U.S. Department of the Interior

U.S. Geological Survey

Scientific Investigations Report 2015–5091

U.S. Geological Survey Assessment of Reserve Growth 

Outside of the United States

U.S. Geological Survey Assessment of 

Reserve Growth Outside of the United 

States

By Timothy R. Klett, Troy A. Cook, Ronald R. Charpentier, Marilyn E. Tennyson, 

and Phuong A. Le

Scientific Investigations Report 2015–5091

U.S. Department of the Interior

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

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2015

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Suggested citation:

Klett, T.R., Cook, T.A., Charpentier, R.R., Tennyson, M.E., and Le, P.A., 2015, U.S. Geological Survey assessment of 

reserve growth outside of the United States: U.S. Geological Survey Scientific Investigations Report 2015–5091, 

13 p., http://dx.doi.org/10.3133/sir20155091.

ISSN 2328-0328 (online)
iii

Figures

1. Diagram showing field-development activities that can increase reserves

estimates (reserve growth).........................................................................................................2

2. Diagram showing the differences between conventional and unconventional

accumulations. Conventional accumulations contain oil and(or) gas that are

buoyant upon a water column....................................................................................................3

3. Bar chart showing the range of uncertainty of original oil in-place volumes for the

68 large U.S. oil accumulations that were individually analyzed in this study ...................7

4. Bar charts showing the distribution of recovery factors used to calculate reserve

growth in accumulations outside the United States...............................................................8

5. Circular (pie) diagrams showing crude oil and natural gas endowment outside of

the United States ..........................................................................................................................9

Contents

Abstract...........................................................................................................................................................1

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

Purpose...................................................................................................................................................1

Scope......................................................................................................................................................2

Definition of Reserve Growth.......................................................................................................................2

Terminology.....................................................................................................................................................3

Assessment of Reserve Growth Outside of the United States...............................................................4

Assessment Results for Discovered Accumulations Outside of the United States ...........................9

Future Research Directions .......................................................................................................................10

Summary........................................................................................................................................................10

Acknowledgments.......................................................................................................................................10

References Cited..........................................................................................................................................10

Appendix 1. Final Report of the AAPG CORE Subcommittee 8-11-09 ..............................................12

Introduction..........................................................................................................................................12

Status of USGS Energy Team GTK 2009 ..........................................................................................12

Discussion and Recommendations .................................................................................................13

Summary...............................................................................................................................................13

Tables

1. Table of discovered, conventional accumulations in the U.S. that were individually

analyzed in this study, estimated ranges of original in-place volumes (lognormal

distribution), estimated ranges of recovery factors (triangular distribution), and

reported or estimated coproduct ratios (point values) ..........................................................4

2 Table of assessment results for discovered accumulations outside of the United

States (technically recoverable, conventional petroleum resources)................................9
iv

Conversion Factors

Multiply By To obtain

barrel (bbl) 0.1590 cubic meter (m3

)

barrel (bbl) 0.136 metric ton (MT), average gravity

cubic feet (ft3

) 0.02382 cubic meter (m3)

cubic meter (m3

) 35.3147 cubic feet (ft3)

metric ton (MT) 7.33 barrel (bbl), average gravity
Abstract

The U.S. Geological Survey estimated volumes of potential additions to oil and gas reserves for the United States by 

reserve growth in discovered accumulations. These volumes 

were derived by using a new methodology developed by the 

U.S. Geological Survey and reviewed by the American Association of Petroleum Geologists Committee on Resource Evaluation. This methodology was used to assess reserve growth in 

individual accumulations (reservoirs, groups of reservoirs, or 

fields). Selected, large, well-studied, conventional accumulations in the United States that are estimated to contribute most 

to reserve growth were assessed using analysis of geology and 

engineering practices. Potential additions to oil and gas reserves 

for large, discovered, conventional accumulations outside of 

the United States due to reserve growth were assessed using the 

U.S. accumulations as analogs. Potential oil and gas volumes 

were assumed to be added to proven plus probable reserves.

The U.S. Geological Survey estimated volumes of technically recoverable, conventional petroleum resources resulting 

from reserve growth for discovered fields outside the United 

States that have reported in-place oil and gas volumes of 500 

million barrels of oil equivalent or greater. The mean volumes 

of reserve growth were estimated at 665 billion barrels of crude 

oil; 1,429 trillion cubic feet of natural gas; and 16 billion barrels 

of natural gas liquids. These volumes constitute a significant 

portion of the world’s oil and gas resources and represent the 

potential future growth of current global reserves over time 

based on better assessment methodology, new technologies, and 

greater understanding of reservoirs.

Introduction

Purpose

The U.S. Geological Survey (USGS) assesses undiscovered conventional and unconventional, technically 

recoverable oil and gas resources of the United States 

(excluding Federal Outer Continental Shelf) and the world. 

The Bureau of Ocean Energy Management (BOEM) is 

responsible for the assessment of oil and gas resources of 

the Federal Outer Continental Shelf. Reserves in discovered conventional accumulations can sometimes increase 

because of delineation of additional in-place petroleum 

volumes, improved recovery efficiency, and revisions from 

recalculation of viable reserves in dynamically changing economic, operating, and regulatory/political conditions (fig. 1). The USGS considers additions to reserves 

as a resource and, therefore, assesses reserve growth. This 

report describes the USGS methodology and assessment 

process for estimating volumes of reserve growth, as well 

as estimates of reserve growth in accumulations outside of 

the United States.

The estimates presented in this report were derived 

using a new method to assess reserve growth in discovered 

conventional accumulations developed by the USGS (Klett 

and others, 2011). This methodology is different from that 

used in past USGS assessments (Cook, 2013). Estimates of 

the distributions of in-place oil and gas and recovery factors 

in large, well-studied, U.S. accumulations (individual reservoirs, groups of reservoirs, or fields) were used as analogs 

for the assessment of accumulations outside of the United 

States. The USGS assessment method was reviewed by the 

Subcommittee on Growth-to-Known Reserves of the American Association of Petroleum Geologists Committee on 

Resource Evaluation of the (AAPG CORE) in March 2008 

(Appendix 1).

