Presented to:Coal-Seq VI
April 10, 2008
Central Appalachian Basin(SECARB)
Nino Ripepi and Michael KarmisVirginia Tech
Michael J. Miller and J. Matthew ConradMarshall Miller and Associates
AcknowledgementThis material is based upon work supported by the Department of Energy
National Energy Technology Laboratory under DE‐FC26‐04NT42590
This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or
implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily
constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States
Government or any agency thereof.
SECARB Coal Group Team
Southern States Energy BoardVirginia Center for Coal and Energy Research Virginia TechMarshall Miller and Associates, Inc.Geological Survey of AlabamaUniversity of AlabamaSouthern CompanyKentucky Geological SurveyAdvanced Resources InternationalEastern Coal Council
SECARB Coal ProjectsContributing Partners
AlawestAlpha Natural ResourcesAMVESTBuckhorn CoalCCP2 ProjectCDX GasCNX GasCONSOL EnergyCumberland Resources CorporationDart Oil & GasDenbury ResourcesDominion E&PDominion ResourcesEastman Chemical
EPRIEquitable ProductionInstitute for Clean Energy Technology (MSU)International Coal Group GeoMetMcJunkin AppalachianNorfolk SouthernNatural Resource PartnersOak Ridge National Laboratory Penn VirginiaPine Mountain Oil & GasPiney LandPocahontas LandRMB Earth Science ConsultantsUniv. British Columbia
SECARB Coal Projects
G2-B
G2-A
CO2 ECBM recovery:- Unmineable coals can provide
sequestration and add economic value- At least 1,000 MMT CO2 of feasible
capacity in the targeted areasTwo Field Validation Sites:
- Central Appalachian Basin, G2-A- Black Warrior Basin, G2-B- Inject 1,000 tons of CO2 at each site
SECARB Coal Group Phase II Project Tasks
Regional Characterization and Site SelectionReservoir ModelingCore Hole Drilling and EvaluationPilot Preparation and Risk AnalysisPilot Project OperationsInterpretation and AssessmentPublic OutreachTechnology Transfer
Central Appalachian Field Test –Progress Overview
Finalized Sequestration and ECBM Assessment for Central Appalachian BasinDeveloped a suite of geologic maps for sequestration and ECBM analysisSelected a donated CNX Gas well for field testFinalized indemnification and operating agreements with CNX Gas and Buckhorn Coal CompanyConducted required safety training from CNX GasCompleted and submitted NEPA QuestionnaireWorking with EPA and Virginia Department of Mines, Minerals and Energy on permitting requirements– UIC Permit Application– Corehole Permitting
Knott
Letcher
Lee
Harlan
Magoffin
Tazewell
Dickenson
Scott
Wise
Washington
Russell
Grayson
Bland
SmythWythe
Carroll
Pulaski
Boone
McDowellPike
Floyd
Buchanan
Wayne
Johnson
Martin
Lincoln
Mingo Logan
Mercer
Wyoming
Raleigh
Giles
Summers
Fayette
KY
WV
VA
CBM Target Area
0 5 10 2015Scale in Miles
CBM FIELDS
Nora Field
Oakwood Field
Welch Field
Loup Creek Field
Study Area CBM Fields
Bradshaw Field
Slab Fork Field
Buck Knob Field
Horizontal CBMVertical CBM
Central Appalachian Basin
GeneralizedStratigraphic
Column
Pocahontas No. 1Pocahontas No. 2Pocahontas No. 3Pocahontas No. 4Pocahontas No. 5Pocahontas No. 6Pocahontas No. 7Pocahontas No. 8Pocahontas No. 9
Lower HorsepenWar CreekMiddle HorsepenUpper HorsepenLower SeaboardMiddle SeaboardGreasy CreekUpper Seaboard
TillerJawboneRavenAilyKennedy
Nor
ton
Form
atio
nLe
e Fo
rmat
ion
Poc
ahon
tas
Form
atio
n
Prospective Coalbeds ForCarbon Sequestration
Evaluation CriteriaCarbon Sequestration and ECBM Potential
Thickness, rank and gas content of coals developed for CBM productionAreas where CBM production has been established (higher expected carbon dioxide injectivity and existing infrastructure)Excludes deep mine areas (potential leakage of injected carbon dioxide because of subsidence)
Evaluated Sequestration Area
Sequestration Potential
Phase II Study Areas
Storage capacity in all non-mining areas23.1 Tcf
(1,341 MMt)
Storage only in developed CBM areas6.86 Tcf
(398 MMt)
West Virginia portion of study area has 8.88 Tcf total storage capacity and 1.49 Tcf storage capacity in CBM development areas.
