1
Enhanced Coalbed Methane Recovery
presented by:
Scott Reeves
Advanced Resources International
Houston, TX
SPE Distinguished Lecture Series
2002/2003 Season
Advanced Resources International
2
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
Outline
3
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.
4
Power Plant
CO2/N2 CH4
CH4CH4
CH4
CH4CO2/N2
Deep, Unmineable Coal
CO2/N2
CH4
CH4 CH4
CH4
Integrated Power Generation, CO2Sequestration & ECBM Vision
5
U.S. CO2-ECBM/Sequestration Potential
100%152.2101.750.6100%89.834.016.339.3TOTALS
31%47.027.819.242%37.711.78.118.0Alaska
2%3.62.90.73%2.31.30.30.7Western Washington
13%19.616.23.415%13.68.51.83.3Powder River
1%1.50.60.82%1.40.30.30.8Wind River
3%3.92.41.53%3.01.00.61.4Hanna-Carbon
12%18.515.03.59%7.93.51.33.0Greater Green River
0%0.30.20.12%1.90.00.31.6Uinta
9%14.010.53.63%2.41.50.30.5Piceance
1%1.50.11.41%0.60.00.10.4Raton
10%15.74.311.412%10.41.12.37.0San Juan
2%2.41.70.72%1.90.90.40.7Gulf Coast
0%0.50.10.40%0.10.00.00.1Arkoma
1%1.40.90.51%0.90.30.10.4Cherokee/ Forest City
3%4.03.80.22%1.41.20.00.1Illinois
2%3.12.21.01%0.80.40.10.4Black Warrior
0%0.50.00.50%0.10.00.00.1C. Appalachia
10%14.713.01.74%3.42.30.30.8N. Appalachia
%of
TotalTotal(Tcf)
Incremental Recovery
in “Non-
Commercial”Area
Incremental Recovery
in “Commer-cial” Area
%of
TotalTotal(Gt)
Injection for CO2
Sequestra-tionin “Non-
Commer-cial”Area
Injection for
ECBM in “Com-
mercial”Area
Replace-ment
of Primary RecoveryVolume
Basin
ECBM Potential (Tcf)CO2 Sequestration Potential (Gt)
6
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
Outline
7
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 in3) contains 100,000 – 1,000,000 ft2
of surface area• Pore throats of 20 –500 angstrom• Production by desorption, diffusion and Darcy
flow (3 D’s of CBM production)
8
Example Coal Sorption Isotherms
0.0
100.0
200.0
300.0
400.0
500.0
600.0
700.0
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
Abs
olut
e A
dsor
ptio
n (S
CF/
ton)
Carbon Dioxide
Methane
Nitrogen
CO2/CH4 ratio = 2:1
N2/CH4 ratio = 0.5/1
CO2/N2 ratio = 4:1
San Juan Basin coal
9
Variability of CO2/CH4 Ratio
CO2/CH4 Sorption Ratio vs Coal Rank
y = 2.5738x-1.5649
R2 = 0.9766
02468
101214
0.36 0.56 0.76 0.96 1.16 1.36 1.56 1.76 1.96
Coal Rank, Vro (%)
CO
2/C
H4
Rat
io
100 psi1000 psi3000 psi
Sub HV HVA MV LV
10
N2-ECBM Recovery Mechanism
• Inject N2 into cleats.• Due to lower adsorptivity, high percentage of N2
remains free in cleats:Lowers CH4 partial pressureCreates compositional disequilibrium between sorbed/free gas phases
• Methane “stripped” from coal matrix into cleat system.
• Methane/nitrogen produced at production well.• Rapid N2 breakthrough expected.
11
CO2-ECBM Recovery Mechanism
• Inject CO2 into cleats.• Due to high adsorptivity, CO2 preferentially
adsorbed into coal matrix.Methane displaced from sorption sites.
• Methane produced at production well.• Efficient displacement process – slow CO2
breakthrough.
