Coal-Seq VII. CO 2 in Coal Seams and Gas Shale Reservoirs

Transcription

1 Illinois Basin: Tanquary CO 2 (Coal) Injection Pilot Scott M. Frailey Illinois State Geological Survey Coal-Seq VII Seventh International Forum on Geologic Sequestration of CO 2 in Coal Seams and Gas Shale Reservoirs March 7-8, 2011 Houston, Texas Midwest Geological Sequestration Consortium

2 Acknowledgements The Midwest Geological Sequestration Consortium is funded by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) via the Regional Carbon Sequestration Partnership Program (contract number DE-FC26-05NT42588) and by a cost share agreement with the Illinois Department of Commerce and Economic Opportunity, Office of Coal Development through the Illinois Clean Coal Institute. The Midwest Geological Sequestration Consortium (MGSC) is a collaboration led by the geological surveys of Illinois, Indiana, and Kentucky Schlumberger and Landmark Graphics software via University Program and Schlumberger Carbon Service for technical consultation Gallagher Drilling, Inc. field operation partner

3 Tanquary ECBM Pilot Test Purpose: To determine the CO 2 injection and storage capability, and the ECBM recovery potential of Illinois Basin coal Single Coal Seam CO 2 (gas) Injection Test Injection of up to 200 tons of CO 2 depending di on injectivity i i rate and monitoring well results Pressure above CH 4 adsorption pressure

4 The Coal Springfield Coal, high volatile bituminous rank 7 feet thick at 900 ft depth; 385 psig Undersaturated; scf/ton (dmmf); >92% CH 4 w/ lesser N 2 and CO 2 CO 2 adsorption isotherm 3x CH 4 Well developed cleats; 1-2 cm spacing Calcite and/or kaolinite filling

5 DST Results Perm 2 to 7 md Skin +5 to +8 FSIP= 391 psi Depth: 896 ft Normal pressure (0.433 psi/ft)

6 DST Anomaly (Repeatable) 1 st three wells have unique pressure 450 characteristic th 350 DST designed with 300 water cushion to gwater provide back pressure Hypothesis that 50 pressure dependent 0 permeability or gas desorption pressure is causing this feature. Pressure, psig Inj 1 Springfield Coal Time, hours Noticeable inflection point in curvature of pressure-time plot

7 The Well Arrangement Four Wells Monitoring well (M-3) Central injector Ground water Monitoring well Monitoring well (M-2A) Face cleats Butt Butt cleat cleat ats ats Ground water Monitoring well Injection well (I-1B) Ground water Monitoring well Monitoring well (M-1) Ground water Monitoring well One, 100 ft face cleat observation well Two, butt cleat observation wells 50 and 100 ft All Wells Cased to TD and Cemented to Surface

8 Well Completion Perforation 6 shots per foot Pictures: 60 phasing 3/8 diameter Acid 9% formic acid 250 gallon 1000 gallon water 1250 gallons swabbed Schlumberger Glossary

9 CO 2 Storage Tank and Pump Skid

10 Injection Equipment & Wellhead

11 Injection and Storage Equipment Well Layout Parallels Cleat Orientations in Near-by Wabash Mine Monitoring well (M-3) Coal Mine Cleat Orientations portable generator Ground water Monitoring well booster pump pump skid CO 2 storage tank Butt 98-5 utt cleat engineer heater Ground water Monitoring well Ground water Monitoring well tool trailer Ground water Monitoring well Face cleat Injection well (I-1B) 52-4 Monitoring well (M-2A) office trailer Monitoring well (M-1) Tanquary Field ECBM Site Plan and Equipment Layout Updated

12 Pilot Schedule Overview Water Injection tests: June 17-20, 2008 CO 2 Injection started: June 25, 2008 Pressure transient t tests t through h July 17, 2008 CO 2 Injection ended: January 14, 2009 Water Injection tests: t November 2009-May 2010 Pressure Transient Tests: falloff and pulse Step rate tests Production Tests: September November 2010 Site P&A-December 2010

13 Pre-CO 2 Water Pressure Transient Testing: Injection-falloff tests Analytical Models Equivalent Permeability: md d(44 (4.4 md, average) Skin: -1.9 to -3.4 Acid treatment reduced skin Pulse tests Average permeability anisotropy: 8.33:1 Permeability anisotropy aligned with well locations (confirmed mine observation of cleat orientation)

14 CO 2 Pressure Transient Testing Series of CO 2 injection transients or pulses followed by shut-in periods Week 1: three 8 hours injection pulses Week 2: two 12 hour injection pulses Week 3: three 24 hour injection pulses Several multiday operational shut-ins Near end of CO 2 injection, another series of pressure transient periods with CO 2

15 CO 2 Pressure Transient Testing 2 g CO 2 Effective Permeability 0.5 md 0.6 md 1.3 md 3.6 md 2.5 md

16 CO 2 Pressure Transient Testing 2 g Observation Well Responses Fastest, largest pressure response in Face Cleat direction

17 Continuous CO 2 Injection: Cumulative Injection 100 tons (tons/day) In njection Rate /9 9/29 10/19 11/8 11/28 12/18

18 Continuous Injection Injectivity (rate/ p) Injectivity Index Composite Rate (to ons/day) Composite Rate Composite Injection Index I1B BHP BH Pressure (psig g) / Inj Index I1B /9 9/29 10/19 11/8 11/28 12/18 1/7 Time (Central Daylight Time) -500