Identified unconventional (continuous) oil and gas 

accumulations, such as shale gas, tight gas, tight oil, and tar 

sands, were excluded from this assessment of reserve growth. 

The USGS assesses unconventional, technically recoverable 

oil and gas resources using a methodology that is different 

from that used to assess conventional resources (Charpentier 

and Cook, 2011). This methodology to assess unconventional 

resources includes potential additions to reserves.

In addition to estimating potential additions to reserves in 

discovered accumulations by reserve growth, the USGS makes 

estimates of the potential fully developed (grown) sizes of 

undiscovered conventional accumulations to aid in the estimation of undiscovered oil and gas resources.

U.S. Geological Survey Assessment of Reserve Growth 

Outside of the United States

By Timothy R. Klett, Troy A. Cook, Ronald R. Charpentier, Marilyn E. Tennyson, and Phuong A. Le
2 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

Scope

The recently developed USGS method to assess reserve 

growth was used to estimate technically recoverable crude oil 

and natural gas volumes that have the potential to be added 

to reserves in discovered conventional accumulations under 

proven technology currently in practice within the trend or 

play, or which can reasonably be extrapolated from geologically similar trends or plays. These estimates do not assume 

or include estimates based on the application of speculative 

future technologies. The assessment methodology estimates 

future potential additions to reserves using current technology, but not necessarily current economics. No time period 

was assumed for the estimated reserve growth volumes in this 

report to take place.

Reserve growth was assessed for oil in oil accumulations 

and was assessed for nonassociated gas in gas accumulations. Reserve growth of coproducts (associated/dissolved 

gas and natural gas liquids in oil accumulations, and total 

liquids in gas accumulations) was calculated based on the 

volumetric coproduct ratios with the primary commodity (oil 

or gas) within the accumulation. Only crude oil and nonassociated natural gas that flows to a wellbore (either naturally 

or upon various production operations) were assessed directly. 

Associated and dissolved natural gas and natural gas liquids 

were assumed to grow by the same ratio as the primary commodity (gas in gas accumulations, oil in oil accumulations).

No attempt was made to estimate economically recoverable resources. Costs and economics of drilling and production 

operations to promote reserve growth can be analyzed and 

modeled to provide information on current and future development and production operations; however, these cost data were 

not included in this study.

Definition of Reserve Growth

Reserve growth is the increase in estimated volumes of 

oil and natural gas that might be recovered from existing fields 

and reservoirs through time. Most reserve growth results from 

delineation of new reservoirs, field extensions, or enhanced 

recovery techniques that improve efficiency; or from recalculation of reserves due to changing economic and operating 

conditions (fig. 1). Many accumulations show no growth of 

reserves and many reserve volumes shrink, however. The term 

“reserve growth” as used here, is synonymous with “growthto-known,” “reserve appreciation,” “ultimate recovery appreciation,” “field growth,” or “reservoir growth,” among others.

Figure 1. Diagram showing field-development activities that can increase reserves estimates (reserve growth). Reserve growth is 

defined as increases in successive estimates of recoverable quantities of crude oil, natural gas, and natural gas liquids in discovered 

conventional accumulations. Reserve growth can be grouped into three activities: (1) delineation of additional in-place petroleum 

volumes, which increases the degree of geologic assurance (for example, infill drilling; new reservoirs, pools, or pay zones; extensions); 

(2) improved recovery efficiency, which increases the degree of technological feasibility (for example, enhanced recovery, well 

stimulation, recompletions, new completions of bypassed zones); and (3) revisions resulting from recalculation of viable reserves in 

dynamically changing economic, operating, and regulatory/political conditions, which increases the degree of economic feasibility (for 

example, reevalution of production performance, more efficient operations) (Klett, 2005).

Known extent of

proven reservoir

Infill drilling

Enhanced

recovery

New reservoirs,

pools, or pay zones

Extensions

Well stimulation,

recompletions

New completions

of bypassed zones

Reevaluation of production performance

More efficient operations

Other revisions
Terminology 3

Terminology

Several technical terms are used in this report to describe 

reserve growth. These terms and their definitions according to 

the USGS are presented below.

Accumulation is a deposit of crude oil, natural gas, natural 

gas condensate, and(or) natural gas liquids (NGL) within a field, 

or reservoir(s) within a field. An accumulation might equate to a 

single reservoir, group of reservoirs, or an entire field.

Oil accumulations are defined by the ratio of gas to oil as 

containing less than 20,000 cubic feet of gas per barrel of oil.

Gas accumulations are defined by the ratio of gas to oil 

as containing 20,000 or more cubic feet of gas per barrel of 

oil. Gas in this type of accumulation is assumed to be nonassociated gas rather than associated with or dissolved in an oil 

accumulation.

Conventional accumulations contain oil and(or) gas that 

are buoyant upon a water column. Conventional accumulations have discrete boundaries typically bounded by dry holes, 

and usually have relatively good reservoir properties (porosity 

and permeability) (fig. 2).

Unconventional accumulations contain oil and(or) 

gas that are not buoyant upon a water column. Unconventional accumulations are regional in extent and typically have 

relatively poor reservoir properties whereby stimulation is 

required for production (fig. 2).

Resource is a concentration of petroleum in or on the 

earth’s crust, some of which is potentially economically 

extractable.

Original in-place volume is the volume of crude oil, 

natural gas, and NGL originally present in the reservoir(s) 

whether or not they are technically or economically 

recoverable.

Recoverability or recovery efficiency is the estimated 

fraction (known as recovery factor) of the original in-place 

volume that can be extracted.

Cumulative production is the total volume of petroleum 

that has been extracted.

Remaining reserves are estimated volumes of petroleum that are expected to be commercially recovered, as of a 

specified date (exclusive of production). Remaining reserves 

are commonly classified as proved, proved-plus-probable, and 

proved-plus-probable-plus-possible. Reserves are resources, 

but resources are not necessarily reserves.