12
Modeling Sensitivity Study
• San Juan Basin setting (3000 ft, 40 ft coal, 10 md).
• Inject C02 and N2 at rates of 10 Mcfd/ft, 25 Mcfd/ft and 50 Mcfd/ft.
• 15 year period.
Quarter 5-Spot Well Pattern
1 2
4
3
5
13
Gas Production Response – N2 Injection
100
1000
10000
0 1000 2000 3000 4000 5000
Days
Gas
Rat
e, M
scfd
0
10
20
30
40
50
60
70
Nitr
ogen
Con
tent
, %
Base Case Injection @ 25 Mcfd/ft
Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft
Base Case Injection @ 25 Mcfd/ft
Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft50 Mcfd/ft
Incremental Recoveries:
10 Mcfd/ft – 0.6 Bcf (21%)
25 Mcfd/ft – 1.1 Bcf (39%)
50 Mcfd/ft – 1.6 Bcf (57%)
14
Gas Production Response – CO2 Injection
100
1000
10000
0 1000 2000 3000 4000 5000
Days
Gas
Rat
e, M
scfd
Base Case Injection @ 25 Mcfd/ft
Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft
Base Case Injection @ 25 Mcfd/ft
Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft50 Mcfd/ft
•No CO2 breakthrough•CO2/CH4 ratio is 2:1 whereas N2/CH4 ratio is 0.5/1
Incremental Recoveries:
10 Mcfd/ft – 0.1 Bcf (4%)
25 Mcfd/ft – 0.4 Bcf (14%)
50 Mcfd/ft – 0.8 Bcf (29%)
15
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
Outline
16
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
17
Farmington
Aztec
Bloomfield
Dulce
Durango PagosaSprings
COLORADONEW MEXICO
LA PLATA CO. ARCHULETA
R
Allison Unit
F A I RW
A Y
Florida RiverPlant
Tiffany Unit San Juan Basin Outline
N2 Pipeline
Field Sites, San Juan Basin
18
Allison Unit Base Map
143
141140
142
POW#2
104
101106
102
108
112
119
130
115
132
121
111
114
131
120
113
62
12M
61
19
Injector
Producer
Well Configurations
20
Allison Production History
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
Jan-
89
Jul-8
9
Jan-
90
Jul-9
0
Jan-
91
Jul-9
1
Jan-
92
Jul-9
2
Jan-
93
Jul-9
3
Jan-
94
Jul-9
4
Jan-
95
Jul-9
5
Jan-
96
Jul-9
6
Jan-
97
Jul-9
7
Jan-
98
Jul-9
8
Jan-
99
Jul-9
9
Jan-
00
Jul-0
0
Jan-
01
Jul-0
1
Date
Rat
es, M
cf/m
o
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
Indi
vidu
al W
ell G
as R
ate,
Mcf
/d
Gas Rate, Mcf/moCO2 Injection Rate, Mcf/moWell Gas Rate, Mcf/d
16 producers, 4 injectors, 1 POW
Line pressures reduced, wells recavitated, wells reconfigured, onsite compression installed
+/- 3 1/2 Mcfd
Peak @ +/- 57 MMcfd
Injectivity reduction
21
Site Description
3100 feet
3 (Yellow, Blue, Purple)
43 feetYellow – 22 ft Blue – 10 ftPurple – 11 ft
100 md
1650 psi
120°F
Average Depth to Top Coal
No. Coal Intervals
Average Total Net Thickness
Permeability
Initial Pressure
Temperature
ValueProperty
22
Progression of CO2 Displacement(@ mid-2002)
Face Cleat
ButtCleat
N
23
Incremental Recovery
n/an/an/an/a100.5*W/o CO2injection
3.21.26.4**1.6102.1W/CO2injection
CO2/CH4Ratio
CO2Production
(Bcf)
Total CO2Injection
(Bcf)
Incremental Recovery
(Bcf)Total Methane Recovery (Bcf)Case
*6.3 Bcf/well** 20 Mcfd/ft
Note: OGIP for model = 152 Bcf.
