Swell Packer case histories. FORCE Stavanger, April 2004 Rune Freyer

Transcription

1 Swell Packer case histories FORCE Stavanger, April 2004 Rune Freyer

2 Contents Rubber swelling Swell Packer Constrictor Installations Applications

3 Rubber swelling Thermodynamic absorption rubber/oil Continued expansion until equilibrium Swelling pressure 3-6bar Reduced mechanical properties, not degradation No swelling in pure water Traces of oil in flowing water enough Swelling pressure measurement

4 Dimensions and design Fully flexible OD/base pipe dimensions Small clearance ( OD 8.5 hole)

5 DP (bar) Estimated/correlated P " base pipe 5.5" base pipe 6.625" base pipe 7" base pipe Simulation live Simulation dead Hole ID (inch)

6 Swell Packer for oil based mud Delays swelling to run in hole OBM at 106 C for 3days 3 layer construction 8 wells with 42 packers So far C 8,55 8,35 8,15 7,95 7,75 7,55 7,35 Oil Based Mud Crude 106º 20 C 76 C 106 C Diffusion barrier + Low swell Low swell outer layer WBM Packer D iffusion barrier looses effect 7,

7 Constrictor TM alternative to gravel pack Limit annular solids transport Avoid logistics, rig cost, fluids and risk Short (300mm) elements Slide onto base pipe Not a testable seal +/-6 and 8.5 OH Flexible OD Constrictor application

8 Splice less cable feed through Splice less application PS! Better installation tool designed shortly

9 Advantages Self repairing, continues to expand Rugged construction Set at BHST Logistics/setting No rig time, wash pipe, tools, pumping No environmental impact Track record

10 Applications CH straddle Gravel pack Replacement OH screen isolation OH straddle OH Carbonate Stimulation/ water control Mechanical inflow control Replace cement in reservoir / perf HPHT Multilateral junction Steam DTS control Gas wells OH Frac Expandable Smart Well

11 Installations 197packers installed in 43 wells 24 packers in 5 installations through windows 9 wells with 64 packers verified, no failure 41 packers installed in 8 wells in OBM OH carbonate frac Draw down test of integrity Norsk Hydro, Grane Statoil Heidrun gravel pack Statoil Snorre B smart well Statoil Gullfaks Sat smart well Shell Nigeria 3 zone smart well Shell Malaysia OH isolation Shell North Cormorant TTRD

12 The end (Or just the end of the beginning.)

13 Can use OBM - hole stability Avoid annular flow no plugging Robust screens Eliminate gravel pack - cheaper Liner hanger Sand screens Constrictor Swell Packer Repeat unit

14 Shell North Cormorant Cementing problems Slim hole sidetrack Intermittent blank and preperforated Oil based mud 110 C Dogleg in window 18deg

15 TTRD Achievements 2003 Past Achievements: Max KOP ft Max OH 3200 ft Hole sizes 4.5 to 5 Liner size 2 7/8 3.5 Bi-centre bit tech Slotted 2-7/8 Liner K-Formate Mud ARC3 Real Time PWD Improvements ROP Bits/Agitator Directional Control Casing Exits Equipment Mngmnt Mud (Micromax) Well Control (Radar) Abandonment Improvements: Mud (Micromax) Higher MWs >700pptf Well Control New philosophy Cementing A annulus isolations Spacers improved Cleanout improvements Improvements: SqueezeCrete success Zonal isolation with Swelling packers Eliminate clean-outs Eliminate perforating Well Complexity CN-18S5 CN-29S3 CN-13S1/2 CN-17S1 CA-28S3 BB-14S2 CN-24S2 CN-18S6 CN14S2 CN32S4 CN24S3 Well Cost PAST TTRD wells First 2 wells 2003 Second 2 wells 2003 Fifth well 2003 Tomorrow

16 CN24s3 A Step Change in TTRD design Swelling Packers Technology (EWS) CN24s3 - A first in UK North Sea and in TTRD application Eliminate cementing of 2-7/8 liner and subsequent clean-out of liner Potential for more effective zonal isolation in small hole sizes with high drawdown/differential pressures Elimination of cement debris following clean-up saving 350k 1,000k per TTRD well (15-30% of total well cost) Potential to eliminate perforating 400k 750k per TTRD well for CT Provide a step change in economics % increase in VIR for slim holes

