Enhanced Coalbed Methane Recovery - Advanced Resources ...

Enhanced Coalbed Methane Recovery
presented by:
Scott Reeves
Advanced Resources International
Houston, TX
SPE Distinguished Lecture Series
2002/2003 Season
1
Advanced Resources International

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
CH 4
CO 2 /N 2
CH 4
CH 4 Deep, Unmineable
Coal
CH 4
CH 4
CH 4
CH 4
CH 4
CO 2 /N 2
4

U.S. CO 2 -ECBM/Sequestration Potential
CO 2
Sequestration Potential (Gt)
ECBM Potential (Tcf)
Basin
Replacement
of Primary
Recovery
Volume
Injection
for
ECBM in
“Commercial”
Area
Injection for
CO 2
Sequestra-tion
in “Non-
Commer-cial”
Area
Total
(Gt)
%
of
Total
Incremental
Recovery
in
“Commercial”
Area
Incremental
Recovery
in
“Non-
Commercial”
Area
Total
(Tcf)
%
of
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
Cherokee/ Forest City
0.1
0.4
0.0
0.1
1.2
0.3
1.4
0.9
2%
1%
0.2
0.5
3.8
0.9
4.0
1.4
3%
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
600.0
CO 2
/CH 4 ratio = 2:1
N 2
/CH 4
ratio = 0.5/1
San Juan Basin coal
Carbon Dioxide
Absolute Adsorption (SCF/ton)
500.0
400.0
300.0
200.0
CO 2
/N 2
ratio = 4:1
Methane
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
CO2/CH4 Ratio
14
12
10
8
6
4
2
0
Sub HV HVA MV LV
y = 2.5738x -1.5649
R 2 = 0.9766
0.36 0.56 0.76 0.96 1.16 1.36 1.56 1.76 1.96
Coal Rank, Vro (%)
100 psi
1000 psi
3000 psi
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
1 2
3
• 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
and 50 Mcfd/ft.
• 15 year period.
4
Quarter 5-Spot Well Pattern
5
12

Gas Production Response – N 2 Injection
10000
70
60
Gas Rate, Mscfd
1000
Incremental Recoveries:
10 Mcfd/ft – 0.6 Bcf (21%)
25 Mcfd/ft – 1.1 Bcf (39%)
50 Mcfd/ft – 1.6 Bcf (57%)
50
40
30
20
Nitrogen Content, %
10
100
0 1000 2000 3000 4000 5000
0
Days
Base Case Injection @ 25 Mcfd/ft
Injection @ 10 Mcfd/ft
Injection @ 50Mcfd/ft
13

Gas Production Response – CO 2 Injection
10000
Gas Rate, Mscfd
1000
Incremental Recoveries:
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
Injection @ 10 Mcfd/ft
Injection @ 50Mcfd/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
LA PLATA CO.
ARCHULETA
COLORADO
NEW MEXICO
Durango
Florida River
Plant
F A I R W A Y
N2 Pipeline
Tiffany Unit
Pagosa
Springs
San Juan
Basin Outline
Allison Unit
Dulce
Aztec
Farmington
Bloomfield
R
17

Allison Unit Base Map
61
104
111
12M
106
112
101
130
142
114
POW#2
115
108
131
141
113
140
132
143
120
102
121
119
62
18

Well Configurations
Injector
Producer
19

Individual Well Gas Rate, Mcf/d
Allison Production History
2,000,000
1,800,000
1,600,000
1,400,000
16 producers, 4 injectors, 1 POW
Injectivity reduction
Line pressures reduced, wells recavitated, wells
reconfigured, onsite compression installed
Peak @ +/- 57 MMcfd
4,000
3,500
3,000
1,200,000
2,500
1,000,000
2,000
800,000
1,500
600,000
400,000
Gas Rate, Mcf/mo
CO2 Injection Rate, Mcf/mo
1,000
Well Gas Rate, Mcf/d
200,000
+/- 3 1/2 Mcfd
500
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
Rates, Mcf/mo

Site Description
Property
Value
Average Depth to Top Coal
3100 feet
No. Coal Intervals
3 (Yellow, Blue, Purple)
Average Total Net Thickness
Permeability
43 feet
100 md
Yellow – 22 ft
Blue – 10 ft
Purple – 11 ft
Initial Pressure
1650 psi
Temperature
120°F
21

