reeves dl presentation

7/21/2019 Reeves DL Presentation

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1

Enhanced Coalbed Methane Recovery

presented by:

Scott Reeves

Advanced Resources International

Houston, TX

SPE Distinguished Lecture Series

2002/2003 Season



2/52

2

Introduction

ECBM Process

Pilot Projects

Economics

Closing Remarks

Outline


3/52

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.


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4

Power

Plant

CO2/N2 CH4

CH4

CH4

CH4

CH4CO2/N2

Deep, UnmineableCoal

CO2/N2

CH4

CH4CH4

CH4

Integrated Power Generation, CO2Sequestration & ECBM Vision


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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 River0%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%0.90.30.10.4

Cherokee/ 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

%

ofTotal

Total(Tcf)

Incremental

Recovery

in

Non-

CommercialArea

Incremental

Recovery

in

Commer-cial Area

%

ofTotal

Total(Gt)

Injection for

CO2

Sequestra-tion

in Non-

Commer-cialArea

Injection

for

ECBM in

Com-

mercialArea

Replace-

ment

of Primary

Recovery

VolumeBasin

ECBM Potential (Tcf)CO2

Sequestration Potential (Gt)


6/526

Introduction

ECBM Process

Pilot Projects

Economics

Closing Remarks

Outline


7/527

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 Darcyflow (3 Ds 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

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Pressure (psia)

AbsoluteAdsorption(SCF/ton)

Carbon Dioxide

Methane

Nitrogen

CO2/CH

4ratio = 2:1

N2/CH4 ratio = 0.5/1CO

2/N

2ratio = 4:1

San Juan Basin coal


9/529

Variability of CO2/CH4 Ratio

CO2/CH4 Sorption Ratio vs Coal Rank

y = 2.5738x-1.5649

R

2

= 0.9766

0

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/CH4Ratio

100 psi

1000 psi

3000 psi

Sub HV HVA MV LV


10/5210

N2-ECBM Recovery Mechanism

Inject N2 into cleats.

Due to lower adsorptivity, high percentage of N2remains free in cleats:Lowers CH4partial pressure

Creates compositional disequilibrium between sorbed/free gasphases

Methane stripped from coal matrix into cleat

system. Methane/nitrogen produced at production well.

Rapid N2breakthrough expected.


11/5211

CO2

-ECBM Recovery Mechanism

Inject CO2 into cleats. Due to high adsorptivity, CO2preferentially

adsorbed into coal matrix.Methane displaced from sorption sites.

Methane produced at production well.

Efficient displacement process slow CO2breakthrough.


12/5212

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


13/5213

Gas Production Response N2 Injection

100

1000

10000

0 1000 2000 3000 4000 5000

Days

Gas

Rate,

Mscfd

0

10

20

30

40

50

60

70

NitrogenContent,%

Base Case Injection @ 25 Mcfd/ft

Injection @ 10 Mcfd/ft Injection @ 50Mcfd/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%)


14/5214

Gas Production Response CO2 Injection

100

1000

10000

0 1000 2000 3000 4000 5000

Days

Gas

Rate,

Mscfd


Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft


Injection @ 10 Mcfd/ft Injection @ 50Mcfd/ft50 Mcfd/ft

No CO2breakthrough

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%)


15/5215

Introduction

ECBM Process

Pilot Projects

Economics

Closing Remarks

Outline


16/5216

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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Farmington

Aztec

Bloomfield

Dulce

Durango PagosaSprings

COLORADONEW MEXICO

LA PLATA CO. ARCHULETA

R

Allison Unit

FA

IR

WA

Y

Florida RiverPlant

Tiffany Unit San JuanBasin Outline

N2 P

ipelin

e

Field Sites, San Juan Basin


18/5218

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


19/5219

Injector

Producer

Well Configurations


20/5220

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

Ja

n-89

Jul-89

Ja

n-90

Jul-90

Ja

n-91

Jul-91

Ja

n-92

Jul-92

Ja

n-93

Jul-93

Ja

n-94

Jul-94

Ja

n-95

Jul-95

Ja

n-96

Jul-96

Ja

n-97

Jul-97

Ja

n-98

Jul-98

Ja

n-99

Jul-99

Ja

n-00

Jul-00

Ja

n-01

Jul-01

Date

Rates,Mcf/m

o

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

IndividualWellGasR

ate,Mcf/d

Gas Rate, Mcf/mo

CO2 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


21/5221

Site Description

3100 feet

3 (Yellow, Blue, Purple)

43 feet

Yellow 22 ftBlue 10 ft

Purple 11 ft

100 md

1650 psi

120F

Average Depth to Top Coal

No. Coal Intervals

Average Total Net Thickness

Permeability

Initial Pressure

Temperature

ValueProperty


22/5222

Progression of CO2 Displacement(@ mid-2002)

Face

Cleat

Butt

Cleat

N


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Incremental Recovery

n/an/an/an/a100.5*

W/o CO2injection

3.21.26.4**1.6102.1

W/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!


