Development of a Probabilistic Assessment Methodology 

for Evaluation of Carbon Dioxide Storage 

By Robert C. Burruss, Sean T. Brennan, Philip A. Freeman, Matthew D. Merrill, Leslie F. Ruppert, 

Mark F. Becker, William N. Herkelrath, Yousif K. Kharaka, Christopher E. Neuzil, Sharon M. Swanson, 

Troy A. Cook, Timothy R. Klett, Philip H. Nelson, and Christopher J. Schenk 

Open-File Report 2009–1035 

U.S. Department of the Interior 

U.S. Geological Survey 
U.S. Department of the Interior 

KEN SALAZAR, Secretary 

U.S. Geological Survey 

Suzette M. Kimball, Acting Director 

U.S. Geological Survey, Reston, Virginia: 2009 

For product and ordering information: 

World Wide Web: http://www.usgs.gov/pubprod

Telephone: 1-888-ASK-USGS 

For more information on the USGS—the Federal source for science about the Earth, 

its natural and living resources, natural hazards, and the environment: 

World Wide Web: http://www.usgs.gov

Telephone: 1-888-ASK-USGS 

Suggested citation:

Burruss, R.C., Brennan, S.T., Freeman, P.A., Merrill, M.D., Ruppert, L.F., Becker, M.F., Herkelrath, W.N., Kharaka, 

Y.K., Neuzil, C.E., Swanson, S.M., Cook, T.A., Klett, T.R., Nelson, P.H., and Schenk, C.J., 2009, Development of a 

probabilistic assessment methodology for evaluation of carbon dioxide storage: U.S. Geological Survey Open-File 

Report 2009–1035, 81 p., available only online at http://pubs.usgs.gov/of/2009/1035/. 

Any use of trade, product, or firm names is for descriptive purposes only and does not imply 

endorsement by the U.S. Government. 

Although this report is in the public domain, permission must be secured from the individual 

copyright owners to reproduce any copyrighted material contained within this report. 

ii
Contents 

1. Introduction................................................................................................................................................................ 1

1.1. Purpose and Scope............................................................................................................................................. 1

1.2. Conceptual Framework ....................................................................................................................................... 3

1.3. Organization of the Report .................................................................................................................................. 6

2. Geologic Concepts and Models for Probabilistic Assessment of CO2 Storage Resources ........................................ 7

2.1. Assessment Units ............................................................................................................................................... 7

2.1.1. Geologic Concept: Physical Trap and Saline Formation Components ......................................................... 7

2.1.2. Extent ......................................................................................................................................................... 10

2.1.3. Examples of Potential Additional Constraints ............................................................................................. 15

2.1.3.1. Subsurface Pressure ........................................................................................................................... 15

2.1.3.2. Formation Water Salinity...................................................................................................................... 15

2.1.4. Minimum Size............................................................................................................................................. 15

2.2. Trapping Processes .......................................................................................................................................... 16

2.3. Seals................................................................................................................................................................. 16

2.3.1. Rock Types and Properties ........................................................................................................................ 17

2.3.2. Seal Integrity .............................................................................................................................................. 17

2.4. Subsurface Fluid Flow: Injection Rates, Displacement, and Other Flow Considerations Related to 

CO2 Sequestration ........................................................................................................................................ 19

2.5. Geochemical Processes Associated with CO2 Sequestration in Geologic Formations ..................................... 21

2.5.1. CO2 Reactions with Reservoir and Seal over Time .................................................................................... 21

2.5.2. Geochemical Reactions.............................................................................................................................. 23

2.6. Storage Efficiency ............................................................................................................................................. 24

3. Storage Resource Classification and Estimation ..................................................................................................... 26

3.1. Storage Types for Volumetric Calculation Methods .......................................................................................... 27

3.1.1. Physical Trap Model and Storage Volumes................................................................................................ 27

3.1.2. Saline Formation Model and Storage Volumes .......................................................................................... 30

3.2. Probabilistic Calculations .................................................................................................................................. 31

3.2.1. Probabilistic Calculations for Discovered Physical Traps ........................................................................... 31

3.2.1.1. Example of Probabilistic Calculations, SEOR......................................................................................... 33

3.2.2. Probabilistic Modeling of Storage in Saline Formations.............................................................................. 37

3.2.3. Assigning Geologic Probability Values to Determine Unconditional Storage Resources............................ 39

3.3. Data Sources and Manipulations ...................................................................................................................... 40

3.3.1. Sources ...................................................................................................................................................... 40

3.3.2. Manipulations ............................................................................................................................................. 40

3.4. Basic Input Data Forms..................................................................................................................................... 41

3.4.1. Physical Trap Form .................................................................................................................................... 42

3.4.1.1. Identification Information...................................................................................................................... 43

3.4.1.2. Characteristics of Storage Assessment Unit........................................................................................ 43

3.4.1.3. Numerical Inputs.................................................................................................................................. 43

3.4.1.4. Characteristics of Physical Traps in the Storage Assessment Unit...................................................... 44

3.4.1.5. Storage Volume Calculation Methods.................................................................................................. 44

3.4.1.6. Physical Trap Probability of Containment ............................................................................................ 45

iii
3.4.1.7. Selected Ancillary Data........................................................................................................................ 45

3.4.1.8. Allocations of Physical Traps ............................................................................................................... 46

3.4.2. Saline Formation Form ............................................................................................................................... 46

3.4.2.1. Identification Information...................................................................................................................... 47

3.4.2.2. Characteristics of Storage Assessment Unit........................................................................................ 47

3.4.2.3. Area Calculation for the Saline Formation ........................................................................................... 47

3.4.2.4. Characteristics of the Saline Formation ............................................................................................... 48

3.4.2.5. Saline Formation Storage Volume ....................................................................................................... 48

3.4.2.6. Saline Formation Probability of Containment....................................................................................... 48

3.4.2.7. Selected Ancillary Data........................................................................................................................ 48

3.4.2.8. Allocations of the Saline Formation...................................................................................................... 48

4. Discussion: Science and Data Needs...................................................................................................................... 48

4.1. Inputs for Probabilistic Calculations .................................................................................................................. 49

4.2. Aggregation of Storage Volumes at the Basin and National Level .................................................................... 49

4.3. Geochemistry.................................................................................................................................................... 50

4.4. Seals................................................................................................................................................................. 50

4.5. Geologic Databases.......................................................................................................................................... 50

4.6. Hydraulics and Flow.......................................................................................................................................... 51

4.7. Injectivity ........................................................................................................................................................... 51

5. Conclusions ............................................................................................................................................................. 52

Acknowledgments........................................................................................................................................................ 52

References Cited......................................................................................................................................................... 53

Glossary ...................................................................................................................................................................... 61

Appendix A. Assessment Input Forms......................................................................................................................... 67

A.1. Physical Traps (PTs) Assessment Model: Basic Input Data Form.................................................................... 67

A.2. Saline Formation (SF) Assessment Model: Basic Input Data Form .................................................................. 75

Figures 

1. Diagram showing densities of CO2 and CH4 at depths of 1, 2, and 3 kilometers ........................................... 5

2. Schematic diagram of petroleum generation, migration, and accumulation................................................... 8

3. Schematic cross section through a storage assessment unit illustrating the relationship between 

discovered physical traps and the saline formation in a fill and spill model.................................................... 9

4. Pressure-temperature diagram of the phase behavior of CO2 showing the liquid-vapor coexistence 

curve terminating in the critical point............................................................................................................ 11

5. Diagram showing approximate pressure versus depth relationships for CO2 .............................................. 13

6. Maps illustrating an example of a storage assessment unit for CO2 ............................................................ 14

7. Diagram showing simulated pressure head buildup versus time in an injection well in a hypothetical 

aquifer.......................................................................................................................................................... 20

8. Schematic diagram illustrating CO2 storage types through 10,000 years .................................................... 22

9. Graph of relative types of trapping for injected CO2, over 100 years ........................................................... 23

10. Flow diagram illustrating generation of aggregate physical trap storage distribution from the input 

 values on the physical trap form ................................................................................................................. 32

iv
11. Chart showing the probability distribution of storage size in any one of 25 large discovered 

physical traps............................................................................................................................................... 35

12. Chart showing the probability distribution of the aggregate mass of CO2 storage resource ........................ 36

13. Flow diagram illustrating generation of aggregate saline formation storage distribution from input 

values on the saline formation form............................................................................................................. 38

14. Flow diagram of key steps in the USGS assessment method for estimating the CO2 storage 

resources in discovered and undiscovered physical traps........................................................................... 42

15. Flow diagram of key steps in the USGS assessment method for estimating the CO2 storage 

resources in saline formations ..................................................................................................................... 47

Tables 

1. Volumetric formulas for discovered physical traps....................................................................................... 27

2. Realistic cumulative fluid production and injection data for 10 large discovered physical traps in a 

hypothetical storage assessment unit containing 400 PTDs that have net cumulative volumes 

that exceed the minimum size of 12.5 million barrels .................................................................................. 34

3. Input parameters for probabilistic calculation of SEOR for 25 large discovered physical traps that 

produced oil in a hypothetical, but geologically realistic, storage assessment unit ...................................... 35

4. Percentiles of CO2 storage resource within the distribution shown in figure 12 ........................................... 36

Conversion Factors 

Multiply By To obtain 

Length 

inch (in.) 2.54 centimeter (cm) 

foot (ft) 0.3048 meter (m) 

mile (mi) 1.609 kilometer (km) 

meter (m) 3.281 foot (ft) 

kilometer (km) 0.6214 mile (mi) 

Area 

square inch (in2) 6.452 square centimeter (cm2) 

square foot (ft2) 0.09290 square meter (m2) 

acre 0.4047 hectare (ha) 

acre 0.004047 square kilometer (km2

) 

square meter (m2

) 0.0002471 acre 

Volume 

gallon (gal) 3.785 liter (L) 

v
Multiply By To obtain 

barrel (bbl), (petroleum, 1 barrel=42 gal) 0.1590 cubic meter (m3) 

cubic foot (ft3) 0.02832 cubic meter (m3) 

1,000 cubic feet (MCF) 28.32 cubic meter (m3

) 

liter (L) 0.2642 gallon (gal) 

cubic meter (m3

) 6.290 barrel (petroleum, 1 barrel = 42 gal) 

Mass 

pound, avoirdupois (lb) 0.4536 kilogram (kg) 

ton, short (2,000 lb) 0.9072 megagram (Mg) 

ton, long (2,240 lb) 1.016 megagram (Mg) 

milligram (mg) 0.00003527 ounce, avoirdupois (oz) 

gram (g) 0.03527 ounce, avoirdupois (oz) 

kilogram (kg) 2.205 pound avoirdupois (lb) 

megagram (Mg) = 1 metric ton (t) (1,000 kg) 1.102 ton, short (2,000 lb) 

megagram (Mg) 0.9842 ton, long (2,240 lb) 

million metric tons 1.102 million short tons 

Pressure 

atmosphere, standard (atm) 101.3 kilopascal (kPa) 

bar 100 kilopascal (kPa) 

pound-force per square inch (lbf/in2

 or psi) 6.895 kilopascal (kPa) 

kilopascal (kPa) 0.009869 atmosphere, standard (atm) 

kilopascal (kPa) 0.01 bar 

kilopascal (kPa) 0.2961 inch of mercury at 60°F (in Hg) 

kilopascal (kPa) 0.1450 pound-force per square inch (lbf/in2

) 

megapascal (MPa) 145 pound-force per square inch (lbf/in2

) 

Pressure gradient 

pound-force per square inch per foot 

(lb/in2

/ft or psi/ft) 

22.62 kilopascal per meter (kPa/m) 

Density 

pound per cubic foot (lb/ft3) 16.02 kilogram per cubic meter (kg/m3) 

pound per cubic foot (lb/ft3) 0.01602 gram per cubic centimeter (g/cm3) 

kilogram per cubic meter (kg/m3

) 0.06242 pound per cubic foot (lb/ft3) 

gram per cubic centimeter (g/cm3

) 62.4220 pound per cubic foot (lb/ft3) 

Electric power 

megawatt electrical (MWe) 3,600,000,000 joule per hour (J/hr) 

Hydraulic conductivity 

meters per second (m/s) 3.281 foot per second (ft/s) 

Hydraulic diffusivity 

vi
Multiply By To obtain 

square meter per second (m2/s) 10.76 square foot per second (ft2/s) 

Temperature in degrees Celsius (°C) may be converted to degrees Fahrenheit (°F) as follows: 

°F=(1.8×°C)+32 

Temperature in degrees Fahrenheit (°F) may be converted to degrees Celsius (°C) as follows: 

°C=(°F–32)/1.8 

Concentrations of chemical constituents in water are given in milligrams per liter (mg/L). 

Abbreviations, Acronyms, and Symbols 

AU assessment unit 

bbl petroleum barrel or barrels 

BOE barrel of oil equivalent; see glossary 

C condensate 

CCS carbon capture and storage 

CEOR storage efficiency, conventional enhanced oil recovery 

cf/bbl cubic feet per barrel 

CF1 conversion factor, petroleum barrels (42 gallons) to cubic meters: 0.159 bbl/m3

CF2 conversion factor, acre-feet to cubic meters: 1,233.5 m3/acre-ft 

CG growth factor 

CH4 methane 

CO2 carbon dioxide 

CSE storage efficiency factor 

CVOC cumulative volume of oil accumulations and condensate 

CWD correction factor, water recharge or water flooding 

D depth 

DOE U.S. Department of Energy 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

FVF formation volume factor 

GIS geographic information system 

GOR gas:oil ratio 

H2O water 

IR incremental recovery 

MCF thousand cubic feet 

MMbbl million barrels 

MMBOE million barrels of oil equivalent 

MMCF millions of cubic feet 

Mt million metric tons 

NCV net cumulative volume 

NOGA USGS National Oil and Gas Assessment 

NTP fraction of storage interval thickness with porosity greater than the minimum used for evaluation of 

petroleum resources (fraction) 

O oil 

OOIP original oil in place 

P pressure 

vii
viii

psi pounds per square inch 

PT physical trap 

PTD physical trap, discovered 

PTDs physical traps, discovered 

PTs physical traps 

PTU physical trap, undiscovered 

PTUs physical traps, undiscovered 

PVT pressure, volume, temperature 

RF oil recovery factor 

s second 

SAU storage assessment unit 

SAUs storage assessment units 

SEOR storage, conventional enhanced oil recovery 

SF saline formation 

SNCV storage, net cumulative volume 

STKV storage, total known volume 

STTV storage, total trap volume 

TA trap area 

TDS total dissolved solids 

TI thickness, interval 

TKV total known volume 

TTV total trap volume 

USGS U.S. Geological Survey 

CO2 density of carbon dioxide 

 porosity 
Development of a Probabilistic Assessment Methodology for 

Evaluation of Carbon Dioxide Storage 

By Robert C. Burruss, Sean T. Brennan, Philip A. Freeman, Matthew D. Merrill, Leslie F. Ruppert, Mark F. Becker, 

William N. Herkelrath, Yousif K. Kharaka, Christopher E. Neuzil, Sharon M. Swanson, Troy A. Cook, Timothy R. Klett, 

Philip H. Nelson, and Christopher J. Schenk 

1. Introduction 

1.1. Purpose and Scope 

The U.S. Geological Survey (USGS) has a long history of assessing national and global ground- and 

surface-water resources and geologically based energy and mineral resources. In 2007, the Energy 

Independence and Security Act (Public Law 110–140) authorized the USGS to conduct a national 

assessment of geologic storage resources for carbon dioxide (CO2) in cooperation with the U.S. 

Environmental Protection Agency (EPA) and the U.S. Department of Energy (DOE). A first step in planning 

for a national assessment is the development of a methodology to estimate storage resource potential that 

can be applied uniformly to geologic formations across the United States. 