19 Interpretation t ti of Injection Injection rate: decreased over several weeks; followed by relatively constant rate Injectivity: Includes effects of pressure buildup, injectivity decreases over only a few days Perm reduction due to coal swelling? After shut-in, relative high rates returned; perm reduction not obvious directly from field data Analytical model shows CO2 effective permeability increases To be verified with numerical modeling

20 Observation Wells Early Gas Detection CH 4 gas at M-1 and M-3 within hours of CO 2 injection CO 2 at M-1 within a month of injection at 11-13% 13% and remained constant M-3 no CO 2 M-2 water only Monitoring well (M-2A) Monitoring well (M-3) Face cleats Butt Butt clea clea ats ats Ground water Monitoring well Injection well (I-1B) Ground water Monitoring i well Monitoring well (M-1)

21 Gas Column in Observation Wells 1 st Gas Withdrawal Gas production (prior to extended injection period) Gas removed from two butt cleat wells: 220 scf and 50 scf No CO 2 detected t d Pressure above adsorption pressure, free gas via competitive desorption from CO 2 In situ water returned to each well.

22 Gas Column in Observation Wells 2 nd Gas Withdrawal Four months after CO 2 injection CO 2 concentration 2 M-1: spiked to 95% M-2: spiked to 90% M-3: spiked to 70% Observations Subsequently all CO 2 concentration lowered Water did not return to wells

23 Interpretation t ti of Gas Detection ti ECBM (mmscf-ch 4 / ton CO 2 ) CH 4 competitively desorbed via CO 2 above the desorption pressure of CH 4 Production rates via numerical modeling CO 2 Storage (ton CO 2 / ton coal) Estimate plume size and coal volume Based on numerical modeling

24 Post-CO 2 Injection 2 j Water Pressure Transient Testing Lower rates and higher injection pressure Direct field observation: water injection rate slightly lower than pre-co 2 water injection rate Possibilities Coal swelling Gas/water relative permeability effect Slightly greater skin factor

25 Permeability Comparison: Effective Permeability to Water Well I-1b M-1 M-2 M-3 Avg Pre- CO 2 Post CO 2 Preliminary

26 Rate (Pressure) Dependent Permeability IVE (PSI/ST B/D) 10 1 DP & DERIVAT Delta-T (hr) Multiple falloff tests as part of a pulse test Perm range 0.64 to 1.4 md

27 Rate (Pressure) Dependent Permeability Perme eability, m Water Injection Rate, bwpd Preliminary

28 Permeability Anisotropy: Pulse Tests (Analytical Solution) k butt butt / k face k butt md k face md k eq md Pre-CO Post CO 2 Preliminary

29 Fracture Pressure: Step Rate Tests Pre-CO2 Step Rate Test M-3 Post-CO2 Step Rate Tests All wells

30 Fracture Pressure: Step Rate Tests Well Pre- Post- CO 2 CO 2 I-1b Rate v Pressure M (psi) Pressure M M Rate (gpm) Preliminary

31 Additional Tests and Data to be Analyzed In situ gas content and desorption pressure Water withdrawal tests Gas production and sampling CO 2 pulse tests: storativity

32 Work Remaining i Finalize pressure transient analyses Changes to compressibility (storativity) Pressure dependent permeability Numerical modeling ECBM Storage Analytical results verification Interpret t withdrawal/production d ti data

33 Tanquary ECBM Pilot Summary Cumulative injected 100 tons Sustained Rate tons per day Field observations Liberated methane from CO 2 CO 2 and dch 4 first detected d in low perm direction i Face cleat well gas detected only after small drawdown No indication of reduced injectivity after first few days of injection

34 Tanquary ECBM Pilot Summary, contd. Preliminary interpretation of post-co 2 water pressure transient tests permeability reduced Indicates coal swelling, relative permeability effect, or near wellbore damage Fracture gradient higher in CO 2 injection well compared to pre-co 2 injection (in M1)

35 Tanquary Pilot Staff Dave Morse: drilling/coring logistics, gas content, geology, coal characterization John Rupp, Maria Mastalerz: lab experiments Satya Harpalani: laboratory experiments Jim Kirksey: pilot coordination, operations Damon Garner: database management/ analyses Ivan Krapac, Abbas Iranmanesh, Bracken Wimmer: water and gas sampling Keith Hackley and Joe Chou: gas analyses

36 Tanquary Pilot Staff Mike Dodd: pump operations Kevin Wolfe: data acquisition, site logistics, data analyses Steve Sargent: data acquisition Andrew Anderson: COMET Modeling Gallaghers: field operations and logistics, drilling and completion design Trimeric Corp: equipment design Gary Crawford: pressure transient analyses

37 Publications SPE SPE

38 Illinois Basin: Tanquary CO 2 (Coal) Injection Pilot Scott M. Frailey Illinois State Geological Survey Coal-Seq VII Seventh International Forum on Geologic Sequestration of CO 2 in Coal Seams and Gas Shale Reservoirs March 7-8, 2011 Houston, Texas Midwest Geological Sequestration Consortium