[PPT] - Enhanced Coalbed Methane Recovery presented by: Scott Reeves PowerPoint Presentation

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Enhanced Coalbed Methane Recovery

presented by:

Scott Reeves Advanced Resources International Houston, TX SPE Distinguished Lecture Series 2002/2003 Season

Advanced Resources International

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Introduction
ECBM Process
Pilot Projects
Economics
Closing Remarks

Outline

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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.

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Power Plant CO2/N2 CH4 CH4 CH4 CH4 CH4 CO2/N2 Deep, Unmineable Coal CO2/N2 CH4 CH4 CH4 CH4

Integrated Power Generation, CO2 Sequestration & ECBM Vision

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U.S. CO2-ECBM/Sequestration Potential

100% 152.2 101.7 50.6 100% 89.8 34.0 16.3 39.3 TOTALS 31% 47.0 27.8 19.2 42% 37.7 11.7 8.1 18.0 Alaska 2% 3.6 2.9 0.7 3% 2.3 1.3 0.3 0.7 Western Washington 13% 19.6 16.2 3.4 15% 13.6 8.5 1.8 3.3 Powder River 1% 1.5 0.6 0.8 2% 1.4 0.3 0.3 0.8 Wind River 3% 3.9 2.4 1.5 3% 3.0 1.0 0.6 1.4 Hanna-Carbon 12% 18.5 15.0 3.5 9% 7.9 3.5 1.3 3.0 Greater Green River 0% 0.3 0.2 0.1 2% 1.9 0.0 0.3 1.6 Uinta 9% 14.0 10.5 3.6 3% 2.4 1.5 0.3 0.5 Piceance 1% 1.5 0.1 1.4 1% 0.6 0.0 0.1 0.4 Raton 10% 15.7 4.3 11.4 12% 10.4 1.1 2.3 7.0 San Juan 2% 2.4 1.7 0.7 2% 1.9 0.9 0.4 0.7 Gulf Coast 0% 0.5 0.1 0.4 0% 0.1 0.0 0.0 0.1 Arkoma 1% 1.4 0.9 0.5 1% 0.9 0.3 0.1 0.4 Cherokee/ Forest City 3% 4.0 3.8 0.2 2% 1.4 1.2 0.0 0.1 Illinois 2% 3.1 2.2 1.0 1% 0.8 0.4 0.1 0.4 Black Warrior 0% 0.5 0.0 0.5 0% 0.1 0.0 0.0 0.1

C. Appalachia

10% 14.7 13.0 1.7 4% 3.4 2.3 0.3 0.8

N. Appalachia

%

f

Total Total (Tcf) Incremental Recovery in “Non- Commercial” Area Incremental Recovery in “Commer- cial” Area %

f

Total Total (Gt) Injection for CO2 Sequestra-tion in “Non- Commer-cial” Area Injection for ECBM in “Com- mercial” Area Replace- ment

f Primary

Recovery Volume Basin

ECBM Potential (Tcf) CO2 Sequestration Potential (Gt)

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Introduction
ECBM Process
Pilot Projects
Economics
Closing Remarks

Outline

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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
f surface area
Pore throats of 20 –500 angstrom
Production by desorption, diffusion and Darcy

flow (3 D’s of CBM production)

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Example Coal Sorption Isotherms

0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 200 400 600 800 1000 1200 1400 1600 1800 2000

Pressure (psia) Absolute Adsorption (SCF/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

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Variability of CO2/CH4 Ratio

CO2/CH4 Sorption Ratio vs Coal Rank

y = 2.5738x-1.5649 R2 = 0.9766 2 4 6 8 10 12 14 0.36 0.56 0.76 0.96 1.16 1.36 1.56 1.76 1.96 Coal Rank, Vro (%) CO2/CH4 Ratio

100 psi 1000 psi 3000 psi

Sub HV HVA MV LV

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N2-ECBM Recovery Mechanism

Inject N2 into cleats.
Due to lower adsorptivity, high percentage of N2

remains free in cleats:

Lowers CH4 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 N2 breakthrough expected.

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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.

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Modeling Sensitivity Study

San Juan Basin setting

(3000 ft, 40 ft coal, 10 md).

Inject C02 and N2 at rates
f 10 Mcfd/ft, 25 Mcfd/ft

and 50 Mcfd/ft.

