Sequestration of CO2 in a depleted sandstone oil reservoir: results of a field
demonstration test
Rajesh Pawar1, John Lorenz2, Charles Byrer3, Reid Grigg4, Bruce Stubbs5,
Robert Benson6, James Krumhansl2, Philip Stauffer1
1
Los Alamos National Laboratory,
Los Alamos, New Mexico, USA 87545
2
Sandia National Laboratories,
Albuquerque, New Mexico, USA 87185
3
National Energy Technology Laboratory,
Morgantown, West Virginia, USA 26507
4
New Mexico Institute of Mining & Technology,
Socorro, New Mexico, USA 87801
5
Pecos Petroleum Company,
Roswell, New Mexico, USA 88203
6
Colorado School of Mines,
Golden, Colorado, USA 80401
Abstract
Injection of CO2 in depleted oil reservoirs is one of the most direct carbon management strategies.
We present results of the first geologic CO2 sequestration field test in the US. The main objectives
of the project are to monitor and predict migration and fate of CO2 injected into a depleted
sandstone oil reservoir and to better understand CO2 sequestration related processes. The field test
was centred around injection of about 2100 tonnes of CO2. Geophysical monitoring surveys,
laboratory experiments and numerical simulations were performed in support of the field test.
Results show that the response of the west Pearl Queen reservoir during the field test was
significantly different than the predictions based on pre-injection characterization data.
Keywords: CO2, field test, depleted oil reservoirs, sequestration
Introduction
Injection of carbon dioxide (CO2) in geological formation is considered to be one of the most direct
carbon management strategies. Although saline reservoirs, deep coal deposits, depleted gas
reservoirs and several other potential reservoirs are available, depleted oil reservoirs are especially
attractive because of infra-structural, site-characterization, and economic advantages. In particular,
numerous wells have already been drilled in these fields and CO2 pipelines may also be in place for
use in ongoing enhanced oil recovery projects. Most of these reservoirs are extensively
characterized and a lot of characterization information might be available in public domain.
Depleted oil reservoirs have potential offsetting benefits from enhanced oil recovery, which can
improve the overall economics of sequestration projects. Even though CO2 is being used for
enhanced oil recovery (EOR) operations for over 3 decades, sequestration of CO2 in depleted oil
reservoirs as a long-term carbon management strategy still needs validation. It is necessary to
understand long-term effect of CO2 storage in the reservoir, to develop a regulatory framework, to
determine safety and to better characterize the overall economics. This requires undertaking
specific projects where the main goal is to examine sequestration specific issues in an environment
that is conducive to sequestration studies and not typical EOR projects. This paper provides details
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of one such project. The project is funded by the U.S. Department of Energy and is the very first
field demonstration project in the US and one of the very first field demonstration projects in the
world. The objective of this project is to provide important elements of the science and technology
base to properly evaluate the safety and efficacy of long-term CO2 sequestration in a depleted oil
reservoir in particular, but in any geologic reservoir in general. The central part of the project was
injection of approximately 2100 tonnes of CO2 in a depleted sandstone oil reservoir. The fieldinjection experiment was combined with multiple monitoring techniques, laboratory experiments
and numerical modeling to characterize the reservoir response to CO2 injection and storage. The
ultimate goal of the project is to predict the migration of CO2 within the reservoir, to assess the
ability of geophysical techniques to monitor the process, and to determine the reservoir reactions
driven by the CO2 injection. This paper provides a brief overview of various project activities.
Further details can be obtained from Pawar et al. [1].
West Pearl Queen field
The field experiment took place in the west Pearl Queen field (Figure 1), which is owned and
operated by the Strata Production Company (SPC) of Roswell, New Mexico.
Los Alamos
Albuquerque
Colorado
Socorro
Roswell
Arizona New
Mexico
Hobbs
Texas
west Pearl
Queen field
Figure 1
The location of west Pearl Queen field.
