mlth cim scssv retrofit gaslift system for tlp wells · vba packer @ 28,908’ md (19,004’ tvd)...

32nd Gas-Lift WorkshopThe Hague, The Netherlands

February 2 - 6, 2009

This presentation is the property of the author(s) and his/her/their company(ies).It may not be used for any purpose other than viewing by Workshop attendees without the expressed written permission of the author(s).

Retrofit Gaslift System for TLP wells

Presenter: Abi Babajide

Contributors: Johnnie Garrett, Jim Hall

CIM

SCSSV

MLTH

DHPG

Feb. 2 - 6, 2009 2009 Gas-Lift Workshop 2

Outline

• What is tubing punch and packoff gaslift system (a.k.a retrofit gaslift)? Application for TLP wells?

• Choosing a candidate well• Job design• Field Testing• Operation• Results


What is a Tubing Punch and Packoff Gaslift System?

Concept: Punch a hole in tubing, displace backside, set packoff assembly across punched hole with gaslift valve as part of packoff assembly, gaslift well through punched hole and gaslift valve.

The ChallengeTubing punch and packoff gaslift system as an “econo” gaslift system has long been done in shelf locations. Its application in a TLP environment has largely been untested, and poses a new set of challenges. This presentation will discuss the Ursa A9 tubing punch and packoff gaslift installation, what new technologies were employed, and the challenges and successes of the job. It’s application was the first for Shell at a TLP location in the Gulf of Mexico.


So, what’s different for TLPs versus Shelf locations?A few things to consider:• Equipment• Depth, Deviation• Cost• Annular gas volume*• Risks – HSE case*

What we did:• Identified well that could benefit from this operation (Ursa

A9) and designed job• Performed field testing• Put together HSE case• Implemented


Ursa TLP Overview• Set in 3,800 Feet of Water• Initial production 1999• 11 of the 24 Well Slots were Batch Set Across the Shallow Water Flow

Interval. • 11 DVA wells, completed between 1999 & 2004

Typical Ursa DVA well:– 18,000 - 29,000 ft MD– 5 ½” x 4 ½” tubing– Net feet 100-270ft, Perfs: 12-21 spf– Single or stacked zone sand control completions– Equipped with DHPG, SCSSV, Chem Inj Mandrel– No H2S tolerant tubing material currently installed– Gas lift mandrel in 1 well, installed in 2006*

• Crosby, Princess and Pastel Pink Subsea Tiebacks• Nameplate Capacity = 168 MBO/D, 40 MBW/D • and 540 MMCF/D• Peak Production: Total TLP (TG) 176 MBOPD, 326 MMSCFPD


Ursa A9 Well History• Well A-9 put on production in August-03 in the Aqua Terra-Cotta sand, fault block D. Is

the deepest measured depth well in the Gulf of Mexico at ~29,000’ MD• Peak rate from well was 20,677 bopd and 28.2 MMscfpd in Sept-03• Ramped up well wide open in LP system in June 2004• Well production uneventful until Feb-05 when it loaded up at a seemingly low water cut

(~ 17%). Prior to loadup, February well test was 6293 bopd and 12.6MMscfpd• Nitrogen bullhead intervention performed on the well in early March-05 to kick off the

well. Pumped two tubing volumes of nitrogen into the well twice without any success.• The well was finally brought back on production in April-05 after the BHP had built up

enough to facilitate flow with the help of a new unloading system (test separator pump)• Since then, well has loaded up several more times, requiring prolonged (1mo+) shut-ins

to reach the minimum observed SBHP to unload• Rig operations to pull the tubing and re-run with gas-lift mandrels were considered in

1Q-06 but ruled too risky. DRB ruled in favor of evaluating a “Tubing Punch” option to provide kick-off lift gas and minimize load-up time between shut-ins.

• Zone abandonment ruled out due to reserves left behind.• Well has a planned uphole recompletion to large reservoir.


Ursa A9 Well Unload (4/30/06 – 5/6/06)Wells loads up after shut ins. Unload in May 2006 – Took about 7 days to unload well to minimal backpressure (flare) before being able to flow well in production system (LP). Total gas flared ~20mmscf (~4mmscf/d). Total volume in system ~25,000 barrels fluid.

