Undiscovered Oil and Gas Resources: An Evaluation of the Department of the Interior's 1989 Assessment Procedures (1991)

The undiscovered conventional crude oil and natural gas evaluated in the Department of the Interior (DOI) resource assessment comprise a limited part of the total base of petroleum available for future production. This appendix defines and discusses all of the key components of the petroleum resource base for those who are unfamiliar with petroleum industry terminology.

The total in-place resource base of crude oil and natural gas (the amount that existed prior to any production) consists of the total volume that was formed and trapped within the earth's crust. The in-place resource is a function of the organic content of the source beds from which the hydrocarbons have been derived, the physical conditions under which they formed and migrated, and the effectiveness of the “trap.” (A “trap” is a discontinuity in the properties of the underground formations that, because of reduction in permeability, slows the upward migration of the generated oil and gas so that they accumulate temporarily, although for a long time in human terms, and can be located and produced.)

In general, the historically evaluated recoverable portion of the in-place oil and gas resource base is composed of four main parts: cumulative production, proved reserves, indicated and inferred reserves, and undiscovered resources (see Figure 2.1), which will be discussed below.

The quantity of crude oil, natural gas, and/or natural gas liquids produced by a well, a field, a province, a country, or the petroleum industry from initial production to the present time is termed cumulative production. In the United States, crude oil is measured in terms of stock-tank barrels of 42 U.S. gallons at atmospheric pressure (14.73 pounds per square inch), corrected to 60 degrees Fahrenheit. Natural gas volumes commonly are measured in terms of cubic feet at an absolute pressure of 14.73 pounds per square inch and a temperature of 60 ° F.

In addition to company records, states and the federal government keep records of oil and gas production. Such records are needed for regulatory, royalty, and taxation purposes. Quantities of crude oil produced through time are reasonably well known because records have been kept since the early days of production. The records for natural gas and natural gas liquids are less complete because, through the mid-twentieth century, the market value of natural gas was small. Much of the early natural gas production was flared and no records were maintained of that production. Additionally, some states have not taxed the production of natural gas and hence have not maintained records of that production. However, reasonable estimates of cumulative production for both crude oil and natural gas have been made.

Proved reserves are those portions of in-place crude oil, condensate, natural gas, natural gas liquids, and associated substances that have been identified and are considered, on the basis of geologic and engineering data, to be recoverable under current economic and government regulatory conditions using existing technology. The producibility of those reserves is supported either by actual production or conclusive reservoir tests. Quantities of proved reserves are normally estimated using volumetric or material balance calculations or by extrapolation of production rate curves or pressure-decline curves through time.

The volume of a reservoir that is considered to contain proved reserves includes that portion delineated by drilling and defined by gas-oil, oil-water, or gas-water contacts. The adjoining portions of the reservoir that are not yet drilled, but that can be reasonably judged as economically productive on the basis of geological and engineering data, also may be considered to contain proved

reserves. In the absence of information on fluid contacts, the lowest known structural occurrence of petroleum is considered to be the lower proved limit of the reservoir. The term measured reserves, as used by the Department of the Interior (DOI), includes that part of the identified economic resource that is estimated from geologic evidence supported directly by engineering data to be recoverable in future years from known reservoirs under existing economic and operating conditions. These measured reserves are generally equivalent to proved reserves.

Proved reserve estimates are compiled by the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE). The reserve estimates are revised annually based upon a stratified sample of operator production and reserve data, additional geologic and/or engineering data, and changes in economic or regulatory conditions.

Indicated reserves are quantities of crude oil or natural gas that may become economically recoverable from producing reservoirs through the application of currently available improved recovery techniques. The improved techniques may already be in use, but their effects on ultimate recovery are not yet known. Alternatively, when known, the results of the application of such techniques to similar reservoirs may be used to estimate additional indicated recovery.

Inferred reserves are part of the identified economic resources that are expected to be added to proved reserves as new field wells are drilled to extend known fields, as earlier reserve estimates are revised, and as production is developed from new producing zones in known fields. The Potential Gas Committee (PGC) category of probable resources is similar to inferred reserves. Inferred reserves have traditionally been estimated based on statistical extrapolation of past revisions to estimates of proved reserves (growth of known fields). Estimates of probable resources are usually based on analysis of individual fields and the potential for extensions and new pool discoveries in those fields.

As inferred and indicated reserves are converted to proved reserves over time, fields increase in size. These increases collectively are termed reserve growth.

