Enhanced Coalbed Methane Recovery presented by: Scott Reeves Advanced Resources International Houston, TX SPE Distinguished Lecture Series 2002/2003 Season Advanced Resources International 1
Outline • Introduction • ECBM Process • Pilot Projects • Economics • Closing Remarks 2
Introduction • Enhanced coalbed methane recovery (ECBM) involves gas injection into coal to improve methane recovery, analogous to EOR. • Typical injection gases include nitrogen and carbon dioxide. • Relatively new technology - limited field data to gauge effectiveness. • Growing interest in carbon sequestration spurring considerable R&D into integrated ECBM recovery/carbon sequestration projects. 3
Integrated Power Generation, CO 2 Sequestration & ECBM Vision Power Plant CO 2 /N 2 CH 4 CO 2 /N 2 CH 4 CH 4 CH 4 Deep, Unmineable Coal CH 4 CH 4 CH 4 CH 4 CO 2 /N 2 CH 4 4
U.S. CO 2 -ECBM/Sequestration Potential CO 2 Sequestration Potential (Gt) ECBM Potential (Tcf) Replace- Injection Injection for Incremental ment for CO 2 Incremental Recovery of Primary ECBM in Sequestra-tion Recovery in Recovery “Com- in “Non- % in “Non- % Volume mercial” Commer-cial” Total of “Commer- Commercial” Total of Basin Area Area (Gt) Total cial” Area Area (Tcf) Total N. Appalachia 0.8 0.3 2.3 3.4 4% 1.7 13.0 14.7 10% C. Appalachia 0.1 0.0 0.0 0.1 0% 0.5 0.0 0.5 0% Black Warrior 0.4 0.1 0.4 0.8 1% 1.0 2.2 3.1 2% Illinois 0.1 0.0 1.2 1.4 2% 0.2 3.8 4.0 3% Cherokee/ Forest City 0.4 0.1 0.3 0.9 1% 0.5 0.9 1.4 1% Arkoma 0.1 0.0 0.0 0.1 0% 0.4 0.1 0.5 0% Gulf Coast 0.7 0.4 0.9 1.9 2% 0.7 1.7 2.4 2% San Juan 7.0 2.3 1.1 10.4 12% 11.4 4.3 15.7 10% Raton 0.4 0.1 0.0 0.6 1% 1.4 0.1 1.5 1% Piceance 0.5 0.3 1.5 2.4 3% 3.6 10.5 14.0 9% Uinta 1.6 0.3 0.0 1.9 2% 0.1 0.2 0.3 0% Greater Green River 3.0 1.3 3.5 7.9 9% 3.5 15.0 18.5 12% Hanna-Carbon 1.4 0.6 1.0 3.0 3% 1.5 2.4 3.9 3% Wind River 0.8 0.3 0.3 1.4 2% 0.8 0.6 1.5 1% Powder River 3.3 1.8 8.5 13.6 15% 3.4 16.2 19.6 13% Western Washington 0.7 0.3 1.3 2.3 3% 0.7 2.9 3.6 2% Alaska 18.0 8.1 11.7 37.7 42% 19.2 27.8 47.0 31% TOTALS 39.3 16.3 34.0 89.8 100% 50.6 101.7 152.2 100% 5
Outline • Introduction • ECBM Process • Pilot Projects • Economics • Closing Remarks 6
Gas Storage in Coal (CBM 101) • Dual-porosity system (matrix and cleats) • Gas stored by adsorption on coal surfaces within matrix (mono-layer of gas molecules, density approaches that of liquid) • 1 lb coal (15 in 3 ) contains 100,000 – 1,000,000 ft 2 of surface area • Pore throats of 20 –500 angstrom • Production by desorption, diffusion and Darcy flow (3 D’s of CBM production) 7
Example Coal Sorption Isotherms 700.0 San Juan Basin coal CO 2 /CH 4 ratio = 2:1 Carbon Dioxide 600.0 N 2 /CH 4 ratio = 0.5/1 Absolute Adsorption (SCF/ton) CO 2 /N 2 ratio = 4:1 500.0 400.0 Methane 300.0 200.0 Nitrogen 100.0 0.0 0 200 400 600 800 1000 1200 1400 1600 1800 2000 Pressure (psia) 8