Unload to flare Put in LP production system

Shut in – well loads up

Watercut at start of unload ~45%. When well unloaded, watercut settles at ~20-25%


Ursa A9 Well Unload (7/23/06 – 8/2/06)Wells loads up after shut ins. Unload in July 2006 – Took about 11 days to unload well to minimal backpressure (flare) before being able to flow well in production system (LP). Total gas flared ~26mmscf (~2.5mmscf/d). Total volume in system ~33,000 barrels fluid.

Unload to flare Put in LP production system


Prosper match at various water cuts

Well seems unstable past 40% w/c


Different Designs evaluated…

1 2 3 4

Chosen: Option #4


Tubing Punch with packoff

SCSSV

A casing

5.5" tubing

Tubing packoff

2nd Tubing packoff?

Tubing packoff design with approximate dimensions

3.5" OD

2.375" OD

2.875" OD

gaslift mandrel

2.375" OD

3.5" OD

packer

2.5" ID

2.98" ID

2.98" ID

1.99" ID

1.99" ID

~ 7'

~ 2'

~ 20'

Design #4 Chosen: Tubing Punch with Packoff Design 5.5”Weatherford –

wireline retrievable packer

X-over 5.5”PES BB X 2.875”

2 3/8” Slimhole(SMOR-1A) Gaslift Mandrel

5.5”Weatherford–wireline

retrievable packer

Pack-off Stinger

Feb. 2 - 6, 2009 2009 Gas-Lift Workshop 12Prepared by: JP StrickerDate: 8/04/03

Upper SRBCD (Upper Aqua Terra Cotta) perfs (12 spf):28,790’ – 28,900’ MD (18,923’ – 18,998’ TVD)

CIM

SCSSV

MLTH

10 7/8" x 8 5/8" crossover @ 8,707’ MD (8,576’ TVD)

8 5/8” 49# x 8 5/8” 57.4# crossover @ 17,168’ MD (12,747’ TVD)

Top of 6 5/8” 35# Liner @ 27,844’ MD (18,348’ TVD)There is no 6 5/8” hanger or liner top packer, cement only.

PBTD: 29,097’ MD (19,136’ TVD)6 5/8” shoe @ 29,260’ MD (19,252’ TVD)

TD: 29,320’ MD (19,293’ TVD)

XN

DHPG @ 27,531’ MD (18,173’ TVD)

HPH production packer @ 27,655’ MD (18,242’ TVD)

Frac packed with 132,378# 20/40 Carbolite, 1,189 #/ft MD and 53’ blan

VBA packer @ 28,591’ MD (18,791’ TVD)

DHPG

RPT nipple @ 27,766’ MD (18,305’ TVD)

NWD sump packer @ 29,018’ MD (19,080’ TVD)

MLTH @ 4,302’ MD/TVD

CIM @ 7,918’ MD (7,891’ TVD)

SCSSV @ 7,992’ MD (7,959’ TVD)

8 5/8” shoe @ 28,150’ MD (18,520’ TVD)

RPTRPT

Telescoping joint @ 27,768’ MD (18,306’ TVD)

5 1/2” x 7 1/16” @ 4,078’ MD/TVD

7 1/16” x 5 12” @ 7,440’ MD (7,432’ TVD)

VBA packer @ 28,908’ MD (19,004’ TVD)

Lower SRBCD (Lower Aqua Terra Cotta) perfs (12 spf):28,962’ – 29,010’ MD (19,041’ – 19,075’ TVD)

Frac packed with 33,351# 20/40 Carbolite, 685 #/ft MD and log showetop of screen.

XN nipple @ 28,926’ MD (19,016’ TVD)

Circulating ports @ 27,787’ MD (18,316’ TVD)

HPW packer @ 27,791’ MD (18,319’ TVD)

4 1/2” x 5 1/2” tubing crossover@ 16,972’ MD (12,655’ TVD)

Note: Base of sub-yellow sand is @ 27,786’ MD.

