1995 National assessment of United States oil and gas resources

OVERVIEW OF THE 1995 NATIONAL ASSESSMENT OF POTENTIAL ADDITIONS TO TECHNICALLY RECOVERABLE RESOURCES OF OIL AND GAS-ONSHORE AND STATE WATERS OF THE UNITED STATES

U.S. GEOLOGICAL SURVEY CIRCULAR 1118

Cover. Map of the United States showing regions 1 through 8 (see fig. 3) as defined for this report, 1995 National Assessment of United States Oil and Gas Resources.

By U.S. Geological Survey National Oil and Gas Resource Assessment Team

U.S. GEOLOGICAL SURVEY CIRCULAR 1118

Overview of the 1995 National Assessment of potential additions to technically recoverable resources of oil and gas-onshore and State waters of the United States

Free on application to U.S. Geological Survey, Information Services Box 25286, Federal Center Denver, CO 80225 FIGURES

6. Map of lower 48 States showing location of continuous-type plays for oil and gas in sandstones, shales, and chalks.................................................................................................................................... 10
7. Sketch depicting continuous-type play as a collection of hydrocarbon-containing cells........................................... 11
8. Map of lower 48 States showing areas of coal-bed gas and locations of plays assessed ........................................... 12
9. Distribution of undiscovered technically recoverable conventional oil resources, by region, based on mean estimates for the regions................................................................................................................................... 16
10. Distribution of undiscovered technically recoverable conventional gas resources, by region, based on mean estimates for the regions................................................................................................................................... 16
11. Estimated cumulative probability distributions for undiscovered technically recoverable conventional oil resources of onshore areas and State waters of the United States......................................................................... 17
12. Estimated cumulative probability distributions for undiscovered technically recoverable conventional gas resources of onshore areas and State waters of the United States........................................................................ 17
13. Potential reserve additions for non-associated gas in continuous-type plays as a function of estimated ultimate recovery (EUR) per well ....... ......... ........................................... ... ......... .......... ........... ... ............... 20

TABLES

1. Estimates of national totals for undiscovered technically recoverable conventional oil, gas, and NGL resources; growth of reserves in known fields; technically recoverable resources in continuous-type (unconventional) accumulations; and measured reserves............................................
2. Estimates of undiscovered technically recoverable conventional oil, gas, and NGL resources by petroleum region and province .. .. .. .. .. ... .. .. ........ ... .. .. ... .. ... .. .. .. ...... .. .... .. .. .. .. ... .. .. ............ ...... ....... .. .. ........................ 14
3. Estimated future growth (inferred reserves) of conventional fields as of December 31, 1991 .. ...................... .......... 17
4. Technically recoverable resources estimated for continuous-type plays in sandstones, shales, and chalks, onshore United States.................................................................................................................. 18
5. Technically recoverable resources of gas estimated for continuous-type plays in coal beds, onshore United States................................................................................................................................ 19

UNIT ABBREVIATIONS AND ACRONYMS USED IN THIS REPORT

v

MEMBERS OF THE U.S. GEOLOGICAL SURVEY 1995 NATION/ L OIL AND GAS RESOURCE ASSESSMENT TEAM-Continued

Graphic Data Display ............................................................. Timothy R. Klett Graphics .................................................................................Laura L. Zink

Video Production Producer, Director, Writer ............................................ Jonathan Swinchatt Co-Producer ................................................................. David G. Howell Associate Producer ....................................................... Nick Hardigg Computer Graphics and Animation ............................... Jose Vigil Geological Coordination Alaska Region ..............................................................Kenneth J. Bird Pacific Coast Region ..................................................... Caroline M. Isaacs

Colorado Plateau and Basin and Range Region ............. John A. Grow

Rocky Mountains and Northern Great Plains Region ..... Cornelius M. Molenaar

Midcontinent Region .................................................... Ronald R. Charpentier

West Texas and Eastern New Mexico Region ............... Mahlon M. Ball Gulf Coast Region ........................................................ Christopher J. Schenk Eastern Region ............................................................. Robert T. Ryder Coordinator, Continuous-Type Deposits .................................. James W. Schmoker Geologic Specialist, Continuous-Type Deposits ............. Thomas D. Fouch

Statistics, Continuous-Type Deposits ............................ Robert A. Crovelli Computation, Continuous-Type Deposits ...................... Richard H. Balay Petroleum Engineer ...................................................... Lynn E. Boone

Coordinator, Coal-Bed Gas ....................................................Dudley D. Rice Geologic Specialist, Coal-Bed Gas ................................ Ronald. C. Johnson

Assistant, Coal-Bed Gas .............................................. Thomas M. Finn Resource Specialist, Coal-Bed Gas ............................... Advanced Resources

Geologic Specialist, Gas Hydrates ........................................... Timothy S. Collett Geologic Specialist, Deep Gas ................................................ Thaddeus S. Dyman

Geologic Specialist, Heavy Oil. ............................................... Mark J. Pawlewicz

Geochemical Specialist ........................................................... Jerry L. Clayton

Economics ..............................................................................Emil D. Attanasi

Discovery-Process Models ...................................................... Lawrence J. Drew Scarlet Tang Zenon C. Valin David Vaughan

Alice A. Springfield Joseph T. Springfield

International, Inc.

Joseph R. Hatch Michael D. Lewan James G. Palacas

John D. Grace (consultant) Keith R. Long

Richard F. Mast Vll

MEMBERS OF THE U.S. GEOLOGICAL SURVEY 1995 NATIONAL OIL AND GAS RESOURCE ASSESSMENT TEAM-Continued MEMBERS OF THE U.S. GEOLOGICAL SURVEY 1995 NATIONAL OIL AND GAS RESOURCE ASSESSMENT TEAM-Continued

Province Geologists-Continued This report summarizes the results of a 3-year study of the oil and gas resources of onshore areas and State waters of the United States by the U.S. Geological Survey (USGS). A parallel study of the Federal offshore is being conducted by the Minerals Management Service (MMS).

Assuming existing technology, there are approximately 110 billion barrels of technically recoverable oil onshore and in State waters. This includes measured (proved) reserves, future additions to reserves in existing fields, and undiscovered resources.