Small incremental recovery due to limited injection volumes.INJECTIVITY IS CRITICAL!
24
Tiffany Unit Base Map
Producer-to-Injector Conversions
Previous Study Area
25
Well Configurations
Multiple Injector Wells
Producer Well
26
Tiffany Production History
100
1,000
10,000
100,000
1,000,000
Sep-83
Sep-84
Sep-85
Sep-86
Sep-87
Sep-88
Sep-89
Sep-90
Sep-91
Sep-92
Sep-93
Sep-94
Sep-95
Sep-96
Sep-97
Sep-98
Sep-99
Sep-00
Sep-01
Sep-02
Date
Gas
Rat
es, M
cf/m
o
Gas Rate, Mcf/mo
N2 Injection Rate,Mcf/mo
34 producers, 12 injectors
Injection initiated
Suspension periods
+/- 5MMcfd
Peak @ 26 MMcfd
Max Inj Rate = 26 MMcfd
27
Site Description
2970 feet
7 total (A, A2, B, C, D, E, F)4 main (B, C, D, E)
47 feetB – 13 ftC – 11 ftD – 9 ftE – 14 ft
<5 md
1600 psi
120°F
Average Depth to Top Coal (A)
No. Coal Intervals
Average Net Thickness
Permeability
Initial Pressure
Temperature
ValueProperty
28
Progression of N2 Displacement(@ mid-2002)
Face Cleat
ButtCleat
N
29
Current Field Results(through mid-2002)
n/an/an/an/a*35.3W/o N2injection
1.21.314.0**10.545.8W/N2injection
N2/CH4Ratio
N2Production
(Bcf)
Total N2Injection
(Bcf)
Incremental Recovery
(Bcf)Total Methane Recovery (Bcf)Case
*1.0 Bcf/well** 46 Mcfd/ft
Note: OGIP for model = 438 Bcf.
At N2/CH4 ratio of 0.75:1 and reproduced volume of 25%, ultimate incremental recovery estimated to be +/- 14 Bcf or 40% improvement over primary.
30
Summary of Field Results
• Field results are in general agreement with theoretical understanding; reservoir models can reasonably replicate/predict field behavior.
• Low-incremental recovery with CO2 injection at Allison due to low injection volumes.
• CO2 injectivity key success driver; strong evidence that coal permeability (and injectivity) reduced with CO2injection.
• Incremental recoveries with N2 injection at Tiffany currently; estimated to provide 40% improvement over primary.
31
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
Outline
32
Hypothetical Field Setting (US onshore)
Example CBM BasinWell Injection Pattern
(4 Sections)
Conventional Recovery – 48 Bcf(2.5 Bcf/well)
Incremental Recovery – 16 Bcf(1 Bcf/well)
Sec. 6 Sec. 5
Sec.7 Sec. 8
33
Economics of CO2 ECBM
Hub Gas Price $3.00Less: Basin Differential ($0.30)
BTU Adjustment (@ 5%) ($0.15)Wellhead Netback $2.55
Less: Royalty/Prod. Taxes (20%) ($0.51)O&M/Gas Processing ($0.50)
Gross Margin $1.54Capital Costs(1) ($0.25)CO2 Costs (@ ratio of 3.0 to 1)(2) ($0.90)
Net Margin $0.39
(1) Capital Costs = $500,000 *4 (inj wells) = $2,000,000/16 Bcfg= $0.13/Mcfg * 2 = $0.25/Mcfg
(2) CO2 Costs = $0.30/Mcf * 3.0 = $0.90/Mcf (CO2)
US $/Mcf
34
Economics of N2 ECBM
Hub Gas Price $3.00Less: Basin Differential ($0.30)
BTU Adjustment (@5%) ($0.15)Wellhead Netback $2.55
Less: Royalty/Prod. Taxes (20%) ($0.51)O&M/Gas Processing ($1.00) (double over CO2
case)Gross Margin $1.04Capital Costs(1) ($0.25)N2 Costs (@ ratio of 0.5 to 1)(2) ($0.30)Net Margin $0.49
US $/Mcf
(1) Capital Costs = $500,000 * 4 (inj. wells) = $2,000,000/16 Bcfg= $0.13/Mcfg * 2 = $0.25/Mcfg
(2) N2 Costs = $0.60/Mcf * 0.5 = $0.30/Mcf (N2)
35
ECBM Economic Considerations
• N2 – ECBM appears favorable, but early breakthrough requires costly post-production gas processing.