Additional Information• Ran gradient survey. Fluid level below

SCSSV when well shut-in (~8505’ MD)• Watercut high during initial start up of well,

but drops over time as well unloads– Look at: Gaslift for kickoff versus Continuous

lift• Max injection gas pressure available on

platform ~1350psi (sales gas pressure). Need high pressure gas to lift if gaslift packoff set deeper than ~8100’ MD

• Will need to punch hole in 5.5” 23# 13Chrome tubing without damaging casing

• Install fairly big packoff in 5.5” tubing• Well angle builds up to ~63 degrees• If gaslift packoff set deep, will likely need

tractor to get to depth and operate setting tools


Job Design• Design for well lifecycle (reservoir pressures, watercuts, …) and

for good probability of successful installation• Operation will be done with electric line and slickline• Hole punch will be done with a punching tool rather than a

shaped charge, as this provides less risk of damaging the casing• If punch hole below SCSSV, only DHPG TEC line at risk• Packoff will be 2-7/8” x 3-1/2” with a 2-3/8” mandrel• 1” mandrel valve will be used for gas injection and can deliver

desired injection rates (varies over well life: ~ 2mmscf/d to 5mmscf/d)

• Nitrogen will be used for kickoff until Ursa gaslift case in place– Found nitrogen generation units that can deliver up to 10mmscf/d at

up to 95% N2 purity– Take platform uptime into account for economics on how often may

need to kickoff well


N2 injection rate of 4mmscf/d (2800scf/min)Reservoir Pressure = 4500psi

0

1000

2000

3000

4000

5000

6000

7000

20% 30% 40% 50% 60% 70% 80% 100%

Watercut

Liqu

id R

ate

(bfp

d) 17000' and Pinj = 200014750' and Pinj = 200013500' and Pinj = 200012500' and Pinj = 200011500' and Pinj = 200010500' and Pinj = 2000

Dynamic Modeling Tool Results

Check: Can we kickoff the well from a dead state?Then, optimize lift depth


Field Testing: Punch Tool•Kinley Perforator from Baker

•Punches hole through tubing without damaging casing per vendor reports

•Performed field trial

•Can fire tool with:

•Electronic firing head attached to connect to the e-line adapters.

•Mechanical firing head on slickline, with spang jars and shear pins

Prepared by: JP StrickerDate: 8/04/03

CIM

SCSSV

MLTH

XN

DHPG

RPTRPT

UrsaMC 810Well A-9

Pressure up on the tubing and punch a 0.75” hole in tubing at 5’ above the bottom packer.

Baker charge test of the 5 1/2" tubing. Shot resulted in entry hole of 0.75“.

Exit hole was also 0.75“.


HSE assessment

• Tubing Punch and Packoff gaslift option ALARP for TLP locations, under certain criteria. Keep in mind:– May not apply to sour wells– Need to define time/duration of equipment use in well,

especially if using less than 100% pure N2 (eg: from N2 generators)

– N2 for kickoff versus natural gas (natural gas may need separate HSE case for TLPs)


Gas Lift Pack-Off Installation Well Services Operations1. Rig up electric line equipment on to the well.2. Make a dummy/gauge run to tubing punch depth.3. Set bottom packer w/ landing nipple incorporated.4. Rig down electric line and rig up slickline.5. Set positive plug in the landing nipple.6. Rig down slickline and rig up electric line.7. Equalize the tubing and casing pressure at tubing punch depth.8. Run in the well and punch a ¾” hole in the 5.5” tubing just above the

bottom packer.9. Displace casing fluid through the perforation.10. Rig down electric line and rig up slickline.11. Equalize and retrieve bridge plug.12. Rig down slickline and rig up electric line.13. Set the gaslift pack-off assembly with the upper packer.14. Test the tubing.15. Rig down.


Operational Difficulties and LearningsPunching hole in tubing:• Several attempts made to activate tubing punch tool on electronic firing

head not successful. Ended up using mechanical firing head to activate tubing punch tool.

Setting Packoff assembly and top packer:• Attempted to sting into the lower packer. After 2 attempts at running

speeds of 50 and 75ft/min, activated tractor. Switched power relay to tractor mode, activated tractor and pushed assembly into lower packer. Stung in.

• Attempted to switch relay power back to electric line mode in order to fire charge to set upper packer. Could not switch back from tractor mode or communicate with tractor. Tests showed there was voltage going to eline.

• Pulled out at rope socket, rigged up braided line and fished assembly out of well.

• Inspection BHA. Eline vendors crossover spring conducting the electricity between eline tool and tractor tool overheated, couldn't handle the amperage load when the tractor was activated.

