U.S. Department of the Interior

U.S. Geological Survey

Fact Sheet 2011–3075

June 2011

Development of an Assessment Methodology for 

Hydrocarbon Recovery Potential Using Carbon Dioxide and 

Associated Carbon Sequestration: Workshop Findings

Geologic carbon dioxide (CO2) sequestration coupled 

with enhanced oil recovery using CO2 in existing hydrocarbon 

reservoirs can increase the U.S. hydrocarbon recoverable 

resource volume and prevent CO2 release to the atmosphere, 

potentially limiting CO2 contribution to global warming as a 

greenhouse gas.

Printed on recycled paper

Introduction

The Energy Independence and Security Act of 2007 

(Public Law 110–140) authorized the U.S. Geological Survey 

(USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO2

) and requested that the 

USGS estimate the “potential volumes of oil and gas recoverable by injection and sequestration of industrial carbon dioxide 

in potential sequestration formations” (121 Stat. 1711). The 

USGS developed a noneconomic, probability-based methodology to assess the Nation’s technically assessable geologic 

storage resources available for sequestration of CO2 (Brennan 

and others, 2010) and is currently using the methodology to 

assess the Nation’s CO2 geologic storage resources. Because the 

USGS has not developed a methodology to assess the potential 

volumes of technically recoverable hydrocarbons that could 

be produced by injection and sequestration of CO2, the Geologic Carbon Sequestration project initiated an effort in 2010 

to develop a methodology for the assessment of the technically 

recoverable hydrocarbon potential in the sedimentary basins of 

the United States using enhanced oil recovery (EOR) techniques 

with CO2 (CO2

-EOR). In collaboration with Stanford University, the USGS hosted a 2-day CO2

-EOR workshop in May 

2011, attended by 28 experts from academia, natural resource 

agencies and laboratories of the Federal Government, State and 

international geologic surveys, and representatives from the oil 

and gas industry. The geologic and the reservoir engineering 

and operations working groups formed during the workshop 

discussed various aspects of geology, reservoir engineering, and 

operations to make recommendations for the methodology. The 

findings of the two groups are discussed below.

Workshop Findings

Geologic Aspects

A new assessment methodology could use and build 

upon the reservoir and associated data already assembled by 

the USGS National Oil and Gas Assessment (NOGA) project 

(http://energy.cr.usgs.gov/oilgas/noga/) in previous assessments 

of undiscovered hydrocarbon resources. The assessment 

methodology could then assess individual oil reservoirs that are 

appropriate for CO2

-EOR injection techniques at the basin scale 

to estimate recoverable hydrocarbons using CO2 injection. The 

assessed reservoirs within each basin could be grouped based on 

previously defined NOGA Total Petroleum System assessment 

units with similar lithology and geologic characteristics.

Each assessed reservoir would meet the minimum size criteria used by the NOGA (0.5 million barrels of oil), and further 

characterization would be based on oil-to-gas ratio, depth, temperature, pressure, viscosity, and the API (American Petroleum 

Institute) gravity of the oil.

The methodology would estimate the original oil in 

place, if not available from the databases or publicly available 

sources, and use production data, such as cumulative production, reported reserves, and all other geologic parameters, for 

each reservoir by consulting commercial, State, and Federal 

databases and the petroleum geology and reservoir engineering literature for a comprehensive assessment. These same 

data sources would be consulted for an estimated hydrocarbon 

recovery factor for primary, secondary (with water floods), and 

tertiary recovery techniques that would use CO2 injected into the 

reservoir to improve oil recovery.

The assessment methodology would not include the 

residual oil zone (ROZ), which is the transition zone at the bottom of oil column, until the ROZ production viability has been 

established. The ROZ was discussed at the workshop as having 

future potential for additional oil recovery and therefore would 

be noted in the assessment for future study.

Reservoir Engineering and Operations Aspects

A volumetric approach to estimate recoverable hydrocarbon volumes for all conventional reservoirs at the field 

scale would be used. If sufficient data exist, production-based 

methods would be used for reservoirs in the primary or waterflood phase to determine estimated ultimate recoverable (EUR) 

hydrocarbon volumes; this may provide some check on volumetric estimates and in some cases may be the only source for 

an indirect estimate of the oil-in-place value.

Exponential decline-curve analysis can be used to estimate 

EUR volumes for most reservoirs that are currently not under 

pressure maintenance or EOR, and hyperbolic decline-curve 

analysis can be used for some reservoirs with early decline, 

strong water drive or horizontal wells. The exponential declinecurve analysis uses a semilogarithmic plot of the cumulative oil 

recovery versus the oil production rate to estimate the ultimate 
Coalbed methane 

production

Injection of CO2

 into geologic reservoirs

Pipeline transporting CO2

from powerplants to 

injection site

Offshore natural gas 

production with CO2

separation and 

sequestration

Deep coal 

seam

Deep brine 

formation

Depleted 

hydrocarbon 

reservoir

Reservoir 

trap/seal

Natural gas 

reservoir

Brine 

formation

Figure 1. Conceptual diagram showing the geologic sequestration 

of carbon dioxide (modified from Burruss and Brennan, 2003).

recoverable hydrocarbon volume; the hyperbolic decline curve 

uses a semilogarithmic graph with the production rate on the log 

scale and time on the coordinate scale.