• CO2 - ECBM also appears favorable, but maintaining injectivity a key success driver.
• More experience required to validate & optimize economic performance.
• CO2/N2 mixture may be optimum.High N2 concentrations early for rapid methane recoveryIncreasing CO2 concentrations later for efficient methane displacement.
36
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
Outline
37
Closing Remarks
• ECBM recovery appears to hold considerable promise; on the verge of commerciality with a bright future.
• CO2 sequestration economic drivers (carbon credits) will substantially improve financial performance and accelerate commercial adoption.
• In U.S., CO2-ECBM/sequestration potential is substantial; recently assessed at 90 Gt CO2 and 150 Tcf of incremental gas recovery.
38
Closing Remarks• More work is needed to economically optimize the process.
N2/CO2 mixturesCO2 injectivitySpacing, patterns, rates, etc.Reservoir settings (coal rank)
• Reservoir response is generally consistent with theoretical understanding of CO2/N2 processes.
Reasonable predictions of reservoir response possible.Informed investment decisions.
• Acknowledgements:U.S. Department of EnergyBurlington ResourcesBP America
• For more information:www.coal-seq.com
39
Enhanced Coalbed Methane Recovery
presented by:
Scott Reeves
Advanced Resources International
Houston, TX
SPE Distinguished Lecture Series
2002/2003 Season
Advanced Resources International
40
Well #132 Performance
0
500
1000
1500
2000
2500
3000
3500
4000
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
Days
CH
4 R
ate,
Msc
f
CO2 Injection No CO2 Injection
CH4 Recovery w/o CO2 injection = 6.1 BcfCH4 Recovery w/ CO2 injection = 6.9 BcfCH4 Incremental Recovery = 0.8 Bcf
0
500
1000
1500
2000
2500
3000
3500
4000
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
Days
CH
4 R
ate,
Msc
f
CO2 Injection No CO2 Injection
CH4 Recovery w/o CO2 injection = 6.1 BcfCH4 Recovery w/ CO2 injection = 6.9 BcfCH4 Incremental Recovery = 0.8 Bcf
41
Nitrogen Content of Produced Gas
0
2
4
6
8
10
12
14
< 1 1 - 10 10 - 20 20 - 30 30 - 40 40 - 50 > 50
Last N2 Concentration (%)
No.
Wel
ls
Average = 12.3 %
42
Matrix Shrinkage/Swelling
Source: “An Investigation of the Effect of Gas Desorption on Coal Permeability”, paper 8923, 1989 Coalbed Methane Symposium.
43
Relevant Formulas*
Pressure-Dependence Shrinkage/Swelling
*Used in COMET2. Alternative formulation presented by Palmer & Mansoori; SPE 36737, 1996.