This report defines and describes an assessment methodology for evaluation of the resource potential 

for storage of CO2 in the subsurface. Descriptions of assessment methods are available in the literature that 

address storage resources and capacities at a variety of scales, using a variety of storage mechanisms (Bachu 

and others, 2007; Bradshaw and others, 2007; U.S. Department of Energy, National Energy Technology 

Laboratory, 2008a). The methodology presented in this report is intended for evaluations from the regional 

to subregional scale in which storage assessment units (SAUs) can be defined on the basis of common 

geologic and hydrologic characteristics. The resource that is assessed is the volume of pore space into which 

CO2 can be injected and retained for tens of thousands of years. The calculation of subsurface pore volume 

for potential CO2 storage has been described in a number of publications (Bachu, 2003: Bradshaw, 2004; 

Bachu and others, 2007; U.S. Department of Energy, National Energy Technology Laboratory, 2008a; van 

der Meer and Egberts, 2008). The methodology in this report uses probabilistic methods to incorporate 

uncertainty and natural variability in volumetric parameters. The methodology incorporates statistical 

evaluation of the sizes and numbers of potential storage sites to identify the range of possible storage 

 1
resources within a storage assessment unit and the probability that some fraction of all the storage sites could 

retain a minimum storage mass of CO2. The estimated mass of storage resource is further evaluated with 

parameters that describe the probability of successful containment of CO2. 

As discussed below, the physical properties of CO2 at subsurface pressures and temperatures are 

similar to the properties of petroleum. Therefore, the CO2 resource assessment methods are built on the 

principles of USGS geologic oil and gas resource evaluation and assessment that were most recently 

described in Charpentier and Klett (2005), Crovelli (2005), Klett and Schmoker (2005), Klett and others 

(2005a), Schmoker (2005), and Schmoker and Klett (2005). These methods have been developed and refined 

over the last 40 years through periodically updated USGS national oil and gas assessments (NOGA) and 

world energy assessments. The current NOGA methodology is a refinement of methods that were 

extensively peer reviewed (Buckley and others, 1999; Curtis and others, 2001). NOGA reports on 

methodology and projects are recognized as the only publicly available, comprehensive assessment of U.S. 

oil and gas resources. NOGA data are used widely by policymakers, including the U.S. Congress, other 

Federal agencies, State geological surveys and oil and gas commissions, Tribal governments, and local 

governments, and by landowners, industry, and researchers. 

Oil and gas assessments conducted by the USGS evaluate the technically recoverable, undiscovered 

resource, which is a fraction of the total in-place resource that may be recoverable with technology available 

at the time of the assessment and for some limited time into the future, for example, on the order of decades. 

Similarly, this assessment methodology for CO2 storage resources focuses on the technically accessible 

resource, not a total in-place resource volume. This is a resource that may be available using present-day 

geological and engineering knowledge and technology for CO2 injection into geologic formations. However, 

no economic factors are used in the estimation of the volume of the resource. 

The methodology emphasizes large storage masses of CO2 for two reasons. First, petroleum resource 

assessment research indicates that most of the resource volume is found in a relatively small number (up to a 

few tens) of large accumulations, despite the possible presence of many (possibly hundreds) of much smaller 

accumulations. Second, successful deployment of geologic storage as one of many carbon management 

technologies to mitigate climate change will require storage of large masses of CO2 (hundreds of millions to 

thousands of millions of metric tons) as discussed in Pacala and Socolow (2004) and Brennan and Burruss 

(2006). Therefore, we need assessment methods that can identify the storage assessment units (SAUs) that 

have the potential to store the largest masses of CO2 and thereby have significance for national policy 

discussions on implementation of geologic sequestration technologies. However, the methods described here 

 2
can be applied to storage resources of any size and are applicable to smaller areas than those required for the 

national assessment. 

The present stage of development of the methodology focuses on storage resources in porous 

geologic formations in sedimentary basins. In particular, the methodology addresses the storage resources of 

SAUs that contain physical traps (PTs) that have produced petroleum, traps that contain petroleum but have 

not been discovered, and parts of formations between traps that are filled with saline formation water, called 

saline formations (SF) in this report. Formations that have never produced oil and gas can also be evaluated 

with this methodology. Storage in other types of geological formations, such as unminable coal beds, 

organic-matter-rich shale, basalt, or other potential geologic storage formations, is not addressed at this time. 

However, the probabilistic methods used in this report should be flexible enough that they can be modified 

to evaluate other types of geologic storage resources for CO2 sequestration. 

This report is intended for a technical audience of geologists and engineers who are familiar with the 

concepts of petroleum geology, natural resource assessment, and CO2 sequestration science. Following 

publication of this report, the USGS will establish a panel of experts in CO2 sequestration science from 

Federal and State agencies, academia, industry, and international geoscience agencies to review the 

methodology before it is published in the Federal Register, as required by the Energy Independence and 

Security Act of 2007 (Public Law 110–140). After review, an executive summary may be written for a 

nontechnical audience. 

1.2. Conceptual Framework 

Probabilistic methods of natural resource assessment are built on models of resource formation 

(mineral deposit models, petroleum systems) and models of resource discovery (discovery process or deposit 

simulation models). Developing geologically consistent models for the formation of deposits of a geologic 

commodity (for example, gold, petroleum, copper) is a critical step in the resource assessment process. The 

models provide a basis for understanding how high concentrations of a commodity (a deposit or 

accumulation) form in the earth. This knowledge improves evaluations of the possible distribution of 

resource accumulations in unexplored areas. Discovery process or deposit simulation models are developed 

from the history of exploration and discovery of resource accumulations. Statistical models based on the size 

and number of accumulations discovered over time are used to estimate distributions of the size and number 

of undiscovered accumulations. In areas with resource potential but little or no history of exploration and 

 3
deposit discovery, deposit models based on geologic analogs of extensively explored areas can be used to 

estimate resource potential (Klett and others, 2000; Schmoker and Klett, 2000). 

For geologic sequestration of CO2 to be a successful technology for limiting CO2 emissions to the 

atmosphere, a geologic resource must be identified that can retain (trap) CO2 in the subsurface. The retention 

time must be long, thousands to hundreds of thousands of years, to prevent CO2 from returning to the 

atmosphere or migrating in ways that may cause adverse environmental effects such as contamination of 

shallow ground water. Therefore, the resource for geologic storage of CO2 must have two properties: space 

(“porosity,” pore volume, or pore space) in which to inject CO2 and a trapping mechanism that will retain 

the CO2 in that space. Any area in the crust of the Earth that has a relatively high concentration of both pore 

space and trapping mechanisms can be considered an “accumulation” of the storage resource. Another 

geologic property of the subsurface that affects our concepts of the resource for CO2 storage is that there is 

no “empty” pore space in which to inject CO2. All pore space is filled with a fluid, such as formation water, 

crude oil, or gas. Therefore, injection of CO2 will cause the CO2 to interact with the existing pore-filling 

fluid or the pore walls in several ways, physically displacing the fluid or dissolving and mixing with the 

fluids or reacting with the pore walls. 

CO2 at subsurface conditions has a lower density than formation water (fig. 1) so that CO2 injected 

into subsurface pore space will displace formation water and rise buoyantly until it encounters a 

permeability barrier. At subsurface temperatures and pressures, CO2 is a fluid with a density that is within 

the range of densities of naturally occurring crude oil and significantly higher than the density of natural gas 

(fig. 1). 

 4
Figure 1. Densities of CO2 (carbon dioxide) and CH4 (methane, the main component of natural gas) at depths of 

1, 2, and 3 kilometers (km) at two different thermal gradients: 25°C/km and 40°C/km. The ranges of values for 

formation water (H2O) and crude oil are shown for comparison. 

In the subsurface, the density and buoyancy of CO2 are similar to those of crude oils so that a free 

CO2 phase will flow and accumulate in ways that are directly analogous to the flow and accumulation of oil 

and gas in traps. The key features of petroleum accumulations (petroleum systems, see figure 2 and 

discussion below) are adequate pore volume to contain the fluid, a three-dimensional trap with a seal 

(permeability barrier) to retain the fluid, and adequate permeability (flow properties) to allow extraction of 

fluid by flow to a wellbore. Because of the similarities in properties between CO2 and petroleum in the 

subsurface, resource assessment methods based on petroleum system models and discovery process models 

appear to be logical starting points for development of methods to assess the storage resource for CO2

sequestration. 

The geologic commodity that is assessed in this methodology is pore space in the subsurface. The 

fraction of the total volume of pore space within a storage assessment unit (SAU) that could be occupied by 

 5
CO2 can be described as the total in-place resource. The methodology presented in this report addresses that 

fraction of the total resource that is technically accessible with present-day knowledge and experience. The 

only parts of a storage formation with documented pore volume and trap geometry that can retain a buoyant 

fluid and that have measured flow properties are the known petroleum accumulations. The data used to 

estimate pore volume in these accumulations can be used directly, along with the known accumulation size 

and number distributions, to estimate storage resource in PTs. Furthermore, the data can be extrapolated to 

estimate storage resource in SFs. Statistical evaluation of the distributions of the geologic properties that 

control the volume of pore space and the distribution of the size and number of traps combine to serve as the 

basis of the methods in this report. 

1.3. Organization of the Report 

The report is divided into five sections. Section 1 is a review of the conceptual framework for 

assessment of storage resources used in this report. Section 2 describes the geologic model on which the 

methodology is based and the factors that may have the greatest effect on storage resources. Section 2 also 

includes descriptions of the geologic concepts of CO2 storage in SFs and in oil and gas reservoirs, or PTs. 

Section 3 introduces the description of the volumetric equations, Monte Carlo simulation techniques, and the 

necessary input data to estimate storage resources in depleted oil and gas reservoirs (PTs) and SFs (SF) that 

occur within the same strata as the oil and gas reservoirs. Prototype data input forms for each type of storage 

are included in appendix A and are described in section 3. Section 3 also includes data sources, data quality, 

and examples of storage sizes generated by the methodology. A discussion of the data gaps, knowledge 

gaps, and research directions needed to (1) reduce the uncertainties in estimates of CO2 storage resources 

and (2) refine the statistical modeling of geological storage resource estimates is included in section 4. 

Conclusions are presented in section 5. A glossary follows the “References Cited.” 

 6
2. Geologic Concepts and Models for Probabilistic Assessment of CO2 Storage 

Resources 

2.1. Assessment Units 

2.1.1. Geologic Concept: Physical Trap and Saline Formation Components 

The definition of a storage assessment unit (SAU) requires a geologic concept for CO2 storage. The 

fundamental storage process described in the conceptual framework for this assessment methodology is 

retention within geologic formations by permeability barriers. The SAU is a mappable rock package that 

consists of a porous flow unit for storage that is bounded by a sealing formation (permeability barrier, cap 

rock, or confining layer). Within the SAU there are two geologic components: the physical traps (PTs), 

which are three-dimensional containers, and the saline formation (SF), which is the porous flow unit 

between PTs. The SF is referred to as the “saline aquifer” in some sequestration literature. The objective of 

the methodology is to quantify the storage resource within PTs and that portion of the SF that will retain 

buoyant CO2. The trapping mechanisms other than physical trapping that may operate in the SF are 

described below. 

The components of a petroleum system that are most directly analogous to CO2 storage are 

petroleum migration and accumulation, which are schematically illustrated in figure 2. In this illustration, oil 

and gas are generated at some depth greater than the reservoir rock and migrate into the reservoir along a 

fault. 

 7
Figure 2. Schematic diagram of petroleum generation, migration, and accumulation. Redrawn from a copyrighted 

diagram by ExxonMobil presented by the American Geological Institute in the Earth Science World Image Bank 

(as image h5inrc) at http://www.earthscienceworld.org/images/index.html; used with permission. 

When the buoyant hydrocarbons encounter a porous and permeable reservoir unit, the hydrocarbons 

displace formation water and migrate updip beneath a seal. When the hydrocarbons encounter a trap 

enclosed by the seal, the buoyant fluids continue to displace formation water, forming an accumulation. 

During geologic sequestration of CO2, the buoyant fluid is injected into the storage formation (one 

component of the SAU) from a wellbore. However, as shown in figure 1, the CO2 density is less than that of 

formation water and commonly falls in the range of densities of crude oils. Therefore, CO2 will migrate and 

accumulate in a trap enclosed by a seal in the same way that petroleum accumulates. 

The PTs can either be discovered traps (PTDs), by definition the traps that were discovered during oil 

and gas exploration, or undiscovered traps (PTUs). The PTDs described here are defined only as the PTs that 

have produced oil and gas, excluding any traps that may have been discovered but that have not produced 

any volume of hydrocarbons or water. The potential storage volumes of the PTDs are based on rock and fluid 

properties and volumes measured during petroleum exploration and production. Potential storage volumes in 

the PTUs can be inferred from the volumes of technically recoverable, undiscovered oil and gas evaluated 

 8
during the USGS National Oil and Gas Assessment (NOGA). The volumetric properties of the SF are 

estimated from the properties measured in the PTDs and in wildcat (nonproducing) exploration boreholes. 

The total storage resource within an SAU is the sum of the resource volumes in the PTs and SF. A 

schematic illustration of the relationships of PTs and SF in an SAU is shown in figure 3. This model for the 

SAU is also called the “fill and spill model” for CO2 storage. In the cross section of an SAU illustrated in 

figure 3, there are segments that are classified as PTDs that are larger than the minimum size (PTD1 and 

PTD3) and a segment that is a small discovered trap (PTD2) that did not contain commercial volumes of 

petroleum. Therefore, the potential storage resource in PTD2 is included in the resource within the SF part of 

the SAU. 

Figure 3. A schematic cross section through a storage assessment unit (SAU) illustrating the relationship 

between discovered physical traps (PTDs) and the saline formation (SF) in a fill and spill model. 

The relationships between the storage resources in the PTs and the SF of this hypothetical SAU can 

be illustrated by considering the filling sequence of PTs and SF as CO2 is injected in the downdip leg of 

PTD1. The initially injected CO2 should flow buoyantly into PTD1, filling the volume of storage resource 

 9
that can be estimated from the cumulative production of hydrocarbons. Continued injection will fill the 

additional volume of the trap to the spill point, at which point it will continue to flow updip into PTD2. PTD2 

had hydrocarbon shows in the wildcat exploration well but did not contain commercial volumes of 

hydrocarbons. Therefore, there are no production data to evaluate this PTD. Continued injection will fill the 

trap to the spill point on fault 1, shown as a laterally transmissive fault in figure 3. Once a small trap on the 

footwall of the fault is filled, additional injected CO2 will spill into PTD3. All of the storage resource within 

the formation between PTD1 and PTD3 is in the SF. The storage resource of PTD3 is estimated from the 

cumulative volume of hydrocarbon production from this trap. If the amount of injected CO2 exceeds the 

volume of PTD3, it will migrate laterally under the seal, and the additional CO2 will accumulate until it 

reaches a regional spill point. It may be possible to store additional volumes of CO2 until the total injected 

volume reaches another regional spill point labeled “maximum fill.” This could be the maximum amount of 

technically accessible storage resource because as shown in figure 3, fault 2 extends to the surface. If the 

fault surface is permeable, then it could be a leakage pathway to the surface if CO2 injection continued until 

CO2 spilled updip to the fault. 

In this schematic illustration, the only parts of the SAU along the cross section that have measured 

volumetric and flow parameters are within PTD1 and PTD3. Limited amounts of data may be available from 

wildcat wells and small PTDs (such as PTD2), but the properties of the SF must be inferred from the 

properties documented in PTD1 and PTD3. 

2.1.2. Extent 

The vertical extent of an SAU in depth is determined by the pressure, volume, and temperature 

(PVT) properties of CO2, whereas the area of the SAU is defined by the geology. The phase relations of CO2

are shown in figure 4. The critical point of CO2 is the maximum temperature and pressure at which liquid 

and vapor CO2 can coexist (fig. 4). 

 10
Figure 4. Pressure-temperature diagram of the phase behavior of CO2 showing the liquid-vapor coexistence 

curve terminating in the critical point. At pressures and temperatures higher than this point, CO2 is a fluid with 

variable density commonly referred to as a supercritical fluid. The vertical bar to the left of the pressure axis 

shows the approximate depth in feet for a hydrostatic pressure gradient. The red line labeled 25oC/km shows 

the pressures and temperatures in the subsurface for this thermal gradient and a hydrostatic pressure gradient. 

Note that at depths greater than 3,000 ft, CO2 should be supercritical in the subsurface. 

At temperatures and pressures greater than the critical point, CO2 is supercritical and has densities in 

the range of 500 to 700 kilograms per cubic meter (kg/m3

). The pressure and temperature requirements are 

typically met at depths greater than 800 meters (m, or about 2,600 feet) at hydrostatic pressure conditions. 

To limit the potential of CO2 migrating to pressure and temperature conditions where it could convert from 

 11
the supercritical state to liquid and vapor, we have chosen a minimum depth of storage of 3,000 feet (ft). 

