gas volumes to high water cut wells.•Improved available injection gas volumes/pressures in North field.

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PROBLEM DISCUSSION

•Recovery time is delayed by re-pressuring wells after systems upsets.

•High water cut wells located nearest compression point take priority when coming back online.

Manual onsite well by well allocation of gas lift gas

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ACTION/RESULTS

•Developing system to provide computer control of gas volume.•Installing gas lift automation on platforms and wells.

•Gas lift Automation System commissioned.•FieldWare GasLift application for remote monitoring and control of gas lifted wells/lift gas allocation in place.

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PROBLEM DISCUSSION

•Earlier attempts at surface injection gas optimization had not been successful.

•Recommended field wide gas lift allocation - not successful.

Surveillance process - Needed improvement

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ACTION/RESULTS•Altec technician trained all field personnel in basic gas lift principles, optimization, trouble shooting techniques.•Altec technician visited each platform with senior operator - Discussed each well focussing on:1 - Injection gas pressure available on platform2 - Wells with freezing problems across manual control valve3 - Wells that require manipulation to kick-off•Staffed well analyst position offshore.

•Buy in from:* Production operators* Operations foremen* Production advisors* Engineering

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PROBLEM DISCUSSION

•Wells would not kick-off after extended shut-downs due to:

1 - Improper gas lift valves designs

2 - Large ported valves used

•Incorrect thermal gradients data used in simulations/analysis.

Extended kick-off time after compressors shut downs

Freezing at injection gas control valves

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ACTION/RESULTS

•Reviewed gas lift designs and implemented changes.•Designed gas lift with IPO valve as operating valve.

•Eliminated methanol injection on “C” and “D” platforms.•Reduced cycle time after systems upsets and platform shut-downs. •Increased operating casing pressure allowing better recovery time.

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PROBLEM DISCUSSION

•Wells producing less than 200 BFPD required a high GLR to keep them in stable flow.

Low rate wells using excess gas lift gas

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ACTION/RESULTS

•Checked annular fluid levels for all wells.•Modeled wells for intermittent lift application.•Installed Altec 1” ABBA(TM) pilot valve along with standing valve in intermittent lift candidates.

•Averaged 17% increase in oil production from candidates wells.•Averaged 22% decrease in injection gas to candidate wells.

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PROBLEM DISCUSSION

•Most wells have more than one selective isolated between packers.

•Zones produced individually - Production not optimized.

Multi zones production

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ACTION/RESULTS

•Set standing valve between zones when lower interval is lower pressure:* Preventing cross flow during shut-ins / production.*Allows multiple zones to remain open and contribute as pressures allows.

•More sands produced through same conduit, depleting reserves in a more timely manner.•Zones commingled with standing valves have exceeded modeled production rates and reserves estimations

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Summary / Results

Optimization training and calibration facility setup June/July 2000

Well work proceeded October 2000 ( 45 wells program )

Well work approximately 75% completed

Results to date are as follows:•1573 BOPD gained•-1374 MCFGPD less injection required•Quicker recovery time after upsets•Average daily production above 26,000 BOPD

More efficient surveillance process

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PROBLEM DISCUSSION

•Evaluate and address Risks

•Establish Benchmarks

•Test operation and measure results

Possible to use Simultaneous G/L and ESP?

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I-8 ESP and Gas Lift - Completion sketch

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Risks

Ingress of gas to cable - explosive decompression causing damage==> Lead sheathed cable (REDALEAD size 4, galv armor)

Ingress of gas through field splice/pothead==> No field splice - cable splice done in factory before shipping

QCI penetrator==> Checked gas tolerant within expected conditions

Critical issue is pressure bleed down of casing==> Sought advice from REDA, applied additional factor to avoid bleeding pressure down too quickly.


I-8 Completion design: Cable issues

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I-8 ESP and Gas Lift

ESP + gas lift Gas lift ESP + gas liftESP

I-8 ESP and Gas Lift trial

0

200

400

600

800

1000

1200

1400

1600

5/26/01 5/27/01 5/28/01 5/29/01 5/30/01 5/31/01 6/1/01 6/2/01 6/3/01 6/4/01 6/5/01 6/6/01 6/7/01

Time

BPD

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Flowing Pressure during Trial

Intake (flowing) pressure at pump

900920940960980

100010201040106010801100

5/25/01 5/27/01 5/29/01 5/31/01 6/2/01 6/4/01 6/6/01 6/8/01

Date

Pre

ss

ure

(p

si)

ESP only ESP + G/L ESP + G/LG/L only

BHP lowered only slightly with ESP+gas lift(Higher BHP with gas lift only)

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Water Cut - 2001

I-8: Water cut vs. time

0

0.1

0.2

0.3

0.4

0.5

9/Jan/01 29/Jan/01 18/Feb/01 10/Mar/01 30/Mar/01 19/Apr/01 9/May/01 29/May/01 18/Jun/01

Date

Wa

ter

cu

t

Steady increase in water cut vs. time

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Recommendations

Continue trial on I-8 to validate water cut trends

Test on “gas lift only” again (once water cut stable)to validate water cut trends with different drawdowns

Possible to apply ESP+G/L technique on other platforms ifwell productivities exceed pump capacities

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PROBLEM DISCUSSION

•Well work data, well model files, installation drawings or designs - not consolidated.

•Data files incomplete and not updated.

Wells data files - Incomplete

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ACTION/RESULTS

•Build electronic well summary for each well.•Performed well work is reported and available onshore electronically.•Winglue database is maintained on a shared drive in network.•Databases are checked for accuracy before use.

•Common and correct/updated database accessible by all.•Migration to WellView software to capture lessons learned.

presented by: andrew mabian pecten cameroon company subsidiary of shell e&p int’l prepared by:

Documents

gas lifted wells

esp wells

valve inventory

pressure gauges

check valve integrity

test data

orifice valves

live valves