17 North Cormorant 12 Day Wells CN24s3 5th Well of TTRD campaign producing 90% OIL HIGHLIGHTS Milled Dual Exit Window in one successful run. SqueezeCrete slurry exceeded expectations for cement repair Excellent performance - Shoe to shoe drilling days Avg ROP 48fph New technology BHA design 17.5deg DLS achieved with motor & agitator Micromax-weighted OBM. Lower ECD s and virtually NO sag! Swelling packers for zonal isolation cut down on rig time and good zonal isolation Swelling packers Eliminated cementing & CT perforating Good hole conditions through use of PWD tool. Lost Time Twist-off in NMDC however successfully fished in one run! Minor environmental discharge (0.6m3 oil) to sea consequential to OBM taken through production facilities CT had to be used with N2 in order to lift the well offline TODAY S REALITY 12 DAY WELL TIMES Swelling packers A Step change in performance Drilled Depth (feet) EXPECTATION 12d wells NORTH CORMORANT TODAY TTRD with swelling packers completion AFE CN24s3 Actual CN24s3 Possible with today's technology

18 Completion fluid for the screen section: 1,25 s.g. Na/K-COOH formate mud 30" casing shoe 18 5/8" casing shoe ZXP packer 1.06 s.g NaCl Brine Template funnel 10 3/4" liner Template 10 3/4" SC m MD (upper barrier) 10 3/4" tie-back string 10 ¾ top PBR Value: Shale intervals: m MD m MD m MD m MD m MD m MD m MD m MD m MD m MD m MD Reduced cost 800kUSD/well compared to ECPs 2 less runs Reduced risk for installation failures Increased production by reduced plugging Verified by PLT 13 3/8" casing shoe Top screen 2014,76 m MD Swell Packers on screen joints RA tracer sub Silver-110M RA tracer sub Cobalt-60 2 screen joints 3539 m MD iner hanger / ZXP - packer 2055,26 m MD (closed pos.) 10 3 /4" casing shoe 1.25 S.G. NaCl POLYMER BRINE 7" blank pipe 4 Swell Packers mounted on one joint of 7" blank pipe 7" screen section 9 1/2" open hole to 3540 m MD

19 Case 1: Swell Packers in Grane Emulsion 19API crude Demobilize shale particles in annulus Pressure isolation of screen annulus 800kUSD/two runs saved/well Heaven compared to inflatables (NH rigrep)

20 SABAH SHELL PETROLEUM CO. LTD FINAL WELL COMPLETION a.h.bthf Well No : SF-37 Location : SFJT-B Wellhead Type : Cameron Triple Wellhead + Single X Mas tree Tubing : 3.1/2 9.2# L80 K.Fox (Conventional S/String ) 13.3/8 Casing 949 Depth Date Completed : 4 th July 2003 All Depth in Ft. AH.BTHF Maximu m Dev. : ahbthf Long String 3.1/2 Flow Coupling 3.1/2 TRSCSSV Min ID /2 SPM /2 SPM 3.1/2 SPM 3.1/2 SPM 3.1/2 SPM 3.1/2 SPM Status Closed BKR-5 BKR-5 BKR-5 DKO-2 DM Y DM Y SF-37 Final Completion Diagram 6-18 Open Hole 5,7 Packer OD 3-1/2 Lower completion Top of 7 PBR /8 Casing /2 SSD 7 Seal stem located with half mule shoe /2 SSD Closed Closed SF37: Swell Packer Predrilled Tubing Swell Packer Blank Tubing Swell Packer /2 X-Nipple /2 X-Nipple Swell Packer Predrilled Tubing /2 X-Nipple Blank Tubing No Plug No Plug No Plug SF-37's water cut has come down from ~95% to 0! This is very good proof of the packers working! 5298 Swell Packer Predrilled Tubing Swell Packer /2 Bull nose /8 Open hole TD: 6784

21 Well No : SF-38 Location : SFJT-B Wellhead Type : Cameron Triple Wellhead + Single X Mas tree Tubing : 3.1/2 9.2# L80 K.Fox (Conventional S/String ) SABAH SHELL PETROLEUM CO. LTD FINAL WELL COMPLETION DIAGRAM@ ah.bdf Depth Date Co mp leted : 15 th July 2003 All Depth in Ft. 71 ft elevation Maximum Dev. : ahbdf Long String 3.1/2 Flow Coupling 3.1/2 TRSCSSV 3 1/2 SSD Min ID /8 Casing /2 SPM + BKR Top of /8 Casing 3484 Blank Tubing Min ID:2.992, Max. OD: Blank Tubing Min ID:2.992, Max. OD: ZONE-1A ZONE-1B ZONE-2 ZONE-3 Blank Tubing Min ID:2.992, Max. OD: ZONE-4 6 1/8 Open hole TD: /2 SPM + BKR-5 3.1/2 SPM + BKR-5 3.1/2 SPM + DKO-2 3.1/2 SPM + DMY 7 Seal stem located with half mule shoe Max OD /2 X-Nipple Swell Packer No Sand Screens Swell Packer No.2 3 1/2 SSD Blank Tubing Swell Packer No Blank Tubing Swell Packer No /2 SSD Swell Packer No Predrilled Tubing Swell Packer No.6 3 1/2 X-Nipple Swell Packer No Predrilled Tubing Swell Packer No /2 XN-Nipple Swell Packer No Predrilled Tubing Swell Packer No /2 Bull nose SF-38 Final Completion Diagram 1500 BOPD against 1400 promised 0% water cut Sand = 2 pptb 545 psi FTHP (so there's plenty of room to bean up from current 28/64") GOR = 238 scf/stb The GOR is VERY encouraging because there is a gas sand present. This GOR is LOWER than many Rev. 2 wells with more expensive completions.