Although CO2 can be stored at depths of less than 3,000 ft, the amount of storage per unit volume of pore 

space may be significantly less than that at depths greater than 3,000 ft, particularly if CO2 is in the vapor 

phase. Therefore, the potential for additions to the storage resource may be relatively small. The minimum 

depth of storage sets the upper depth limit of the SAU, which in turn limits the areal extent of the SAU on 

the updip portions of the SAU. 

A lower depth limit for CO2 storage is more arbitrary than the upper depth limit, and at least one 

methodology (U.S. Department of Energy, National Energy Technology Laboratory, 2008a) does not set any 

depth limit. However, CO2 injected at the wellhead within the range of pipeline pressures, for example, 150 

bar (2,175 pounds per square inch, psi), results in pressures at the bottom of the well that will be equal to or 

higher than hydrostatic pressure at depths of 1 to 3 km as shown in figure 5. Therefore, CO2 injected at these 

depths will displace normally pressured formation water without additional compression. If injection 

wellhead pressure from the delivery pipeline is slightly higher than illustrated in this figure, injection depths 

without additional compression can extend to about 13,000 ft (~4 km). Therefore, we have chosen to limit 

the maximum depth of assessed units to 13,000 ft. If geologic and hydrologic conditions indicate that CO2

storage may be possible at greater depths, then this storage can be assessed and reported as potential 

additions to the CO2 storage estimates. The process and consequences of the creation of the SAU are shown 

in an example using the Frio Formation in figure 6. 

 12
Figure 5. Approximate pressure versus depth relationships for CO2 at two different densities compared to 

subsurface pressure in a hydrostatic column of formation water (hydrostatic gradient), pressure due to the load 

of the rock column (lithostatic gradient), and a generic gradient for the pressure necessary to fracture the rock 

(fracture gradient). The dashed blue lines show the approximate change in pressure with depth for a static 

column of CO2 extending from the top of an injection well (injection pressure) into the subsurface for CO2 at two 

different densities. The densities are 0.5 and 0.7 grams per cubic centimeter (g/cm3). The straight lines are an 

approximation of the pressure versus depth relationship, which will be curved and a function of injection 

pressure, injection rate, and other flow variables. The pressure labeled “Injection pressure” is in the range of 

pressures in CO2 pipelines for enhanced-oil-recovery (EOR) projects. 

 13
Figure 6. Example of a storage assessment unit (SAU) for CO2. A, SAU for the Frio Formation encompasses 

parts of two units defined for the USGS National Oil and Gas Assessment (NOGA): the Frio Stable Shelf Oil and 

Gas Assessment Unit and the Frio Expanded Fault Zone Oil and Gas Assessment Unit (U.S. Geological 

Survey, 2009). The SAU is constrained to the parts of the formation where the structure top (Swanson and 

Karlsen, 2009) is at least 3,000 ft below surface but above the lower depth limit of 13,000 ft. The Frio Formation 

test case is limited to Texas onshore and State waters. B, The gross formation thickness grid (Swanson and 

Karlsen, 2009) for the Frio Formation SAU excludes volumes at depths below 13,000 ft below the surface. C, 

The gross formation thickness grid for the Frio Formation SAU is revised also to exclude the overpressured 

zone derived from Wallace and others (1981). The presence of an overpressured zone can reduce the 

thickness to zero where the overpressure occurs above the top of the storage formation. In this example, the 

depth to the top of the overpressured zone is defined by the first occurrence of a pressure gradient of 0.5 pound 

per square inch per foot (lb/in2/ft). 

 14
2.1.3. Examples of Potential Additional Constraints 

2.1.3.1. Subsurface Pressure 

The lower depth limit of an SAU may be affected by the subsurface pressure regime. In relatively 

young sedimentary basins, such as the Gulf of Mexico, the pressures in formation fluids may exceed the 

hydrostatic pressure gradient (pressures commonly called overpressures), in some cases approaching the 

pressures due to lithostatic load (the black line labeled “Lithostatic gradient” in figure 5). Storage of CO2 at 

overpressure conditions will be difficult due to additional compression needed to inject CO2 at these 

conditions. Another limit to the technically accessible resource may be regulatory limits to injection 

pressure. For example, proposed regulations on CO2 injection wells (U.S. Environmental Protection Agency, 

2008) state that the injection pressure should not exceed 90 percent of the fracture pressure gradient for the 

lithology of the storage formation. The presence of naturally occurring overpressures may require injection 

pressures that are higher than this limit. 

2.1.3.2. Formation Water Salinity 

The U.S. standard for the salinity of drinking water is 500 milligrams per liter (mg/L) total dissolved 

solids (TDS), but any formation water with salinities lower than 10,000 mg/L TDS, regardless of depth, has 

the potential to be remediated and used as a potable water supply (U.S. Environmental Protection Agency, 

2009). The U.S. Environmental Protection Agency (2008) has proposed the 10,000 mg/L TDS limit for 

injection of CO2. Therefore, the potential storage resources for CO2 in formations with salinities less than 

10,000 mg/L TDS are not assessed in this methodology. Although salinities of formation water commonly 

increase with depth, it is possible that formation water within an assessment unit may be less saline than the 

10,000 mg/L limit near the updip extent of the formation, eliminating a portion of the SAU. 

2.1.4. Minimum Size 

The concept of minimum size of technically accessible storage resources is important for 

probabilistic models of geologic resource assessment. A minimum accumulation size is used in the NOGA 

methodology as a way to eliminate any resource that will not be significant over the time span considered 

for the assessment. The minimum storage size used for this assessment methodology is 2 million cubic 

meters (approximately equivalent to 12.5 million petroleum barrels) of pore volume, which is equivalent to 

approximately 1 to 1.4 million metric tons of CO2. This value represents the smallest potential storage size 

for an individual CO2 storage project. However, a more relevant minimum storage size that could be used is 

 15
20 million metric tons of CO2, as that represents the mass of CO2 emissions from an individual industrial 

source generating 1 million metric tons of CO2 per year over a timeframe of 20 years. An even larger 

minimum size could be 400 million metric tons of CO2, the storage volume that is needed to store the 

cumulative emissions of a 1,000-megawatt coal-fired powerplant that is estimated to emit about 8 million 

metric tons of CO2 per year (Brennan and Burruss, 2006) over the 50-year typical lifetime of a powerplant. 

By using probabilistic methods to evaluate the sizes and numbers of traps within an SAU, we can evaluate 

both the aggregate storage resource of the SAU and the probability that any trap or a fraction of the SF may 

retain at least a minimum storage mass required for deployment of carbon capture and storage (CCS) 

projects. 

2.2. Trapping Processes 

A number of processes will trap CO2 in the subsurface. These include (1) physical trapping, or 

structural and stratigraphic trapping, of the buoyant phase below a seal or within a structure that has vertical 

and lateral permeability barriers (an oil and gas reservoir); (2) trapping by capillary forces in the pores of 

reservoir rocks on the trailing edge of the mobile CO2 plume, typically referred to as capillary trapping and 

less commonly referred to as residual trapping; (3) solution trapping, where the CO2 is dissolved in 

formation water, forming aqueous species such as H2CO3, HCO3

–

, and CO3

2–; (4) dissolution trapping by 

dissolution in residual oil, mixing with residual gas, or solid organic matter (coal or kerogen) sorption; and 

(5) mineral trapping by precipitation of carbonate-bearing mineral phases, such as calcite, magnesite, 

siderite, and dawsonite. For development of this assessment methodology we focused on physical and 

capillary trapping and dissolution and mixing of CO2 in formation water and residual hydrocarbons. 

2.3. Seals 

Seals (confining units, aquitards, cap rock) are regional geologic strata that inhibit the migration of 

fluids from adjacent geologic strata. The presence and adequacy of a seal is critical for defining a potential 

SAU for CO2 sequestration. A seal may consist of single or multiple formations that have physical 

properties, usually defined by the lithofacies and burial history, that allow the retention of underlying fluids 

and gases. The petroleum industry has conducted extensive research on regional seal properties, seal 

behavior of faults, and the causes of seal failure (Skerlec, 1999; Couples, 2005; Hermanrud and others, 

2005; Lowry, 2005; Nordgård Bolås and others, 2005). Assessment methods for geologic storage of CO2

will require evaluation and prediction of seal integrity. Subsurface data from wells, formation tests, and 

 16
laboratory measurements of rock properties are available from geographic regions with an extensive history 

of oil and gas exploration and production. Geologic provinces with sparse or poorly distributed 

measurements of seal properties may require additional measurements to assess seal integrity. Oil- and gasproducing basins are the most promising geologic provinces for CO2 sequestration because geologists have 

data for the basins about lithology and depositional environment; extent, thickness, and integrity of top and 

fault seals; and the history of fluid migration. 

2.3.1. Rock Types and Properties 

Many rock types exhibit properties that can behave as a seal for CO2 sequestration within the SAU as 

long as the seal unit or units have a wide geographic extent. Typical rock types that are documented as top 

seals include unfractured evaporites (halite, gypsum-anhydrite), mudrock (shale, mudstone, siltstone, 

claystone), argillaceous carbonate mudstone (clay-rich micrite), chert and other siliceous mudrock 

lithofacies, and some volcanic deposits such as basalt. Rock strata exhibiting the following physical 

properties can be effective seals: (1) sufficient geographic extent throughout a basin; (2) sufficient thickness, 

low permeability, and high capillary entry pressure to inhibit diffuse porous flow; and (3) sufficient ductility 

to deform plastically under strain without fracturing. 

Mudrock, the most common seal for oil and gas traps, exhibits most or all of the necessary attributes 

to act as a regional seal. Within some sedimentary basins, thick, regionally extensive, fine-grained and very 

fine grained sandstone and siltstone with low permeability can serve as adequate seals under normal 

(hydrostatic) pressure gradients. Fine-grained carbonate, basalt, and chert are commonly brittle, rendering 

them susceptible to faulting and fracturing, resulting in high potential for seal failure. Evaporites, such as 

gypsum and anhydrite, exhibit ideal seal properties, but, in some areas, their geographic extent and thickness 

are limited. Where extensive salt deposits exist, such as deep below the U.S. Gulf Coast, salt could behave 

as an adequate seal; however, the depth and pressures may be prohibitive for CO2 injection. Regional shale 

(or mudrock) layers associated with major marine transgressions (marine flooding surface) are very effective 

top seals in many passive margin continental settings with hydrocarbon accumulations. 

2.3.2. Seal Integrity 

Oil and gas exploration companies routinely study top seals and fault seal traps to predict which traps 

will hold hydrocarbon accumulations and which traps will not. Similar approaches need to be undertaken to 

understand seal integrity for the injection and storage of CO2. The two primary pathways of fluids through a 

 17
seal that may account for seal failure are (1) diffuse porous flow where the capillary entry-pressure of the 

seal is exceeded by the pore pressure as determined by the column height of the fluids (Hermanrud and 

others, 2005) and (2) leakage through fractures and faults. Diffuse porous flow is not considered to be a 

significant factor in the movement of fluids through seals (Couples, 2005). Flow simulations through 

mudrock seals suggest that CO2 under Darcy flow is slow enough that the pore network of the seal retards 

vertical flow. However, sensitivity analysis of simulated fracture flow indicates that fractures are likely to 

serve as conduits for CO2 migration (Cavanagh and others, 2006). Studies of seal fractures in oil and gas 

fields indicate that fracture flow accounts for large volumes of fluid movement through the seal. Skerlec 

(1999) estimated that a fracture with a permeability of 0.05 millidarcy (mD) in a seal overlying a typical 

North Sea field can leak more than 100 billion barrels per million years (or approximately 273 barrels per 

day). 

 Overpressured reservoirs can exceed the fracture pressure of the overlying seal, resulting in active 

fracturing and fluid flow during injection. Active fracturing is a potential hazard for CO2 injection and may 

occur in a seal where the pore pressure in the trap, resulting from either the CO2 injection rate or the height 

of the buoyant column of CO2, exceeds the fracture pressure of the seal. For this reason, an understanding 

of the fracture pressure and burial history within a basin is important for evaluating a seal in an SAU. 

Previously existing faults and fractures have the potential to be permeability barriers that act as seals 

or to be transmissive, allowing fluid flow across the fault or up the fault plane. Vertical migration along a 

fault plane or through an extensive fracture system within a seal formation may result in seal failure. Fault 

seals have been extensively investigated to understand hydrocarbon migration and trapping (Skerlec, 1999; 

Brown, 2003; Jones and Hillis, 2003; Couples, 2005; Hermanrud and others, 2005). Capillary entry 

pressures of faults are a significant parameter to determine the effectiveness of the fault seal. The integrity of 

the fault seal may be affected by the juxtaposition of the strata within the fault plane, fluid pressures, 

mineralogy, and geometry of the fault system. Fluid movement along faults can be inhibited by clay smear 

or shale gouge, cataclasis, or cementation of authigenic minerals such as quartz and dolomite (Gluyas and 

Swarbrick, 2004). Threshold ratios of shale to sand within the fault blocks and fault plane have been 

developed for specific basins to estimate the effectiveness of fault seals (Skerlec, 1999). For CO2

sequestration, an approach analogous to oil and gas exploration will be needed to assess the effects of faults 

on fault seal integrity, sustainment of column height, and the potential for seal failure. 

 18
2.4. Subsurface Fluid Flow: Injection Rates, Displacement, and Other Flow Considerations Related to 

CO2 Sequestration 

Target formations for sequestration must accommodate CO2 injection rates that are large enough to 

make full-scale sequestration practical without inducing large pressure changes that can fracture the rock. 

Characterizing the ability to maintain large CO2 injection rates requires consideration of time-varying fluid 

flow in porous media and accompanying changes in fluid storage. Injected fluid is accommodated by (1) 

fluid compression, (2) expansion of the pores, and (3) displacement of fluids already in the pores. These 

processes may occur simultaneously in the same volume of rock as a result of fluid pressure increases. 

Confining layers (seals and low-permeability interbedded strata) adjoining aquifers can accept large 

volumes of fluid displaced during injection. As a result, pressure increases during injection (fig. 7) are 

strongly controlled by confining layer properties. In formations from which water, oil, or gas have been 

extracted, system behavior during extraction may provide information about the confining layers. In many 

situations, however, little is known about confining layer hydraulic behavior and even the large-scale 

connectedness and behavior of the aquifer are unknown. Research to improve characterization of these flowcontrolling aspects of subsurface systems is crucial to incorporate flow aspects into future updates of this 

methodology and any large-scale CO2 injection efforts. 

 19
Figure 7. Simulated pressure head buildup versus time in an injection well in a hypothetical aquifer. The Theis 

(1935) solution is calculated according to an assumption that the aquifer confining layers are impermeable, 

whereas the so-called “leaky aquifer” solution allows movement of water into the confining layers. The curves 

are based on the following assumed values: an injection rate of 1.5 × 107 m3 per year; an aquifer hydraulic 

conductivity and specific storage of 7.4 × 10-6 m/s and 1.0 × 10-6 1/m, respectively; and, for the “leaky aquifer” 

case, a confining layer hydraulic diffusivity of 3.0 × 10-6 m2/s. Abbreviations are as follows: m2 = square meters, 

m3 = cubic meters. m2/s = square meters per second, 1/m = inverse meters. 

 20
2.5. Geochemical Processes Associated with CO2 Sequestration in Geologic Formations 

2.5.1. CO2 Reactions with Reservoir and Seal over Time 

Injected CO2 may react with reservoir and seal rocks, causing dissolution, precipitation, and 

transformation of minerals that may result in changes in porosity and permeability (Hepple and Benson, 

2005; Xu and others, 2005; Kharaka and others, 2006) and potentially affecting the probability of 

containment of CO2. Geochemical reactions with formation water and reservoir and seal rocks begin 

immediately upon injection of supercritical CO2 and continue until the system reaches equilibrium, probably 

on the time scale of tens of thousands of years [fig. 8 (Benson and Cook, 2005)]. 

During injection (Han, 2008; Han and McPherson, 2008), the bulk of the CO2 will be stored as a 

supercritical fluid by structural and stratigraphic trapping. Some of the CO2 will dissolve in formation water, 

causing solution trapping through the formation of aqueous species such as H2CO3, HCO3

–

, and CO3

2-. 