The technically recoverable conventional resources of natural gas in measured reserves, future additions to reserves in existing fields, and undiscovered accumulations equal approximately 715 trillion cubic feet of gas.

In addition to conventional gas resources, the USGS has made an assessment of technically recoverable resources in continuous-type (largely unconventional) accumulations. We estimate about 300 TCFG (trillion cubic feet of gas) of technically recoverable natural gas in continuous-type deposits in sandstones, shales, and chalks, and almost 50 TCFG of technically recoverable gas in coal beds.

The total technically recoverable oil and gas resource base onshore and in State waters of the United States is listed in table 1 and shown on figures 1 and 2.

The purpose of the National Oil and Gas Resource Assessment Project is to develop a set of scientifically based hypotheses concerning the quantities of oil and gas that could be added to the measured (proved) reserves of the United States.

The word assessment sometimes has the connotation of an inventory. But this is not the case in this study. The quantities being evaluated here are largely unknown. This assessment is an attempt to bound the uncertainties concerning potential additions to oil and gas reserves under specified conditions. As such, the assessment consists of a set of

INTRODUCTION

constructs, based on the best information and theory available to the USGS scientists charged with this effort.

The U.S. Geological Survey has occasionally conducted assessments of the oil and gas resources of the United States since shortly after the tum of the century. Each successive assessment is a refinement of previous work. Sy~tematic National Assessments have been conducted more regularly since 1975. In 1982, the Minerals Management Service was formed and given responsibility for resource evaluation in the Federal offshore areas of the United States. Th~ USGS retained responsibility for onshore areas and State waters. In 1991, the two organizations (USGS and MMS) began their second joint study of the oil and gas resources of the United States. This report summarizes the results of the U~l}S part of that study and reports estimates of potential add :tions to reserves onshore and under State waters of the Unite1 States. Documentation for this assessment is available on the CD-ROM that supports this report (Gautier and others, 1995).

The previous USGS/MMS assessment (Mast and others, 1989) encompassed estimates of both technically recoverable and economically recoverable resources. Th~ present report concerns only technically recoverable reso·rrces. A parallel study concerns the economic evaluation of the resources described in this report. The geological assessment of technically recoverable resources makes no ae~mpt to predict at what time or what part of potential addW0ns will be added to reserves. For the National Assessment, resources and potential reserve additions are evaluated rega""dless of political, economic, and other considerations.

The onshore and State water areas of the United States were divided into eight regions consisting of 71 vrovinces (fig. 3). These regions and provinces are similar, but not identical, to those addressed by U.S. Geological Survey Circular 860 (Dolton and others, 1981) and the U.S. De"Jartment of the Interior report from the previous National Assessment of oil and gas resources (Mast and others, 1989). Within these provinces, about 560 plays were assessed, of which about 100 were in continuous-type deposits; the remainder were hypothetical and confirmed conventional plays. 1.9

Figure 1. Technically recoverable oil resources of the United gas; BCFG, billion cubic feet of gas. States. exclusive of Federal offshore. BBO, billion barrels of oil; MMBO, million barrels of oil.

The estimates presented in this document reflect USGS understanding as of January 1, 1994, and are intended to capture the range of uncertainty, to provide indicators of the relative potential of various petroleum provinces, and to provide a guide useful in considering possible effects of future oil- and gas-related activities within the United States.

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Figure 2. Technically recoverable gas resour.es of the United States, exclusive of Federal offshore. TCFG, tri1lion cubic feet of

COMMODITIES ASSESSED

The commodities considered in this st''dy were crude oil, natural gas, and natural gas liquids that can be expected to be produced from the subsurface through a well. Most heavy oil deposits were assessed as convent:'Jnal resources. Specifically excluded from consideration we~e gas dissolved

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in geopressured brines and resources in tar deposits and oil shales. Gas in clathrate structures (gas hydrates) were not assessed as technically recoverable resources; however, a chapter concerning these in-place volumes of gas is included in the supporting CD-ROM (Gautier and others, 1995). Specifically included in this assessment were technically recoverable gas from low-permeability "tight" sandstone reservoirs, gas and oil from fractured shale reservoirs, and coal-bed gas. The systematic inclusion of unconventional resources marks a significant departure from previous USGS assessments.

Crude oil, as considered in this assessment, is a natural liquid consisting mainly of a mixture of complex hyd-ocarbon molecules. Natural gas is a mixture of hydrocarbon gases, mainly methane, and certain non-hydrocarbon gases such as carbon dioxide, hydrogen sulfide, nitroger. and helium. This analysis assessed hydrocarbon gases, although minor amounts of non-hydrocarbon gases may be included. Natural gas liquids (NGL) are the heavierhomologs of methane, which are in the gas phase under reservoir pressure and temperature conditions. NGL includes those portions of the reservoir gas that are liquefied at the surface in various field facilities and in gas-processing plants. NGL commonly includes propane, ethane, butane, pentane, natural gasoline, and condensate.

ASSESSMENT CATEGORIES

Previous USGS assessments focused on undiscovered conventional accumulations of oil and gas and additions to reserves in known fields. This assessment is broader in scope because it considers three categories of resources: (1) undiscovered conventional accumulations of oil and gas, (2) future additions to reserves of known fields, and (3) oil and gas in continuous-type accumulations (largely equivalent to ""unconventional" categories of other analysts).

UNDISCOVERED CONVENTIONAL ACCUMULATIONS

Undiscovered conventional accumulations of oil and gas are the traditional fare of the oil and gas industry and have been the focus of most previous USGS oil and gas assessments. These resources include those postulated to exist outside known fields or accumulations and that, if found, could be extracted using traditional development practices. These accumulations generally exist as discrete accumulations, which are usually, but not invariably, defined, controlled, or limited by hydrocarbon/water contacts. Undiscovered accumulations are shown in the right third ofthe McKelvey box (fig. 4 ). Undiscovered technically recoverable accumulations, those assessed in this report, are within the hachured area shown on figure 4.

Figure 4. Diagrammatic representation of petroleum resource classification (modified from the U.S. Bureau of Mines and U.S. Geological Survey, 1980). The figure ("'McKelvey box") represents total resource endowment. Area inside heavy bord::r in upper center and right represents technically recoverable resources that are estimated in this study.