Recoverable volume (reported volumes that are also 

called field size or accumulation size) is the sum of cumulative 

production and remaining reserves. Recoverable volume can 

also be defined as cumulative volumes of oil, gas, and natural 

gas liquids that might be extracted with known technologies by the end of the development and production process. 

Reported recoverable volumes are called known recoverable 

volumes in this paper.

Figure 2. Diagram showing the differences between conventional and unconventional accumulations. Conventional accumulations 

contain oil and(or) gas that are buoyant upon a water column. Conventional accumulations have discrete boundaries typically bounded 

by dry holes, and usually have good reservoir properties (porosity and permeability). Unconventional accumulations contain oil and(or) 

gas that are not buoyant upon a water column. Unconventional accumulations are regional in extent and typically have poor reservoir 

properties whereby stimulation is required for production. Figure modified by Schenk and Pollastro (2002) from Schmoker (1996).

Land surface 

Conventional

structural gas

accumulation

Coal-bed gas

Conventional

stratigraphic gas

accumulation

Conventional

structural oil

accumulation

Continuous gas

accumulation

Transition

zones 

Gas

Oil

Water

Tens of miles or kilometers

EXPLANATION
4 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

Assessment of Reserve Growth Outside 

of the United States

The USGS method for calculating reserve growth 

uses reported estimates of original in-place volumes and 

recoverability (recovery factors) of accumulations that were 

individually analyzed. Volumetric data and recovery factors 

for accumulations outside of the United States are reported 

for fields as a whole and as single estimates for any given 

year. Original in-place volumes and recovery factors for 

accumulations outside the United States were taken from 

the proprietary IHS (2009) International Exploration and 

Production Database.

Because recoverable volumes for individual reservoirs 

were not reported for many fields outside of the United States, 

the individual accumulation analysis was not used. Data 

acquired from individually analyzed U.S. accumulations were 

used as analogs in this study. Studies of 68 large, well-studied 

oil accumulations and two large, well-studied gas accumulations in the United States provided probability distributions for 

uncertainty of original in-place volumes and recovery factors 

for non-U.S. accumulations (table 1).

The uncertainty ranges of in-place volumes of individually analyzed U.S. oil or gas accumulations were applied to 

the in-place volumes of oil and gas fields outside of the United 

States. The probability distributions of recovery factors of the 

individually analyzed accumulations were used in the calculation of reserve growth. Large oil and gas accumulations, 

reported at a field level by IHS, are more likely to experience 

reserve growth, and their respective in-place volumes should 

be relatively well reported and accurate. Only fields in the IHS 

(2009) international database having original in-place volumes 

of 0.5 billion barrels of oil (BBO) or more of oil in oil fields, 

or 3 trillion cubic feet of gas (TCFG) or more of gas in gas 

fields were used for this assessment. The in-place and recovery 

factor distributions were statistically combined using a Monte 

Carlo simulation for 50,000 iterations. Estimates of future 

reserve growth are relative to the sum of cumulative production and proven-plus-probable reserves, reported as recoverable volumes, in the database. The results of the Monte Carlo 

simulation were then aggregated to provide an approximation 

of reserve growth for the world.

The range of uncertainty of original oil in-place volumes 

for U.S. oil accumulations (fig. 3), normalized to a central 

tendency of 1.0, was applied to reported original in-place 

Table 1. Table of discovered, conventional accumulations in the U.S. that were individually analyzed in this study, estimated ranges 

of original in-place volumes (lognormal distribution), estimated ranges of recovery factors (triangular distribution), and reported or 

estimated coproduct ratios (point values).—Continued

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; CFG/BO, cubic feet of gas per barrel of oil; NGL, natural gas liquids; BO/MMCFG, barrels of 

oil per million cubic feet of gas; Min., minimum; Med., median; Max., maximum]

Oil in oil accumulations

Estimated original

in-place hydrocarbons, MMBO Estimated recovery factor Gas/oil

CFG/BO

NGL/gas

BO/MMCFG Min. Med. Max. Min. Mode Max.

Alaska and Pacific Coast regions

Alpine, all reservoirs 950 1,000 1,200 0.40 0.45 0.55 1,021 75.0

Brea-Olinda, all reservoirs 1,200 1,600 2,400 0.35 0.40 0.45 1,129 118.4

Coalinga, all reservoirs 3,000 3,500 5,000 0.30 0.45 0.65 234 40.0

Cymric: Welport, diatomite 425 600 1,000 0.25 0.40 0.55 266 70.7

Cymric Welport and McKittrick Front, pre-Monterey 145 175 210 0.30 0.40 0.55 2,262 56.2

Cymric: Welport, Tulare 550 700 1,000 0.55 0.65 0.85 51 67.6

Dominguez, all reservoirs 1,000 1,200 1,450 0.35 0.40 0.50 1,461 69.4

Elk Hills, Stevens, Monterey, and older reservoirs 2,300 2,700 3,500 0.35 0.40 0.50 3,128 78.7

Elk Hills, shallow oil zone 1,300 1,600 2,000 0.45 0.48 0.55 784 53.4

Endicott, all reservoirs 1,125 1,150 1,200 0.45 0.48 0.55 1,000 54.8

Endicott, Kekiktuk basal tar mat not quantitatively assessed

Huntington Beach, all reservoirs 3,250 3,500 6,000 0.35 0.40 0.55 747 53.3

Inglewood, all reservoirs 1,000 1,400 2,500 0.40 0.45 0.55 681 41.0

Kern River, Kern River and Vedder 3,400 3,600 4,200 0.70 0.75 0.85 4 67.6

West Sak, West Sak East 7,000 9,000 15,000 0.10 0.20 0.50

West Sak, West Sak West not quantitatively assessed

Kuparuk River, Kuparuk River 5,100 6,000 7,000 0.50 0.60 0.70 6 188.5
Assessment of Reserve Growth Outside of the United States 5

Table 1. Table of discovered, conventional accumulations in the U.S. that were individually analyzed in this study, estimated ranges 

of original in-place volumes (lognormal distribution), estimated ranges of recovery factors (triangular distribution), and reported or 

estimated coproduct ratios (point values).—Continued

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; CFG/BO, cubic feet of gas per barrel of oil; NGL, natural gas liquids; BO/MMCFG, barrels of 

oil per million cubic feet of gas; Min., minimum; Med., median; Max., maximum]

Oil in oil accumulations

Estimated original

in-place hydrocarbons, MMBO Estimated recovery factor Gas/oil

CFG/BO

NGL/gas

BO/MMCFG Min. Med. Max. Min. Mode Max.