Initially, the total content of dissolved CO2 species in formation brines will be in the range of 1 to 5 percent 

by brine weight (Spycher and Pruess, 2005). According to computer modeling, capillary trapping of CO2 in 

the pores of reservoir rocks trailing the supercritical plume is likely to be volumetrically limited during the 

injection phase of a sequestration project (Han and McPherson, 2008). 

Through time, residual, solution, and mineral trapping will become the dominant storage phases 

(figs. 8 and 9), thereby increasing storage containment. The amount of CO2 sequestered in each phase will 

be dependent on reactivity of the reservoir minerals, the chemical composition of the formation water, and 

reservoir pressure and temperature (Hitchon, 1996; Knauss and others, 2005; Perry and others, 2007; Han 

and McPherson, 2008). 

 21
Figure 8. Schematic diagram illustrating CO2 storage types through 10,000 years (from Benson and Cook, 2005). 

The term solubility trapping here is synonymous with the term solution trapping used in the text. 

 22
Figure 9. Relative types of trapping for injected CO2, over 100 years, from a numerical model of the SACROC 

unit of the Kelly-Snyder field, western Texas. During the first 30 years of the simulation, CO2 is injected for 

enhanced oil recovery (EOR). The remaining time in the modeled results shows the response of the system with 

no additional injection. Modified from Han (2008). 

2.5.2. Geochemical Reactions 

Experimental measurements and equations of state for CO2 and brines indicate that CO2 solubility 

increases with decreasing salinity of formation water, increasing the ratio of dissolved calcium (Ca) to 

sodium (Na) and increasing pressure of CO2. CO2 solubility decreases with increasing temperature to about 

150°C and then increases at higher temperatures (Duan and Sun, 2003; Rosenbauer and others, 2005). 

Computer simulations, laboratory experiments, and field tests indicate that the amount of CO2 sequestered 

by mineral trapping (Gunter and others, 1997; Hellevang and others, 2005; Palandri and others, 2005; Perry 

 23
and others, 2007) is primarily dependent on the reactivity of the reservoir minerals but affected by the 

chemical composition of the formation water and reservoir temperature and pressure (Hitchon, 1996; Knauss 

and others, 2005; Perry and others, 2007; Han and McPherson, 2008). Injection of CO2 into limestone 

reservoirs will result in relatively rapid dissolution of carbonate minerals to saturation with calcite and a ~2-

percent increase in porosity (Emberley and others, 2005; Rosenbauer and others, 2005). Kharaka and others 

(2006, 2009) showed that injection of CO2 into arkosic sandstone initially lowered pH values (as low as 

~3.0) leading to dissolution of calcite and iron oxyhydroxides. Their geochemical simulations indicated that 

brine pH would increase over time as a result of the slower dissolution of feldspar minerals (oligoclase), 

leading to the precipitation of calcite, dawsonite, and other minerals over time (Kharaka and others, 2006, 

2009). More carbonate minerals would ultimately precipitate from sandstones with more feldspar minerals 

and where the feldspars were more calcic (for example, anorthite). Reactive siliceous reservoir and seal 

rocks that contain high concentrations of magnesium, iron, and calcium (Mg, Fe, and Ca) can sequester high 

volumes of CO2 as carbonate minerals. 

Abundant relevant and detailed information exists on the chemical composition of formation water 

produced with oil and gas and obtained from drill-stem tests and other fluid sampling procedures carried out 

on exploration wells (see Kharaka and Hanor, 2007, for a recent review and list of references). The USGS 

produced-waters database (Breit, 2002) contains chemical data for approximately 70,000 U.S. wells, which 

can be used to determine salinities and chemical composition of formation waters for CO2 storage 

assessments in the United States. 

2.6. Storage Efficiency 

The storage efficiency factor is the fraction of the total pore volume of a PT or the SF that will be 

occupied by CO2. In practice, this value is not well known and is given as a distribution that reflects the 

range and most likely value of the parameter. The distribution of values may have significantly different 

ranges depending on the dominant trapping processes and whether storage occurs in the PTs or the SF of an 

SAU. The storage efficiency is the sum of the fractions of storage due to each trapping mechanism 

(buoyancy, capillarity, dissolution, solubility, mineralization). For example, in a PT within a storage 

formation with homogeneous porosity and permeability, trapping will be dominated by buoyancy. The 

maximum fraction of the porosity in the trap that can be filled with CO2 is the complement of the irreducible 

water saturation due to gravity drainage. In this case, storage efficiency will have relatively high values and 

may range from 0.4 to 0.8. However, if the storage formation in the PT has a heterogeneous distribution of 

 24
flow properties with large variations in permeability on relatively short length scales, then storage may be 

dominated by capillarity and solubility. This situation will decrease storage efficiency to a range on the order 

of 0.05 to 0.20. In the SFs, physical trapping due to buoyancy may be of limited importance, with trapping 

dominated by capillarity, solubility, and mineralization. Each of these trapping processes retains a relatively 

small amount of CO2 per unit of storage formation, resulting in storage efficiencies on the order of 0.01 to 

0.05 (U.S. Department of Energy, National Energy Technology Laboratory, 2008a). However, the 

uncertainty in storage efficiency in SFs may be larger than this range because the processes that retain CO2

within SFs are not as well understood as the processes in PTs. 

In traps where buoyancy is the dominant trapping mechanism, the fraction of pore space that will be 

occupied by CO2 can be reduced by any factor that causes the buoyant fluid to escape from the PT, such as 

failure of the seal or the presence of transmissive faults. Capillary trapping of CO2 will occur only in 

portions of the rock that the CO2 plume has moved through. The movement of a CO2 plume is by nature 

anisotropic, because the storage formation is heterogeneous. Therefore, the CO2 plume will interact with the 

portions of the storage formation that have relatively higher transmissivities than the rest of the storage 

formation. Furthermore, the fraction of pore space occupied by CO2 via capillary trapping will be a function 

of the heterogeneity in the distribution of porosity within the storage formation (Doughty and others, 2007). 

Similarly, the fraction of pore space occupied by CO2 via solution, dissolution, or mineral trapping will also 

be determined by heterogeneity, as all of these processes are dependent on the interaction of the CO2 plume 

with formation fluids and minerals. 

The maximum values for storage efficiency assume ideal trapping conditions for all storage types. 

Factors that control the minimum values for the storage efficiency distribution in PTs are any geologic or 

hydrologic process that reduces pore volume available for CO2 storage. For storage determined by fluid 

production, the minimum efficiency values are controlled by factors such as recharge of formation water that 

refills pore space or compaction of the formation reducing pore volume. In addition, any process that 

reduces the size of the trap, such as seal failure, transmissive faults, or well bore failure, will reduce the 

storage efficiency of the PTs. 

The storage processes in SFs are different than those in PTs in that the relative percentage of CO2

trapped as a buoyant fluid may be much lower in SFs. Other processes such as capillary, solution, and 

dissolution trapping in SFs may be more important than in PTs. The uncertainty in storage efficiency in SFs 

may be large because the processes that retain CO2 within SFs are not as well understood as processes in 

PTs. Similar to the previous discussion of the impact of heterogeneity on plume migration, capillary 

 25
trapping, and other trapping processes, the heterogeneity of the SF may be a critical factor in estimating the 

storage efficiency of SFs. However, all the factors that control storage efficiency in PTs, such as the seal, 

faults, and well failure, must also be factored into the storage efficiency estimate for SFs. 

3. Storage Resource Classification and Estimation 

The probabilistic methods used in this assessment methodology are based on the methods developed 

over many years by USGS geoscientists for assessment of undiscovered, technically recoverable oil and gas 

resources (referred to here as “NOGA methods”, where NOGA stands for the USGS National Oil and Gas 

Assessment). Two types of NOGA methods are relevant to CO2 storage assessment: (1) conventional 

petroleum accumulation assessments and (2) deposit simulation assessments. Both methods estimate 

resource in conventional accumulations at the assessment unit (AU) or play level, where the goal is 

estimation of the aggregate volume of resource within an estimated number and size distribution of discrete, 

undiscovered, conventional accumulations (Schmoker and Klett, 2000). The NOGA conventional petroleum 

accumulation assessment method is used in basins that have a history of oil and gas exploration and 

development, with adequate statistics to apply discovery process modeling (Drew, 1990, 1997; Drew and 

Schuenemeyer, 1993; Houghton and others, 1993). The NOGA deposit simulation model is used in USGS 

evaluations of oil and gas resources in the North Slope of Alaska, where there are significant limitations on 

data available from historical exploration and development and the amount of geological information is also 

limited (Schuenemeyer, 2005). Both methods can take into account additional geologic factors that may 

limit the chance of successful discovery of resources greater than a minimum size – the overall evaluation of 

these factors is expressed as a probability of success (evaluation of risk). The resource estimated without 

taking into account these geologic factors is referred to as the conditional resource, whereas the resource 

estimated accounting for these geologic factors is referred to as the unconditional resource. The two methods 

differ on how the unconditional resource is determined. The NOGA conventional methodology 

unconditional resource takes into account the possibility that there might be no recoverable resource in the 

entire AU greater than some minimum size. In contrast, the deposit simulation methodology provides for the 

evaluation of success at two levels: (1) a probability that the entire play may not contain a deposit that meets 

the minimum size: and (2) a probability that individual deposits may not meet the minimum size. 

The CO2 storage resource assessment methodology adapts these NOGA methods to the evaluation of 

technically accessible storage resource. Both conditional and unconditional resources are evaluated as 

described below. 

 26
3.1. Storage Types for Volumetric Calculation Methods 

3.1.1. Physical Trap Model and Storage Volumes 

Discovered traps (PTDs) within a SAU are the oil and gas reservoirs within the flow unit of the SAU 

that have a history of oil and gas production. In this storage type, retention of free-phase CO2 by a seal is the 

dominant trapping mechanism, although dissolution trapping in the residual oil phase and residual formation 

water also occur. Because hydrocarbons were present and produced from the PTD, an effective seal is 

present, and the production history provides information about the flow properties of the PTD. If there is 

evidence of seal failure or problems with fluid flow in the PTD, then this information can be incorporated 

into the factors used to evaluate containment success. The data gathered on the PTDs can be used to make 

inferences about the properties of the PTUs. The numbers and sizes of undiscovered conventional 

accumulations estimated for NOGA AUs can be used in conjunction with the data from the PTDs to create 

the data distributions required for the CO2 storage resource input form. 

Four types of storage resources can be estimated in PTs. Each type can be evaluated in this 

methodology. The formulas and inputs used to calculate the volumes of resource in each type of storage are 

given in table 1 and discussed in later sections of this report. 

Table 1. Volumetric formulas for discovered physical traps (PTDs). 

[Symbols are defined in the table footnotes] 

Calculation method Storage type Formula 

 A Conventional EOR, SEOR = OOIP* IR * CEOR

 B Net cumulative volume, NCV, SNCV = NCV*CWD* CF1*CO2

 C Total known volume, STKV = TA*TI*NTP**CSE* CF2*CO2

 D Total trap volume, STTV = STKV * CG

OOIP: volume of original oil in place (OOIP) in petroleum barrels. If values are not available, OOIP can be calculated from the

cumulative volume of produced hydrocarbon liquids by using a recovery factor. The equation for calculating OOIP follows: OOIP 

= CVOC /RF. 

CVOC: cumulative volume of produced hydrocarbon liquids in reservoirs that are classified as oil accumulations (oil (O) + 

condensate (C) in petroleum barrels). 

RF: oil recovery factor (fraction). 

 27
IR: incremental recovery of OOIP induced by CO2 enhanced-oil-recovery (EOR) methods (fraction). 

CEOR: storage efficiency of conventional EOR, in metric tons of CO2 retained in the reservoir per barrel of incremental oil 

recovered (fraction). 

NCV: net cumulative volume of reservoir fluid produced, in barrels at subsurface conditions. See text for discussion of conversion 

of volume of produced gas to subsurface volume in barrels. 

CWD: correction factor for potential refilling of trap by natural water recharge or water flooding during oil recovery (fraction). This 

may limit the fraction of the trap that can be filled with CO2 (see discussion in Shaw and Bachu, 2002). 

CF1: conversion factor, petroleum barrels (42 gallons) to cubic meters (m3

): 0.159 bbl/m3 

CO2: density of CO2 in metric tons per cubic meter (metric tons/m3). 

TA: trap area from which hydrocarbons and water have been produced, in acres, defined by production well locations. 

TI: interval thickness of storage formation, in feet. 

NTP: fraction of TI, with porosity greater than the minimum used for evaluation of petroleum resources (fraction). The product (TI* 

NTP) is commonly called “net pay,” “net productive interval,” or “net porous interval.” 

: porosity (fraction). 

CSE: storage efficiency factor; that fraction of the pore space that can be occupied by CO2. In PTs, this value should approach the 

complement of the irreducible water saturation. 

CF2: conversion factor, acre-feet to cubic meters (m3

) = 1,233.5 m3/acre-ft. 

CG: growth factor, accounting for the potential that the area of the trap that produced hydrocarbons, TA, may be less than the area 

of the trap to the spill point. Default value is 1.0 (no growth), but if values can be estimated from geologic information, they 

should be >1.0. 

PTs that are classified as oil reservoirs have the gas:oil ratio (GOR) less than 20,000 cubic feet per 

barrel (cf/bbl); for such PTs, one type of storage resource is related to the net CO2 left in place following 

conventional CO2 EOR practice (water-alternating-gas injection) (J.P. Meyer, Contek Solutions, Plano, Tex., 

written commun., 2009). This is called conventional EOR storage (SEOR). This estimate of storage is 

typically the smallest storage resource assigned to a specific trap. However, CO2 injection for EOR is a 

proven technology that is currently in use in oil fields. Furthermore, EOR can be initiated in oil fields prior 

to depletion without damaging the resource, providing a CO2 storage technology that could be deployed 

today. 

Another type of storage resource in PTs is based on the net cumulative volume (NCV) of oil, gas, 

and water produced from the PTD. This is SNCV. The NCV is the cumulative volume of fluid production (oil, 

gas, and water) minus the volume of fluid injected (water and gas) over the production history of the PTD. 

Accurate calculation of NCV (commonly called fluid balance in the petroleum engineering literature) 

 28
requires correction of the volumes of the fluids measured at surface conditions to the volumes that they 

occupied in the subsurface through the use of formation volume factors for each fluid. If there has been no 

natural water recharge (water drive) or water injection into the PTD, and no evidence of loss of porosity due 

to compaction after fluid extraction, then the NCV may be the storage resource with the least uncertainty. If 

there is some evidence of natural water drive or the reservoir has undergone secondary recovery by 

waterflooding, then this volume must be modified by a correction factor, CWD, that accounts for the fraction 

of pore space that is “refilled” by water that cannot be displaced by injected CO2 (Shaw and Bachu, 2002). 

This storage resource is not applicable to PTUs, which are, by definition, undiscovered and have not had any 

fluid removed or injected. Therefore, PTUs are not considered for the NCV calculation. 

A third type of storage resource, the total known volume (TKV), is based on the total volume of pore 

space within the area of an oil and gas reservoir, called STKV. The volume is calculated by using the area of 

the reservoir as defined by the locations of the wells that produced fluids from that reservoir, the net sand 

reservoir thickness beneath the field, the porosity, and a correction factor, CSE, where “SE” stands for 

storage efficiency, that accounts for the fraction of pore space that can be occupied by injected CO2. Once all 

recoverable hydrocarbons have been removed from the trap, especially in pressure-depleted gas fields, the 

upper limit on CSE is related to the irreducible water saturation of the trap in the presence of CO2. Values for 

irreducible water saturation in petroleum reservoirs are not well known, but they probably range from a 

minimum of about 0.2 in gas reservoirs to about 0.6 in oil reservoirs (Craft and Hawkins, 1991). Therefore, 

reasonable values for CSE in TKV should range from 0.8 to 0.4 for CO2 storage in PTs. If it is possible to 

establish a correlation between the area of a reservoir and the volume of technically recoverable 

hydrocarbons, then the number and sizes of undiscovered fields estimated in NOGA for the AU can be used 

to estimate the storage resource of the PTUs. 