INFERRED RESERVES (RESERVE GROWTH)

Inferred reserves (reserve growth) include those resources expected to be added to reserv~s as a consequence of extension of known fields, through revisions of reserve estimates, and by additions of new pools in discovered fields. Also included in this category are resources expected to be added to reserves through application of improved recovery techniques. This category thus includes both the "indicated reserves" and the "inferred reserves" described in earlier USGS assessment publications (e.g., Mast and others, 1989). Predictions of reserve growth refer to fields found before 1992 (the date of most reserve data used in this report). The analysis of reserve growth in discrete conventional accumulations is based on the proprietary Oil and Gas Integrated Field File (OGIFF) of the Energy Information Administration (EIA). Inferred reserves are shown in the stippled area of the middle third of the McKelvey box (fig. 4).

CONTINUOUS-TYPE (UNCONVENTIONAL) ACCUMULATIONS

Continuous-type (unconventional) acc·1mulations are, for the purposes of this assessment, defined to include those oil and gas resources that exist as geograph;r;ally extensive accumulations that generally lack well-defined oil/water or gas/water contacts (fig. 5). This geologically grounded definition provides a set of consistent criteria to 1,~ applied in the determination of whether a specific accumulation is or is not conventional. This geologic definition intentionally avoids the regulatory criteria of the Federal Ene-:-gy Regulatory Commission (FERC) designations and does not rely on any specific permeability as a defining criterion. Included in this

TERMINOLOGY

Figure 5. Geologic setting of continuous-type gas and oil accumulations relative to discrete accumulations in structural or stratigraphic traps.

ments (e.g., Mast and others, 1989): "indicated reserves" and "inferred reserves."

Indicated reserves.-That part of identified oil resources in known productive teservoirs in existing fields in addition to measured reserves that are expected to respond to improved recovery techniques. For this report, indicated reserves are included as part of inferred reserves.

Barrels of oil equivalent (BOE).-Gas volume that is expressed in terms of its energy equivalent in barrels of oil. For this assessment, 6,000 cubic feet of gas equals 1 barrel of oil equivalent (BOE).

Gas-oil ratio (GOR).-A verage ratio of associated-dissolved gas to oil; a point estimate of the volume of gas (in cubic feet) dissolved in oil or otherwise associated with a barrel of oil in known or postulated oil accumulations. As in the most recent National Assessment (Mast and others, 1989), an accumulation with a GORin excess of 20,000 is considered a gas accumulation.

NGL to non-associated gas ratio.-The volume of natural gas liquids (in barrels) contained in 1 million cubic feet of gas in a known or postulated gas accumulation.

NGL to associated-dissolved gas ratio.-The volume of natural gas liquids (in barrels) contained in 1 million cubic feet of associated-dissolved gas in a known or postulated oil accumulation.

Field.-An individual producing unit consisting of a single pool or multiple pools of hydrocarbons grouped on, or related to, a single structural or stratigraphic feature.

Accumulation.-A single oil or gas deposit as defined by the trap, charge, and reservoir characteristics of the play.

Play.-A play is a set of known or postulated oil and (or) gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, migration pathway, timing, trapping mechanism, and hydrocarbon type.

Play area.-The two-dimensional plan extent over which a play concept is considered to be valid and within which all known accumulations and potential for undiscovered accumulations or other additions to reserves within the play exist.

Play attributes.-Geologic characteristics that describe principal properties of and necessary conditions for the occurrence of oil and (or) gas accumulations of the minimum size (1 MMBO [million barrels of oil] or 6 BCFG [billion cubic feet of gas]) within the defined parameters of a play. Although many combinations of individual underlying elements are possible, three attributes were considered in the evaluation of play risk in this assessment. These attributes are as follows:

1. Charge.-The occurrence of conditions of hydrocarbon generation and migration adequate to cause an accumulation of the minimum size. Included in this attribute are subsidiary elements, including existence of source rocks with sufficient organic matter of the appropriate composition, appropriate temperature and duration of heating to generate and expel
2. Reservoir.-The occurrence of reservoir rocks of
3. Trap.-The occurrence of those structures,

Play probability.-Play probability represents the product of the probabilities of the three play attributes considered in this assessment (charge, reservoir, and trap). It is an estimate, expressed as a decimal fraction, of the chance that oil or natural gas exist within the particular play. For recoverable resources, the play probability represents the likelihood that technically recoverable quantities of oil or natural gas exist in at least one accumulation of the minimum size (1 MMBO or 6 BCFG) in the area being assessed.

Conditional estimates.-Sizes, numbers, or volumes of oil or natural gas that are estimated to exist in an area, assuming that they are present. Conditional estimates, therefore, do not incorporate the risk that the area may be devoid of oil or natural gas.

Risked (unconditional) estimates.-Resources that are estimated to exist, including the possibility that the area may be devoid of oil or natural gas. Statistically, the risked mean may be determined through multiplication of the mean of a conditional distribution by the related probability of occurrence. Resource estimates presented in this report are risked estimates.

Cumulative probability distributions for resource estimates.-Graphical depictions of estimated resource volumes presented with associated cumulative probabilities of occurrence. These distributions are used to derive the 95 percent, 5 percent, and mean resource levels reported in this publication: a low case, with a 95 percent probability of that amount or more occurring (a 19 in 20 chance); a high case, with a 5 percent probability of that amount or more occurring (a 1 in 20 chance); and a mean case representing an arithmetic average of all possible resource outcomes weighted by their probabilities.

The USGS portion of the National Assessment Project relies largely on data that are either published or commercially available. Some USGS geologic data are from in-progress studies and have not necessarily been published. sufficient quantities of oil and (or) gas, and timing of expulsion of oil and gas from source rocks appropriate for filling available traps.

sufficient quantity and quality to permit the containment of oil and (or) gas in volumes sufficient for an accumulation of the minimum size.

pinch-outs, permeability changes, and similar features necessary for the entrapment of oil and (or) gas in at least one accumulation of the minimum size. Included in this attribute are existence of seals sufficient for entrapping hydrocarbons and capable of holding oil and gas accumulations during appropriate ranges of geologic time.