15 year period.

Quarter 5-Spot Well Pattern 1 2 4 3 5

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Gas Production Response – N2 Injection

100 1000 10000 1000 2000 3000 4000 5000 Days Gas Rate, Mscfd 10 20 30 40 50 60 70 Nitrogen Content, %

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/ft 50 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%)

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Gas Production Response – CO2 Injection

100 1000 10000 1000 2000 3000 4000 5000 Days Gas Rate, Mscfd

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/ft

50 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%)

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Introduction
ECBM Process
Pilot Projects
Economics
Closing Remarks

Outline

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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

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17 Farmington Aztec Bloomfield Dulce Durango Pagosa Springs

COLORADO NEW MEXICO LA PLATA CO. ARCHULETA

R

Allison Unit

F A I R WA Y

Florida River Plant

Tiffany Unit San Juan Basin Outline

N

2

Pipeline

Field Sites, San Juan Basin

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Allison Unit Base Map

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

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Injector Producer

Well Configurations

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Allison Production History

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-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

Rates, Mcf/mo 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Individual Well Gas Rate, Mcf/d Gas Rate, Mcf/mo CO2 Injection Rate, Mcf/mo Well 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

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Site Description

3100 feet 3 (Yellow, Blue, Purple) 43 feet Yellow – 22 ft Blue – 10 ft Purple – 11 ft 100 md 1650 psi 120°F Average Depth to Top Coal

No. Coal Intervals

Average Total Net Thickness Permeability Initial Pressure Temperature Value Property

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Progression of CO2 Displacement

(@ mid-2002)

Face Cleat Butt Cleat

N

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Incremental Recovery

n/a n/a n/a n/a 100.5* W/o CO2 injection 3.2 1.2 6.4** 1.6 102.1 W/CO2 injection

CO2/CH4 Ratio CO2 Production (Bcf) Total CO2 Injection (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!

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Tiffany Unit Base Map

Producer-to-Injector Conversions Previous Study Area

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Well Configurations

Multiple Injector Wells Producer Well

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Tiffany Production History

100 1,000 10,000 100,000 1,000,000 S e p

8

3 S e p

8

4 S e p

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5 S e p

8

6 S e p

8

7 S e p

8

8 S e p

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9 S e p

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S e p

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1 S e p

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2 S e p

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3 S e p

9

4 S e p

9

5 S e p

9

6 S e p

9

7 S e p

9

8 S e p

9

9 S e p

S

e p

1

S e p

2

Date

Gas Rates, Mcf/mo 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

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Site Description

2970 feet 7 total (A, A2, B, C, D, E, F) 4 main (B, C, D, E) 47 feet B – 13 ft C – 11 ft D – 9 ft E – 14 ft <5 md 1600 psi 120°F Average Depth to Top Coal (A)

No. Coal Intervals

Average Net Thickness Permeability Initial Pressure Temperature Value Property

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Progression of N2 Displacement

(@ mid-2002)

Face Cleat Butt Cleat

N

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Current Field Results

(through mid-2002)

n/a n/a n/a n/a *35.3 W/o N2 injection 1.2 1.3 14.0** 10.5 45.8 W/N2 injection

N2/CH4 Ratio N2 Production (Bcf) Total N2 Injection (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

f 25%, ultimate incremental recovery estimated

to be +/- 14 Bcf or 40% improvement over primary.

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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 CO2 injection.

Incremental recoveries with N2 injection at Tiffany

currently; estimated to provide 40% improvement over primary.

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Introduction
ECBM Process
Pilot Projects
Economics
Closing Remarks

Outline

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Hypothetical Field Setting (US onshore)

Example CBM Basin Well 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

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Economics of CO2 ECBM

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) 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

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Economics of N2 ECBM

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 CO2

case)

Gross Margin $1.04 Capital 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)

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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 recovery Increasing CO2 concentrations later for efficient methane displacement.

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Introduction
ECBM Process
Pilot Projects
Economics
Closing Remarks

Outline

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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.

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Closing Remarks

More work is needed to economically optimize the process.