Progression of CO 2 Displacement
(@ mid-2002)
Face
Cleat
Butt
Cleat
N
22

Incremental Recovery
Case
Total Methane
Recovery (Bcf)
Incremental
Recovery
(Bcf)
Total CO 2
Injection
(Bcf)
CO 2
Production
(Bcf)
CO 2
/CH 4
Ratio
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
** 20 Mcfd/ft
Small incremental recovery due to limited injection volumes.
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
1,000,000
34 producers, 12 injectors
Peak @ 26 MMcfd
+/- 5MMcfd
100,000
10,000
Injection initiated
1,000
100
Gas Rate, Mcf/mo
N2 Injection Rate,
Mcf/mo
Suspension periods
Max Inj Rate = 26 MMcfd
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
26
Gas Rates, Mcf/mo

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
Permeability
47 feet

Progression of N 2 Displacement
(@ mid-2002)
Face
Cleat
Butt
Cleat
N
28

Current Field Results
(through mid-2002)
Case
Total Methane
Recovery (Bcf)
Incremental
Recovery
(Bcf)
Total N 2
Injection
(Bcf)
N 2
Production
(Bcf)
N 2
/CH 4
Ratio
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
** 46 Mcfd/ft
At N 2
/CH 4
ratio of 0.75:1 and reproduced volume
of 25%, ultimate incremental recovery estimated
to be +/- 14 Bcf or 40% improvement over primary.
Note: OGIP for model = 438 Bcf.
29

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 CO 2 injection at
Allison due to low injection volumes.
• CO 2 injectivity key success driver; strong evidence that
coal permeability (and injectivity) reduced with CO 2
injection.
• Incremental recoveries with N 2 injection at Tiffany
currently; estimated to provide 40% improvement over
primary.
30

Outline
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
31

Hypothetical Field Setting
(US onshore)
Example CBM Basin
Well Injection Pattern
(4 Sections)
Sec. 6 Sec. 5
Sec.7 Sec. 8
Conventional Recovery – 48 Bcf
(2.5 Bcf/well)
Incremental Recovery – 16 Bcf
(1 Bcf/well)
32

Economics of CO 2 ECBM
US $/Mcf
Hub Gas Price $3.00
Less: 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 $1.54
Capital Costs (1) ($0.25)
CO 2
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) CO 2 Costs = $0.30/Mcf * 3.0 = $0.90/Mcf (CO 2 )
33

Economics of N 2 ECBM
US $/Mcf
Hub Gas Price $3.00
Less: 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 CO 2
case)
Gross Margin $1.04
Capital Costs (1) ($0.25)
N 2 Costs (@ ratio of 0.5 to 1) (2) ($0.30)
Net Margin $0.49
(1) Capital Costs = $500,000 * 4 (inj. wells) = $2,000,000/16 Bcfg
= $0.13/Mcfg * 2 = $0.25/Mcfg
(2) N 2
Costs = $0.60/Mcf * 0.5 = $0.30/Mcf (N 2
)
34

ECBM Economic Considerations
• N 2 – ECBM appears favorable, but early
breakthrough requires costly post-production gas
processing.
• CO 2 - ECBM also appears favorable, but
maintaining injectivity a key success driver.
• More experience required to validate & optimize
economic performance.
• CO 2 /N 2 mixture may be optimum.
‣ High N 2 concentrations early for rapid methane recovery
‣ Increasing CO 2 concentrations later for efficient methane
displacement.
35

Outline
• Introduction
• ECBM Process
• Pilot Projects
• Economics
• Closing Remarks
36

Closing Remarks
• ECBM recovery appears to hold considerable
promise; on the verge of commerciality with a bright
future.
• CO 2 sequestration economic drivers (carbon credits)
will substantially improve financial performance and
accelerate commercial adoption.
• In U.S., CO 2 -ECBM/sequestration potential is
substantial; recently assessed at 90 Gt CO 2 and 150
Tcf of incremental gas recovery.
37

Closing Remarks
• More work is needed to economically optimize the process.
‣N 2 /CO 2 mixtures
‣CO 2 injectivity
‣Spacing, patterns, rates, etc.
‣Reservoir settings (coal rank)
• Reservoir response is generally consistent with theoretical
understanding of CO 2 /N 2 processes.
‣Reasonable predictions of reservoir response possible.
‣Informed investment decisions.
• Acknowledgements:
‣U.S. Department of Energy
‣Burlington Resources
‣BP America
• For more information:
www.coal-seq.com
38

Enhanced Coalbed Methane Recovery
presented by:
Scott Reeves
Advanced Resources International
Houston, TX
SPE Distinguished Lecture Series
2002/2003 Season
39
Advanced Resources International

Well #132 Performance
4000
3500
CH 4 Recovery w/o CO 2 injection = 6.1 Bcf
CH 4 Recovery w/ CO 2 injection = 6.9 Bcf
CH 4 Incremental Recovery = 0.8 Bcf
3000
CH4 Rate, Mscf
2500
2000
1500
1000
500
0
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
Days
CO2 Injection
No CO2 Injection
40