Kuparuk River, Ugnu not quantitatively assessed

Long Beach, all reservoirs 3,000 3,100 3,600 0.35 0.40 0.55 1,155 81.5

Lost Hills, diatomite 2,000 2,800 4,500 0.20 0.35 0.55 4,279 20.4

Lost Hills, Monterey opal-CT and chert not quantitatively assessed

Lost Hills, Tulare, Etchegoin 655 700 1,500 0.45 0.55 0.65 813 44.6

McKittrick Main Area, all reservoirs 525 800 1,700 0.40 0.50 0.60 165 45.1

Midway-Sunset, diatomite 300 1,500 3,000 0.10 0.20 0.40 58 2452.3

Midway-Sunset, non-diatomite 6,000 8,000 12,000 0.45 0.60 0.70 168 62.3

Milne Point, Schrader Bluff 1,600 2,000 2,500 0.10 0.20 0.50 1,040 75.0

Milne Point, Sag River and Kuparuk River 920 1,000 1,100 0.40 0.50 0.60 267 75.0

Milne Point, Ugnu 1,000 2,000 4,000 0.01 0.10 0.20 0 0.0

North Belridge, diatomite 400 600 1,000 0.25 0.40 0.55 973 28.3

North Belridge, Temblor and older sandstones 300 350 500 0.25 0.30 0.40 9,981 36.4

North Belridge, Tulare, Etchegoin 50 100 300 0.45 0.55 0.65 0.6 16.0

Prudhoe Bay, Sadlerochit (Ivishak) 20,000 23,500 28,000 0.55 0.60 0.70 2,700 73.9

Prudhoe Bay, Lisburne 1,600 1,800 3,000 0.15 0.25 0.45 550 175.0

Orion, Schrader Bluff 1,100 1,400 2,000 0.10 0.20 0.50 730 75.0

Polaris, Schrader Bluff 550 750 1,000 0.10 0.20 0.50 2,048 75.0

Prudhoe Bay, heavy oil and tar 1,001 1,500 2,000 0.01 0.05 0.10 0 0.0

Richfield, all reservoirs 800 1,000 2,400 0.26 0.30 0.45 841 60.0

San Ardo, all reservoirs 1,400 1,500 2,250 0.45 0.60 0.70 156 62.3

Santa Fe Springs, all reservoirs 2,100 2,378 2,700 0.30 0.35 0.40 1,322 63.5

Seal Beach, all reservoirs 850 900 1,000 0.35 0.40 0.50 1,035 54.4

South Belridge, diatomite 2,500 5,000 8,000 0.25 0.40 0.55 828 28.2

South Belridge, Monterey opal-CT and chert not quantitatively assessed

South Belridge, Tulare 1,650 1,900 2,200 0.65 0.75 0.85 24 16.0

Torrance, all reservoirs 900 1,000 2,000 0.35 0.40 0.55 650 0.0

Ventura-Rincon-San Miguelito, all reservoirs 4,100 4,500 5,000 0.35 0.40 0.50 2 1250.0

Wilmington Trend, all reservoirs 7,600 9,000 12,000 0.35 0.40 0.55 446 16.2

Colorado Plateau and Basin and Range, and Rocky Mountains and Northern Great Plains regions

Aneth Area, Desert Creek 1,000 1,100 1,250 0.45 0.50 0.65 619 99.9

Oregon Basin, Phophoria, Tensleep, Madison 1,020 1,100 1,200 0.46 0.48 0.55 310 12.9

Rangely, all reservoirs 1,750 1,900 2,100 0.57 0.62 0.65 744 53.1

Salt Creek Area, all reservoirs 1,600 1,650 2,000 0.50 0.52 0.60 811 0.3

West Texas and Eastern New Mexico region

Artesia-Maljamar: Guadalupe, all reservoirs 1,000 1,200 1,800 0.45 0.50 0.55 1,058 110.5

Cowden North, all reservoirs 1,400 1,600 2,100 0.48 0.50 0.60 1,428 86.3

Cowden South, all reservoirs 2,100 2,200 3,000 0.30 0.35 0.40 542 174.3

Eunice Area, all reservoirs 4,200 4,500 5,000 0.35 0.40 0.45 9,710 40.1

Fullerton, all reservoirs 1,500 1,600 2,000 0.33 0.36 0.40 1,180 199.9
6 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

volumes for oil accumulations and for gas accumulations outside the United States. This distribution ranges from approximately 0.2 to 3.7 and has a mean value of 1.1. A value was 

randomly selected from this distribution during each Monte 

Carlo iteration and multiplied times the reported in-place 

volume of the field, resulting in a probability distribution for 

in-place volumes.

An empirical probability distribution of recovery factors of the 68 U.S. oil accumulations that were assessed by 

individual accumulation analysis was used as an analog to 

estimate recovery factors in oil fields outside the United States 

(fig. 4). This distribution ranges from approximately 0.01 to 

0.85 and has a mean value of 0.46. This distribution for U.S. 

accumulations was based on accumulations with a wide range 

of reservoirs, oil types, and degrees of development. A uniform probability distribution of gas recovery factors ranging 

from 0.7 to 0.9 was applied to gas fields outside of the United 

States. Reported recovery factors for gas fields outside of the 

United States varied widely, and only two U.S. gas accumulations have been individually analyzed.