φ = φi + φi Cp (P-Pi) + (1 - φi) Cm dPi
dCi
(C-Ci)
n
k = φi
φ n = +/- 3
44
Permeability Changes with Net Stress, Gas Concentration, and Sorptive Capacity
0
50
100
150
200
250
0 500 1000 1500 2000 2500 3000 3500
Pressure, psi
Perm
eabi
lity,
md Methane
Carbon Dioxide
Matrix Shrinkage Pressure Dependence
Sorption Capacity
45
Typical Injection Profile, Allison Unit
Well #143
0
10000
20000
30000
40000
50000
60000Ja
n-89
Jul-8
9
Jan-
90
Jul-9
0
Jan-
91
Jul-9
1
Jan-
92
Jul-9
2
Jan-
93
Jul-9
3
Jan-
94
Jul-9
4
Jan-
95
Jul-9
5
Jan-
96
Jul-9
6
Jan-
97
Jul-9
7
Jan-
98
Jul-9
8
Jan-
99
Jul-9
9
Jan-
00
Jul-0
0
Date
Rat
e
500
700
900
1100
1300
1500
1700
1900
2100
2300
2500
Pressure
CO2, Mcf/mo
BHP, psi
46
Permeability History for Injector
0
50
100
150
200
250
0 500 1000 1500 2000 2500 3000 3500
Pressure, psi
Perm
eabi
lity,
md
Start
Depletion
Displace w/ CO2ContinuedInjection
47
CO2 Sorption Behavior(Pc=1073psi, Tc=88ºF)
Source: SPE 29194: “Adsorption of Pure Methane, Nitrogen and Carbon Dioxide and their Binary Mixtures on Wet Fruitland Coal”, 1994.
48
0.0
100.0
200.0
300.0
400.0
500.0
600.0
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
Gib
bs A
dsor
ptio
n (S
CF/
ton)
N2 on Mixed CoalCH4 on Well #1CH4 on Well #10CH4 on Mixed CoalCO2 on Mixed Coal
Nabs = NGibbs1- ρgasρads
Pure Gas Gibbs Adsorption on Tiffany Coals at 130° F
49
CO2 Absolute Adsorption on Tiffany Mixed Coal Sample Using Different
Adsorbed-Phase Densities
0
100
200
300
400
500
600
700
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
Abo
slut
e A
dsor
ptio
n (S
CF/
ton)
1.181.251.40
Adsorbed Phase Density(g/cc)
Saturated liquid density at triple pointZGR estimateGraphical estimate
50
Multi-Component Sorption Behavior
Extended Langmuir Theory
Other Langmuir Models: Loading Ratio Correlation (LRC), Real Adsorbed Solution (RAS),
Ideal Adsorbed Solution (IAS)
Equations of State: Van der Walls (VDW), Eyring, Zhou-Gasem-Robinson (EOS-S, PGR)
Simplified Local Density Models: Flat Surface (PR-SLD), Slit (PR-SLD)
pL
pCi(pi) = , i = 1, 2, 3,…, n.
VLi pi
pLi 1 + Σn
j=1
51
Accuracy of Model Predictions for Pure Gas Adsorption
7.02.11.82.0Carbon Dioxide
6.02.32.33.5Nitrogen
3.03.02.32.6Methane
Experimental Error
ZGR-EOSLRC(n = 0.9)
LangmuirComponent
Quality of Fit, % AAD, for Specified Model
52
Accuracy of Model Predictions for Binary/Ternary Gas Adsorption
(based on pure-gas adsorption data)
14.027.05.05.0
55.921.617.64.3
44.55.2
15.85.4
47.820.713.22.9
N2 – CH4 - CO2:N2 (10%)CH4 (40%)CO2 (50%)Total
29.06.05.0
48.74.93.5
37.35.73.8
44.95.23.5
N2 – CO2:N2 (20%)CO2 (80%)Total
7.06.04.0
27.010.41.4
21.010.52.2
25.99.01.2
CH4 – CO2:CH4 (40%)CO2 (60%)Total
7.017.07.0
11.910.011.5
12.09.38.2
15.86.2
12.2
CH4 – N2:CH4 (50%)N2 (50%)Total
Experimental Error% AAD
ZGR-EOS% AAD
LRC(n=0.9)% AAD
Langmuir% AAD
Mixture,(Feed Mole %)
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