The field has produced about 250,000 barrels of oil since 1984. The reservoir is a sandstone
reservoir with simple geology. All of the production from the field had been solely through
primary recovery operations, which made the field an attractive test site as interpretation of the field
experiment results would not have complications resulting from enhanced oil recovery operations.
In addition, the operator of the field had given complete freedom as per the type of experiment that
could be conducted in the field. The demonstration project was centred around field injection of
CO2 in one of the wells in the field. At the end of injection, the injection well was shut in for six
months. After six months the injection well was opened for flow and the production from the well
was monitored. In addition to the injection well, an offset well was used as a monitoring well. The
injection and monitoring wells were about 396 meters apart. The project consisted of three phases;
pre-injection characterization phase, injection and soak phase, and post-soak production phase.
Phase I: pre-injection characterization
In Phase I, pre-injection characterization activities were performed to determine potential response
of reservoir to CO2 injection and to characterize migration of CO2 in the reservoir. The
characterization activities included:
• Geologic characterization.
• Baseline geophysical characterization.
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• Laboratory experiments to characterize multi-phase flow characteristics of rock.
• Laboratory experiments to characterize the geo-chemical reactions between reservoir rock and
CO2.
• Numerical simulations for reservoir fluid flow and CO2 injection.
The data available for reservoir geologic characterization was limited to log data, outcrop data and
core data from one well. Characterization results indicated that the west Pearl Queen reservoir was
fairly homogeneous. A geologic model was developed based on the available data and was used to
develop a reservoir fluid flow model. Numerical flow simulation results indicated that CO2 could be
injected at a rate of 101.6 tonnes/day without exceeding the regulatory bottom hole pressure
constraint. In addition, simulations also predicted that injected CO2 could migrate up to the
proposed monitoring well within the proposed six months soak period. Laboratory experiments
performed to characterize geo-chemical interactions indicated formation of clays after 17 months of
exposure. Numerical simulations were performed to match observations of geo-chemical
experiments. It was observed that in order to match the laboratory experiment results formation of
dawsonite had to be suppressed during simulations. Results of pre-injection characterization
activities were used to design Phase II activities.
Phase II: CO2 injection and soak
Phase II of the project consisted of the field injection of CO2. Prior to injecting CO2 a highresolution, 3-dimensional, 9-component surface seismic survey was acquired. Acquisition of
seismic survey was part of the geophysical monitoring activities to monitor migration of CO2 in the
reservoir. It should be noted that interpretations of the pre-injection seismic survey were not
available prior to the beginning of CO2 injection. Figure 2 shows the data acquired during field
experiment.
2500
Pressure (MPa)
40
Rate (m3/day)
35
Cumulative CO2 (tonnes)
2000
30
1500
25
20
1000
15
10
Cumulative CO2 (tonnes)
Rate (m3/day) or Surface Pressure (MPa)
45
500
5
0
12/20/2002 12/30/2002
0
1/9/2003
1/19/2003
1/29/2003
2/8/2003
Time
Figure 2
The injection data during field test.
As can be seen from the figure, CO2 was injected at a constant rate of 40.64 tonnes/day at surface
injection pressure of 9.6 MPa. The injection rate could not be increased by increasing the surface
injection pressure, as this would have resulted bottom hole pressure in excess of 19.9 MPa which
was the regulatory constraint based on the rock fracturing pressure. The observed field injection
rate was significantly lower than the rate estimated based on pre-injection characterization. The
injection rate and surface injection pressure remained constant during the entire injection operation.
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After injecting approximately 2123 tonnes of CO2 over a period of 50 days, a downhole pressure
monitor was deployed in the injection well and the well was shut-in for six months. Figure 3 shows
the reservoir pressure measured during the six months soaking period.
25
Pressure (MPa)
20
15
10
5
0
0
50
100
150
200
250
Time (Days)
Figure 3
Reservoir pressure measured during six months shut-in period.
