Sequestration in Coal - Unconventional Gas · 1 PDS030402(CO2 Forum).ppt The Coal-Seq Project Field...

PDS030402(CO2 Forum).ppt1

The Coal-Seq Project

Field Studies of ECBM and CO2

Sequestration in CoalPresented by:

Scott R. Reeves

Advanced Resources International

Coal-Seq I Forum

March 14 & 15, 2002

Houston, Texas


Presentation Outline

• Project Description

• Allison Unit

• Tiffany Unit

• Supporting Studies

• Closing Remarks


Project Objectives

• Perform Two Detailed (Reservoir Modeling) Field Studies of Long-Term, Multi-Well CO2/N2Injection into Coalseams (Allison & Tiffany Units, San Juan Basin).

• Couple that with Fundamental Understanding of CO2 Sequestration Reservoir Mechanics (“benchtop” studies of sorption behavior, coal swelling, geochemistry).

• Develop Screening Model to Evaluate Potential Coalseam Sequestration Projects

• Assess Potential for Coalseam Sequestration across U.S

• Disseminate Results to Industry


Unique Project Features

• Studying CO2 sequestration based primarily on the results of long-term, multi-well field tests.

• Laboratory studies play supporting (not primary) role.

• Also look specifically also at N2injection.


Why Nitrogen?• Power plant flue gases contain mostly nitrogen

– not having to process flue gas to a pure CO2stream has important front-end cost reduction implications.

• Nitrogen is an effective ECBM injectant – early incremental methane production also has important cost implications for lowered net CO2sequestration costs.

• Examining both “end points” will facilitate “unified” understanding of reservoir mechanics and improve reliability of mixed gas injection predictions.


Two Reservoir Mechanisms

• Methane stripping (nitrogen)• Methane displacement (carbon

dioxide)

Note: BP (Amoco) holds numerous patents on both N2and CO2 injection for ECBM recovery.


Adsorption Isotherms, San Juan Basin

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700.0

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Pressure (psia)

Abs

olut

e A

dsor

ptio

n (S

CF/

ton)

Pure Gas Absolute Adsorption on Tiffany coals at 130°F wet coal


Gas Production ResponseNitrogen Carbon Dioxide

Gas Production Response to CO2 Flooding

10

100

1000

0 30 60 90 120 150 180 210 240Month

Gas

Rat

e, M

scfd

Base Case

CO2 @ 500 McfdCO2 @ 250 Mcfd

1.0 Bcf (2.7 Bcf CO2 sequestered)

@500 Mcfd1.8 Bcf

0.4 Bcf (1.4 Bcf CO2sequestered)

@ 250 Mcfd1.1 Bcf

Incremental CH4 Recoveries

Gas Production Response to N2 Flooding

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100

1000

0 30 60 90 120 150 180 210 240Month

Gas

Rat

e, M

scfd

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

Nitr

ogen

Con

tent

Nitrogen Content

Base Case

N2 @ 500 Mcfd

N2 @ 250 Mcfd

Net Methane


Injection/Production Ratios

Injection/Production Ratios500 Mcfd Inj Rate

0

1

10

100

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10,000

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Month

Inj/P

rod

Rat

io

N2 Inst N2 Cum

CO2 Inst CO2 Cum


Field Response Expectations

Nitrogen– Immediate gas production increase – Early N2 breakthrough– N2/CH4 ratio reaching minimum of <1 at N2

breakthrough, then gradually increasing

Carbon Dioxide– Delayed gas production increase– Late CO2 breakthrough– CO2/CH4 ratio stabilizing at +/- 2:1


• Allison Unit• San Juan basin• Upper Cretaceous Fruitland Coal• Burlington Resources• Carbon dioxide injection• 16 producers• 4 injectors• 1 pressure observation well

• Tiffany Unit• San Juan basin• Upper Cretaceous Fruitland Coal• BP America• Nitrogen injection• 34 producers• 12 injectors

Only Two “Commercial-Scale” Field Tests Exist Worldwide


Field Sites, San Juan Basin

F a r m i n g t o n

A z t e c

B l o o m f i e l d

D u l c e

D u r a n g o P a g o s a S p r i n g s

C O L O R A D O N E W M E X I C O

L A P L A T A C O . A R C H U L E T A C O .

C O A L S i t e

K A O 9 9 1 0 0 . C D R

A l l i s o n U n i t

F A I R W A Y

F l o r i d a R i v e r P l a n t

T i f f a n y U n i t

San Juan Basin Outline

N2 Pipeline




• Allison Unit

• Tiffany Unit


• Closing Remarks


• Field on primary production in 1989.• CO2 injection commenced in 1995 (four

wells).• Production enhancement program

implemented (recavitation, line pressure reduction, well reconfigurations, onsite compression)

• CO2 injection suspended for 12-months in August, 2001 to carefully study “long-term” effects of ECBM operations.

