Enhanced Coalbed Methane Recovery - Unconventional … DL Presentation.pdf · Enhanced Coalbed Methane Recovery presented by: ... •CO2/CH4 ratio is 2:1 whereas N2/CH4 ratio is 0.5/1

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 %)