Distributions of reserve-growth volumes were calculated for each of the 1,467 oil fields having 500 million barrels of oil equivalents (MMBOE) or more of original in-place 

oil and 347 of the gas fields having 500 MMBOE or more 

of original in-place gas outside of the United States. Probability distributions of the original in-place volumes for each 

Table 1. Table of discovered, conventional accumulations in the U.S. that were individually analyzed in this study, estimated ranges 

of original in-place volumes (lognormal distribution), estimated ranges of recovery factors (triangular distribution), and reported or 

estimated coproduct ratios (point values).—Continued

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; CFG/BO, cubic feet of gas per barrel of oil; NGL, natural gas liquids; BO/MMCFG, barrels of 

oil per million cubic feet of gas; Min., minimum; Med., median; Max., maximum]

Oil in oil accumulations

Estimated original

in-place hydrocarbons, MMBO Estimated recovery factor Gas/oil

CFG/BO

NGL/gas

BO/MMCFG Min. Med. Max. Min. Mode Max.

Goldsmith-Andector, all reservoirs except Clear Fork 1,850 2,100 2,600 0.40 0.45 0.50 1,760 93.3

Hobbs, all reservoirs 800 1,000 1,300 0.50 0.55 0.60 1,906 90.9

Howard-Glasscock, all reservoirs 1,500 1,600 1,800 0.35 0.38 0.50 125 0.3

McElroy-Dune, all reservoirs 3,300 3,600 4,000 0.25 0.33 0.40 511 144.1

Robertson-Flanagan, all reservoirs 1,500 1,600 2,000 0.30 0.35 0.40 518 117.7

Salt Creek (Permian Basin), all reservoirs 680 700 730 0.60 0.63 0.65 670 199.6

Scurry, all reservoirs 3,000 3,100 3,300 0.55 0.62 0.65 727 334.6

Seminole, all reservoirs 1,250 1,300 1,400 0.55 0.60 0.65 987 129.7

Slaughter-Levelland, all reservoirs 4,200 4,600 5,600 0.48 0.50 0.60 710 169.9

Scarborough and South Sand Belt, all reservoirs 2,900 3,000 3,500 0.35 0.40 0.45 3,191 44.3

Vacuum, all reservoirs 1,600 1,800 2,100 0.45 0.50 0.55 1,447 161.0

Wasson Area, Clear Fork and older reservoirs 900 1,000 1,200 0.27 0.33 0.45 653 125.0

Wasson Area, San Andres-Glorieta 4,410 4,500 4,600 0.58 0.60 0.63 924 136.1

Yates, all reservoirs 4,000 4,300 5,000 0.40 0.45 0.55 86 186.0

Gulf Coast region

Conroe, all reservoirs 1,350 1,400 1,600 0.55 0.60 0.65 1,894 49.7

East Texas, Woodbine 7,000 7,100 7,500 0.78 0.80 0.85 263 450.7

Hawkins, all reservoirs 1,300 1,350 1,500 0.70 0.72 0.75 662 139.4

Midcontinent and Eastern regions

Sho-Vel-Tum, all reservoirs 3,550 3,600 4,000 0.50 0.52 0.60 348 2552.9

Gas in gas accumulations

Estimated original

in-place hydrocarbons, BCFG Estimated recovery factor Liq/gas

BO/MMCFG Min. Med. Max. Min. Mode Max

Gulf Coast region

Monroe, all reservoirs 8,300 9,000 10,000 0.90 0.92 0.95 0.0

Midcontinent and Eastern regions

Hugoton, all reservoirs 85,000 87,000 90,000 0.85 0.87 0.90 45.4
Assessment of Reserve Growth Outside of the United States 7

field were sampled by Monte Carlo simulation to calculate 

an overall probability distribution (fig. 3). Complete dependency (perfect positive correlation where the correlation 

coefficient is 1.0) was assumed among the in-place volumes 

for all oil and gas fields.

Figure 3. Bar chart showing the range of uncertainty of original oil in-place volumes for

the 68 large U.S. oil accumulations that were individually analyzed in this study. The range 

is normalized to a central tendency of 1.0 and was applied to reported original in-place 

volumes for both oil and gas accumulations outside the United States. A value was randomly 

selected from this distribution during each Monte Carlo iteration and multiplied times the 

reported in-place volume of the accumulation, resulting in an in-place probability. (Std Dev, 

Standard Deviation; %, percent)

Normalized Uncertainty of Original Oil In-Place for Oil in Oil Accumulations

Original Oil In-Place

EXPLANATION

Minimum 0.220

Maximum 3.71

Mean 1.05

Std Dev 0.171

Values 50,000

5.0% 90.0% 5.0%

0.899 1.298

7

6

5

4

3

2

1

0

Frequency

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Uncertainty

Probability distributions of the recovery factors for each 

of the 1,467 oil fields and 347 of the gas fields outside of the 

United States were used to calculate an overall probability distribution of recoverability by Monte Carlo simulation (fig. 4). 

Complete independence (correlation coefficient of 0) was 

assumed among the fields because no two fields are developed 

in the same manner.
8 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

Figure 4. Bar charts showing the distribution of recovery factors used to calculate reserve growth in accumulations

outside the United States. A. An empirical probability distribution of recovery factors of the 68 U.S. oil accumulations 

that were assessed using individual accumulation analysis. The recovery factors were used for oil accumulations 

outside of the United States. This distribution, based on U.S. accumulations, was used because a wide range of 

reservoirs, oil types, and degrees of development are represented. B. A uniform probability distribution of gasrecovery factors was applied to gas accumulations outside of the United States because reported recovery factors 

for gas accumulations outside of the United States varied widely and because only two U.S. gas accumulations were 

assessed using individual accumulation analysis. (Std Dev, Standard Deviation; %, percent)

Distribution of Recovery Factors for Oil in Oil Accumulations

5.0% 90.0% 5.0%

0.198 0.723

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

Frequency

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9

Recovery Factor

Recovery Factor

EXPLANATION

Minimum 0.0107

Maximum 0.849

Mean 0.461

Std Dev 0.148

Values 50,000

A

Recovery Factor

EXPLANATION

Minimum 0.700

Maximum 0.900

Mean 0.800

Std Dev 0.0577

Values 50,000

5.0% 90.0% 5.0%

0.7100 0.8900

B Distribution of Recovery Factors for Gas in Gas Accumulations

6

5

4

3

2

1

0

Frequency

0.65 0.70 0.75 0.80 0.85 0.90 0.95

Recovery Factor
Assessment Results for Discovered Accumulations Outside of the United States 9