Nitrogen Content of Produced Gas
14
12
Average = 12.3 %
10
No. Wells
8
6
4
2
0
< 1 1 - 10 10 - 20 20 - 30 30 - 40 40 - 50 > 50
Last N2 Concentration (%)
41

Matrix Shrinkage/Swelling
Source: “An Investigation of the Effect of Gas Desorption on Coal Permeability”, paper 8923, 1989 Coalbed Methane Symposium.
42

Relevant Formulas*
Pressure-Dependence
Shrinkage/Swelling
φ = φ i + φ i C p (P-P i ) + (1 - φ i ) C m dP i
dC i
(C-C i )
k =
n
φ n = +/- 3
φi
*Used in COMET2. Alternative formulation presented by Palmer & Mansoori; SPE 36737, 1996.
43

Permeability Changes with Net Stress, Gas
Concentration, and Sorptive Capacity
Matrix Shrinkage
Pressure Dependence
250
Permeability, md
200
150
100
50
Sorption Capacity
Methane
Carbon Dioxide
0
0 500 1000 1500 2000 2500 3000 3500
Pressure, psi
44

Typical Injection Profile,
Allison Unit
Well #143
60000
2500
2300
50000
2100
Pressure
40000
30000
CO2, Mcf/mo
1900
1700
1500
20000
10000
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
Rate
BHP, psi
1300
1100
900
700
500
Date
45

Permeability History for Injector
250
Start
Permeability, md
200
150
100
50
Continued
Injection
Depletion
Displace w/ CO2
0
0 500 1000 1500 2000 2500 3000 3500
Pressure, psi
46

CO 2 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.
47

Pure Gas Gibbs Adsorption on
Tiffany Coals at 130° F
Gibbs Adsorption (SCF/ton)
600.0
500.0
400.0
300.0
200.0
N abs
= N Gibbs
1- ρ gas
ρ ads
N2 on Mixed Coal
CH4 on Well #1
CH4 on Well #10
CH4 on Mixed Coal
CO2 on Mixed Coal
100.0
0.0
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
48

CO 2 Absolute Adsorption on Tiffany
Mixed Coal Sample Using Different
Adsorbed-Phase Densities
700
600
Aboslute Adsorption (SCF/ton)
500
400
300
200
100
Adsorbed Phase Density(g/cc)
1.18
1.25
1.40
Saturated liquid density at triple point
ZGR estimate
Graphical estimate
0
0 200 400 600 800 1000 1200 1400 1600 1800 2000
Pressure (psia)
49

Multi-Component Sorption
Behavior
Extended Langmuir Theory
V Li p i
, i = 1, 2, 3,…, n.
C i (p i ) =
n
p
p
Li 1 + Σ
j=1
p L
Other Langmuir Models:
Equations of State:
Simplified Local Density Models:
Loading Ratio Correlation (LRC), Real Adsorbed Solution (RAS),
Ideal Adsorbed Solution (IAS)
Van der Walls (VDW), Eyring, Zhou-Gasem-Robinson (EOS-S, PGR)
Flat Surface (PR-SLD), Slit (PR-SLD)
50

Accuracy of Model Predictions for
Pure Gas Adsorption
Quality of Fit, % AAD, for Specified Model
Component
Langmuir
LRC
(n = 0.9)
ZGR-EOS
Experimental
Error
Methane
2.6
2.3
3.0
3.0
Nitrogen
3.5
2.3
2.3
6.0
Carbon
Dioxide
2.0
1.8
2.1
7.0
51

Accuracy of Model Predictions for
Binary/Ternary Gas Adsorption
(based on pure-gas adsorption data)
LRC
Mixture,
Langmuir
(n=0.9)
ZGR-EOS
Experimental Error
(Feed Mole %)
% AAD
% AAD
% AAD
% AAD
CH 4 –N 2 :
CH 4 (50%)
N 2 (50%)
Total
15.8
6.2
12.2
12.0
9.3
8.2
11.9
10.0
11.5
7.0
17.0
7.0
CH 4 –CO 2 :
CH 4 (40%)
CO 2 (60%)
Total
25.9
9.0
1.2
21.0
10.5
2.2
27.0
10.4
1.4
7.0
6.0
4.0
N 2 –CO 2 :
N 2 (20%)
CO 2 (80%)
Total
44.9
5.2
3.5
37.3
5.7
3.8
48.7
4.9
3.5
29.0
6.0
5.0
N 2 –CH 4 -CO 2 :
N 2 (10%)
CH 4 (40%)
CO 2 (50%)
Total
47.8
20.7
13.2
2.9
44.5
5.2
15.8
5.4
55.9
21.6
17.6
4.3
14.0
27.0
5.0
5.0
52