A fourth type of storage is called the total trap volume (TTV). This is the storage resource of the PT 

if we had complete knowledge of the structure of the trap so that the volume of the trap to the spill point can 

be defined. If all traps in a SAU were filled to the spill point, then TTV should equal TKV. However, we 

know that many petroleum traps are not completely filled, so that TKV is some fraction of TTV. If there is 

geologic evidence of the extent of trap fill within an SAU, then a trap fill factor can be defined and applied 

to the TKV to determine TTV. In the absence of any data on the extent of trap fill, then it may be 

appropriate to ignore this type of storage volume. By doing so, some part of this “missing fraction” of trap 

volume automatically is assigned to the volume of the SF. 

 29
3.1.2. Saline Formation Model and Storage Volumes 

The saline formation (SF) is the CO2 storage portion of the flow unit of the SAU that has no PTs 

greater than the minimum size. The CO2 will be trapped in the SF primarily by capillary forces; however, 

buoyant trapping is also likely due to filling of small undiscovered traps and heterogeneity in fluid flow 

caused by natural permeability differences within geologic strata. 

The SF within the SAU is the remainder of the flow unit not assessed by the PT methodology. For 

this methodology, the SF is defined by the areal extent of the SAU, minus the PTD area, and an estimate of 

the distribution of the PTU area. Known regions of the SAU that are not suitable for SF storage must be 

removed, for example, known areas of salt or shale diapirs, igneous intrusions, or other nonflow-unit 

intrusions. If there are no oil or gas production data, or no NOGA estimates of PTUs, then the entire SAU is 

considered an SF. 

For the purposes of this methodology, it is assumed that CO2 will be stored only within the most 

porous interval of a storage formation. Porous interval thickness is commonly referred to as the “net sand” 

or “pay zone” or “porous interval”; for this methodology, it is referred to as the “net porous interval.” The 

net porous interval thickness is used to define the volume of storage within the SF. Therefore, some estimate 

of the thickness of this porous rock is needed. Because of the natural variations in ranges of porosity 

between potential SAUs throughout the United States and the world, the minimum porosity used to estimate 

the thickness of the net porous interval must be defined by the assessment geologist using available data for 

the formations in the SAU. 

The storage resource calculation for the SF is similar to volumetric resource, or TKV, of the PTs, in 

that it is based on the total volume of pore space in the entire SF. The volume of resource is calculated from 

the area, thickness, porosity, and storage efficiency. The assessment geologist calculates the mean values for 

the area, thickness, and porosity for the entire SF and then estimates the uncertainty of each of those mean 

values. The goal is to determine how representative the mean values are for the entire SF. As the area of the 

SF is typically clearly defined, the uncertainty in the mean area of the SF is small. The mean values for 

thickness and porosity of the SF are calculated by using the values gathered from the research for the 

framework geology of the SAU. However, the thickness and porosity data may be primarily from the PTs, in 

which case there could be significant uncertainty about whether the mean values calculated from those data 

accurately represent the SFs. The storage efficiency should be determined by the assessment geologist on the 

basis of the quality of the first three inputs; however, this distribution is difficult to quantify. In the case 

studies used to develop this methodology, a range of storage efficiency factors from a minimum of 0.01 to a 

 30
maximum of 0.05 is used. This range is based on previously published estimates (van der Meer, 1995; U.S. 

Department of Energy, National Energy Technology Laboratory, 2008a). 

3.2. Probabilistic Calculations 

3.2.1. Probabilistic Calculations for Discovered Physical Traps 

Formulas for estimating the four types of storage resource in PTs are given in table 1. These 

formulas convert trap volume to storage resource in metric tons of CO2. For any set of PTs, the storage 

resource can be calculated deterministically and the individual masses summed to give an aggregate storage 

resource of PTDs within an SAU. However, many of the parameters have significant uncertainties or ranges 

of measured values that should be incorporated into the calculations to clearly show the limits of our 

knowledge of potential storage resources. Over time, as our knowledge of volumetric factors in individual 

SAUs improves, the uncertainties should decrease, and the range of possible values of storage resources will 

narrow and more accurately represent the storage resource. The ranges of values and uncertainties can be 

incorporated into the volumetric calculations with Monte Carlo simulation techniques (Charpentier and 

Klett, 2005). The result is a probability distribution of all possible storage sizes of individual PTDs for a 

given set of input parameters for a specific type of storage. This size distribution can then be used with a 

distribution of the number of PTDs that are being considered for storage. This number distribution is limited 

by a minimum storage size parameter and may be, for example, a single number, such as 50 PTDs with 

greater than 20 million metric tons of storage or, for an SAU with a limited number of PTDs, simply the total 

number of PTDs. 

These two distributions, the sizes of possible storage and the number of PTDs, are equivalent to the 

two inputs used in the USGS Monte Carlo simulator for calculating undiscovered, conventional oil and gas 

resources. These inputs are the size and number distribution of undiscovered accumulations of oil or gas. 

The output of the simulator is a probability distribution of the aggregate volume of the undiscovered 

resource and a distribution of sizes of the largest possible undiscovered accumulation. In the present case of 

estimation of storage resources, the inputs are known distributions, but the calculation is exactly the same, in 

this case with the output being a distribution of the possible sizes of the aggregate storage resource and a 

distribution of the sizes of the largest possible storage resource in a single PTD. The sequence of calculations 

is shown in figure 10. 

 31
Figure 10. A flow diagram illustrating how the aggregate physical trap (PT) storage distribution is generated from 

the input values on the PT form (appendix A.1). TKV method, total known volume method, which is method C in 

table 1; CSE, storage efficiency factor. 

 32
 33

3.2.1.1. Example of Probabilistic Calculations, SEOR

The basic concept of modeling the aggregate storage resource of PTDs can be illustrated with 

geologically realistic cumulative production data for a hypothetical SAU that contains 400 PTDs that meet 

the minimum size limit of 2 million m3 of potential storage volume. Table 2 lists cumulative production data 

and approximate net cumulative volume in barrels for 10 PTDs that are classified as oil or gas fields. Of the 

400 hypothetical PTDs, 50 have an estimated storage resource as NCV that is greater than 20 million metric 

tons CO2, and 25 of those are classified as oil reservoirs (GOR less than 20,000 cf/bbl) for which a storage 

estimate from EOR is meaningful. Table 3 lists the input parameters used in the probabilistic calculation of 

the distribution of possible CO2 storage in the 25 PTDs due to conventional EOR. A probability distribution 

of the range of masses of CO2 storage in the PTDs is shown in figure 11. This range of sizes of possible 

storage is equivalent to the range of sizes of undiscovered oil and gas accumulations that is used in the 

NOGA methodology to estimate the technically recoverable resource of undiscovered oil and gas in a 

NOGA assessment unit. 
 34

Table 2. Realistic cumulative fluid production and injection data for 10 large discovered physical traps (PTDs) in a hypothe

assessment unit (SAU) containing 400 PTDs that have net cumulative volumes (NCVs) that exceed the minimum size of million cubic meters). 

[ID, identifier; Cum., cumulative; MCF, thousand cubic feet; bbl, barrel; --, none.] 

PT 

ID 

PT area, 

acres 

Cum. gas 

production, 

103 MCF 

Cum. gas 

injection, 

103 MCF 

Cum. water 

injection, 

103 bbl 

Cum. water 

production, 

103 bbl 

Cum. oil 

production, 

103 bbl 

Cum. 

condensate 

production, 

103 bbl 

Approximate net 

cumulative volume 

(NCV), 103 bbl 

3 31,400 4,798,900 -- 10,000 26,300 99,100 32,000 4,946,300 4 50,100 1,978,500 0.003 969,000 2,237,300 808,700 415 4,055,915 

14 14,500 500,300 478 617,700 811,100 284,000 419 977,641 

15 16,700 809,600 617 5,400 36,600 114 1,000 841,297 

22 24,200 225,000 -- 12,500 246,500 101,500 3,000 563,500 

23 15,600 484,500 -- 5,100 27,400 18,800 1,400 527,000 

24 8,900 513,600 -- 800 5,000 415 1,700 519,915 30 14,300 275,400 -- 79,100 159,200 64,000 1,300 420,800 

48 2,600 19,400 -- 60,100 269,200 33,300 11,800 273,600 

49 8,700 262,600 2,500 4,700 1,800 -- 0.083 257,200 
Table 3. Input parameters for probabilistic calculation of SEOR for 25 large discovered physical traps (PTDs) that 

produced oil in a hypothetical, but geologically realistic, storage assessment unit (SAU). 

[The production data for the 5 PTDs in table 2 that are classified as oil fields are part of the set of inputs included in the 

distributions in this table. Ranges of values for IR and CEOR were provided by J.P. Meyer, (Contek Solutions, Plano, Tex., written 

commun., 2009). Terms are discussed in section 3.1.1. CEOR, storage based on CO2 enhanced-oil-recovery (EOR) methods; CVOC, 

cumulative volume of produced hydrocarbon liquids in oil accumulations] 

Input parameters Shape of the 

distribution of values Most likely Minimum Maximum 

Cumulative oil recovery, CVOC, 

in barrels Log-normal 110,000,000 3,000,000 980,000,000 

Oil recovery factor, RF Triangular 0.44 0.16 0.68 

EOR incremental recovery 

factor, IR

Triangular 0.15 0.07 0.23 

EOR CO2 storage factor, CEOR, 

in metric tons/barrel Triangular 0.36 0.13 0.58 

Figure 11. Probability distribution of storage size in any one of 25 large discovered physical traps (PTDs) due to 

conventional EOR in a hypothetical storage assessment unit (SAU). The distribution is calculated with Crystal 

BallTM for 10,000 iterations of the formula for method A in table 1 using the distributions of input parameters 

listed in table 3. 

 35
The hypothetical size distribution shown in figure 11 can be used with the number of PTDs (25) to 

make a probabilistic estimate of the CO2 storage resource due to conventional EOR. We have not written a 

probabilistic algorithm specifically for CO2 storage calculations. However, because we have a calculated 

size distribution and a number of PTDs, these values can be used with existing USGS probabilistic 

algorithms for calculating the volume of undiscovered oil and gas resources (Charpentier and Klett, 2005). 

An example of the probability distribution of the aggregate mass of CO2 storage resource due to 

conventional EOR for a hypothetical SAU is shown in figure 12, and 95th, 50th, and 5th percentiles of 

occurrence of the technically accessible storage resource in 25 traps with a hypothetical SAU are given in 

table 4. 

Figure 12. Probability distribution of the aggregate mass of CO2 storage resource due to conventional EOR in 25 

hypothetical oil-bearing discovered physical traps (PTDs) with possible storage sizes described by the 

distribution in figure 11. 

Table 4. Percentiles of CO2 storage resource within the distribution shown in figure 12. 

Percentile 

Aggregate storage, SEOR, 

million metric tons CO2

P95 320 

P50 450 

P5 630 

 36
A similar sequence of probabilistic calculations can be done for SNCV. The first step is calculation of 

the probability distribution of possible storage size in PTDs using the formula for method B in table 1. For 

example, NCV is calculated for PTDs with cumulative production data similar to data shown in table 2. At 

the present stage of development of the numerical methods, we use a default value of 1.0 for CWD, but a 

distribution of values could be determined by an assessment geologist using data from production histories 

of the PTDs. The subsurface density of CO2 at reservoir temperature and pressure appropriate for the SAU is 

calculated from the online database, “Thermophysical Properties of Fluid Systems,” provided by the 

National Institute of Standards and Technology (2009). Because the depth of PTDs can vary between 3,000 

and 13,000 ft, and geothermal gradients in basins have some spatial variability, we use a distribution of CO2

densities with a range that spans the possible minima and maxima of temperatures and pressures in the SAU. 

The formula for method B and distributions of NCV, CWD, and CO2 are used with Crystal BallTM to calculate 

a size distribution of storage in PTDs. Then the number of PTDs and the calculated size distribution are used 

to calculate the distribution of aggregate storage resource in exactly the same manner as in the preceding 

example of storage resource through conventional EOR. 

Calculation of STKV follows the same pattern; see method C in table 1. The only significant 

difference is that for traps in formations with a large range of depth and (or) thickness in the SAU, there may 

be several thickness intervals for which the storage resource may be calculated. For example, if the base of 

the SAU extends to depths greater than 13,000 ft, then storage resources can be calculated within the depth 

interval from 3,000 to 13,000 ft or within the full formation interval from 3,000 ft to maximum depth. If 

overpressure conditions exist, then the SAU interval thickness extends from the top of the formation where it 

is >3,000 ft deep to the depth of the top of the overpressure zone. 

Following calculation of STKV, the storage resource in the total trap volume, STTV, is calculated by 

using a growth factor, CG, that represents the potential increase in volume up to the spill point of the trap. 

See method D in table 1. 

3.2.2. Probabilistic Modeling of Storage in Saline Formations 

The probabilistic calculations use the inputs from uncertainty of the mean for the area, net porous 

interval, and porosity and the CSE distribution for the SF to model the probability distribution of possible 

storage sizes for the SF (fig. 13). Unlike the PT method, which uses a number distribution and a size 

distribution to determine the storage distribution, the SF method has no number distribution, as there is only 

 37
one SF for each SAU. Therefore, the storage size distribution determined by the above calculation is the 

distribution of CO2 storage for the SF. 

Figure 13. A flow diagram illustrating how the aggregate saline formation (SF) storage distribution is generated 

from input values on the SF form (appendix A.2). CSE, storage efficiency factor. 

 38
3.2.3. Assigning Geologic Probability Values to Determine Unconditional Storage Resources 

The calculations in sections 3.2.1 and 3.2.2 are used to determine the conditional CO2 storage 

resource, which is the amount of storage possible without assessing success. Although storage resource 

exists throughout the SAU in both PTs and the SF, there remains a possibility that storage within some of 

the PTs or the SF may not be successful. Success is defined as the probability that, on the basis of 

geological, geochemical, and geophysical evidence, there is a likelihood that CO2 will be retained at 

volumes equal to or greater than the minimum size. For PTs, this minimum size, as described in section 

2.1.4, is 12.5 MMbbl. For SFs, the minimum size is the product of the minimum storage efficiency value for 

that SF and its calculated pore volume. This minimum value will typically be no less than 1 percent of the 

total pore volume of the SF. The likelihood of success is determined by geologic factors that are not taken 

into account during the calculation of the conditional storage volume. These geologic factors are combined 

and referred to below as the geologic probability. The geologic probability, when applied to the probabilistic 

calculations, results in the estimation of the unconditional storage resource. 

The primary factor in determining the geologic probability, which is used to evaluate the success of 

the individual PT or the SF, is the probability of containment. This probability of containment differs from 

how containment is discussed in section 2.6. The probability of containment estimates the likelihood that 

CO2 will be stored within a PT or the SF above the minimum amount. If the assessment geologists have 

some evidence for seismic, injection, or reactivity issues, they should raise them during the assessment. 

However, it is difficult to numerically evaluate how these factors might reduce the potential for storage 

success in a PT or the SF, so values must be assigned on the basis of the judgment of the assessment 

geologists. 

The probability of containment is some number between 0 and 1, with a 1 being a certainty of storing 

the minimum volume of CO2 within an individual PT or the SF. If the value is less than 1, then it will reduce 

the number of PTs that meet the size limit (fig. 10). The reduced number of PTs is then used to determine 

the unconditional aggregate storage resource. The probability of containment for the SF captures the 

possibility that the CO2 contained within the formation will not be above some minimum percentage of the 

total pore space (fig. 13). Therefore, if the probability of containment is less than 1, then some of the 

iterations of the probabilistic calculations will be zeroed, essentially assessed as no storage, as there is a 

chance that the SF will not meet the minimum storage requirements. This treatment is similar to the 

assessment-level probability of NOGA. The modified, presumably lesser, storage aggregate distribution for 

 39
PTs and storage size distribution for the SF are referred to as the unconditional storage resource as it 

incorporates the geologic probability that the CO2 will be contained within the PTs or the SF. 