Variability of CO 2 /CH 4 Ratio CO2/CH4 Sorption Ratio vs Coal Rank Sub HV HVA MV LV 14 100 psi 12 1000 psi CO2/CH4 Ratio y = 2.5738x -1.5649 10 3000 psi R 2 = 0.9766 8 6 4 2 0 0.36 0.56 0.76 0.96 1.16 1.36 1.56 1.76 1.96 Coal Rank, Vro (%) 9
N 2 -ECBM Recovery Mechanism • Inject N 2 into cleats. • Due to lower adsorptivity, high percentage of N 2 remains free in cleats: � Lowers CH 4 partial pressure � Creates compositional disequilibrium between sorbed/free gas phases • Methane “stripped” from coal matrix into cleat system. • Methane/nitrogen produced at production well. • Rapid N 2 breakthrough expected. 10
CO 2 -ECBM Recovery Mechanism • Inject CO 2 into cleats. • Due to high adsorptivity, CO 2 preferentially adsorbed into coal matrix. � Methane displaced from sorption sites. • Methane produced at production well. • Efficient displacement process – slow CO 2 breakthrough. 11
Modeling Sensitivity Study 2 1 • San Juan Basin setting (3000 ft, 40 ft coal, 10 md). • Inject C0 2 and N 2 at rates of 10 Mcfd/ft, 25 Mcfd/ft 3 and 50 Mcfd/ft. • 15 year period. 4 5 Quarter 5-Spot Well Pattern 12
Gas Production Response – N 2 Injection 10000 70 60 50 Nitrogen Content, % Gas Rate, Mscfd Incremental Recoveries: 40 10 Mcfd/ft – 0.6 Bcf (21%) 1000 25 Mcfd/ft – 1.1 Bcf (39%) 30 50 Mcfd/ft – 1.6 Bcf (57%) 20 10 100 0 0 1000 2000 3000 4000 5000 Days Base Case Injection @ 25 Mcfd/ft Base Case Injection @ 25 Mcfd/ft 50 Mcfd/ft Injection @ 10 Mcfd/ft Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft Injection @ 50Mcfd/ft 13
Gas Production Response – CO 2 Injection 10000 Gas Rate, Mscfd Incremental Recoveries: 1000 10 Mcfd/ft – 0.1 Bcf (4%) 25 Mcfd/ft – 0.4 Bcf (14%) 50 Mcfd/ft – 0.8 Bcf (29%) •No CO 2 breakthrough •CO 2 /CH 4 ratio is 2:1 whereas N 2 /CH 4 ratio is 0.5/1 100 0 1000 2000 3000 4000 5000 Days Base Case Injection @ 25 Mcfd/ft Base Case Injection @ 25 Mcfd/ft Injection @ 10 Mcfd/ft Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft Injection @ 50Mcfd/ft 50 Mcfd/ft 14
Outline • Introduction • ECBM Process • Pilot Projects • Economics • Closing Remarks 15
Only Two “Large-Scale” Field Tests Exists Worldwide • San Juan Basin, Upper Cretaceous Fruitland Coal • Allison Unit • Burlington Resources • Carbon dioxide injection • 16 producers • 4 injectors • 1 pressure observation well • Tiffany Unit • BP • Nitrogen injection • 34 producers • 12 injectors 16
Field Sites, San Juan Basin ARCHULETA LA PLATA CO. Durango Pagosa Springs Florida River Plant N 2 Pipeline San Juan Tiffany Unit Basin Outline F A I R WA Y COLORADO NEW MEXICO Dulce Allison Unit Aztec Farmington Bloomfield R 17
Allison Unit Base Map 61 104 111 101 12M 106 112 114 130 142 115 POW#2 131 141 108 113 140 102 120 143 132 121 119 62 18
Well Configurations Producer Injector 19