• Re-ran in hole on eline with packoff assembly with top packer and tractor using tractor vendors crossover. Activated tractor to sting assembly into bottom packer, switched back to eline mode and set top packer.


~200psi - @ system pressure

Well appears to be loading up

Started injecting nitrogen

Well attempting to unload. BHP is coming up slightly, but temperature still increasing slightly

At 80% dump on the single WEMCo we had running. Cut back on N2 to manage produced water.

Unloading with nitrogen

Crosby compressor shut down. Increased pressure on FWKO. Had to increase backpressure on test separator in order to dump to FWKO.

Managing increased backpressure by increasing N2 rate until N2 ran out about 1 hour after compressor shut down

Crosby compressor back online. Trying to unload well to as min. backpressure as possible to flare. Will it unload??

Watercut ~ 60%. Well unloading for about 42 hours. Total fluid so far ~10,000barrels of fluid. If can keep well flowing/unloading for long enough at enough rate, will we see watercut reduction?

~50psi – going to flare- liquids going to system, gas to flare

Well Unload


As slugging reduced, temperature started coming back up. Watercut ~50%. The well stopped slugging (red line) and stabilized.

Rate ~5000bfpd from well @ ~50% watercut

Compressor problems. Increase in backpressure from ~40psi to ~300psi. Well barely flowing since then.

Watercut came down from 60% to 50%. Total fluids produced so far ~ 26,000 barrels of fluid. Well has been flowing for about 6 days.


Successful Well Unload

Ursa A9 March 2008 Unload

3000

3500

4000

4500

5000

5500

6000

09-Mar-08 11-Mar-08 13-Mar-08 15-Mar-08 17-Mar-08 19-Mar-08

Date

Dow

n H

ole

Pres

sure

Gau

ge

(psi

)

0

5000

10000

15000

20000

25000

Rat

es (b

pd)

Average Fluid Rate Average Oil Rate

well put into system


Results

• Successfully installed tubing punch and packoff gaslift system

• Kicked off well with nitrogen from ~14,750’ MD• Restored production from a dead well to making an

average of 4000bopd• Achieved significant cost savings using this retrofit gaslift

system versus a well workover with gaslift mandrels• Additional cost savings achievable using nitrogen from

nitrogen generators at 99% N2 purity. Cost savings $1million+

• Another tool in our toolbox. Use it where applicable




Questions?




Back Up


MECHANICAL WELL SKETCHCurrent Status

7/24/2007



Directional

Straight hole ......... to 6, 300' MD (KOP)Build to 63 degrees ...….... at 10,000' MD to 20,600’ MDDrop to 55 degrees ........... at 21,200’ MD to 28,000’ MDDrop to 44 degrees ........... through TD at 29,320’ MD

Datum:

A 2% KCl & MEG (8,000 ft)8.9 PPG CaCl2

B 14.0 PPG SBM/PAPH

207' - (H&P 204) KB to MSL

Production Riser: 14" 109# X80

Annulus Fluid:

Tree: 5-1/8" 15M (4.688" QN)

Water depth: 3,797'

Slot: 22

89.97' - RKB to Load Shoulder

CIM

SCSSV

MLTH





TD: 29,320’ MD (19,293’ TVD)

XN

DHPG @ 27,531’ MD (18,173’ TVD)


Frac packed with 132,378# 20/40 Carbolite, 1,189 #/ft MD and 53’ blank coverage.

VBA packer @ 28,591’ MD (18,791’ TVD)

DHPG

RPT nipple @ 27,766’ MD (18,305’ TVD)



CIM @ 7,918’ MD (7,891’ TVD)

SCSSV @ 7,992’ MD (7,959’ TVD)

8 5/8” shoe @ 28,150’ MD (18,520’ TVD)

RPT


5 1/2” x 7 1/16” @ 4,078’ MD/TVD

7 1/16” x 5 12” @ 7,440’ MD (7,432’ TVD)

VBA packer @ 28,908’ MD (19,004’ TVD)


Frac packed with 33,351# 20/40 Carbolite, 685 #/ft MD and log showed sand coverage is above top of screen.