As can be seen from the figure, during the injection period the pressure in the vicinity of wellbore
was close to the rock fracturing pressure. As the injection stopped the pressure decreased and
reached a steady-state during the soak period.
Phase III: Post-soak monitoring
At the end of the soak period another high-resolution, 3-dimensional surface seismic survey was
acquired. The acquisition parameters of this survey were exactly same as the pre-injection survey.
The pre- and post-injection surveys were used to monitor the injected CO2 plume. Figure 4 shows
the difference between RMS amplitude of the pre- and post-injection P-wave data and the extent of
CO2 plume interpreted through application of the seismic survey.
Injection well
Monitor well
Figure 4
Interpretation of injected CO2 plume through interpretation of time-dependent 3-dimensional
seismic survey.
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The results show that high-resolution, surface surveys may have capability to detect small volumes
of CO2 (~ 2100 tonnes). After acquiring the second set of seismic survey, the injection well was
vented. The rates of production of liquids and gas during venting operation were monitored. In
addition periodic samples of fluids were collected for chemical compositional analyses. Figure 5
shows results of compositional analyses of gas samples collected from the monitoring well.
60.00
12/9/2003
6/15/2004
10/15/2004
12/8/2004
50.00
Mole %
40.00
30.00
20.00
10.00
0.00
Methane
CO2
Ethane Propane Butane Pentane Hexane Heptane
Gas component
Figure 5
Chemical composition of gas samples collected at different times from the monitoring well.
The dates shown on the legend represent the dates at which the gas samples were collected. The xaxis of the figure shows the different hydro-carbon components present in the gas sample. The yaxis shows the mole % of hydro-carbon component in the gas sample. As can be seen from the
figure, the injected CO2 had not travelled to the monitor well even 24 months after beginning of
injection.
Currently, the Phase III of the project is in progress, where field experiment data, pre-injection
characterization data and numerical simulations are being used to interpret the reservoir response to
CO2 injection and to understand CO2 migration in the reservoir.
Conclusions
The field observations to date indicate that in order to accurately predict migration of CO2 in the
storage reservoir, extensive characterization as well as detailed knowledge of reservoir dynamic and
static response to CO2 injection is necessary. The pre-injection geologic interpretations, based
solely on log and outcrop data, indicated that the west Pearl Queen reservoir was homogeneous.
Analysis of 3-dimensional surface seismic survey indicated that the reservoir was a lot more
heterogeneous than the pre-injection characterization based on log data. Injection rate observed
during the field experiment was significantly lower than the predictions based on pre-injection
numerical flow simulations. Similarly pre-injection flow simulations had predicted that injected
CO2 plume will migrate to the monitoring well within six months after injection. On the other hand,
during the field experiment the injected CO2 plume had not migrated to the monitoring well, even
after 24 months.
The project results also show that high-resolution, 4-dimensional surface seismic survey can be
successfully used to monitor at least ~2100 tonnes of CO2. Results of geochemical laboratory
experiments indicate formation of clays. Further investigation related to clay formation will be
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necessary as presence of clays can change permeability of reservoir impacting injection as well as
migration behaviour. Formation of dawsonite had to be suppressed to better match the results of
geochemical experimental data. This is an important result as dawsonite is being predicted as one of
the stable mineral products formed during geologic sequestration. Our observations indicate that
further investigation in the thermodynamic and kinetic behaviour of dawsonite formation is
necessary to better predict CO2 mineral sequestration.
Acknowledgements
This work was funded by the US Department of Energy. The CO2 used during the field experiment
was donated by KinderMorgan CO2 Company.
List of References
[1] Pawar RJ, Warpinski NR, Lorenz JC, Benson RD, Grigg RB, Stubbs BA, et al. Overview of a
CO2 sequestration field test in the west Pearl Queen reservoir, New Mexico. In: Bachu S, Grobe M,
editors. Special Issues of Environmental Geosciences on CO2 Capture and Storage in Geological
Media, in preparation.
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