Allison Production History 2,000,000 4,000 Peak @ +/- 57 MMcfd 16 producers, 4 injectors, 1 POW 1,800,000 3,500 Line pressures reduced, wells recavitated, wells reconfigured, onsite compression installed 1,600,000 3,000 Individual Well Gas Rate, Mcf/d 1,400,000 Injectivity reduction 2,500 1,200,000 Rates, Mcf/mo 1,000,000 2,000 800,000 1,500 600,000 Gas Rate, Mcf/mo CO2 Injection Rate, Mcf/mo 1,000 400,000 Well Gas Rate, Mcf/d 500 200,000 +/- 3 1/2 Mcfd 0 0 Jan-89 Jul-89 Jan-90 Jul-90 Jan-91 Jul-91 Jan-92 Jul-92 Jan-93 Jul-93 Jan-94 Jul-94 Jan-95 Jul-95 Jan-96 Jul-96 Jan-97 Jul-97 Jan-98 Jul-98 Jan-99 Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Date 20
Site Description Property Value Average Depth to Top Coal 3100 feet No. Coal Intervals 3 (Yellow, Blue, Purple) Average Total Net Thickness 43 feet Yellow – 22 ft Blue – 10 ft Purple – 11 ft Permeability 100 md Initial Pressure 1650 psi Temperature 120°F 21
Progression of CO 2 Displacement (@ mid-2002) Butt Cleat Face Cleat N 22
Incremental Recovery Incremental Total CO 2 CO 2 Recovery Injection Production Total Methane CO 2 /CH 4 (Bcf) (Bcf) (Bcf) Recovery (Bcf) Ratio Case W/o CO 2 injection 100.5* n/a n/a n/a n/a W/CO 2 injection 102.1 1.6 6.4** 1.2 3.2 *6.3 Bcf/well Small incremental recovery due to limited injection volumes. ** 20 Mcfd/ft INJECTIVITY IS CRITICAL! Note: OGIP for model = 152 Bcf. 23
Tiffany Unit Base Map Previous Study Area Producer-to-Injector Conversions 24
Well Configurations Producer Well Multiple Injector Wells 25
Tiffany Production History Peak @ 26 MMcfd 1,000,000 34 producers, 12 injectors +/- 5MMcfd 100,000 Gas Rates, Mcf/mo 10,000 Injection initiated 1,000 Gas Rate, Mcf/mo Suspension periods N2 Injection Rate, Max Inj Rate = 26 MMcfd Mcf/mo 100 3 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 1 2 8 8 8 8 8 8 8 9 9 9 9 9 9 9 9 9 9 0 0 0 - - - - - - - - - - - - - - - - - - - - p p p p p p p p p p p p p p p p p p p p e e e e e e e e e e e e e e e e e e e e S S S S S S S S S S S S S S S S S S S S Date 26
Site Description Property Value Average Depth to Top Coal (A) 2970 feet No. Coal Intervals 7 total (A, A2, B, C, D, E, F) 4 main (B, C, D, E) Average Net Thickness 47 feet B – 13 ft C – 11 ft D – 9 ft E – 14 ft Permeability <5 md Initial Pressure 1600 psi Temperature 120°F 27
Progression of N 2 Displacement (@ mid-2002) Butt Cleat Face Cleat N 28
Current Field Results (through mid-2002) Incremental Total N 2 N 2 Recovery Injection Production Total Methane N 2 /CH 4 (Bcf) (Bcf) (Bcf) Recovery (Bcf) Ratio Case W/o N 2 injection *35.3 n/a n/a n/a n/a W/N 2 injection 45.8 10.5 14.0** 1.3 1.2 *1.0 Bcf/well At N 2 /CH 4 ratio of 0.75:1 and reproduced volume of 25%, ultimate incremental recovery estimated ** 46 Mcfd/ft to be +/- 14 Bcf or 40% improvement over primary. Note: OGIP for model = 438 Bcf. 29
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