32 nd Gas-Lift Workshop The Hague, The Netherlands February 2-6, 2009 MLTH CIM Retrofit Gaslift System for TLP wells SCSSV Presenter: Abi Babajide Contributors: Johnnie Garrett, Jim Hall DHPG 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).
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 2009 Gas-Lift Workshop 2
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 Challenge Tubing 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. 2009 Gas-Lift Workshop 3
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 2009 Gas-Lift Workshop 4
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 2009 Gas-Lift Workshop 5
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. 2009 Gas-Lift Workshop 6
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. Shut in well loads up Unload to flare Put in LP production system Watercut at start of unload ~45%. When well unloaded, watercut settles at ~20-25% 2009 Gas-Lift Workshop 7
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 2009 Gas-Lift Workshop 8
Prosper match at various water cuts Well seems unstable past 40% w/c 2009 Gas-Lift Workshop 9
Different Designs evaluated 1 2 3 4 2009 Gas-Lift Workshop 10 Chosen: Option #4
Design #4 Chosen: Tubing Punch with Packoff Design Tubing Punch with packoff Tubing packoff design with approximate dimensions 5.5 Weatherford wireline retrievable packer A casing 5.5" tubing 2.98" ID 3.5" OD X-over 5.5 PES BB X 2.875 SCSSV ~ 20' 1.99" ID 2.375" OD ~ 7' 2.5" ID 2.875" OD Tubing packoff ~ 2' 1.99" ID 2.375" OD gaslift mandrel 2 3/8 Slimhole (SMOR-1A) Gaslift Mandrel 2.98" ID 2nd Tubing packoff? 3.5" OD packer Pack-off Stinger 5.5 Weatherford wireline retrievable packer 2009 Gas-Lift Workshop 11
MLTH 5 1/2 x 7 1/16 @ 4,078 MD/TVD MLTH @ 4,302 MD/TVD Additional Information CIM SCSSV DHPG RPT XN Prepared by: JP Stricker Date: 8/04/03 7 1/16 x 5 12 @ 7,440 MD (7,432 TVD) CIM @ 7,918 MD (7,891 TVD) SCSSV @ 7,992 MD (7,959 TVD) 10 7/8" x 8 5/8" crossover @ 8,707 MD (8,576 TVD) 4 1/2 x 5 1/2 tubing crossover @ 16,972 MD (12,655 TVD) 8 5/8 49# x 8 5/8 57.4# crossover @ 17,168 MD (12,747 TVD) DHPG @ 27,531 MD (18,173 TVD) HPH production packer @ 27,655 MD (18,242 TVD) RPT nipple @ 27,766 MD (18,305 TVD) Telescoping joint @ 27,768 MD (18,306 TVD) Note: Base of sub-yellow sand is @ 27,786 MD. Circulating ports @ 27,787 MD (18,316 TVD) HPW packer @ 27,791 MD (18,319 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. 8 5/8 shoe @ 28,150 MD (18,520 TVD) VBA packer @ 28,591 MD (18,791 TVD) Upper S RBCD (Upper Aqua Terra Cotta) perfs (12 spf): 28,790 28,900 MD (18,923 18,998 TVD) Frac packed with 132,378# 20/40 Carbolite, 1,189 #/ft MD and 53 blan VBA packer @ 28,908 MD (19,004 TVD) XN nipple @ 28,926 MD (19,016 TVD) Lower S RBCD (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 showe top of screen. NWD sump packer @ 29,018 MD (19,080 TVD) PBTD: 29,097 MD (19,136 TVD) 6 5/8 shoe @ 29,260 MD (19,252 TVD) TD: 29,320 MD (19,293 TVD) 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 2009 Gas-Lift Workshop 12
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 2009 Gas-Lift Workshop 13
Dynamic Modeling Tool Results N2 injection rate of 4mmscf/d (2800scf/min) Reservoir Pressure = 4500psi 7000 6000 5000 Liquid Rate (bfpd) 4000 3000 17000' and Pinj = 2000 14750' and Pinj = 2000 13500' and Pinj = 2000 12500' and Pinj = 2000 11500' and Pinj = 2000 10500' and Pinj = 2000 2000 1000 0 20% 30% 40% 50% 60% 70% 80% 100% Watercut Check: Can we kickoff the well from a dead state? 2009 Gas-Lift Workshop 14 Then, optimize lift depth
MLTH CIM SCSSV DHPG RPT Ursa MC 810 Well A-9 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 Pressure up on the tubing and punch a 0.75 hole in tubing at 5 above the bottom packer. XN Prepared by: JP Stricker Date: 8/04/03 2009 Baker Gas-Lift charge test Workshop of the 5 1/2" tubing. Shot Exit hole was also 0.75. 15 resulted in entry hole of 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) 2009 Gas-Lift Workshop 16
Gas Lift Pack-Off Installation Well Services Operations 1. 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. 2009 Gas-Lift Workshop 17
Operational Difficulties and Learnings Punching 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. 2009 Gas-Lift Workshop 18
Well Unload Crosby compressor back online. Trying to unload well to as min. backpressure as possible to flare. Will it unload?? Well appears to be loading up Started injecting nitrogen Unloading with nitrogen Well attempting to unload. BHP is coming up slightly, but temperature still increasing slightly ~200psi - @ system pressure ~50psi going to flare- liquids going to system, gas to flare At 80% dump on the single WEMCo we had running. Cut back on N2 to manage produced water. Crosby compressor shut down. Increased pressure on FWKO. Had to increase backpressure on test separator in order to dump to FWKO. 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? Managing increased backpressure by increasing N2 rate until N2 ran out about 1 hour after compressor shut down 2009 Gas-Lift Workshop 19
Compressor problems. Increase in backpressure from ~40psi to ~300psi. Well barely flowing since then. As slugging reduced, temperature started coming back up. Watercut ~50%. The well stopped slugging (red line) and stabilized. Rate ~5000bfpd from well @ ~50% watercut 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. 2009 Gas-Lift Workshop 20
Successful Well Unload Ursa A9 March 2008 Unload Down Hole Pressure Gauge (psi) 6000 5500 5000 4500 4000 3500 well put into system 25000 20000 15000 10000 5000 Rates (bpd) 3000 09-Mar-08 11-Mar-08 13-Mar-08 15-Mar-08 17-Mar-08 19-Mar-08 Date 0 Average Fluid Rate Average Oil Rate 2009 Gas-Lift Workshop 21
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 2009 Gas-Lift Workshop 22
32 nd Gas-Lift Workshop The Hague, The Netherlands February 2-6, 2009 Questions? 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).