Enhanced CBM Potential
Phase II Study Areas
ECBM potential in all non-mining areas 2.49 Tcf
ECBM only in developed CBM areas 0.79 Tcf
West Virginia portion of study area has 0.80 Tcf total ECBM potential and 0.14 Tcf ECBM potential in CBM development areas.
The Russell County, VA Field Test
CNX Gas Field Test Location
Virginia Pilot Test Site
Offset CBM Wells
1600
1700
1800
1900
2000
2100
2200
2300
LEEFORMATION
POCAHONTASFORMATION
DEPTH GR DENSITY
****
LEE FORMATIONINJECTION TEST
NET COAL: 8.2 FEET
*
*
**
POCAHONTAS FORMATIONINJECTION TEST
NET COAL: 6.4 FEET
LEGENDCOALSANDSTONE
SHALE
INJECTION ZONE
PERFORATED ZONE*
Proposed Injection Zones
Well BD-114
1
10
100
1,000
Mar-02 Sep-02 Mar-03 Sep-03 Mar-04 Sep-04 Mar-05 Sep-05 Mar-06 Sep-06 Mar-07 Sep-07
Month
Gas
Pro
duct
ion
0.1
1
10
100
Wat
er P
rodu
ctio
n
Gas Production, Mcfd Water Production, bbls/d
Injection Well Production History
Pilot Area Gas Composition
WellNo.
Methane(%)
Nitrogen(%)
CO2
(%)Oxygen
(%)Ethane
(%)Propane
(%)Btu
Content
BC114 97.01 .54 1.87 .01 .557 .015 994
BC115 97.11 .57 2.08 .01 .216 .010 989
BD113 96.58 .50 2.49 .03 .392 .002 987
BD114 96.62 .68 2.33 .02 .351 .002 986
BE114 95.67 1.02 1.80 .02 1.418 .059 998
BE113 95.24 1.02 1.91 .01 1.744 .067 999
BD115 97.01 .83 1.35 .02 .740 .033 998
BE115 96.59 .65 1.89 .00 .822 .019 995
Average 96.48 .73 1.97 .02 .780 .026 993
ICBM SP052107
Model 3D View: Thickness
ICBM SP052107
History Match Results
0
10
20
30
40
50
60
70
0 500 1000 1500 2000 2500
Days
Gas
Rat
e (M
scfd
), W
ater
Rat
e (B
bld)
Gas Actual Water Actual Gas Sim Water Sim
Injection Test Plume Model
Growth of the CO2 plume was modeled in all test layers (coal seams)The plume growth was essentially radial in all layersAs expected, the growth is largest in the most permeable layer, the Pocahontas No. 3 coal seamRadial growth occurs to approximately 550 feet from injection well BD-114
CO2 Plume – Pocahontas No. 3Percent CO2 Saturation
1020 feet
Scale In Feet0 100 200
Injection Well
0%0%-10%10%-20%20%-30%30%-40%
40%-50%50%-60%60%-70%70%-80%80%-90%90%-100%
Test Schedule
Site selection (Complete): 04/07 – 12/07Approvals and Permitting: 02/08 – 07/08Soil Gas Monitoring: 03/08 – 09/09Coring: 04/08 – 06/08Formation testing: 05/08 – 06/08Install injection equipment: 07/08 – 08/08Injection testing: 08/08 – 01/09Site closure: 06/09 – 09/09
Core Hole Testing
Geophysical logs: gamma ray, caliper, density, neutron, induction, temperatureDesorption testing to determine current methane gas contentMethane, nitrogen, and carbon dioxide adsorption isothermsPetrographic analyses of core samplesInjection-falloff tests of Lee and Pocahontas formation injection intervals
Measurement, Monitoring and Verification
Monitor CO2 soil flux levels near the injection wellMonitor pressure and gas composition at core holesMonitor casing pressures and gas and water production rates at adjacent CBM wellsMonitor ambient CO2 levels
Current Issues
NEPA and DOE operational approvalCore hole permitting and change in requirementsClass V injection permit (EPA Region 3) and timing issuesCore rig and service vendor availability