3.3. Data Sources and Manipulations 

3.3.1. Sources 

Geologic and assessment models are built on geologic framework studies from USGS oil and gas 

assessments. Such basin studies have resulted in structure and thickness models, stratigraphic columns, cross 

sections, and general knowledge of the geology that are used to identify the SAU. Additional comprehensive 

data searches from published and unpublished work by the USGS, State geological surveys, producer 

associations or agencies; commercial databases; and the general literature are conducted to obtain additional 

information for use by assessment geologists. Quantitative data at the oil and gas field and reservoir level, 

including composition, porosity, permeability, size, thickness, depths, lithology, drive mechanism, and 

production data, are available in a commercial database, “Significant Oil and Gas Fields of the United 

States” (Nehring Associates, Inc., 2008). This database contains information on all fields with at least 0.5 

million barrels of oil equivalent (MMBOE) known recovery (cumulative production plus reserves). Data at 

the individual well level, including location, producing formation, formation tops, bottom hole pressures, 

perforation zones, and production of oil, gas, and water, were obtained from the commercial database, 

“PI/Dwights PLUS on CD” (IHS Inc., 2008a). Volumes of produced and injected water, oil, gas, and 

condensate, along with core sample measurements, were obtained from a separate IHS database called 

“PIDM 2.5” (IHS Inc., 2008b). 

3.3.2. Manipulations 

The areas of PTDs were calculated with a geographic information system (GIS) procedure. Data from 

Nehring and IHS databases were compiled using Nehring field names. All production well locations 

available in the IHS database that were assigned to a field name in the SAU were plotted. A “rubber-band 

outline” was constructed around the wells using a 300-m (984-ft) buffer. Any wells that were assigned the 

same field name but that were separated by more than 3 miles from any well with the same field name were 

excluded from the field outline. Areas within the outline were calculated for each field. These values were 

summed, with overlapping field areas removed, generating the area of the PTDs. 

Accurate calculations of the net cumulative volume of produced fluids for each PTD require a 

procedure used in petroleum engineering called material balance (Craft and Hawkins, 1991). This procedure 

 40
corrects all volumes of produced fluids that are measured at surface conditions to subsurface conditions. 

However, such calculations require detailed information about the production history and volumetric 

properties of fluids that is not available to the USGS. Therefore, NCV was calculated by an approximation 

method that allowed simple conversion of the surface volume of produced gas in thousands of cubic feet to 

subsurface volume in barrels. This method allowed the net cumulative volumes of gas, oil, condensate, and 

water to be summed and converted to subsurface pore volume. The approximation method for converting 

surface gas volume in thousands of cubic feet (MCF) to subsurface volume in barrels is based on the fact 

that the formation volume factor (FVF) for gas in the depth range of 3,000 to 13,000 ft (Schuenemeyer, 

2005) ranges from 100 to 300 surface volumes per reservoir volume and that there are 5.61 cubic feet per 

barrel (cf/bbl). If a FVF of 178 is chosen and converted to barrels, 1 MCF at the surface is equivalent to 1 

barrel of pore volume in the subsurface. This approximation nevertheless allows rapid evaluation of total 

fluid volumes in the subsurface. Surface volumes of oil and condensate should be corrected to subsurface 

volumes also, but, given the uncertainty introduced by the gas volume conversion, corrections to the oil and 

condensate volumes do not appear to be necessary. 

3.4. Basic Input Data Forms 

The purpose of the input forms is to gather all the relevant data in one spreadsheet to supply values 

for the probabilistic calculations and to consolidate important observations about the SAU to facilitate 

storage assessment discussions. The forms are based on the USGS National Oil and Gas Assessment 

(NOGA) input forms (Klett and others, 2005a; Klett and Schmoker, 2005). The PT assessment form is 

similar to that used by the NOGA conventional assessment methodology, and the SF form resembles the one 

used by the North Slope Alaska Deposit Model methodology. The NOGA assessment methods for both 

types of accumulations were important in the development of the CO2 sequestration methodology. For 

example, discovered and undiscovered petroleum accumulations are assigned to geologically consistent 

units called assessment units (AUs) (Schmoker and Klett, 2005); similarly, storage assessment units (SAUs) 

are used in the CO2 sequestration methodology. Each AU is assessed individually, and an input data form is 

completed for each one. Using oil and gas information, the assessment geologist estimates for each AU the 

probability of occurrence of at least one accumulation that has the potential to be added to petroleum 

reserves (Klett and Schmoker, 2005). The CO2 methodology uses similar concepts, based on the attributes 

and characteristics of SAUs that are important for CO2 sequestration. 

 41
3.4.1. Physical Trap Form 

The “Physical Traps (PTs) Assessment Model: Basic Input Data Form” (appendix A.1) is derived 

from the NOGA conventional accumulation assessment form (Klett and others, 2005a). However, instead of 

consolidating data based on the production history of conventional accumulations to determine how much 

resource remains to be discovered, the goal of the PT input form is to gather both production and volumetric 

data for use in assessing the volume of CO2 that can be stored. There are inputs for observations that 

describe relevant features of the SAU and PTs, as well as for the distributions of values needed for the 

probabilistic calculations to assess the storage resource in each of the four storage classifications for PTs. 

These input sections are described below, and the steps in the assessment process are shown in figure 14. 

for each assessment unit

Determine number 

of discovered 

physical traps

Determine probability 

distribution for sizes of 

discovered physical 

Determine probability 

distributions for conditional 

CO2 storage resource in 

discovered physical traps 

Assign probability of 

containment 

Determine probability 

distributions for unconditional 

CO2 storage resource in 

discovered physical traps 

Determine probability 

distribution for the 

number of 

undiscovered physical 

Determine probability 

distribution for sizes of 

undiscovered physical 

traps 

Determine probability 

distributions for unconditional 

CO2 storage resource in 

undiscovered physical traps 

Assign probability of 

containment 

Determine probability 

distributions for conditional 

CO2 storage resource in 

undiscovered physical traps 

Select minimum storage size 

Represent rock volume to be assessed by storage 

assessment units

Figure 14. Flow diagram of key steps in the USGS assessment method for estimating the CO2 storage resources 

in discovered and undiscovered physical traps. These steps are followed for each storage method. See text and 

the physical trap form (appendix A.1) for more information. 

 42
3.4.1.1. Identification Information 

The initial section of the PT form includes basic identification and description of the SAU, as well as 

a section for notes from the assessing geologist. Lines for the assessing geologist’s name and the names of 

the assessment region, province, and SAU are present. NOGA naming conventions will be used for the 

SAUs. NOGA uses a numeric code identifying each region, province, total petroleum system, and 

assessment unit; these codes are globally uniform and identify the same item in all publications. The codes 

are constructed as follows: region, single digit; province, three digits to the right of the region code; total 

petroleum system, two digits to the right of the province code; and assessment unit, two digits to the right of 

the petroleum system code. For CO2 storage assessment, the SAU code will end in “S” to differentiate it 

from NOGA assessment unit codes. The SAU name should include the name of the storage formation and 

the name of the regional seal formation. The spatial relationship between the SAU and the NOGA 

assessment unit (AU) can be recorded following the SAU information. Detailed notes should go under 

assessors’ notes at the end of the section. The next line records the date of the source material that was used 

to populate data fields in this form. Notes from the assessors provide details and conditions specific to the 

assessment unit that are pertinent for comparative and research purposes. 

3.4.1.2. Characteristics of Storage Assessment Unit 

The characteristics of the storage assessment unit (SAU) are entered in the second section of the 

form. These physical characteristics define the boundaries of the SAU and are the first step in determining 

SAU area. The first question refers to the range of preferred storage depths between 3,000 and 13,000 ft, as 

discussed in section 2.1.2. The second line records the area of the SAU defined by the depth range. The 

default depth cutoff for storage of 13,000 ft may be superseded by overpressure [pressure/depth (P/D) > 0.5 

psi/ft] if it occurs at depths shallower than 13,000 ft. The SAU area, incorporating the possible occurrence of 

overpressure, is entered on Line 3a. The minimum, mode, and maximum of the total storage formation 

thickness, estimated according to the criteria in the questions above, are entered on the lines at the end of 

this section. 

3.4.1.3. Numerical Inputs 

The entries in the section of the form on numerical inputs determine the number of traps used to 

estimate the aggregate storage resource. A minimum potential storage volume is used to constrain the 

number of traps. This volume is based on the net cumulative volume (produced volume minus injected 

 43
volume) of all fluids (oil, gas, and water) produced from the trap. In this version of the assessment 

methodology, the minimum volume is ~12.5 million barrels (MMbbl), which is equivalent to 2 million m3. 

However, this value can be changed as needed to meet the goals of a specific assessment. The number of 

PTDs that meet or exceed this minimum size is determined and entered on the second line. The next two 

lines show the number of oil and gas traps determined from the gas:oil ratios (GOR). The number of PTDs 

that are oil traps, is needed to calculate the storage resource that will result from conventional CO2 EOR. 

3.4.1.4. Characteristics of Physical Traps in the Storage Assessment Unit 

Data distributions for the following six factors are required to complete the storage calculations in 

the next section of the form. Values for original oil in place (OOIP) are available in the Nehring Associates, 

Inc., database (Nehring Associates, Inc., 2008) or can be calculated. Net cumulative produced volume is the 

volume of oil and water and gas produced minus the volume of injected water and injected gas corrected for 

reservoir conditions. The result is a net cumulative production that indicates the amount of material that 

occupied pore space in the subsurface that has been removed. Area on Line 10 is defined as the surficial area 

of the PTD fields, as delineated by wells that have produced. The net porous interval represents the thickness 

of the formation that contains a porous constituent, not formation thickness. Porosity data for the PTDs are 

taken from Nehring Associates database (Nehring Associates, Inc., 2008) and IHS (IHS Inc., 2008b). The 

storage efficiency factor, or CSE, is a distribution that defines the fraction of the total available pore space 

that will be occupied by free-phase CO2. 

3.4.1.5. Storage Volume Calculation Methods 

Four different storage volume calculation methods (A–D) are included in the PT assessment form 

and in table 1. Generally, the storage capacities will increase from method A to method D as they become 

more heavily based on estimates of the volumetric properties of the PTD than on measured volumes of 

produced fluids. Data for PTUs can be determined using an internal analog based on size and number 

distributions from the NOGA assessments of undiscovered fields. 

In method A, the storage resource is based on engineering experience with present-day CO2

enhanced-oil-recovery (EOR) methods. The equations for calculating storage due to EOR are included in the 

form. This method yields the most conservative estimate of sequestration storage volume. 

Method B is based on the net cumulative volume (NCV) of produced fluids. This method of 

determining pore space is based on volumes of hydrocarbon and water production and injection as discussed 

in section 3.4.1.4. 

 44
Method C, total known volume (TKV), uses the volumetric properties of the trap, area, net porous 

interval, porosity, and the storage efficiency factor to estimate the available pore space within the PTD. 

The final classification, method D, is based on the total trap volume to the spill point (TTV). The 

TKV storage volume calculated with method C is increased by a growth factor (CG) to yield the TTV. The 

productive area that defines the PTD does not necessarily represent the area of the PT to the spill point. CG is 

determined by the assessor to represent the increase in storage volume that would result if the field outline 

were extended to the trap’s spill point. The growth factor allows for an approximation of the resulting 

increase in area to be factored into the storage volume calculation. However, this CG factor can only be 

determined by the assessment geologist if relevant data exist. 

3.4.1.6. Physical Trap Probability of Containment 

Probability of containment is the fraction of traps that will be able to contain a volume of at least 

12.5 MMbbl (2 million m3) CO2 as discussed in section 3.2.3. This value will modify the number of traps 

considered in the calculation of the aggregate storage resources. 

3.4.1.7. Selected Ancillary Data 

The selected ancillary data section will aid the assessing geologist in determining the probability of 

containment value. Of equal importance, this section records any factors that will have a significant effect on 

CO2 sequestration success. The assessing geologist is expected to provide, as additional information to the 

assessment team, descriptions of any physical, chemical, and mineralogical characteristics of the reservoir 

and confining layers that may have a negative effect on sequestration. The following descriptions of the 

various inputs in the ancillary data section provide the necessary context required by the assessing geologist 

to complete this section of the form. 

Injectivity is indicated by the ability of the CO2 pumped into the subsurface to enter the storage 

formation and move away from the injection point. Transmissivity (see glossary) may be a major factor for 

estimating injectivity. 

Depth to top of storage has implications for the confining potential of the seal and storage formation. 

In addition, the depth converted to subsurface pressure and temperature can be used to estimate the density 

of CO2 needed to convert storage volume to storage mass. The confining layer acts both as a seal and as a 

potential sink for formation water. Confining-layer characteristics that might affect the probability of 

containment must be taken into account by the assessing geologist. Natural seismic risk, which is estimated 

 45
from the historic seismicity of the region, can raise containment concerns. Whether currently active or not, a 

seismic zone may provide conduits within the storage formation where CO2 could bypass the seal formation. 

Variations in reservoir architecture will be important for estimates of injectivity. For example, a 

homogeneous massive sand body may have the same volume as a group of many thin, discontinuous 

heterogeneous sand bodies, but injecting into the latter may be limited by the architecture of the sand body. 

The drive mechanism for the field provides an indication of the flow properties of the storage unit, 

particularly the potential for displacement of water from the formation and the ability to inject CO2. 

Description of the drive mechanism may not be available but may be inferred by the assessment geologist 

from production data. 

Geochemical reactivity is discussed in section 2.5. Fluid rock reactions can increase or decrease 

porosity and permeability of the storage formation, thereby affecting injectivity. Geologic age and 

knowledge of the extent of diagenesis may also contribute important information to studies of reactivity in 

the storage formation. 

Information on formation water composition, mineral composition, and CO2-brine-mineral 

interactions at specific temperature and pressure conditions are to be documented in the ancillary data. All 

affect reactivity and the possible outcomes of geochemical interactions. 

3.4.1.8. Allocations of Physical Traps 

The final section of the form covers the allocation of CO2 storage volume by area for Federal, State, 

tribal, and private lands and NOGA provinces. Allocations include areas such as wilderness areas, national 

forests, national parks, and political areas, such as State and county land. The allocation is based on 

ownership of surface and (or) mineral rights. Owing to the nature of the storage resource distributions per 

allocation, the total of these allocations does not necessarily equal the total storage volume calculated in the 

assessment. 

3.4.2. Saline Formation Form 

The SF form (appendix A.2) is created to aggregate the data needed to assess the volume of CO2 that 

can be stored within the SF on a purely volumetric basis. As in the PT form, the SF form has inputs for the 

observations that describe relevant features about the SAU and SF. Input for the range and distribution of 

values of volumetric parameters are needed for the probabilistic equations to calculate the distribution of 

possible storage resources in the SF. The process for completing these calculations is depicted in figure 15. 

 46
Determine probability distribution for 

conditional CO2 storage in saline 

formation

Assign probability of containment 

Determine probability distribution for 

unconditional CO2 storage in saline 

formation

Estimate uncertainty of mean values 

Calculate mean values for area, 

thickness, and porosity 

Figure 15. Flow diagram of key steps in the USGS assessment method for estimating the CO2 storage resources 

in saline formations. See text and saline formation form (appendix A.2) for more information. 

3.4.2.1. Identification Information 

The sections on identification information are the same on the PT form and the SF form. See text 

section 3.4.1.1. 

3.4.2.2. Characteristics of Storage Assessment Unit 

The sections on SAU characteristics are the same on the PT form and the SF form. See text section 

3.4.1.2. 

3.4.2.3. Area Calculation for the Saline Formation 

Subtracting the area of the PTDs and the PTUs from the total SAU area yields a range of the areas of 

the SF outside of traps. The PT form documents the sum of areas for PTDs greater than the minimum size. 

The distribution and average of the area of the PTUs greater than the minimum size can be provided by the 

NOGA team with values modified using the published assessment reports and the area distribution of the 

PTDs. Fields smaller than the minimum storage size are included in the area of the SF. 

 47
3.4.2.4. Characteristics of the Saline Formation 

The net porous interval represents the thickness of the formation that contains a porous constituent; 

this value is not total formation thickness. When the assessment geologist is determining the mean porosity 

value for the SF and the uncertainty of that mean, the porosity data from fields that were not included in the 

PT assessment should carry a greater weight than the porosity data from fields that were included in the PT 

assessment. The relative robustness or paucity of the datasets for the area, thickness, and porosity will be the 

main control on the uncertainty that the assessing geologist applies to the calculated mean values. 

Storage efficiency (CSE) is the fraction of the total available pore space that will be occupied by freephase CO2. The distribution of storage efficiency values must be justified by the assessment geologist; see 

section 2.6 for discussion of issues related to the estimation of the storage efficiency factor. 

3.4.2.5. Saline Formation Storage Volume 

The storage volume represents the pore volume for the entire SF. The volume is the product of a 

probabilistic calculation that samples the distributions of uncertainty about the mean of the area, net porous 

interval thickness, and porosity. The calculation includes the distribution of possible storage efficiency 

factors. These inputs are recorded on the form. 