N2/CO2 mixtures CO2 injectivity Spacing, 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 Energy Burlington Resources BP America

For more information:

www.coal-seq.com

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Enhanced Coalbed Methane Recovery

presented by:

Scott Reeves Advanced Resources International Houston, TX SPE Distinguished Lecture Series 2002/2003 Season

Advanced Resources International

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Well #132 Performance

500 1000 1500 2000 2500 3000 3500 4000 1000 2000 3000 4000 5000 6000 7000 8000 9000 Days CH4 Rate, Mscf CO2 Injection No CO2 Injection CH4 Recovery w/o CO2 injection = 6.1 Bcf CH4 Recovery w/ CO2 injection = 6.9 Bcf CH4 Incremental Recovery = 0.8 Bcf 500 1000 1500 2000 2500 3000 3500 4000 1000 2000 3000 4000 5000 6000 7000 8000 9000 Days CH4 Rate, Mscf CO2 Injection No CO2 Injection CH4 Recovery w/o CO2 injection = 6.1 Bcf CH4 Recovery w/ CO2 injection = 6.9 Bcf CH4 Incremental Recovery = 0.8 Bcf

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Nitrogen Content of Produced Gas

2 4 6 8 10 12 14 < 1 1 - 10 10 - 20 20 - 30 30 - 40 40 - 50 > 50 Last N2 Concentration (%)

No. Wells

Average = 12.3 %

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Matrix Shrinkage/Swelling

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

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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

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Permeability Changes with Net Stress, Gas Concentration, and Sorptive Capacity

50 100 150 200 250 500 1000 1500 2000 2500 3000 3500 Pressure, psi Permeability, md Methane Carbon Dioxide Matrix Shrinkage Pressure Dependence Sorption Capacity

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Typical Injection Profile, Allison Unit

Well #143

10000 20000 30000 40000 50000 60000 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 Date Rate 500 700 900 1100 1300 1500 1700 1900 2100 2300 2500 Pressure CO2, Mcf/mo BHP, psi

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Permeability History for Injector

50 100 150 200 250 500 1000 1500 2000 2500 3000 3500 Pressure, psi Permeability, md

Start Depletion Displace w/ CO2 Continued Injection

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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.

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0.0 100.0 200.0 300.0 400.0 500.0 600.0 200 400 600 800 1000 1200 1400 1600 1800 2000

Pressure (psia) Gibbs Adsorption (SCF/ton)

N2 on Mixed Coal CH4 on Well #1 CH4 on Well #10 CH4 on Mixed Coal CO2 on Mixed Coal

Nabs = NGibbs 1- ρgas ρads

Pure Gas Gibbs Adsorption on Tiffany Coals at 130° F

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CO2 Absolute Adsorption on Tiffany Mixed Coal Sample Using Different Adsorbed-Phase Densities

100 200 300 400 500 600 700 200 400 600 800 1000 1200 1400 1600 1800 2000

Pressure (psia) Aboslute Adsorption (SCF/ton)

1.18 1.25 1.40 Adsorbed Phase Density(g/cc) Saturated liquid density at triple point ZGR estimate Graphical estimate

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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 p Ci(pi) =

, i = 1, 2, 3,…, n.

VLi pi pLi 1 + Σ

n j=1

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Accuracy of Model Predictions for Pure Gas Adsorption

7.0 2.1 1.8 2.0 Carbon Dioxide 6.0 2.3 2.3 3.5 Nitrogen 3.0 3.0 2.3 2.6 Methane Experimental Error ZGR-EOS LRC (n = 0.9) Langmuir Component

Quality of Fit, % AAD, for Specified Model

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Accuracy of Model Predictions for Binary/Ternary Gas Adsorption

(based on pure-gas adsorption data)

14.0 27.0 5.0 5.0 55.9 21.6 17.6 4.3 44.5 5.2 15.8 5.4 47.8 20.7 13.2 2.9 N2 – CH4 - CO2: N2 (10%) CH4 (40%) CO2 (50%) Total 29.0 6.0 5.0 48.7 4.9 3.5 37.3 5.7 3.8 44.9 5.2 3.5 N2 – CO2: N2 (20%) CO2 (80%) Total 7.0 6.0 4.0 27.0 10.4 1.4 21.0 10.5 2.2 25.9 9.0 1.2 CH4 – CO2: CH4 (40%) CO2 (60%) Total 7.0 17.0 7.0 11.9 10.0 11.5 12.0 9.3 8.2 15.8 6.2 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 %)