Because reservoir pressure and temperature are a function 

of various geologic and reservoir factors, the reservoirs should 

be grouped into subsets on the basis of lithology (sandstone versus limestone), permeability (low, medium, and high), and oil 

gravity (light, medium, and heavy), and a recovery factor range 

for various groups should be established.

The main focus of the planned assessment would be 

on reservoirs within the depth range of 3,000 to 13,000 feet 

because the density of CO2 will be high at these depths; CO2

and oil miscibility that is dependent on oil composition and reservoir conditions (pressure and temperature) can develop; and 

the practical limitations of compression are based on economic 

factors and will vary with location and operator. However, some 

reservoirs outside of the specified depth range may be included 

if the reservoirs show signs of miscibility and other favorable 

factors. Although miscibility generally allows more CO2 volume 

to be sequestered in the reservoirs because of higher displacement efficiency, some of the reservoirs on immiscible flood with 

sufficiently high recovery and (or) size of the formation also 

could be included because they potentially could provide a large 

reservoir volume for carbon sequestration. When performed on 

the same reservoir under similar conditions, miscible flood will 

always outperform immiscible flood.

The assessment methodology would consider the latest 

advances in technology to improve CO2

 injection, including but 

not limited to fracturing, horizontal and multilateral drilling, 

and 4D (four-dimensional) seismic detection technologies, and 

could use the best production practices to improve production and recovery factors, such as pattern flooding, isolation of 

extremely high-permeable zones or streaks, and other reservoir 

considerations.

During the producing life of a reservoir, although a variable amount of the injected CO2

 will stay in the reservoir pore 

space, some of the CO2 will be recovered with the oil at the 

surface. The recovered CO2 is recycled after it is separated from 

the oil, recompressed, and reinjected into reservoir. Therefore, a 

continuous supply of additional CO2

 is required during the operation phase to make up for the loss of CO2

 in the reservoir. To 

prevent fracturing of the reservoir rocks and seal, the reservoir 

pressure during sequestration of CO2

 in EOR operations would 

not exceed its original value.

The conversion of produced hydrocarbon volumes at the 

surface to reservoir pore space available for CO2 sequestration 

uses formation volume factors of oil and gas. Reservoir data in 

known fields would be evaluated and the evaluated reservoirs 

would be used as analogs for reservoirs with little to no data.

The ranges of various reservoir and geologic parameters 

would be established, and Monte-Carlo simulation would be 

used to determine a probabilistic estimate of potential oil recovery and CO2

 sequestered volumes.

Basis for Assessment Methodology

The USGS Geologic Carbon Sequestration project plans 

to develop a geology- and engineering-based methodology to 

assess the potential enhanced oil recovery and CO2 sequestration volumes in oil and gas reservoirs within the sedimentary 

basins of the United States based on the findings of the USGSStanford workshop.

References Cited

Brennan, S.T., Burruss, R.C., Merrill, M.D., Freeman, P.A., 

and Ruppert, L.F., 2010, A probabilistic assessment methodology for the evaluation of geologic carbon dioxide storage: U.S. Geological Survey Open-File Report 2010–1127, 

31 p., accessed May 22, 2011, at http://pubs.usgs.gov/

of/2010/1127/.

Burruss, R.C., and Brennan, S.T., 2003, Geologic sequestration 

of carbon dioxide—An energy resource perspective: U.S. 

Geological Survey Fact Sheet 2003–026, 2 p., accessed June 

16, 2011, at http://pubs.usgs.gov/fs/fs026-03/.

U.S. Geological Survey, [undated]a, Geologic CO2 sequestration 

research at the USGS: U.S. Geological Survey, accessed May 

22, 2011, at http://energy.er.usgs.gov/health_environment/

co2_sequestration/.

U.S. Geological Survey, [undated]b, National oil and gas assessment: U.S. Geological Survey, accessed May 22, 2011, at 

http://energy.cr.usgs.gov/oilgas/noga/.

For further information, please contact

Mahendra K. Verma

U.S. Geological Survey

17842 Wildwood Creek Road

Riverside, CA 92504

Telephone (951) 398-7397

E-mail: mverma@usgs.gov

Peter D. Warwick

U.S. Geological Survey

12201 Sunrise Valley Drive, MS 956

Reston, VA 20192

Telephone: (703) 648–6469

E-mail: pwarwick@usgs.gov

By Mahendra K. Verma and Peter D. Warwick