Inferred reserves (and indicated reserves) are not included in proved reserves due to their uncertain physical and economic recoverability and the

conservatism commonly associated with initial proved reserve estimation. Neither are they included in undiscovered resources, as such quantities have in effect been identified. However, estimates of undiscovered resources must take inferred reserves into account because they are part of the ultimate recovery of a field (or pool) and as such relate to any estimate of field-size distribution in a play. Also, inferred reserves represent a significant portion of the nation's total resources. To leave them out of a discussion of oil and gas resources leaves the estimates of resources incomplete and creates a gap in the evaluation between proved reserves and undiscovered resources. Extended reserve growth must be considered in the same manner.

Indicated reserves, like proved reserves, are reported to the Energy Information Administration by some of the crude oil and natural gas operators. Inferred reserves are not reported by these operators. Rather, their existence is inferred from the historical experience that estimates of the sizes of known fields tend to increase over time. Fields grow as a result of continued drilling and the application of improved recovery techniques. The growth factor for fields of a given age is the ratio of the ultimate amount of oil or gas that the field will produce to the sum at that time of cumulative production and proved reserves. The expected future growth of fields includes inferred reserves.

An additional category of resources allied to inferred reserves is the quantities of crude oil and natural gas that might be recovered through better reservoir development. Such resources are referred to as extended reserve growth and are the subject of considerable current investigation. They include additional reserves to be developed through better placement of wells, known as infill drilling, and better production technology. They are based on more extensive understanding of the geology of oil and gas reservoirs, especially the discontinuities in permeability. Research on the magnitude of this type of resource is still in the early stages and there are no consistently applied methods of calculation. Many current resource estimates do not yet recognize extended reserve growth and some analysts suggest that these resources are part of inferred reserves. However, past methods of refining conventional reserve growth do not incorporate extended reserve growth, as past growth resulted from a different sort of field development. Methods are needed to estimate extended reserve growth as new technologies, and more strategic deployment of current technologies, are applied to reservoir development.

For long-term energy planning, it is essential to look beyond proved and inferred reserves and to anticipate the additional resources that could be developed through continued exploration for new field discoveries. This category of resources, termed undiscovered resources, is the principal subject of this report. Undiscovered resources are resources estimated to exist, on the basis of geologic knowledge and theory, outside of known fields and known accumulations (i.e. beyond reserves and reserve growth). Also included are resources in undiscovered pools that happen to occur within the geographic boundaries of known fields as unrelated accumulations controlled by separate structural or stratigraphic conditions (i.e., the pools are not really part of the fields).

In addition to the division of in-place resources into the four categories described above, the petroleum resource base may be divided into conventional and unconventional categories. The DOI assessment covered conventional, but not unconventional, resources. As discussed below, there are problems with limiting resource assessments to these two categories.

Resources in the conventional category include crude oil, natural gas, and natural gas liquids that exist as discrete accumulations in conventional reservoirs, in a fluid state amenable to extraction techniques employing the most current development practices. In the DOI assessment, conventionally recoverable resources are crude oil and natural gas accumulations that can be extracted from a well by the natural pressure within the reservoir, mechanical pumping to surface, or injection of water or gas to maintain reservoir pressure. Some commonly used techniques, such as massive hydraulic fracturing, were not considered “conventional ” in the DOI's accounting. Not included were extremely viscous oil deposits, tar sands, oil shales, or natural gas either in tight sandstones or fractured shales having in-situ permeabilities of less than 0.1 millidarcy (md). Coal-bed methane, gas from geopressured brines, and gas hydrates also were not

considered conventional resources. However, it is difficult to be precise about the limits of conventional resources. Some natural gas in low-permeability reservoirs is being produced and is included in some resource estimates.

The PGC divides its undiscovered category into possible and speculative. These are projected discoveries of new fields that are associated with productive formations. These new fields would be located within a productive province, and are commonly associated with productive plays but are not part of producing fields. The speculative resource category of the PGC includes projected discoveries of new fields in non-producing strata located in either producing or non-producing provinces.