DATA SOURCES

In several areas. drilling and production information was especially sparse or unreliable. Seven major data sources were used in this assessment:

1. USGS geologic data. both published and unpublished, were used in the development of play definitions, play boundaries, and in the analysis of geologic information concerning undiscovered conventional oil and gas accumulations and possible future developments in continuous-type oil and gas accumulations.
2. The Significant Oil and Gas Fields of the United States file (NRG) is a database commercially available from NRG Associates, Inc., which includes reserves, cumulative production, and various other types of information for most oil and gas fields of the United States larger than 1 million BOE (NRG Associates, Inc., 1993 and 1994 ). The NRG release current as of December 31, 1992 (NRG Associates, Inc., 1993 ), was a major source of reservoir-level information for this assessment.
3. The Well History Control System (WHCS) is a commercially available database of computerized drilling and completion data from almost 2.5 million exploratory and development wells available from Petroleum Information Corp. (PI). Data were used to construct various exploration- and development-intensity maps and plots and statistical analyses of drilling and discovery. For most of the areas assessed, the 1993 and 1994 versions of WHCS were used (Petroleum Information Corp., 1993 and 1994). In most provinces, the WHCS contains essentially all wells drilled. However, in certain areas, especially the Eastern Region, California, and parts of Oklahoma and Louisiana, drilling information is incomplete.
4. Petroleum Information Corp. production data files, including monthly. yearly, and cumulative production information from numerous recent wells in the United States, were employed to construct decline curves and estimated ultimate recovery (EUR) distributions used in the analysis of potential additions to reserves from continuous-type deposits (Petroleum Information Corp., 1994).
5. Energy Information Administration (EIA) Oil and Gas Integrated Field File (OGIFF) is a proprietary file of field-level reserves and production information. The data in OGIFF are collected according to legal mandate by the Department of Energy from operators of oil and gas fields of the United States. This file, which includes yearly estimates of reserves from fields in the United States was used mainly as a database for the prediction of potential additions to reserves of known fields. In a few areas of sparse data, especially Oklahoma and the Appalachian region, the OGIFF was used to supplement NRG for estimation of field sizes. Because of the sensitivity of the OGIFF data, however, the output provided in this report has been generalized, rounded, or elirrinated to avoid releasing any of those data. This is p"'rticularly apparent in the output for provinces 055 (Nemaha Uplift), 056 (Forest City Basin), 060 (Ch~rokee Platform), and 067 (Appalachian Basin).
6. The Energy Information Administration 1993 Annual Report (Energy Information Administration, 1994) is the basis of all measured (proved) reserve information reported here.
7. Other data, including publications, State records, proprietary energy company reports, and other sources, were used by individual province geohgists. Contributions of time, information, and insight by numerous individuals working in the U.S. oil and gas industry and State geological surveys were pmicularly helpful in play definition. In certain area~ of the country where drilling, completion, reserve, or production data are sparse, absent, or unreliable, province geologists devoted significant effort to compiling original databases for reservoir- and field-level information. This was particularly the case for Oklahoma, the States of the Appalachian Basin, Louisiana, and California.

AREAS OF STUDY

The oil and gas resources of the United State2 were evaluated on the basis of interpretation of the geolOK' of its petroleum provinces. For this study, the United Stat~s was divided into eight regions, which, in tum, encompas~ed 71 separate provinces. Regional and provincial boundaries are illustrated in figure 3. The regions are basically geographic but are intended to provide broad geologic groupings of provinces. The provinces themselves are based on natural geologic entities and may include a single dominant structural element or a number of contiguous elements. The provinces are named for structural or geographic features within their boundaries.

The regions and provinces used in this study are generally similar to those used in recent USGS assessments, with a few changes. Notable among these changes are the consolidation of the provinces of Alaska into a simpler three-province scheme, the merging of the Atlantic Coast and Eastern Interior into a single region, the inclusion and assessrent of Florida with the rest of the Gulf Coast, and the movenent of the boundary between the Pacific Coast Region and tl'~ Colorado Plateau and Basin and Range Region along mo ..e geologically defined boundaries, such as the San Andreas fault in southern California. A few other smaller changes have also been made and are described in the supporting play-level documentation included in the CD-ROM (Gautier and others, 1995).

METHODS OF ASSESSMENT

Distinct methodologies were used for assessment of large and small conventional accumulations, continuous-type (unconventional) accumulations, and field growth. The following brief summaries of methodology are provided for convenience, but for a more detailed treatment, the interested reader should refer to the supporting CD-ROM (Gautier and others, 1995).

UNDISCOVERED CONVENTIONAL ACCUMULATIONS

The assessment of undiscovered conventional resources was conducted at the play level. The methodology employed required estimation of the sizes, numbers, and types of undiscovered conventional accumulations of oil and gas and estimation of play risk. Numerous techniques were employed to make these estimates. These include reservoir-simulation modeling, discovery-process modeling, application of analogs, and spatial analysis. The method provides for a systematic integration and analysis of the geologic factors essential for the occurrence of oil and gas, a thorough documentation of the analysis, and an assessment containing information on the size, depth distribution, and number of hydrocarbon accumulations, as well as the quantity of estimated resources. Two principal categories of conventional plays were assessed: confirmed plays and hypothetical plays.

A play was considered confirmed if one or more accumulations of the minimum size (1 MMBO or 6 BCFG) had been discovered in the play. Confirmed plays were commonly assessed by extrapolation or approximation based on sizes, numbers, depths, drilling history, and other properties of known accumulations.

Hypothetical plays were those that were identified and defined based on geologic information but for which no accumulations of the minimum size had, as yet, been discovered. In contrast to confirmed plays, these hypothetical plays cannot, of course, be analyzed based on trends of known accumulations. Rather, properties of undiscovered accumulations must be postulated based on other types of information, including reservoir simulation and application of analog data sets from areas of similar geologic properties and known oil and (or) gas accumulations. Hypothetical plays characteristically carry a much broader degree of uncertainty, as recorded in the range of possible resources reported, than do confirmed plays. In addition to the greater range of reported resources, virtually all hypothetical plays carry a play-level probability of less than one.