Assessment Results for Discovered 

Accumulations Outside of the United 

States

Table 2 lists estimated volumes of technically recoverable, conventional oil and gas resources from reserve growth 

for large accumulations outside the United States. The 

estimated mean volumes of oil and gas are about 665 BBO of 

crude oil; 1,429 TCFG of natural gas [1,043 TCFG of associated and dissolved natural gas and 386 TCFG of nonassociated natural gas]; and 16 billion barrels of natural gas liquids 

Table 2. Table of assessment results for discovered accumulations outside of the United States (technically recoverable, conventional 

petroleum resources) (Klett and others, 2012).

[BBOE, billion barrels of oil equivalent, BBO, billion barrels of oil; TCFG, trillion cubic feet of gas; BBNGL, billion barrels of natural gas liquids. For gas 

fields, all liquids are included under the natural gas liquids (NGL) category. Accum, accumulation. F95 denotes a 95-percent chance of at least the amount tabulated. Other fractiles are defined similary. Negative values indicated the possibility that reported reserves could decrease. Fractiles are not additive except under 

the assumption of perfect positive correlation. Gray shading indicates not applicable]

World outside the 

United States: Discovered accumulations 

with original in-place 

volumes of 0.5 BBOE

or greater

Accumulation type

Number

of

accumulations

Estimated reserve growth

Oil (BBO) Gas (TCFG) NGL (BBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Reserve growth by

commodity

Oil 1,467 329 598 1,205 665 592 956 1,766 1,043 –16 –2 18 –1

Gas 347 –469 210 1,781 386 –14 11 65 17

Total reserve growth 1,814 665 1,429 16

[–1 BBO of natural gas liquids in oil accumulations and 17 

BBO of total liquids in nonassociated gas accumulations] 

(Klett and others, 2012). Negative values indicate the possibility that the size of reported reserves could decrease rather than 

increase. The estimated amount of reserve growth is compared 

with volumes of cumulative production, remaining reserves, 

and undiscovered resources as shown on pie charts in figure 5.

Assuming that the amount of reserve growth is approximately proportional to original in-place volumes, this study 

estimated that about 80 percent of the potential reserve growth of 

the world outside the United States was accounted by this assessment; the other 20 percent was estimated to occur in accumulations with smaller in-place volumes (less than 500 MMBOE).

Figure 5. Circular (pie) diagrams showing crude oil and natural gas endowment outside of the United States. 

Data from IHS (2009) and Schenk (2012). Reserve growth was estimated by United States Geological Survey 

based on IHS (2009) in-place and recovery factor data. (BBO, billion barrels of oil; TCFG, trillion cubic feet of 

gas; %, percent) 

Crude Oil and Natural Gas Endowment

Outside of the United States

Crude Oil - 3,300 BBO Natural Gas - 16,500 TCFG

Remaining Reserves:

1,268 BBO, 39%

Undiscovered

Resources:

565 BBO, 17% Cumulative Production:

795 BBO, 24%

Reserve

Growth:

665 BBO, 20%

Undiscovered

Resources:

5,606 TCFG, 34%

Reserve

Growth:

1,429 TCFG, 9%

Remaining Reserves:

7,474 TCFG, 45%

Cumulative

Production:

1,975 TCFG,

12%
10 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

Acknowledgments

The authors gratefully acknowledge the American 

Association of Petroleum Geologists Committee on Resource 

Evaluation (AAPG CORE) for reviewing the new USGS 

methodology, as well as their advice and guidance at the onset 

of this reserve-growth assessment project.

References Cited

Charpentier, R.R., and Cook, T.A., 2011, USGS methodology 

for assessing continuous petroleum resources: U.S. Geological Survey Open-File Report 2011–1167, 73 p., http://pubs.

usgs.gov/of/2011/1167/. 

Cook, T.A., 2013, Reserve growth of oil and gas fields—

Investigations and applications: U.S. Geological Survey 

Scientific Investigations Report 2013–5063, 29 p., http://

pubs.usgs.gov/sir/2013/5063/. 

IHS, 2009, International exploration and production database: 

Database available from Information Handling Services 

(IHS)15 Inverness Way East, D205, Englewood, Colo., 

80112. 

Klett, T.R., 2005, United States Geological Survey’s reservegrowth models and their implementation: Natural Resources 

Research, v. 14, no. 3, p. 249–264.

Klett, T.R., Attanasi, E.D., Charpentier, R.R., Cook, T.A., 

Freeman, P.A., Gautier, D.L., Le, P.A., Ryder, R.T., Schenk, 

C.J., Tennyson, M.E., and Verma, M.K. (U.S. Geological 

Survey Reserve Growth Assessment Team), 2011, New 

U.S. Geological Survey method for the assessment of 

reserve growth: U.S. Geological Survey Scientific Investigations Report 2011–5163, 9 p., http://pubs.usgs.gov/

sir/2011/5163/. 

Klett, T.R., Cook, T.A., Charpentier, R.R., Tennyson, M.E., 

Attanasi, E.D., Freeman, P.A., Ryder, R.T., Gautier, D.L., 

Verma, M.K., Le, P.A., and Schenk, C.J. (U.S. Geological 

Survey Reserve Growth Assessment Team), 2012, Assessment of potential additions to conventional oil and gas 

resources of the World (outside the United States) from 

reserve growth, 2012: U.S. Geological Survey Fact Sheet 

2012–3052, 2 p., http://pubs.usgs.gov/fs/2012/3052/. 

Schenk, C.J., 2012, An estimate of undiscovered conventional 

oil and gas resources of the world, 2012: U.S. Geological 

Survey Fact Sheet 2012–3042, 6 p., http://pubs.usgs.gov/

fs/2012/3042/. 