XN nipple @ 28,926’ MD (19,016’ TVD)


HPW packer @ 27,791’ MD (18,319’ TVD)



Gas Lift Pack-Off Assembly:Depth Description14,759 4.10’ Weatherford PB production packer 4.312” OD; 1.993” ID w/ offset bottom (13 cr)

4400# tension to retrieve.14,763 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,763 2 3/8” x 9.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,773 2 3/8” gaslift mandrel 6.68’long; 3.850” OD; 1.901” ID – 1” gaslift orifice installed.14,780 2 3/8” x 9.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,790 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,790 2 3/8” x 3.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,794 Anchor Seal Assembly 0.83’ long; 4.312” OD; 2.235” ID – 10,850# tension to retrieve.14,795 Weatherford PB production packer w/ straight bottom 4.10’ long; 4.312” ID; 1.993” ID –

4400# tension to retrieve.14,799 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,800 2 3/8” x 3.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,803 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,804 2 3/8” “X” landing nipple 0.97’ long; 2.625” OD; 1.875” ID14,805 Wireline entry guide 0.56’ long; 3.750” OD; 1.993” ID

Updated 7/30/07 by JMG

0.75” hole punched in tubing at 14,790’

MECHANICAL WELL SKETCHCurrent Status

7/24/2007



Directional

Straight hole ......... to 6, 300' MD (KOP)Build to 63 degrees ...….... at 10,000' MD to 20,600’ MDDrop to 55 degrees ........... at 21,200’ MD to 28,000’ MDDrop to 44 degrees ........... through TD at 29,320’ MD

Datum:

A 2% KCl & MEG (8,000 ft)8.9 PPG CaCl2

B 14.0 PPG SBM/PAPH

207' - (H&P 204) KB to MSL

Production Riser: 14" 109# X80

Annulus Fluid:

Tree: 5-1/8" 15M (4.688" QN)

Water depth: 3,797'

Slot: 22

89.97' - RKB to Load Shoulder

CIM

SCSSV

MLTH





TD: 29,320’ MD (19,293’ TVD)

XN

DHPG @ 27,531’ MD (18,173’ TVD)


Frac packed with 132,378# 20/40 Carbolite, 1,189 #/ft MD and 53’ blank coverage.

VBA packer @ 28,591’ MD (18,791’ TVD)

DHPG

RPT nipple @ 27,766’ MD (18,305’ TVD)



CIM @ 7,918’ MD (7,891’ TVD)

SCSSV @ 7,992’ MD (7,959’ TVD)

8 5/8” shoe @ 28,150’ MD (18,520’ TVD)

RPT


5 1/2” x 7 1/16” @ 4,078’ MD/TVD

7 1/16” x 5 12” @ 7,440’ MD (7,432’ TVD)

VBA packer @ 28,908’ MD (19,004’ TVD)


Frac packed with 33,351# 20/40 Carbolite, 685 #/ft MD and log showed sand coverage is above top of screen.

XN nipple @ 28,926’ MD (19,016’ TVD)


HPW packer @ 27,791’ MD (18,319’ TVD)



Gas Lift Pack-Off Assembly:Depth Description14,759 4.10’ Weatherford PB production packer 4.312” OD; 1.993” ID w/ offset bottom (13 cr)

4400# tension to retrieve.14,763 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,763 2 3/8” x 9.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,773 2 3/8” gaslift mandrel 6.68’long; 3.850” OD; 1.901” ID – 1” gaslift orifice installed.14,780 2 3/8” x 9.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,790 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,790 2 3/8” x 3.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,794 Anchor Seal Assembly 0.83’ long; 4.312” OD; 2.235” ID – 10,850# tension to retrieve.14,795 Weatherford PB production packer w/ straight bottom 4.10’ long; 4.312” ID; 1.993” ID –

4400# tension to retrieve.14,799 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,800 2 3/8” x 3.9’ 13 cr pup joint 2.645” OD; 1.930” ID14,803 2 3/8” 13 cr Collar 0.42’ long, 3.045” OD; 2.645” ID14,804 2 3/8” “X” landing nipple 0.97’ long; 2.625” OD; 1.875” ID14,805 Wireline entry guide 0.56’ long; 3.750” OD; 1.993” ID

Updated 7/30/07 by JMG

0.75” hole punched in tubing at 14,790’


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mlth cim scssv retrofit gaslift system for tlp wells · vba packer @ 28,908’ md (19,004’ tvd)...

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