It is by no means certain that any given play will contain an undiscovered accumulation. In order to express this uncertainty, a risking structure was develop~d based on the three geologic play attributes of charge, rese--voir, and trap.

Estimates of the probability of occurrence for each of the three attributes were expressed as de~imal fract~ons between zero and one. The product of the three values is the play probability (risk= 1 -probability). Because the three play attributes are not necessarily indeperdent, care was taken not to apply multiple risks resulting from a single cause or event.

In addition to the strictly hypothetical pays, the risking structure was also occasionally applied to intensely explored and largely exhausted plays within which the existence of yet another accumulation of the minimum size was uncertain. When calculating resources for hypothetical and largely exhausted plays, the play probability is app.ied against the product of the size and number of undiscovered accumulations estimated to exist in the play. For confirmed plays, other than those that were nearly exhausted, the play probability was one. Plays were not quantitatively assessed when the play probability was 0.10 or less.

For the purposes of this assessment, as in the previous USGS assessment (Mast and others, 1989), a model of the size-frequency distribution of the populatior of oil and (or) gas accumulations was assumed. The Truncated Shifted Pareto (TSP) model describes a "J -shaped" distribution in which ever-increasing numbers of accumulations occur in successively smaller size classes. The distribution is called shifted because it has been statistically moved to have its origin at the minimum accumulation size, in thi~ case 1 MMBO or 6 BCFG. The TSP distribution is referred to as truncated because, for the purposes of analysis, the distribution is cut off at the size of the largest accumulation in the distribution. For a detailed discussion of the TSP distribution, see Houghton and others (1993 ).

An important use of the TSP distribution in this assessment was to provide a guide to province geologists in their development of estimates of undiscovered ac~umulations. A TSP distribution was fit to the population of accumulations known from each play and, in chronological order of discovery, to the first third of the accumulations discovered, the second third discovered, and the last third. The results of these fitted populations were provided to province geologists and review panels as source information regarding the changing size distribution of accumulations within the play as a function of time.

The TSP distribution was also commonly used to model the field-size distribution of the undiscovered population. Unless the province geologist had another sp~cific model in mind, a TSP was fit to the estimated median size and to the estimated largest accumulation expected at a 5 percent probability within the postulated population of undiscovered accumulations, also considering the estimated limiting maximum size. The resulting TSP distribution was used to determine the remaining fractiles of the size distribution of the undiscovered population.

Based on sizes and numbers of accumulations of oil and (or) non-associated gas estimated as undiscovered in each play, resources of each of these commodities were calculated using a Monte Carlo simulation technique and application of play risk. Estimates of undiscovered resources are presented as a range of values corresponding to probabilities of occurrence in order to express the uncertainty inherent in assessment of unknown quantities. The input variables of accumulation sizes and numbers are themselves expressed as density functions of uncertain quantities. The resulting cumulative probability distributions represent the estimated quantity of undiscovered resources-from these distributions, various fractiles (including the low (Fg5), the high (Fs), and the mean estimates) are obtained.

Resources of gas associated with or dissolved in oil (associated-dissolved gas) were derived through use of estimated GOR's as applied to the calculated oil. Similarly, estimates of NGL were separately calculated for associated and non-associated gas by applying ratios provided by the estimators. Total gas and NGL at the play level were determined through summation.

To arrive at the estimated quantity of undiscovered resources for large areas, such as provinces, regions, or the Nation as a whole, distributions estimated for basic assessment units were progressively aggregated, with geological dependency incorporated at each level. In order to aggregate plays within provinces, geologic dependencies between plays were established for the three basic attributes of charge, reservoir, and trap. Province geologists determined for each pair of plays in their province whether the correlation was high (0.9).- moderate (0.5), or low (0.1) for each attribute. Thus, to determine the degree of dependency of plays A and B, if highly correlated with respect to charge (0.9), poorly correlated with respect to reservoirs (0.1), and moderately correlated with respect to trap (0.5), the mean correlation value was calculated to be (0.9+0.1 +0.5)/3, or 0.5. This value of dependency would be used in aggregating plays A and B. For the aggregation of province-level estimates, the provinces within each region were assigned a dependency of 0.5. In aggregation of regions for a national total, regions were considered to be independent.

RESERVE GROWTH (INFERRED RESERVES)

Measured reserves of oil or gas are the estimated quantities that analysis of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known fields under existing economic and operating conditions. This definition of reserves more often leads to underestimates than to overestimates of the remaining resources in a known field. The difference between proved reserves in known fields and remaining recoverable resources in known fields is here called inferred reserves.

In the onshore areas and State water areas of the lower 48 States, the reestimation of reserves in old fields each year has added far more to measured (proved) reserves than have new discoveries. Therefore, the future growth of discovered fields will be an important source of additions to reserves. The estimate of this growth for conventional fields is provided as inferred reserves. Growth of reserves in continuous-type deposits is included within the estimates of technically recoverable resources from those types of deposits.

The Energy Information Administration has created the Oil and Gas Integrated Field File (OGIFF), which lists the estimated size (cumulative production plus proved reserves) for each oil and gas field in the United States. Fifteen estimates of size, as estimated in each of the 15 years from 1977 through 1991, are given for each field. These are the basic data from which the pattern of field growth is calculated.

For the purpose of estimating inferred reserves, the lower 48 States were divided into five areas, and the fields in these areas were divided into oil fields and gas fields. The five areas consisted of the assessment Regions 2, 3 and 4, 5 and 7, 6, and 8 (see fig. 3). Growth functions were calculated for each area for the primary commodities, i.e., oil in oil fields and gas in gas fields. The secondary commodities (associated-dissolved gas and NGL) were assumed to grow proportionally to the primary commodities. Alaska growth was calculated using national growth functions for oil and gas because there were inadequate data to construct specific growth functions for that region.