Schenk, C.J., and Pollastro, R.M., 2002, Natural gas production in the United States: U.S. Geological Survey Fact Sheet 

FS-113-01, 2 p., http://pubs.usgs.gov/fs/fs-0113-01/fs-0113-

01.pdf. 

Most of the world’s reported original in-place and reserves 

volumes for oil in oil fields and gas in gas fields, outside the 

United States, are in 1,814 fields. Specifically, approximately 

85 percent of the world’s original in-place oil outside the 

United States is in 1,467 oil fields (about 9 percent of the total 

number of oil fields). Approximately 79 percent of the original 

in-place nonassociated gas is in 347 gas fields (about 3 percent 

of the total number of nonassociated gas fields).

Future Research Directions

Estimates of reserve growth of conventional oil and gas 

accumulations around the world can become more accurate 

as large, significant non-U.S. accumulations are individually 

analyzed. Assessments of non-U.S. accumulations by individual analyses outside of the United States have not yet been 

performed. An analysis of individual accumulations would 

increase the accuracy of reserve-growth estimates and reduce 

the uncertainty of the estimated volumes of conventional oil and 

gas accumulations both within and outside of the United States. 

Analysis of individual accumulations provides greater knowledge of the drivers of reserve growth. Furthermore, additional 

analyses and results can be compared to the recently released 

estimates of reserve growth outside of the United States in order 

to test the accuracy of the new reserve-growth methodology.

Additional research is required to calculate original inplace gas volumes and recovery efficiencies, in the absence of 

reported values, in order to provide better estimates of reserve 

growth in conventional gas accumulations. Reserve growth of 

gas accumulations was analyzed, but paucity of in-place gas 

volumes prevented individual analysis of many gas accumulations that significantly contributed to reserve growth. Our 

study found that much of the reserve growth in gas accumulations of the United States can be attributed to the addition of 

unconventional gas reservoirs in recent years. Conventional 

gas accumulations undergo some reserve growth, but growth 

is less significant than the reserve growth in oil accumulations 

or from unconventional reservoirs being developed along with 

previously discovered conventional gas reservoirs.

Summary

This 2012 study estimated reserve growth in large oil and 

gas accumulations having in-place volumes of 500 MMBOE 

and greater. These accumulations are the largest contributors 

to reserve growth. Results of this study provide estimates of 

reserve growth for accumulations outside of the United States, 

accounting for much of the reserve growth worldwide. Results 

were reported along with the largest meaningful uncertainty. 

Individual analyses of geologic properties (for example, reservoir heterogeneity) and recovery factors of large U.S. accumulations provided analogs that allowed for more accurate 

estimates of these variables and their ranges for oil and gas 

accumulations outside of the United States.
References Cited 11

Schmoker, J.W., 1996, Method for assessing continuous-type 

(unconventional) hydrocarbon accumulations, in Gautier, 

D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds., 

1995 National assessment of United States oil and gas 

resources—Results, methodology, and supporting data: U.S. 

Geological Survey Digital Data Series DDS–30, Release 2 

(CDROM).

Publishing support provided by: 

Denver Publishing Service Center

For more information concerning this publication, contact:

Center Director, USGS Central Energy Resources Science Center

Box 25046, Mail Stop 939

Denver, CO 80225

(303) 236-1647

Or visit the Central Energy Resources Science Center Web site at:

http://energy.usgs.gov/

Box 25286

Denver, CO 80225

1-888-ASK-USGS
12 U.S. Geological Survey Assessment of Reserve Growth Outside of the United States

Appendix 1. Final Report of the AAPG CORE Subcommittee 8-11-09

Final Report of the Sub-Committee for Growth-toKnown Reserves of the Committee on Resource Evaluation 

(CORE) of the American Association of Petroleum Geologists

Introduction

This final sub-committee report is a culmination of the 

work of the AAPG CORE and its sub-committee on Growthto-Known Reserves (GTK) in response to a 2006 request from 

the USGS Energy Resources Team. In that request, the USGS 

asked the CORE peer review and comment about the methods 

used to develop the Growth-to-Known (GTK) prediction factors for future resource assessments.

Members of the CORE initially met and reviewed the 

analysis with the Team in 2006/early 2007. During the course 

of the review, sub-committee recommendations about how this 

work and analysis might be performed were conveyed verbally to Survey personnel. At the 2007 Long Beach meeting, 

a summary report was compiled and reviewed by a quorum 

of the committee. Some members of the sub-committee met 

again with the Team on March 11-12, 2008. This meeting was 

in conjunction with the biennial Fourth Workshop on Reserve 

Growth conducted by the Team, led by Tim Klett. A draft 

report was submitted to the CORE at the 2008 San Antonio 

meeting. A second draft report was circulated prior to the 

3-31-09 teleconference of CORE. Comments were received 

and a discussion of the draft was held.

These previous CORE and Team meetings identified that 

the key steps in the process of determining the GTK multiplication factors are:

1. Data source: North American data is the most lengthy 

and complete data set to develop and test predictive 

methodologies. The sources of these data are IHS, NRG 

Associates, and the EIA OGIFF. 

2. The evaluation process should be clearly described.

3. Test the forecast accuracy and identify the forecast 

drivers.

4. Use abandoned fields as a benchmark.

5. Study a significant number of fields with all methods.

6. The use of stationary time series where the future = the 

past.

7. Perform hind casting against the results of well characterized field studies.

Status of USGS Energy Team GTK 2009

Early in 2009, Tim Klett advised that the USGS GTK 

Assessment Project was proceeding as planned. In 2008, the 

Team published Chapter I of USGS Bull. 2172. The title of 

the report is Geologic Controls on the Growth of Petroleum 

Reserves by Fishman, Turner, Peterson, Dyman, and Cook. No 

other reports on Reserve Growth were published by the team 

this past year. Tim Klett also advised that several of his team 

members will be presenting their GTK work at the June 2009 

Denver AAPG convention. 