3.4.2.6. Saline Formation Probability of Containment 

Text section 3.4.1.6 addresses the use of probability of containment for the four PT storage 

calculations. In the case of the SF assessment, the discussion of probabilities is equally relevant. 

3.4.2.7. Selected Ancillary Data 

Text section 3.4.1.7 about the PT form discusses the same ancillary data inputs that are requested on 

the SF form. 

3.4.2.8. Allocations of the Saline Formation 

The sections on allocation are the same on the PT form and the SF form. See text section 3.4.1.8. 

4. Discussion: Science and Data Needs 

The science and data needs discussed in this section are specific to development of assessment 

methodologies for CO2 resources. There are many other science and engineering issues that are specific to 

the deployment of large-scale CO2 storage projects. However, many of those issues are site specific and are 

 48
not within the scope of this methodology. The issues we discuss below will help to reduce the uncertainty of 

subsequent national assessments of resources for geologic storage of CO2. 

Of particular importance will be new information from large-scale demonstration projects on 

geologic storage of CO2. Seven projects are currently funded by DOE within their Regional Carbon 

Sequestration Partnership program (U.S. Department of Energy, 2009). As more information on the 

performance of CO2 injection and storage projects, including large scale CO2 EOR projects, becomes 

available, we will be able to refine assessment methods for CO2 storage by incorporating experience from 

the in-place behavior of injected CO2. Future assessment methodologies will benefit as these data become 

available and can be incorporated. 

4.1. Inputs for Probabilistic Calculations 

Though there is an attempt to estimate the storage efficiency of PTs and SFs in this methodology, 

there are no analogs at present to evaluate these values. There have been attempts at modeling these values 

(van der Meer, 1995) or calculating them with probabilistic methods (U.S. Department of Energy, National 

Energy Technology Laboratory, 2008a). The factors that are important for determining storage efficiency, 

such as containment, injectivity, and reactivity, are understood on a basic level from laboratory experiments, 

computer models, and very small scale injection projects (Hovorka and others, 2004). However, there are 

few analogs for large-scale CO2 storage projects in SFs [for example, Sleipner (Arts and others, 2008)] or 

PTs [for example, Weyburn (Emberley and others, 2005) and In Salah (Riddiford and others, 2005)] to 

evaluate these experiments, models, or calculations. When the results of planned large-scale CO2 storage 

projects are available, they should provide the observations and measurements that will refine estimates of 

storage efficiency factors. 

4.2. Aggregation of Storage Volumes at the Basin and National Level 

This methodology is designed to estimate the distribution of CO2 storage resource in individual 

SAUs. To provide information and decision support to policy makers at a variety of scales that may range 

from an individual State or specific Federal lands to total storage in the nation, we need methods to combine 

(aggregate) resources of multiple SAUs and multiple regions into single distributions of the quantity of 

storage. To properly define the distribution of uncertainty about the mean of the aggregate resource, we must 

account for statistical dependencies of volumetric parameters between SAUs within a single geologic 

 49
province or among provinces. Additional work is needed to develop statistical algorithms that can account 

for dependencies and properly aggregate storage resources as needed for policy makers 

4.3. Geochemistry 

Better knowledge of CO2-water-rock interactions at in-place pressures, depths, and formation water 

compositions in large-scale demonstration projects (for example, projects of the DOE Regional Carbon 

Sequestration Partnerships) will be important for evaluating the effects of geochemical reactions on the 

storage of CO2. In-place studies to date are limited in number and size (for example, Kharaka and others, 

2006), and most prior work has been laboratory experiments or computer modeling using reactive transport 

codes. 

To fully understand the potential impact of formation water displacement by CO2 injection and 

storage, we need baseline information on formation water chemistry, including naturally occurring 

concentrations of components that may be considered environmental contaminants. Although data from the 

petroleum industry are available in the USGS produced-waters database (Breit, 2002) the analyses are 

limited in quality and scope. An inventory of ground-water-quality data from 3,000 to 13,000 ft deep across 

the United States needs to be performed to identify available water analyses and, more importantly, to 

identify gaps in measurements of components that may affect ground water quality and the near-surface 

environment. 

4.4. Seals 

In addition to providing containment of buoyant CO2, seals may be important in the uptake of 

formation water displaced by CO2 injection. However, the properties that control potential storage of 

formation water within seals are not well understood. Furthermore, while seal properties are well understood 

at the PT level, there is less knowledge about the seals in a regional sense, for example, over the entire SAU. 

Knowledge of regional seal properties is particularly important for determining the storage efficiency of SFs. 

Although seal integrity in PTs can be inferred from the presence of hydrocarbons, there are no well defined 

criteria to identify the integrity of seals to retain buoyant CO2 where hydrocarbons are not present. 

4.5. Geologic Databases 

National assessments of resource for geologic storage of CO2 require a basic set of spatially 

distributed digital data. Examples include but are not limited to maps and data on geologic structure, fault 

 50
locations, formation thickness, water quality, and petroleum production. Some data are currently available in 

the public domain. For example, the U.S. Department of Energy, National Energy Technology Laboratory 

(2008b), has created the NatCarb online database (http://www.natcarb.org/) with information available from 

the Federal Government, State geological surveys, and State oil and gas regulatory agencies. However, 

national assessments of storage resource will require access to large commercial and proprietary databases 

that contain detailed information on oil and gas exploration and production activities. In addition, regional 

evaluation of subsurface rock and fluid properties will be facilitated by access to privately owned datasets 

such as two and three-dimensional seismic surveys and detailed well test data. Development of data-sharing 

agreements between public and private organizations should be initiated to refine future assessments of 

storage resources. 

4.6. Hydraulics and Flow 

Pressure increases from CO2 injection should propagate away from the injection site, potentially 

extending to and having some effect on flow boundaries (faults, unconformities, basin margins, or the updip 

extent or depth limit of the storage formation). Potential hazards from large-scale CO2 injection could be 

induced seismicity, contamination of shallow ground water, and transport of contaminants out of the storage 

formation. Flow of buoyant fluids such as CO2, particularly in fractures and low-permeability rock, also 

needs further investigation. Movement of CO2 and estimated CO2 plume velocities are important factors in 

determining the areal extent of the CO2 plume and the volume of rock that the plume contacts. 

Understanding the movement and effects of CO2 injection will provide more accurate storage efficiencies 

and assessment volumes. 

4.7. Injectivity 

Injectivity is a rate-based parameter that characterizes the ability of CO2 to enter a storage formation. 

For geological assessments of storage resources, it should be defined by rock and fluid properties and 

subsurface pressure, not by engineering and economic parameters (number of wells, injection pressure, etc). 

At this stage of development of our probabilistic methodology, we are unable to clearly distinguish geologic 

parameters from engineering and economic factors. However, on a qualitative basis, it is evident that 

variations in injectivity will significantly impact estimates of storage resources, particularly in assessments 

of resources that are available within a fixed time span (that is projects with decadal lifetimes of injection). 

 51
We believe an important next step in development of assessment methodology will be a clear definition of 

injectivity that can be quantified and incorporated in probabilistic calculations. 

5. Conclusions 

The goal of this report is to describe a new methodology that uses a probabilistic model that aids in 

assessing the CO2 storage resource of geologic strata in different geologic settings. Creating the 

methodology involved the combination of (1) the knowledge of hydrology, the fluid flow of both aqueous 

and buoyant fluids, geochemistry, petrophysics, and other geologic evidence; (2) USGS experience with the 

assessment of petroleum resources; and (3) extensive datasets, both proprietary and nonproprietary, which 

the USGS has compiled on the rock, fluid, and production properties of the storage and seal formations of 

the storage assessment units (SAUs). This methodology treats the physical traps (PTs) and the saline 

formation (SF) as endmembers of a combined system, which allows for the most comprehensive assessment 

that the USGS can conduct on a given SAU. The goal of the methodology was also to provide the resource 

assessment in several parts, so that decisionmakers can assess various classifications of storage in the SAUs. 

The PTs are subdivided into resource assessments on basis of the storage potential due to (1) enhanced oil 

recovery, (2) the net produced volume of fluid, and (3) the volumetrics of the geologic strata. These 

classifications and the volumetric assessment of SFs are also reported as conditional volumes (that is, 

reported without taking into account the geologic probabilities) and as unconditional volumes, which are 

reduced by incorporating the geologic probabilities. The breadth of the methodology, both in the scope of 

what it accounts for and the wide range of results it can produce, should provide decisionmakers and 

stakeholders with a wealth of information to develop informed conclusions. 

Acknowledgments 

The authors gratefully and enthusiastically thank Ronald R. Charpentier (USGS) for expert guidance 

and advice on developing probabilistic models and calculations. Christopher P. Garrity (USGS) created 

much-needed GIS algorithms to define field areas in physical traps. In the methodology development 

process, extensive collaboration was provided by the USGS Tertiary assessment team, especially Alexander 

W. Karlsen, and the USGS Wind River Basin Province assessment team, in particular Mark Kirschbaum and 

Laura Roberts. James J. Thordsen (USGS) contributed data for hydrologic analysis. Susan D. Hovorka and 

the Gulf Coast Carbon Center team at the Texas Bureau of Economic Geology provided data and helpful 

discussions on the potential for CO2 storage in the sediments of the Texas Gulf Coast. The authors 

 52
appreciate support from Richard Nehring (Nehring Associates, Inc.). Kathleen Winner and Jeffrey S. Kay 

(IHS, Inc.) gave permission to publish production data. The content and presentation of this report benefited 

greatly from the technical reviews of Scott Frailey (Illinois State Geological Survey) and USGS scientists 

David W. Houseknecht, Ronald R. Charpentier, and James L. Coleman. The authors thank Desiree Polyak 

(USGS) for her contributions to the project. Eric Morrissey (USGS) was helpful in the redesign of several 

illustrations within the report. The authors also wish to acknowledge the support of the USGS Enterprise 

Publishing Network, specifically Elizabeth Good and Anna Glover, and the Eastern Region Geology 

Discipline Bureau Approving Official Kathie Rankin. 

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Glossary 

barrels of oil equivalent (BOE) A unit of petroleum volume in which the gas portion is expressed in terms of 

its energy equivalent in barrels of oil. For this assessment, 6,000 cubic feet of natural gas 

equals 1 barrel of oil equivalent (Klett and others, 2005b). 

brine Water having a salinity higher than that of average seawater, that is, more than 35,000 mg/L total 

dissolved solids (TDS). 

buoyancy Upward force on one phase (for example, a fluid) produced by the surrounding fluid (for 

example, a liquid or a gas) in which it is fully or partially immersed, caused by differences in 

density. 

capillary force Adhesive force that holds a fluid in a capillary or a pore space. Capillary force is a function 

of the properties of a fluid and surface and dimensions of the space. If the attraction between 

the fluid and surface is greater than the interaction of fluid molecules, the fluid will be held in 

place. 

capillary pressure In porous media containing two or more fluid phases, the difference in pressure between 

the wetting phase and the other phase(s) or between the other phases. The pressure difference 

results from surface tension at fluid interfaces and increases as the radius of curvature of the 

interfaces decreases. Capillary pressure is higher in rock with small pores and (or) small pore 

throats connecting pores than in rock with large pores and (or) large pore throats. 

capillary trapping The amount of CO2 trapped within a pore that is not connected to a moving CO2 plume. 

The CO2 is held in place when the capillary forces on the CO2 are greater than the buoyant 

forces of the CO2 (Beaumont and Fiedler, 1999).

cap rock See confining layer. 

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carbon capture and storage (CCS) The process of capturing CO2 from an emission source, (typically) 

converting it to a supercritical state, transporting it to an injection site, and injecting it into 

deep subsurface rock formations for long-term storage. 

carbon dioxide plume The extent underground, in three dimensions, of an injected carbon dioxide stream. 

compartments Permeable units that are isolated by permeability barriers from their surroundings. 

Extraction or injection of fluids in such units tends to cause pressure changes that persist for 

long periods of time because of the isolation. 

conditional resource Storage resource estimated for all physical traps (PTs) and saline formations (SFs) 

without taking the minimum size requirement into account. 

confining layer A geologic formation, group of formations, or part of a formation having lower 

permeability than the adjacent underlying or overlying formation; the difference in 

permeability causes preferential flow within the adjacent formation. Used synonymously with 

seal, aquitard, or aquiclude. The confining layer above a flow formation is commonly called a 

top seal. 

CSE See storage efficiency factor.

drive mechanism Drive mechanism for the field indicates the injectivity of the storage space, particularly 

the role of water in the formation and the ability to replace it with CO2. “Water drive” means 

that as hydrocarbons are withdrawn, hydrodynamic water flow replaces the volume of fluid 

withdrawn, providing pressure support for continued production. “Gas expansion” or 

“solution gas drive” means that the pressure is maintained by the compressibility of the gas 

phase. “Compaction” or “rock drive” means that pore space is destroyed during fluid 

production, which can lead to ground subsidence. Combinations of drive mechanisms are 

possible. Pressures measured in petroleum accumulations are equivalent to hydraulic head in 

aquifer systems. 

ductility Ability of a rock to sustain strain, under a given set of conditions, without losing strength or 

undergoing brittle failure (such as in fracturing or faulting). Shale, mudstone, and evaporites 

are typically considered to be very ductile, whereas crystalline rock, carbonate, and chert are 

considered to have low ductile strength within the expected temperature and pressure regime 

of CO2 storage. 

 62
enhanced oil recovery (EOR) Typically, the process of injecting a fluid (for example, water, brine, or CO2) 

into an oil-bearing formation to recover residual oil. The injected fluid thins (decreases the 

viscosity) or displaces extractable oil, which is then available for recovery. 

gas accumulation A hydrocarbon accumulation composed primarily of gas, defined by the USGS as an 

accumulation having a gas:oil ratio of 20,000 cubic feet per barrel or greater. 

gas:oil ratio (GOR) Ratio of gas to oil (in cubic feet per barrel) in a hydrocarbon accumulation. GOR is 

calculated by using volumes of gas and oil at surface conditions. 

geopressure (also overpressure) Fluid pressure at depth that exceeds hydrostatic pressure (~0.43 to ~0.5 

psi/ft). 

geologic storage of CO2 The long-term containment of carbon dioxide in subsurface geologic formations. 

growth factor (CG) Determined by the assessor to represent the increase in resource that would result if the 

field area were extended to the spill point of the physical trap. 

hydraulic conductivity (usually K) Permeability multiplied by fluid density and gravity and divided by 

dynamic viscosity. It describes the resistance to flow offered by a porous medium to a 

particular liquid or gas. It is the proportionality constant in Darcy’s law and has dimensions 

of length per unit time. 

hydraulic diffusivity (usually ) The ratio of hydraulic conductivity K and specific storage. A quantity 

describing how quickly pressure or head perturbations propagate in porous media that is 

analogous to thermal diffusivity and chemical diffusivity. The value of  will determine the 

magnitude and spreading of a pressure increase caused by fluid injection and the rate at which 

confining layers release or accept fluid. 

hydraulic or fluid head (usually h) A measure of the pressure and potential (or elevation) energy of a fluid 

and the level, above a measuring point, to which the fluid will rise in a standpipe or casing; 

normally used to characterize flow in systems without significant variations in fluid density, 

where flow is from high to low head (not from high to low pressure). 

injectivity The likelihood that CO2 could enter a SAU, as defined by rock properties and subsurface 

pressure. It can also be thought of as the relative rate of injection by a single vertical well 

with a maximum pressure of 90 percent of the fracture gradient. 

minimum depth of storage To limit the potential of CO2 migrating to pressure and temperature conditions 

where it could convert from the supercritical state to liquid and vapor. A minimum depth of 

storage of 3,000 ft is used in this CO2 assessment methodology.

 63
minimum storage size The smallest storage size that is considered in the assessment process for physical 

traps (PTs). For this report, the minimum storage size for PTs is equivalent to 12,500,000 

barrels, or approximately 2,000,000 cubic meters. 