Field History/Status - Allison


Allison Unit Base Map

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141140

142

POW#2

104

101106

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108

112

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113

62

12M

61


Allison Production HistoryAllison Unit Performance

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2000000

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-89

Jul-

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-00

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-01

Date

Rat

es, M

cf/m

o

0

5

10

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30

Wel

l C

ou

nt

Gas Rate, Mcf/mo CO2 Injection Rate, Mcf/mo Well Count

16 producers, 4 injectors, 1 POW

Five wells shutin during initial injection period

Injection suspended, five wells reopened

Line pressures reduced, wells reconfigured, onsite compression installed

Injection resumed

Recavitations, line pressure reduced, wells reconfigured, onsite compression installed


Data Available for Model

•Skin, delta-skin due to recavitation•Bottomhole injection pressures

“Inferred” Data•Relative permeability•Porosity•Pore-volume compressibility•Permeability exponent

•Isotherms (2 samples each from 3 wells)•Reservoir pressure (POW#2)•PTA – May 2000 - 8 prod wells•CO2 injection data•Surface CO2 injection pressures•PTA – August 2001 – 4 inj wells

“Raw”Data•Gas production•Water production (limited)•Recent casing pressures•Gas composition•Coal depths/thicknesses•Completion/Restimulation info


Reservoir Model Description

• 16 production wells, 4 injector wells, 1 pressure observation well

• 33 x 32 gridblocks (18,500 ft x 16,800 ft, 7,100 acres)

• 3 (independent) layers (3,168 total gridblocks)

• COMET2 simulator


Model Grid – Map View

N


Model Grid – Cross Section

W-E Cross SectionN-S Cross-Section


Status

Current• Initial history-match achieved.

Next Steps• Review with Burlington, formulate strategy to

achieve final match.• Run “what-if” and economic optimization

cases.• Prepare/publish report.




• Allison Unit

• Tiffany Unit


• Closing Remarks


• Field on primary production in 1983

• Intermittent N2 injection commenced in 1997 (12 wells).

Field History/Status - Tiffany


Tiffany Unit Base Map

Producer-to-Injector Conversions

Previous Study Area


Tiffany Production History

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-83

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Date

Gas

Rat

es

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10000

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35000

Wat

er R

ate

Gas Rate, Mcf/mo N2 Injection Rate, Mcf/mo Water Rate, Bbls/mo

34 producers, 12 injectors


Data Available for Model

•Relative permeability•Absolute permeability•Porosity

“Inferred” Data•Results of simulation study performed in 1993 (permeability, permeability anisotropy and orientation, relative permeability, porosity)

•Coal depths/thicknesses•Completion info •Reservoir pressure (injection wells, June 1997)

“Raw”Data•Gas production•Water production•Gas composition


Reservoir Model Description

• 34 production wells, 12 injector wells• 37 x 73 gridblocks (25,600 ft x 38,900 ft,

22,800 acres)• 4 independent layers (10,804 total

gridblocks)• COMET2 simulator


Model Grid – Map View

N


Model Grid – Cross SectionSW-NENW-SE


Status

Current• Model initialized.

Next Steps• Achieve initial history-match.• Review with BP America, formulate strategy to

achieve final match.• Run “what-if” and economic optimization cases.• Prepare/publish report.




• Allison Unit

• Tiffany Unit


• Closing Remarks


Benchtop Study Topics

• CO2 sorption behavior near critical point, multi-component sorption modeling:qObtained independent data set from TiffanyqDid not observe abnormal CO2 sorption behavior

(validity of Langmuir model?)qSee work of Oklahoma State University

• Matrix shrinkage/swelling:qAnalyzing long-term CO2 injection behavior at

Allison.qSwelling appears to be an issue, but further

analysis required.


Benchtop Study Topics (continued)

• Geochemistry:qPerformed equilibrium modeling on

Tiffany water samples.qNo precipitate problems expected.

• Modeling:qRECOPOL project (Appalachian basin analog).qARC ECBM project (mixed gas injection).qModel comparison study.




• Allison Unit

• Tiffany Unit


• Closing Remarks


Significant Accomplishments• Comprehensive compilation of long-term,

commercial-scale field results; general agreement with laboratory and simulation-based predictions observed.

• Collected independent set of multi-component isotherm data; dispelled abnormal CO2 sorption behavior.

• Collection/analysis of first long-term CO2 injection data in coal to examine existence and magnitude of matrix swelling effects

• Gained insights into potential for precipitates formation with CO2 injection.


Interim Findings/Conclusions

• Feasibility/economics of CO2 sequestration (or ECBM recovery) in coalseams not established

• Field results providing valuable insights into reservoir processes

• Reservoir mechanics of CO2/N2 injection into coalseams not fully understood:– CO2 sorption behavior– Matrix swelling– Modeling requirements and capabilities


Near Term• Complete field studies (i.e., final history

matches, forecasts, economics and field practices). Prepare reports & publications.

• Finalize reservoir mechanism studies (i.e., multi-component isotherms, matrix shrinkage/expansion, geochemical studies). Prepare report & publication.

Future Work


Future Work

Medium Term• Collect coal samples from +/- 10 basins,

perform isotherm testing.• Develop screening model. • Perform assessment of CO2 sequestration

in U.S. coals.• Technology transfer (reports/publications,

disseminate screening model, workshops).

Sequestration in Coal - Unconventional Gas · 1 PDS030402(CO2 Forum).ppt The Coal-Seq Project Field...

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