CONTINUOUS-TYPE ACCUMULATIONS

Continuous-type accumulations may have spatial dimensions approaching those of plays and cannot be represented in terms of discrete, countable entities delineated 3::tTl

c:::

m0

z0

Yj by downdip hydrocarbon/water contacts, as are conventional accumulations. The identification of a continuous-type hydrocarbon accumulation is based on its geologic setting and does not incorporate somewhat ephemeral criteria, such as specified low API gravity, low permeability ("tight"), special regulatory status, or need for unusual engineering techniques. A low-permeability reservoir may or may not be a continuous-type accumulation.

The geologic setting typical of continuous-type accumulations is illustrated by figure 5. Common geologic characteristics of a continuous-type accumulation include occurrence downdip from water-saturated rocks, lack of obvious trap and seal, crosscutting of lithologic boundaries, large areal extent, relatively low matrix permeability, abnormal pressure (high or low), and close association with source rocks. Aspects of hydrocarbon production common to a continuous-type accumulation include a large in-place hydrocarbon volume, a low recovery factor, and a heterogeneous "hit-or-miss" character for production rates and ultimate recoveries of wells.

In the case of continuous-type accumulations, the distinction between undiscovered resources and inferred reserves is blurred. The locations of continuous-type accumulations are commonly well known (implying inferred reserves) (fig. 6), but hydrocarbon estimates may be broadly dependent on geologic knowledge and theory (implying undiscovered resources).

The first step of the assessment procedure is to represent the continuous-type accumulation by a play or plays. As in the case of conventional accumulations, geologic risk is assigned to each play. A gas-to-oil ratio of 20,000 cubic feet of gas per barrel of oil separates gas plays from oil plays.

It is advantageous to envision the hydrocarbons of a continuous-type accumulation as residing areally in cells. A play is then regarded as a collection of cells (fig. 7). The cell area or size is equal to the median spacing, as dictated by drainage area, expected for wells of the play. Virtually all cells in a continuous-type accumulation are capable of producing some hydrocarbons. For purposes of this assessment, however, a productive cell is one for which production from the play is formally reported. An untested cell is one in which the play in question has not been evaluated by a well.

The second step of the assessment procedure is to estimate the number of untested cells in a play and the fraction of untested cells expected to become productive (success ratio). Realistic consideration of the uncertainties associated with the number of untested cells in a play usually leads to a substantial range between the minimum and maximum number of untested cells. Therefore, the number of untested cells is treated as a probability distribution.

Figure 7. Sketch depicting continuous-type play as a col'ection of hydrocarbon-containing cells. Circles represent cells that tave been evaluated by wells; evaluated cells are either productive (solid circles) or nonproductive (open circles). Remaining cells are untested.

The third step of the assessment procedure is tc establish a probability distribution for estimated ultimate recovery (EUR) for untested cells of the play that are expe,~ted to become productive. This distribution provides a reference model for production from cells yet to be drilled. Of course, this statistical model provides no insight as to which u"'tested cells are expected to become productive.

Finally, the combination of play probability, ~uccess ratio, number of untested cells, and EUR probability distribution yields the potential additions to reserves expected for the continuous-type play. The in-place hydrocarbon volume is not us~d in this assessment procedure.

A salient aspect of the assessment method is th!'l.t production and development patterns of the past are projected into the future. No assumptions regarding technology or economics are incorporated into the model.

The information required for the assessment of continuous-type accumulations is supplied by earth scientists who are knowledgeable about the petroleum geology and engineering of the province under consideration. These regional experts complete a data form for each play, which is the source of the input data required for assessment -compntation programs. In those few cases in which there were seriously discordant views regarding a continuous-type play, the opinion of the province geologist has been used.

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Figure 8. Map of lower 48 States showing areas of coal-bed gas and locations of plays assessed.

(2) correlations could assume any value between 1.0 and -1.0, and (3) dependencies at all aggregation levels were estimated in the same manner as that described for conventional plays.

The unit of assessment of potential additions to reserves of coal-bed gas was the play. Coal-bed gas plays were defined as areas within widespread, commonly basin-wide, accumulations that have similar conditions of generation, accumulation, and production of gas (fig. 8). The factors that define the plays include coal-bed thickness, heterogeneity, depth, and composition; seals; gas content; gas composition; permeability; pressure regime; structural setting; and hydrology; as well as conventional trapping mechanisms. It is postulated that recoverable coal-bed gas reserves are generally restricted to present-day depths of burial of 500 to 6,000 ft because of gas content and formation permeability.

The assessment of potential additions to reserves of coal-bed gas was based on the estimation of the number and estimated ultimate recoveries (EUR's) of untested cells within each assessed play. The procedure is similar, in part, to that used in assessment of continuous-type accumulations in sandstones, shales, and chalks that is described above and by Schmoker in the supporting CD-ROM (Gautier and others, 1995). However, the coal-bed gas assessment relied heavily on production forecasting using a reservoir simulator. A range of EUR's and production rates of both gas and water were projected on a "per-well" and "per-foot-of-coal" basis for each play. The reservoir simulator was used because: (1) coal-bed gas accumulations are in early stages of development, and long-term production histories are generally not available, and (2) other methods, such as decline curve analysis and material balance are not adequate for expressing the complex movement of gas and water in coal.

Input parameters for modeling in this study were based on actual data, analog information, and judgments of geologists and engineers. To resolve some of the data uncertainty, particularly for key reservoir parameters such as gas content and permeability, well production was compared to that predicted by the simulator for selected wells. This process is known as "history matching" because the initial data estimates commonly are adjusted to obtain simulated results that are characteristic of actual well performance.

For most plays, long-term production from vertical wells, with a variety of completion techniques, was forecasted. In mining areas, production from wells was modeled. The EUR's predicted by reservoir simulation were used in conjunction with coal thicknesses to establish an EUR probability distribution for potentially productive, untested cells in each play. Seven fractiles (lOOth, 95th, 75th, 50th, 25th, 5th, and Oth) were provided for the computational model, and the distribution was assumed to be lognormal. For plays in which no reservoir simulation was performed, EUR's on a per-foot-of-coal basis from analog plays were scalect and a similar procedure was used. The assessment of coal-b~d gas is based on existing technology.

TECHNICALLY RECOVERABLE CONVENTIONAL RESOURCES

Approximately 460 conventional plays were defined for the 1995 National Assessment, of which 373 were assessed. Of these assessed plays, 290 were confirmed plays and 83 were hypothetical plays.