24/5224

Tiffany Unit Base Map

Producer-to-Injector

Conversions

Previous Study Area


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25

Well Configurations

Multiple Injector Wells

Producer Well


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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

GasRates,

Mc

f/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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27

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


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28

Progression of N2 Displacement(@ mid-2002)

Face

Cleat

Butt

Cleat

N


29/52

29

Current Field Results(through mid-2002)

n/an/an/an/a*35.3

W/o N2injection

1.21.314.0**10.545.8

W/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/CH

4ratio of 0.75:1 and reproduced volume

of 25%, ultimate incremental recovery estimated

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


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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 CO2

injection. Incremental recoveries with N2 injection at Tiffany

currently; estimated to provide 40% improvement over

primary.


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31

Introduction

ECBM Process

Pilot Projects

Economics

Closing Remarks

Outline


32/52

32

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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33

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


34/52

34

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 CO2case)

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

)


35/52

35

ECBM Economic Considerations

N2 ECBM appears favorable, but early

breakthrough requires costly post-production gasprocessing.

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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36

Introduction

ECBM Process

Pilot Projects

Economics

Closing Remarks

Outline


37/52

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 andaccelerate commercial adoption.

In U.S., CO2-ECBM/sequestration potential is

substantial; recently assessed at 90 Gt CO2 and 150Tcf of incremental gas recovery.


38/52

38

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 theoreticalunderstanding of CO2/N2processes.

Reasonable predictions of reservoir response possible.

Informed investment decisions.

Acknowledgements:

U.S. Department of EnergyBurlington Resources

BP America

For more information:

www.coal-seq.com


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39

Enhanced Coalbed Methane Recovery

presented by:

Scott Reeves


Houston, TX

SPE Distinguished Lecture Series

2002/2003 Season



40/52

40

Well #132 Performance

0

500

1000

1500

2000

2500

3000

3500

4000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Days

CH4Rate,Mscf

CO2 Injection No CO2 Inject ion

CH4 Recovery w/o CO2 injection = 6.1 Bcf

CH4 Recovery w/ CO2 injection = 6.9 Bcf

CH4 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

CH4Rate,Mscf

CO2 Injection No CO2 Inject ion

CH4 Recovery w/o CO2 injection = 6.1 Bcf

CH4 Recovery w/ CO2 injection = 6.9 Bcf

CH4 Incremental Recovery = 0.8 Bcf


41/52

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.W

ells

Average = 12.3 %


42/52

42

Matrix Shrinkage/Swelling

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


43/52

43

Relevant Formulas*

Pressure-Dependence Shrinkage/Swelling

*Used in COMET2. Alternative formulation presented by Palmer & Mansoori; SPE 36737, 1996.

= i + i Cp (P-Pi) + (1 -i) Cm dPi

dCi

(C-Ci)

n

k =i n = +/- 3

Permeability Changes with Net Stress Gas


44/52

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

Permeability,md Methane

Carbon Dioxide

Matrix Shrinkage Pressure Dependence

Sorption Capacity


45/52

45

Typical Injection Profile,

Allison UnitWell #143

0

10000

20000

30000

40000

50000

60000

Jan

-89

Ju

l-89

Jan

-90

Ju

l-90

Jan

-91

Ju

l-91

Jan

-92

Ju

l-92

Jan

-93

Ju

l-93

Jan

-94

Ju

l-94

Jan

-95

Ju

l-95

Jan

-96

Ju

l-96

Jan

-97

Ju

l-97

Jan

-98

Ju

l-98

Jan

-99

Ju

l-99

Jan

-00

Ju

l-00

Date

Rate

500

700

900

1100

1300

1500

1700

1900

2100

2300

2500

Pressure

CO2, Mcf/mo

BHP, psi


46/52

46

Permeability History for Injector

0

50

100

150

200

250

0 500 1000 1500 2000 2500 3000 3500

Pressure, psi

Permeability,m

d

Start

Depletion

Displace w/ CO2Continued

Injection

CO S i B h i


47/52

47

CO2 Sorption Behavior

(Pc=1073psi, Tc=88F)

Source: SPE 29194: Adsorption of Pure Methane, Nitrogen and Carbon Dioxide and their Binary Mixtures on Wet Fruitland Coal, 1994.


48/52

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)

Gibb

sAdsorption(SC

F/ton)

N2 on Mixed CoalCH4 on Well #1

CH4 on Well #10

CH4 on Mixed Coal

CO2 on Mixed Coal

Nabs = NGibbs1-gas

ads

Pure Gas Gibbs Adsorption on

Tiffany Coals at 130 F

CO Absolute Adsorption on Tiffany


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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)

Aboslu

teAdsorption(SCF/ton)

1.18

1.25

1.40

Adsorbed Phase Density(g/cc)

Saturated liquid density at triple point

ZGR estimate

Graphical estimate


50/52

50

Multi-Component Sorption

BehaviorExtended 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 +n

j=1

A f M d l P di ti f


51/52

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

Accuracy of Model Predictions for


52/52

y

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 %)

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