32 nd Gas-Lift Workshop The Hague, The Netherlands February 2-6, 2009 Back Up 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).
MLTH CIM 5 1/2 x 7 1/16 @ 4,078 MD/TVD MLTH @ 4,302 MD/TVD 7 1/16 x 5 12 @ 7,440 MD (7,432 TVD) CIM @ 7,918 MD (7,891 TVD) MECHANICAL WELL SKETCH Current Status 7/24/2007 207' - (H&P 204) KB to MSL Datum: 89.97' - RKB to Load Shoulder Water depth: 3,797' Annulus Fluid: A 2% KCl & MEG (8,000 ft) 8.9 PPG CaCl2 B 14.0 PPG SBM/PAPH Tree: 5-1/8" 15M (4.688" QN) Production Riser: 14" 109# X80 Slot: 22 SCSSV SCSSV @ 7,992 MD (7,959 TVD) 10 7/8" x 8 5/8" crossover @ 8,707 MD (8,576 TVD) DHPG Gas Lift Pack-Off Assembly: Depth Description 14,759 4.10 Weatherford PB production packer 4.312 OD; 1.993 ID w/ offset bottom (13 cr) 0.75 hole punched in tubing at 4400# tension to retrieve. 14,790 14,763 2 3/8 13 cr Collar 0.42 long, 3.045 OD; 2.645 ID 14,763 2 3/8 x 9.9 13 cr pup joint 2.645 OD; 1.930 ID 4 1/2 x 5 1/2 tubing crossover 14,773 2 3/8 gaslift mandrel 6.68 long; 3.850 OD; 1.901 ID 1 gaslift orifice installed. @ 16,972 MD (12,655 TVD) 14,780 2 3/8 x 9.9 13 cr pup joint 2.645 OD; 1.930 ID 8 5/8 49# x 8 5/8 57.4# crossover @ 17,168 MD (12,747 14,790 2 3/8 13 cr Collar 0.42 long, 3.045 OD; 2.645 ID TVD) 14,790 2 3/8 x 3.9 13 cr pup joint 2.645 OD; 1.930 ID 14,794 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 ID 14,800 2 3/8 x 3.9 13 cr pup joint 2.645 OD; 1.930 ID 14,803 2 3/8 13 cr Collar 0.42 long, 3.045 OD; 2.645 ID DHPG @ 27,531 MD (18,173 TVD) 14,804 2 3/8 X landing nipple 0.97 long; 2.625 OD; 1.875 ID 14,805 Wireline entry guide 0.56 long; 3.750 OD; 1.993 ID HPH production packer @ 27,655 MD (18,242 TVD) RPT RPT nipple @ 27,766 MD (18,305 TVD) Telescoping joint @ 27,768 MD (18,306 TVD) Note: Base of sub-yellow sand is @ 27,786 MD. Circulating ports @ 27,787 MD (18,316 TVD) HPW packer @ 27,791 MD (18,319 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. 8 5/8 shoe @ 28,150 MD (18,520 TVD) XN Prepared by: JP Stricker Date: 8/04/03 Updated 7/30/07 by JMG VBA packer @ 28,591 MD (18,791 TVD) Upper S RBCD (Upper Aqua Terra Cotta) perfs (12 spf): 28,790 28,900 MD (18,923 18,998 TVD) Frac packed with 132,378# 20/40 Carbolite, 1,189 #/ft MD and 53 blank coverage. VBA packer @ 28,908 MD (19,004 TVD) XN nipple @ 28,926 MD (19,016 TVD) Lower S RBCD (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 showed sand coverage is above top of screen. NWD sump packer @ 29,018 MD (19,080 TVD) PBTD: 29,097 MD (19,136 TVD) Directional 6 5/8 shoe @ 29,260 MD (19,252 TVD) Straight hole... to 6, 300' MD (KOP) Build to 63 degrees...... at 10,000' MD to 20,600 MD TD: 29,320 MD (19,293 TVD) Drop to 55 degrees... at 21,200 MD to 28,000 MD Drop to 44 degrees... through TD at 29,320 MD 2009 Gas-Lift Workshop 25
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