We estimate the undiscovered technically recoverable conventional oil resources of the United States to rang~ from 23.5 BBO (billion barrels of oil) at a 95 percent prob<~bility to as much as 39.6 BBO at a 5 percent probability. The mean estimate of undiscovered conventional oil is 30.3 BE 0. Of this amount, approximately 6.4 BBO exist in accumulations smaller than 1 MMBO. Estimated conventional oil res')urces are listed by region and by province in table 2 and illustrated in figure 9.

Undiscovered technically recoverable conventional gas resources, including both non-associated gas and associated-dissolved gas, range from 207.1 TCFG at a 95 rercent probability to as much as 329.1 TCFG at a 5 percent probability. The mean estimate of undiscovered convention1.l natural gas is 258.7 TCFG. Of this amount, approximately 45.2 TCFG exist in accumulations smaller than 6 BCFG. Estimated conventional gas resources are tabulated by region and by province in table 2 and illustrated in figure 10.

We estimate the undiscovered technically recoverable resources of natural gas liquids in conventional accumulations to range from 5.8 BBNGL (billion barrels of natu~al gas liquids) at a 95 percent probability to as much as 8.9 BBNGL at a 5 percent probability. The mean estimate of undiscovered NGL is 7.2 BBNGL. Estimated NGL resources a~e tabulated by region and by province in table 2.

Figures 9 and 10 show, by use of mean values, the distribution of undiscovered resources of oil and gas by region. We estimate that approximately 28 percent of the undiscovered oil resources and 26 percent of the undiscoven~d gas resources exist in Alaska (Region 1-see fig. 3 ); arproximately 13 percent of undiscovered oil resources and 5 Fs Fs Fs percent of undiscovered gas resources exist in California and the remainder of the Pacific Coast (Region 2-see fig. 3 ); and 18 percent of the undiscovered oil resources and 38 percent of the undiscovered gas resources exist in the Gulf Coast (Region 6-see fig. 3). Of the remaining undiscovered resources, approximately 41 percent of the oil resources and 31 percent of the natural gas resources are distributed among the remaining five regions (Regions 3, 4, 5, 7, and 8-see fig. 3).

Figure 9. Distribution of undiscovered technically recoverable conventional oil resources, by region (see fig. 3). Based on mean estimates for the regions. BBO, billion barrels of oil.

Undiscovered conventional oil and gas resources are estimated within ranges of probability. Estimated national totals for undiscovered conventional oil and gas resources of the onshore and State waters of the United States are listed in table 1 and illustrated in figures 11 and 12. Ranges of probability for resources by region and province are listed in table 2.

INFERRED RESERVES (GROWTH OF CONVENTIONAL FIELDS)

Growth functions were calculated and applied to the 1992 estimates from the OGIFF data for oil and gas for each year of discovery for each region and commodity. The results are summarized in table 3. It is estimated that 60.0 BBO will be added to oil reserves and 322.0 TCFG to gas reserves during the 80 years following 1991.

TECHNICALLY RECOVERABLE RESOURCES IN CONTINUOUS-TYPE DEPOSITS

Sixty-one continuous-type plays wer1~ defined for the 1995 National Assessment, of which 47 w~re assessed. Of the assessed plays, 34 were gas plays and 13 were oil plays. The predominant reservoir rock is sandstone for 32 plays, shale for 20 plays, and carbonate for 9 plays. Although the plays are geographically diverse, none are in Alaska and none extend into State offshore waters (fig. 6).

Technically recoverable hydrocarbor resources from continuous-type accumulations are substantial (table 4). Estimated natural gas resources range bet'veen 219 TCFG (95th fractile) and 417 TCFG (5th fractile), with a mean of 308 TCFG; those for crude oil range betvreen 1.5 and 2. 7 BBO, with a mean of 2.1 BBO; those for n:ttural gas liquids range between 1.1 and 3.5 BBNGL, with a mean of 2.1 BBNGL.

Major coal-bearing areas in the lower 48 States are shown in figure 8. The in-place resources of coal-bed gas are determined by the product of the coal tonn"'ge and gas content. Although the in-place resources are very large for this type of accumulation, the main concern is recoverability. Figure 8 also shows the location of areas within which potential additions to reserves of coal-bed gas were quantitatively assessed for 39 plays. For this assessment, technically recoverable resources of coal-bed gas for the lower 48 States are estimated to range from 42.9 TCFG to 57.6 TCFG, with a mean estimate of 49.9 TCFG. Estimates for individual provinces and regions are presented in table 5.

Figure 10. Distribution of undiscovered techrically recoverable conventional gas resources, by region (see fig. 3). Based on mean estimates for the regions. TCFG, trillion cubic f~et of gas.

Figure 12. Estimated cumulative probability distributions for unFigure 11. Estimated cumulative probability distributions for undiscovered technically recoverable conventional gas resources of discovered technically recoverable conventional oil resources of onshore areas and State waters of the United States. onshore areas and State waters of the United States.

DISCUSSION AND COMPARISON OF RESULTS WITH THE PREVIOUS USGS/MMS ASSESSMENT

On the basis of existing technology and geologic concepts, there are, in total, approximately 110 billion barrels of technically recoverable oil, largely in existing and undiscovered conventional accumulations onshore and in State waters of the United States-this includes measured reserves and inferred reserves in existing fields as well as undiscovered accumulations. This number is significantly larger than the comparable number of about 78 billion barrels of technically recoverable oil recognized at the time of the previous assessment (Mast and others, 1989). In 1993, the United States produced about 2.4 BBO, approximately 50 percent of national consumption. At the time of the last Na6:mal Assessment (1989), yearly production stood at app'"oximately 2.5 BBO. The significant increase in technisally recoverable oil reported in this assessment largely reflects anticipated increases in reserves of known fields.

Estimated mean amounts of undiscovered convenfonal oil resources onshore and in State waters of the United States are about 10 percent lower than those reported in the 1989 National Assessment of oil and gas resources (Mast and others, 1989) (30.3 BBO vs. 33.3 BBO, respectively). Sine~ the last assessment, more than 2 BBO has been discovered in new fields, thereby reducing previous undiscovered qmmtities by that amount. The change in estimated conventional oil resources is also due to a reduction in our estimates of the undiscovered oil resources in part of northern Alaska.