National Oil and Gas Assessment (NOGA) U.S. Geological Survey National Oil and Gas Assessment, 

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

net cumulative volume (NCV) The sum of the cumulative volume of produced oil, gas, natural gas liquids, 

and water minus the total volume of injected gas and water. 

net porous interval Rock within the storage formation that is greater than a minimum porosity as 

determined by the assessment geologist. 

oil accumulation A hydrocarbon accumulation composed primarily of oil, defined by the USGS as an 

accumulation having an gas:oil ratio less than 20,000 cubic feet per barrel. 

original oil in place (OOIP) The volume of oil that was within a physical trap prior to the onset of 

production. 

permeability The capacity of a rock to transmit fluids, controlled by pore size and pore throat geometry. 

physical trap (PT) Conventional oil and gas traps that are available for potential CO2 storage. PTD refers to 

traps that were discovered during oil and gas exploration. PTU refers to undiscovered physical 

traps, which are inferred from the volumes of technically recoverable, undiscovered oil and 

gas resources estimated by the USGS in NOGA reports. 

porosity () The part of a rock that is occupied by voids or pores. Pores can be connected by passages 

called pore throats, which allow for fluid flow, or pores can be isolated and inaccessible to 

fluid flow. Porosity is typically reported as a volume or percentage. 

pressure gradient The change in pore pressure per unit depth, typically in units of pounds per square inch 

per foot (psi/ft) or kilopascals per meter (kPa/m). 

probability of containment The probability that CO2 will be contained within a physical trap or a saline 

formation. It is approximated from well density, well age, well seal technology utilized, 

evidence of surface seepage, presence and density of faults and other structural features, 

reactivity of the regional and local seal, and the seal’s extent. The probability of containment 

is a number between 0 and 1, with a 1 being the certainty of containment within an individual 

physical trap or a saline formation. 

reactivity The propensity of minerals composing the rocks in a geologic formation to interact with 

formation water and injected carbon dioxide. 

 64
saline formations (SF) The sedimentary rock layers that are saturated with formation water with total 

dissolved solids (TDS) greater than 10,000 mg/L TDS. In the CO2 assessment methodology, 

the saline formation is composed of the remainder of the SAU not assessed by the PT 

methodology. 

saline water Water having salinities that are 10,000 to 35,000 mg/L total dissolved solids (TDS). 

salinity A measurement of the water properties determined by the total dissolved solids (TDS), generally 

reported in milligrams per liter. 

seal A geologic unit that inhibits the mixing or migration of fluids and gases between adjacent geologic 

units. 

specific storage Change in fluid volume per reference volume per change in fluid head. This quantity 

describes the ability of a porous medium to store and release fluid under changes in head (and 

thus pressure). It accounts for both fluid compression and matrix (or pore) deformation. 

storage assessment unit (SAU) A mappable volume of rock that includes a porous flow unit for CO2

storage and confining layers. 

storage efficiency factor (CSE) Storage efficiency factor representing the fraction of the total available pore 

space that will be occupied by free-phase CO2. CSE values in the literature range from 0.01 to 

0.05. 

storage types for PTs (table 1):

storage—EOR (SEOR) Storage related to the net CO2 left in place following CO2 enhanced-oilrecovery practices. This storage is evaluated by method A in the physical trap 

assessment methodology. 

storage—net cumulative volume (SNCV) The cumulative volume of fluid production (oil, gas, and 

water) minus the volume of fluid injected (water and gas). This storage is evaluated 

by method B in the physical trap assessment methodology. 

storage—total known volume (STKV) The total volume of pore space within the productive area of an 

oil and gas reservoir. This storage is evaluated by method C in the physical trap 

assessment methodology. 

storage—total trap volume (STTV) The resource volume of the PT to the spill point. This storage is 

evaluated by method D in the physical trap assessment methodology. 

 65
supercritical CO2 Carbon dioxide is in a supercritical fluid state when both the temperature and pressure 

exceed the critical temperature of 31°C and pressure of 74 bars at which liquid and vapor 

CO2 can no longer coexist. 

technically accessible resource The part of the total-in-place storage resource that may be available for 

CO2 injection and storage estimated by using present-day geologic and hydrologic knowledge 

of the subsurface and engineering practice for CO2 injection. Analogous to the term 

“technically recoverable resource” used in USGS oil and gas assessments. 

total dissolved solids (TDS) Synonymous with salinity; see salinity. 

transmissivity (usually T) The ability of a stratigraphic unit to accept or yield fluids with the properties 

included in hydraulic conductivity (K) of a stratigraphic unit multiplied by its thickness.

trapping The physical and geochemical processes by which injected CO2 is retained in the subsurface. 

uncertainty of the mean A distribution centered on the calculated mean of the raw data and bounded by 

values estimated by the assessment geologist to represent the possible range of mean values 

for the entire SF. 

unconditional resource Storage resource estimated for those physical traps and saline formations that meet 

the minimum size requirements. 

 66
 67

Appendix A. Assessment Input Forms 

A.1. Physical Traps (PTs) Assessment Model: Basic Input Data Form 

The input sections for the physical trap form are described in text section 3.4.1. 
Appendix A.1

Assessment Geologist: Date:

Region: Number:

Province: Number:

Storage Assessment Unit (SAU): Number:

SAU Relationship to NOGA AU:

Based on Data as of:

Notes from Assessor: 

CHARACTERISTICS OF THE STORAGE ASSESSMENT UNIT

1) Does the storage formation occur at depths between 3,000 and 13,000 ft? 

minimum: mode: maximum:

2) Area of storage formation at depths between 3,000 ft and 13,000 ft:

3) Is the storage formation overpressured (P/D> 0.5 psi/ft) at depths <13,000 ft? 

3a) If yes, area of SAU from 3,000 ft to known depth of overpressure:

4) Total Storage Formation Thickness (3,000-13,000 ft):

minimum: mode: maximum:

5) What is the minimum total capacity per Physical Trap (barrels)? 

6) Number of discovered traps larger than the minimum size:

7) Based on the GOR < or > 20,000, the number of gas and oil PTDs. a. Gas:

b. Oil:

8) OOIP (BOE): minimum: median: maximum:

9) Net Cum. Volume (barrels): minimum: median: maximum:

10) Area (acres): minimum: median: maximum:

11) Net Porous Interval (ft): minimum: mode: maximum:

12) Porosity (fraction): minimum: mode: maximum:

13) CSE Factor: minimum: mode: maximum:

PHYSICAL TRAPS (PTs) ASSESSMENT MODEL: BASIC INPUT DATA FORM

IDENTIFICATION INFORMATION

NUMERICAL INPUTS

CHARACTERISTICS OF PTDs IN THE SAU

68
14) Storage in PTD (tons): minimum: median: maximum:

From Line 8 and equation A.

15) Number of PTDs:

From Line 7b.

16) Storage in PTU (tons): minimum: median: maximum:

Calculated from internal analog, based on NOGA number and size results.

17) Number of PTUs: minimum: mode: maximum:

Modified from NOGA results.

18) Storage in PTD (tons): minimum: median: maximum:

From Line 9.

19) Number of PTDs:

From Line 6.

20) Storage in PTU (tons): minimum: median: maximum:

Calculated from internal analog, based on NOGA number and size results.

21) Number of PTUs: minimum: mode: maximum:

Modified from NOGA results.

STORAGE VOLUME CALCULATION METHODS

A) Conventional EOR (SEOR) = OOIP * IR * CEOR

B) Net Cumulative Volume, NCV (SNCV) = NCV * CWD * CF1 * ρCO2

69
22) Inputs for the assessment model PTD probabilistic calculation:

Area (Line 10): minimum: median: maximum:

Thickness (Line 11): minimum: mode: maximum:

Porosity (Line 12): minimum: mode: maximum:

CSE Factor (Line 13): minimum: mode: maximum:

23) Number of PTDs:

From Line 6.

24) Inputs for the assessment model PTU probabilistic calculation:

Area (calculated): minimum: median: maximum:

Calculated from internal analog, based on NOGA number and size results.

Thickness (Line 11): minimum: mode: maximum:

Porosity (Line 12): minimum: mode: maximum:

CSE Factor (Line 13): minimum: mode: maximum:

25) Number of PTUs: minimum: mode: maximum:

Modified from NOGA results.

26) Same inputs as Line 22 STKV, with addition of Growth Factor (CG).

Growth Factor (CG): 

27) Number of PTDs:

From Line 6.

28) Same inputs as Line 24 PTU STKV, with addition of Growth Factor (CG).

Growth Factor (CG): 

29) Number of PTUs: minimum: mode: maximum:

Modified from NOGA results.

C) Total Known Volume (STKV) = TA * TI * NTP * Φ * CSE * CF2 * ρCO2

D) Total Trap Volume to spill point (STTV) = STKV * CG

70
Probability of occurrence (0-1.0)

30) Probability of Containment:

See text for description and determination.

Yes No Not Applicable

Injectivity:

Depth to Top of Storage:

Confining Layer Characteristics:

Natural Seismic Risk:

Reservoir Architecture:

Drive Mechanism:

Reactivity:

Geologic Age:

Extent of Diagenesis:

Formation Water Composition:

Mineral Composition:

Formation Water Salinity:

SELECTED ANCILLARY DATA

Assessor is expected to separately describe physical, chemical, and mineralogical characterisitcs of the 

reservoir and confining layers that may influence (marked "yes" below) CO2 sequestration capability.

CO2-Brine-Mineral Interactions at T 

and P:

PHYSICAL TRAP PROBABILITY OF CONTAINMENT

71
ALLOCATIONS OF PTs TO STATES

Surface Allocations (uncertainty of a fixed value)

1 represents area % of the SAU

Volume % in entity mode:

2 represents area % of the SAU

Volume % in entity mode:

3 represents area % of the SAU

Volume % in entity mode:

4 represents area % of the SAU

Volume % in entity mode:

5 represents area % of the SAU

Volume % in entity mode:

6 represents area % of the SAU

Volume % in entity mode:

7 represents area % of the SAU

Volume % in entity mode:

8 represents area % of the SAU

Volume % in entity mode:

72
ALLOCATIONS OF PTs TO GENERAL LAND OWNERSHIPS

Surface Allocations (uncertainty of a fixed value)

1 Federal Lands represents area % of the SAU

Volume % in entity mode:

2 Private Lands represents area % of the SAU

Volume % in entity mode:

3 Tribal Lands represents area % of the SAU

Volume % in entity mode:

4 Other Lands represents area % of the SAU

Volume % in entity mode:

5 State 1 Lands represents area % of the SAU

Volume % in entity mode:

6 represents area % of the SAU

Volume % in entity mode:

7 represents area % of the SAU

Volume % in entity mode:

8 represents area % of the SAU

Volume % in entity mode:

73
ALLOCATIONS OF PTs TO CRITICAL LAND AREAS

Surface Allocations (uncertainty of a fixed value, does not total 100%)

1 Offshore Storage represents area % of the SAU

Volume % in entity minimum mode maximum

2 Urban Lands represents area % of the SAU

Volume % in entity minimum mode maximum

3 represents area % of the SAU

Volume % in entity minimum mode maximum

ALLOCATIONS OF PTs TO PROVINCES

Surface Allocations (uncertainty of a fixed value)

1 represents area % of the SAU

Volume % in entity mode:

2 represents area % of the SAU

Volume % in entity mode:

3 represents area % of the SAU

Volume % in entity mode:

4 represents area % of the SAU

Volume % in entity mode:

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A.2. Saline Formation (SF) Assessment Model: Basic Input Data Form 

The input sections for the saline formation form are described in text section 3.4.2. 

 75
Appendix A.2

IDENTIFICATION INFORMATION

Assessment Geologist: Date:

Region: Number:

Province: Number:

Storage Assessment Unit (SAU): Number:

SAU Relationship to NOGA AU:

Based on Data as of:

Notes from Assessor: 

CHARACTERISTICS OF THE STORAGE ASSESSMENT UNIT

1) Does the storage formation occur at depths between 3,000 and 13,000 ft? 

minimum: mode: maximum:

2) Area of storage formation at depths between 3,000 ft and 13,000 ft:

3) Is the storage formation overpressured (P/D> 0.5 psi/ft) at depths <13,000 ft? 

3a) If yes, area of SAU from 3,000 ft to known depth of overpressure:

4) Total Storage Formation Thickness (3,000-13,000 ft):

minimum: mode: maximum:

AREA OF THE SALINE FORMATION CALCULATION

5) What is the sum of areas of all PTs larger than the minimum size (acres)?

6) What is the sum of the areas for all undiscovered PTs larger than the minimum size?

minimum: mode: maximum:

Area of Saline Formation Equation

Asf = Asau - (Aptd+Aptu) 

where

Asf = Area of Saline Formation

Asau = Area of Storage Assessment Unit (Line 2 or 3a if overpressured)

Aptd = Area of Physical Traps (fixed value from Line 5)

Aptu = Area of Undiscovered Traps (distribution from Line 6)

7) Area of Saline Formation (acres):

minimum: mean: maximum:

SALINE FORMATION (SF) ASSESSMENT MODEL: BASIC INPUT DATA FORM

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CHARACTERISTICS OF THE SALINE FORMATION

8) Net Porous Interval (ft): minimum: mean: maximum:

9) Porosity (fraction): minimum: mean: maximum:

10) CSE Factor: minimum: mode: maximum:

SALINE FORMATION STORAGE VOLUME 

11) Inputs for the assessment model probabilistic calculation:

Inputs include the mean, from the raw data, and lower and upper uncertainties of the mean value.

Uncertainties of the mean values are chosen by the assessing geologist. See text for further explanation.

Area: mean (Line 7): lower uncertainty of the mean:

upper uncertainty of the mean:

Thickness: mean (Line 8): lower uncertainty of the mean:

upper uncertainty of the mean:

Porosity: mean (Line 9): lower uncertainty of the mean:

upper uncertainty of the mean:

CSE Factor (Line 10): minimum: mode: maximum:

Probability of occurrence (0-1.0)

12) Probability of Containment:

See text for description and determination.

SF Storage Volume = TA * TI

 * Φ * CSE

SALINE FORMATION PROBABILITY OF CONTAINMENT

77
Yes No Not Applicable

Injectivity:

Depth to Top of Storage:

Confining Layer Characteristics:

Natural Seismic Risk:

Reservoir Architecture:

Drive Mechanism:

Reactivity:

Geologic Age:

Extent of Diagenesis:

Formation Water Composition:

Mineral Composition:

Formation Water Salinity:

CO2-Brine-Mineral Interactions at T 

and P:

SELECTED ANCILLARY DATA

Assessor is expected to separately describe physical, chemical, and mineralogical characterisitcs of the 

reservoir and confining layers that may influence (marked "yes" below) CO2 sequestration capability.

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ALLOCATIONS OF THE SF TO STATES

Surface Allocations (uncertainty of a fixed value)

1 represents area % of the SAU

Volume % in entity mode:

2 represents area % of the SAU

Volume % in entity mode:

3 represents area % of the SAU

Volume % in entity mode:

4 represents area % of the SAU

Volume % in entity mode:

5 represents area % of the SAU

Volume % in entity mode:

6 represents area % of the SAU

Volume % in entity mode:

7 represents area % of the SAU

Volume % in entity mode:

8 represents area % of the SAU

Volume % in entity mode:

79
ALLOCATIONS OF THE SF TO GENERAL LAND OWNERSHIPS

Surface Allocations (uncertainty of a fixed value)

1 Federal Lands represents area % of the SAU

Volume % in entity mode:

2 Private Lands represents area % of the SAU

Volume % in entity mode:

3 Tribal Lands represents area % of the SAU

Volume % in entity mode:

4 Other Lands represents area % of the SAU

Volume % in entity mode:

5 State 1 Lands represents area % of the SAU

Volume % in entity mode:

6 represents area % of the SAU

Volume % in entity mode:

7 represents area % of the SAU

Volume % in entity mode:

8 represents area % of the SAU

Volume % in entity mode:

80
ALLOCATIONS OF THE SF TO CRITICAL LAND AREAS

Surface Allocations (uncertainty of a fixed value, does not total 100%)

1 Offshore Storage represents area % of the SAU

Volume % in entity minimum mode maximum

2 Urban Lands represents area % of the SAU

Volume % in entity minimum mode maximum

3 represents area % of the SAU

Volume % in entity minimum mode maximum

ALLOCATIONS OF THE SF TO PROVINCES

Surface Allocations (uncertainty of a fixed value)

1 represents area % of the SAU

Volume % in entity mode:

2 represents area % of the SAU

Volume % in entity mode:

3 represents area % of the SAU

Volume % in entity mode:

4 represents area % of the SAU

Volume % in entity mode:

81