POTENTIAL NEW USES FOR
OLD GAS FIELDS:
SEQUESTRATION OF
CARBON DIOXIDE
Paul R. Knox
Susan D. Hovorka
Bureau of Economic Geology
Jackson School of Geosciences
The University of Texas at Austin
Curtis M. Oldenburg
Lawrence Berkeley National Laboratory
AGENDA
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Bureau
of
Economic
Geology
Overview of sequestration issues
Application in oil and gas fields
Enhanced gas recovery
Pressure maintenance
Wet intervals
Summary
GLOBAL CLIMATE CHANGE
INITIATIVE
• “Today, I’m announcing a
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new environmental approach
. . .”
“We must foster economic
growth in ways that protect
our environment”
“. . . set path to slow GHG
emissions, and as science
justifies - stop and then
reverse that growth”
President Bush
February 14, 2002
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of
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Geology
Compliments of H.D. Guthrie, NETL, DOE
GCCI PATHWAY TO 2012:
200
3400
EIA Reference Case
GCCI
180
3000
160
2600
150 MMTCE Gap
in 2012
140
2200
120
2000
1800
2004
2008
Greenhouse Gas Emissions (MMTCE)
Greenhouse Gas Intensity (TC/$MMGDP)
18% REDUCTION IN GHG INTENSITY
2012
Compliments of S.M. Klara, NETL, DOE
THE OPTIONS
Reduce Carbon
Intensity
Sequester
Disposal
Value-Added
Energy efficiency
Saline aquifers
EOR
New technology
Deep oceans
EGR
Biomass
ECBM
Fuel choice
Stop leaks, flares
Venting
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of
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ECONOMIC REALITIES
• Early sequestration will be in value-added
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Economic
Geology
settings, where geographically available
Gas fields: distributed volumes where subsurface
is well-known
Gulf Coast represents a combination of many CO2
sources and high-injectivity intervals
Pipeline networks provide deliverability
Mechanisms to address emissions credits are in
the planning stages
Major oil companies have demonstrated
significant interest in geologic sequestration
APPLICATION TO OIL
AND GAS FIELDS
GWC
GOC
OWC
WET INTERVAL
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of
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Geology
Brine-bearing Ss.
Oil-bearing Ss.
Gas-bearing Ss.
CO2-bearing Ss.
DENSITY OF CO2 AND METHANE
800
CO2
40°C
600
60°C
80°C
400
Gaslike CO2
Liquidlike CO2
200
CH4
40°C
60°C
80°C
0
0
50
100
P (bar)
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of
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Geology
150
200
QAd1546c
VISCOSITY OF CO2 AND METHANE
CO2
7.0E-05
40°C
6.0E-05
5.0E-05
60°C
80°C
4.0E-05
3.0E-05
CH4
2.0E-05
80°C
0
50
60°C
100
P (bar)
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of
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Geology
40°C
150
200
QAd1547c
AGENDA
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Bureau
of
Economic
Geology
Overview of sequestration issues
Application in oil and gas fields
Enhanced gas recovery
Pressure maintenance
Wet intervals
Summary
MODEL SET-UP
CH4 production
CO2 injection
Gas reservoir
Water table
100 m
Scenario I – No production during CO2 injection
Scenario II – Production rate offsetting injection rate
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QAd1548c
MODEL RUNS
Scenario II
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PRESSURE AND GAS FRACTION
1
130
I
120
II
110
CH4
Xgas
100
0.8
90
Historical CH4 production
80
0.7
70
60
I
P
0.6
50
II
40
0.5
30
1940
1950
1960
1970
1980
Year
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of
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0.9
1990
2000
2010
QAd1550c
Scenario I – No production during CO2 injection
Scenario II – Production rate offsetting injection rate
INCREMENTAL PRODUCTION
1.5E+08
Historical production period
Projected
I
1E+08
II
5E+07
No CSEGR
0
1950
1960
1970
1980
1990
2000
2010
2020
Year
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Scenario I – No production during CO2 injection
Scenario II – Production rate offsetting injection rate
QAd1551c
CSEGR: OUTSTANDING ISSUES
• Economic Feasibility
• Field Testing
•Economic feasibility evaluated by Oldenburg, Stevens*,
and Benson (2002) using example from California’s
largest gas reservoir
* Advanced Resources International, Inc.
ECONOMIC PARAMETERS
• Interval is high-porosity, high-permeability
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sandstone at 5,000 ft depth (Rio Vista field)
25 injectors (125 MMcfd, 6,500 tons/d)
18 producers (peak 45 – 90 MMcfd)
8 monitor wells
15 years duration
Costs included mix of new and recompleted
wells, pipelines
Produced gas CO2 content:1-5 yrs = 0%, 5-10 yrs
= 5%, 10-15 yrs = 25%
Methane value
ECONOMIC OUTPUT
From Oldenburg, Stevens, and Benson (2002)
BOTTOM LINE
• For CO2/CH4 volume ratio = 1.5, need CO2 cost ~ $10/t.
• Economics are sensitive to physical processes, specifically
CO2/CH4 volume ratio, mixing, and breakthrough times.
• Economic feasibility will be reservoir-specific.
• Overall conclusion is that CSEGR will require subsidy under
current conditions, but that increases in CH4 price or
decreases in CO2 supply costs can make CSEGR profitable at a
field like Rio Vista.
• Field demonstration project essential to realistic assessment in
the Gulf Coast
AGENDA
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Bureau
of
Economic
Geology
Overview of sequestration issues
Application in oil and gas fields
Enhanced gas recovery
Pressure maintenance
Wet intervals
Summary
SEQUESTRATION AT THE
GAS-OIL CONTACT
CO 2
CO 2
Water
CO 2
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Producing oil well
Perforations
CO 2 injection well
Flow of gas and oil into wellbore
Producing gas well
Flow of CO2 into reservoir
QAc8550c
AGENDA
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Bureau
of
Economic
Geology
Overview of sequestration issues
Application in oil and gas fields
Enhanced gas recovery
Pressure maintenance
Wet intervals
Summary
WET INTERVALS
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Bureau
of
Economic
Geology
Increase overall sequestration volume
Existing subsurface infrastructure
Existing surface infrastructure (pipelines)
Abundant subsurface data
Subsurface activities familiar to
local communities and regulators
U.S. Department of Energy-funded Gulf
Coast pilot in permitting stages
BRINE PILOT
• Purpose: demonstrate feasibility and
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monitoring techniques, evaluate model
predictions
Setting: salt dome flank, Frio sandstone,
5,000 ft depth.
Scope: < 5,000 tonnes (90 MMcf) over 20
days of injection
Monitoring: tracers, pressure and
temperature, logs, seismic
BRINE PILOT LOCATION
Houston
Pilot site
Power plants
Industrial sources
20 miles
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CONCLUSIONS
• Preparations are being made in the event that
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geologic sequestration becomes necessary
Sequestration can substantially enhance
production from mature gas reservoirs and is
economic with low-cost CO2 supplies
Sequestration seems a logical option to maintain
reservoir pressure and facilitate simultaneous oil
and gas production
Sequestration has the potential to extend field
life, increase ultimate recoveries, increase
production rates, and add new revenue streams
to mature fields.
ACKNOWLEDGEMENTS
This work was supported in part by the
Assistant Secretary for Fossil Energy,
Office of Coal and Power Systems through the
National Energy Technology Laboratory, and by
Lawrence Berkeley National Laboratory under
Department of Energy
Contracts No. DE-AC03-76SF00098 and
No. DE-AC26-98FT40417