Our understanding of the thermal history and geoc1,~m ical makeup of the rocks of northern Alaska leads us to expect more natural gas and less oil in the foothills regio'"', an area that includes most of the Arctic National Wildlife Refuge (ANWR) as well as the southern part of the National Petroleum Reserve in Alaska. This information comes from results of drilling the Tenneco Aurora well, located just offshore from the ANWR; results of a major USGS study that summarized all thermal data in Alaska; and USGS studi ~s in the foothills region (which combine thermal-hiftory information with that of the time of origin of rock structure and reveal an unfavorable relationship for the development of hydrocarbon traps). This unfavorable relation has resulted in the downgrading of oil resource potential in the foothills region but not in the coastal plain to the north.

The reduction in Alaska is, in part, offset in the national total by small increases in a number of other regions of the United States (table 2). Estimates of undiscovered conventional oil resources in most other regions of the United States are, in general, similar to those published in the past, although they differ somewhat in detail. For further information, refer to play-level documentation in the supporting CD-ROM (Gautier and others, 1995). It should be emphasized that substantial overlap exists in the resource-range values estimated in the two studies.

Estimates of anticipated inferred reserves are significantly greater than those reported in 1989 (60 BBO vs. 21 BBO). This increase reflects our employment of an entirely different and newer set of field-level reserves data in this assessment. The last National Assessment (Mast and others, Fs

1989) relied on the American Petroleum In<:-titute-American Gas Association data collected during th~ 10-year period 1969-79, whereas, in this assessment, we had access to the last 15 years of data collected by the En~rgy Information Administration (EIA) in its Oil and Gas Integrated Field File (OGIFF). The OGIFF file was collected during a period of extraordinary variations of activity in the U.S. oil and gas industry, including significant changes in oil and gas prices, drilling activity, and development efficienc.y.

For the first time, the USGS has assessed technically recoverable resources in continuous-type (unconventional) accumulations. Included are about 2 fBO in continuous-type deposits, mostly in fractured shale reservoirs of the Bakken, Niobrara, Austin, and similar formations. These resources in unconventional reservoirs may have been partially accounted for as undiscovered resources in the previous National Assessment (Mast and others, 1989).

Proved reserves of the United State~ onshore and in State waters, at the time of this assessm~nt, amounted to approximately 20 BBO, according to EIA. These values are significantly lower than those reported in 1989, when they stood at 24 BBO.

The technically recoverable conventional resources of natural gas from both growth of reserves in existing fields and from undiscovered accumulations onshore and in State waters, as of this assessment, is approximately 580 TCFG, compared with 347 TCFG at the time of the previous National Assessment (1989). Proved reserves of natural gas in the United States stand at approximately 135 TCFG, compared to 157 TCFG in 1989. Natural gas annual production has increased significantly in the intervening years from 17.0 TCFG in 1989 to about 17.8 TCFG in 1993.

Estimated mean amounts of undiscovered techni~ally recoverable conventional gas resources onshore and in State waters are approximately the same as those reported in the previous National Assessment (Mast and others, 1989) (259 vs. 254 TCFG, respectively). Although estimates of conventional natural gas have actually been reduced in a few significant areas, such as the Anadarko Basin, estimates have been raised in a number of others (table 2). The overall ctange probably reflects the discovery of about 26 TCFG during the past 7 years and movement of certain resources previously estimated under conventional categories to plays in cortinuous-type deposits for this assessment.

Estimates of future growth of gas reserves in known fields are up significantly for this assessment, having increased from 93 TCFG in 1989 to approximately 322 TCFG for this assessment. As with oil, this increase ref ~cts, more than anything else, the use of the EIA OGIFF da•a set rather than American Petroleum Institute-American Gas Association data.

In addition to conventional gas resources, the USGS has, for the first time, made a systematic assessme1.t of potential additions to technically recoverable reso'~rces deriving from continuous-type, largely unconventionaL reservoirs of natural gas. Resources in this category were not evaluated in the previous assessment'" (Mast and others, 1989) because of the difficulties in developing adequate methodologies and data. Historically, these resources have contributed little to the national energy supply. However, we estimate there exists, at a mean value, 308 TCFG of te~hni cally recoverable natural gas in continuous-type deposits in sandstones, shales, and chalks, and almost 50 TCFG of technically recoverable gas in coal-bed deposits. These reso'~rces are thus comparable in magnitude to conventional resot' ...ces, although their anticipated deliverability and development economics will be very different than gas in conventional accumulations.

The 1995 National Assessment documents large, technically recoverable resources of non-associated gas in continuous-type deposits. Significant extraction effort w::ll be required to obtain this gas. Based on existing technolog:r, the assessment indicates that approximately 960,000 productive wells will be required to recover potential reserve additions of 300 TCFG, based on the distribution of EUR's shown in figure 13. Furthermore, extrapolation of present-day su -;cess ratios implies that roughly 570,000 "dry" holes would have to be drilled along with the productive wells. By way of perspective, the most oil and gas wells of all kinds drilled in the United States in 1 year is about 92,000, and from 1986 to the present the total has been less than 40,000 wells per ye1r. In the case of discrete (conventional) fields, most reso':trces have been recovered from relatively few, large fields. Analogously, in the case of continuous-type gas accumulations, most gas is expected to be recovered from a relatively small subset of productive wells. The assessment data show that one-half of the mean potential recoverable resources o~ 300 TCFG will be produced by about 100,000 wells, 25 percent will be produced by an additional 150,000 wells, and the remaining 25 percent will require some 700,000 producing wells (fig. 13).

Figure 13. Potential reserve additions for non-associated gas in continuous-type plays as a function of estimated ultimate recovery (EUR) per well.

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ACKNOWLEDGMENTS

The USGS wishes to thank numerous indi victuals in industry, academia, and State geological organizations for their help. The American Association of Petroleum Geologists, as an organization, was particularly helpful in identifying individuals who were willing to contribute time and expertise to this project.

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