 The Team will be using the NRG Associates 2008 

Significant Oil and Gas Fields of the U.S. From this data base 

the Team will combine some NRG fields to “whole fields” 

where there exist boundary issues that create more than one 

data set for a named field. They will construct the reserve 

growth functions using the Lp-Norm Criterion (the renamed 

Monotone Least-Squares Method) and the Modified Arrington 

Methods. As reported in the summary of Chapter I, to add 

more precision to these statistical methods, the USGS Team 

investigated some of the geologic factors that affect oil field 

reserve growth. In this study they identified 10 U.S. formations that possess gross geologic differences as determined 

by environments of deposition. Further they defined various 

categories of reservoirs within these formations on other basis 

such as: porosity and permeability; source rocks; traps and 

seals; structural evolution; and postdepositional history. They 

concluded that “(oil) fields with low production variability 

have the potential for more predictable growth than fields with 

high production variability”. They attribute this conclusion to 

reservoir heterogeneity.

Additionally, they will use Individual Field Analysis 

Method (based on several field studies in the San Joaquin 

Valley, California) on significant “outliers” (big fields). This 

method involves determining probabilistic estimates of inplace hydrocarbons combined with probabilistic estimates of 

recovery factor. From this estimate of ultimate recovery, they 

will subtract cumulative production. The remaining reserve 

estimate can be used to determine future reserve growth. New 

reserve growth functions will be developed by the above 

methods, tested, and if satisfactory, applied to the “outliers” of 

U.S. reservoirs in future assessments.

Also, the USGS Team plans to apply the above statistical 

and field analysis approach for future world assessments using 

the IHS International data base. 
Appendix 1. Final Report of the AAPG CORE Subcommittee 8-11-09 13

Discussion and Recommendations

Key Steps 1 and 2; Data Source and Description of 

Methods; The sub-committee endorses the Team’s use of NRG 

and IHS field data as the most complete available for historical 

growth. We think these data sets, in particular NRG in the U.S., 

will allow the development of the most detailed historical field 

growth functions by year and total field life to date. These are 

the data that most of the industry uses to study the growth of 

field reserves. With the NRG U.S. growth factors as a guide, 

the Team will use the IHS international reserve data, which 

grows more complete each year, for World Assessments.

 The recent (2008) publication of Chapter I, USGS Bulletin 2172, together with the presentations to be given at this 

year’s convention, and at planned biennial Workshops show 

that the process of developing reserve growth functions are 

constantly being refined. The methods are clearly described by 

the Team in these public presentations.

Key Steps 2, 4, and 6; Evaluation, Forecast, and Time 

Series; The sub-committee endorses the use of both the Lp 

Norm (ex-Monotone) and Modified Arrington Methods for 

the statistical development of the field growth functions for 

future assessments. These methods are based on construction 

of a discovery table by either discovery year or year since 

first production, and using the data bases to identify the field 

reserve increases through time. Both methods use this table 

to calculate an annual growth factor and a cumulative growth 

factor. The Modified Arrington method was used to develop 

functions in past U.S. and World assessments.

Additionally, the Team continues to refine the results of 

the forecast methodology by evaluating the geologic factors 

affecting reserve growth. In Bulletin 2172-I, they selected 10 

U.S. formations to investigate the variation of reserve growth 

function in siliciclastic and carbonate reservoirs. The functions 

for these gross categories also were studied by introducing depositional setting, source rock, and post-depositional alteration. 

Further studies of this nature can only help bring more geologic 

insight to what has been mainly a statistical prediction.

The development of the growth functions should continue to use the most recent NRG data in the U.S. Some of the 

abandoned fields’ growth functions while inactive are being 

used as calibration of the predictions. The Team will remove 

“continuous plays” in analyzing the growth of field reserves. 

These continuous accumulations will be treated separately. 

It is worth noting that the USGS has requested the CORE to 

review separately their continuous assessment methodology. 

That work is just commencing.

Key Step 3, Drivers; The sub-committee recommends the 

studies continue to identify the important drivers of growth. 

These drivers may be geologic, technologic, economic, or sociopolitical. Once the drivers have been identified, we suggested 

that the Team look at utilizing graphic presentation “tornado 

charts” to analyze the drivers and show their relative importance. 

Key Step 5 Multiple Methods; The subcommittee endorses 

the use of statistical and field study methods on the big oil field 

“outliers”. The analysis is based on studies of the large mature 

oil fields in the San Joaquin Basin. The method consists of an 

extensive field study that treats large fields as an assessment 

unit. In most mature petroleum provinces, the large or giant 

fields have the most volumetrically significant reserve growth. 

The reserve growth of several large fields will dominate the 

growth potential for the area or province. The field analysis 

involves acquiring the geologic characteristics of the field, 

information on the total resource in-place (OOIP), estimating 

how much of the oil will be recovered by all means, and comparing to known recoverable oil. The goal is to predict a range 

of increases in reserves based on the geology and future development technology. The production history plots are an excellent graphic to demonstrate field growth and relate cumulative 

production to OOIP. The cumulative plots could be extended for 

a forecast period by plotting the estimated growth calculated by 

the various methods. Like the estimates of OOIP, it would be 

a simple matter to place future time events on the graphic that 

might influence the shape of the extended creaming curve. 

Summary

The sub-committee endorses the Energy Resources Science Center use of the statistical methods of the Lp Norm and 

Modified Arrington to develop field growth functions based 

on NRG Associates field data in future National and World 

Resource Assessments. Further, we endorse the continued 

refinement of the methods by the ongoing investigation of 

the effects of formation, reservoir type, and other factors at 

the reservoir level. Also, we support the use of field studies 

of the “big oil fields” to develop growth functions based on 

estimates of OOIP.

The members of the sub-committee wish to thank the 

Team for their co-operation during this review.

I wish to thank the members of the sub-committee for 

their comments on this report.

Lee B Backsen, coordinator

Sub-committee for Growth-to-Known Reserves, AAPG 

CORE committee

Klett and others—U.S. Geological Survey Assessment of Reserve Growth Outside of the United States—Scientific Investigations Report 2015–5091

ISSN 2328-0328 (online)

http://dx.doi.org/10.3133/sir20155091