22 SF Rev3 Budget versus EFC Cost Performance Well Cost RM' % 47 SF 39 SF 38 SF 37 - Budget EFC SF Average well cost comparison Savings on: Well Cost (RM Million) % Budget EFC 16 - Liners - Cement - Cleanout - ESS (now Poromax) - Scraper runs - Perforation runs - Packers 0 - Completion equipment Well cost Rev2 Well cost Rev3

23 Cost Performance SF Rev.2 and Rev.3 Benchmarking Cost per foot (Rm/ft) comparison Budget Actual (EFC) RM per ft % -29% 0 SF-31 SF-32 SF-33 SF-34 SF-35 SF-36 SF-37 SF-38 SF-39 Avg Rev2 Avg Rev3

24 Conclusions Significantly Cheaper Wells Installation relatively easy Production / Packer working very encouraging Can do even cheaper

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26 Snorre B Well D-4H Completion schematic Drawing: 1 Date: File: D-4Hcomplettering skisse.ppt Rev: 3 Clamps m MD Value: Packer depths: Casing depths: 13 3/8 : m MD Sand production Prod. Packer: expected 3192 m MDin perforations at water onset Iso. packer #1: 3586 m MD Liner depths: Reduced erosion risk of smart well equipment Iso. packer #2: 4116 m MD 9 5/8 liner: m MD No down hole Iso. packer operations #3: 4611 m MD during installation 7x5 1/2 screen: m MD Long packers ensure efficient sealing TOC = 3013 m MD Verified by downhole gauges Tubing: 7, 13 Cr-80, 29 lbs/ft NSCC 5 ½, 13 Cr-80, 20 lbs/ft Vam Top 5 ½, 13 Cr-80, 23 lbs/ft Vam Top 4 ½, 13 Cr-80, 13.5 lbs/ft NSCT 7 tubing 3192 m 3586 m 4116 m 4611 m Swell Packers 5 ½ 5 ½ 5 ½ 4 ½ Sone #1 Sone #2 Sone #3 Sone #4 Lunde

27 Case 2: Down hole test 8,15 OD WBM, 7 perforated liner 8-1/2 Open hole Coiled tubing deployed test plug Successfully inflow tested February 2003 P

28 Case 3: Isolation in Carbonates (1/3) 2380 meters horizontal reservoir section 9-5/8 Casing Shoe 8-1/2" Hole WBM, 7.9 OD 5-1/2 preperforated liner

29 Case 3: Isolation in Carbonates (2/3) 3-1/2 Inner isolation string (2.992 ID) WBM 4,4 x 3-1/2-4m SSD (OD , ID )

30 Case 3: Isolation in Carbonates (3/3) 9-5/8 Casing Shoe 8-1/2" Hole 3.5" tubing 5-1/2" Perforated liner Liner Annulus Isolation Tubing Liner Isolation Isolated and controlled production interval

31 Hole ID DP [bar] % Swell Packer simulations Differential pressure profile % % For: % Date: % By: % % % 3000 Input % ipe OD in 127 mm % acker OD in 143 mm % DP [Psi] % 3567 own hole viscosity 1.50 cp % 2842 ole ID in mm % perational pressure 50 bar % % % 522 Output % 0 inal OD (20bar DP) in mm % olume swell % at Hole ID 106% Hole ID 56.0 [in] % 232 ime to fully set max DP 35 days % ime to operational pressure N/A days % ime to first seal 15 days % P at "Hole ID" 212 psi 15 bar a % Swell profile 66.0 % % Input % 30 able OD 0.25 in mm % umber of cables 2 Insufficient rubber thickness % % ressure calculations are based on failure pressure of a 3m long element, modified with 20% safety factor % longer packer will enable higher differential pressure but exact correlations are not mapped % iming of swelling process will vary dependent of fluid circulation and is based on WBM construction % iming of swelling in gas may be estimated by EWS BM construction will take longer time % WS advise designs with differential pressure exceeding simulated limitations also allowing for washouts % % Oil Field Units SI Units % emperature F 138 C 5 ase pipe wt 12.6 ppf 18.8 kg/m ase pipe length 19.7 ft 6m 0 lement length 9.8 ft 3m acker weight excl pipe 26.2 lbs 11.9 kg acker mass lbs kg Hole ID [in] Time to seal Time to fully set acker volume ft^ % Differential pressure [bar] Time to swell [days] Differential pressure [Psi]

32 Splice less cable feed through Competent formation One string No cable splicing at packers