The term unconventional resources originally was applied to in-place resources of crude oil and natural gas not recoverable using existing or evolving technology, but which might be recoverable through the development of new technology. The boundary between conventional and unconventional resources is not well defined, because in most instances there is a continuum of geologic conditions between conventional and unconventional resources. It must be recognized that unconventional resources are being currently produced with existing technology, and, for natural gas, are making a significant contribution to current production. As improvements in recovery technology move portions of unconventional resources into the conventional category, their continued exclusion from resource assessments results in understating the volume of potentially available petroleum. Because of the evolutionary shifts of unconventional into conventional resources, it is generally difficult to distinguish between these two categories unless the technology to produce the resource does not exist and the evolutionary development of current technology does not promise a solution. The issue is complicated further through the creation of arbitrary boundaries that have been established from time to time by legislation.

There are several categories of unconventional crude oil deposits. Heavy crude oils have enough mobility that, given time, they can be produced through a well bore in response to thermal recovery methods. Tar sands contain sufficient immobile bitumen so that they will not flow into a well bore, even if thermally stimulated. Oil shale is an organic-rich rock that yields oil when heated. The oil derived from processing tar sands and shales is termed synthetic crude. It differs from conventional crude oil in that it is deficient in the lighter

hydrocarbon components and commonly has a greater proportion of hydrogen-deficient (unsaturated) hydrocarbons.

A number of diverse types of unconventional gas deposits are known. Gas in low-permeability reservoirs (“tight gas”) is natural gas present in blanket or lenticular sandstones that are relatively impermeable (in-situ effective permeability of less than 0.1 md). Such natural gas is widespread, especially in Cretaceousand Cenozoic-age formations in the West (see Table D-1 for an explanation of the geologic time scale). It is now commercially recovered in some areas from the better-quality low-permeability reservoirs, mostly through the application of massive hydraulic fracturing.

The process by which vegetation is converted to coal over geologic time also generates large quantities of natural gas. Such natural gas is considered to be unconventional natural gas in the coal beds and conventional natural gas in adjacent permeable sedimentary strata. Coal-seam gas (commonly referred to as coal-bed methane) is produced in the San Juan and Piceance basins of the West, in parts of the Appalachian basin of the East, and the Black Warrior basin of the Southeast.

Shale gas was generated from organic-rich mud deposited mostly during Devonian time in a shallow sea that covered the eastern half of the United States. The gas-bearing shales are presently confined to the Illinois, Michigan, and Appalachian basins, with production further restricted, mostly to the south-western part of the Appalachian basin.

Geopressured brine reservoirs are brine-filled rock units that have internal fluid pressures in excess of that expected from the pressure exerted by a column of water whose height is equal to the depth of burial of the reservoir. Such reservoirs commonly exist in deep, geologically young sedimentary basins in which the formation fluids (mostly brines) bear a part of the overburden load. The geopressured fluids of the Gulf Coast basin have been found to contain between 30 and 80 cubic feet of dissolved methane per barrel of brine. There is no current commercial production of this resource because the value of the extracted gas is less than the cost of producing the brine, separating the gas, and disposing of the brine.

Natural gas hydrates are ice-like crystals of water and gas (methane entrapped in voids between water crystals) which are found in regions of high pressures and low temperatures. One solid cubic foot of gas hydrates is estimated to contain about 132 cubic feet of gas. Conditions favorable to the formation of natural gas hydrates occur in permafrost zones and in relatively deep seabeds. Possibly large volumes of gas exist in the hydrate state, but there

is no commercial gas production from this unconventional resource in North America.

Gas in low-permeability sandstones and fractured-shale reservoirs (having in-situ permeabilities to gas of less than 0.1 md), coal-bed methane, gas in geopressured shales and brines, and gas hydrates are considered by the DOI as unconventional gas resources and were not included in the 1989 resource assessment.

Cumulative production, as stated previously, is the total past production, the history of which may indicate future trends. Rising or falling production trends, in the absence of major changes in reserves, economics, or geopolitics, tend to continue, at least in the short term. Proved reserves have a more direct relation to production. Although individual oil fields vary in the rates at which they can be produced, on average only about one-tenth of the remaining recoverable crude oil can be efficiently removed from a reservoir each year. Withdrawal at faster average rates commonly will cause reservoir damage that will reduce ultimate production. This average rate of recovery is sometimes expressed as the proved reserves/production ratio (R/P ratio).

The production of natural gas commonly is divided into categories of associated and non-associated natural gas. Associated natural gas is produced from a reservoir in association with oil. Non-associated natural gas is produced from a reservoir in which there is little or no oil. Some hydrocarbon liquids may be produced along with the non-associated natural gas.

The rate of production of associated gas is controlled by the oil production rate, because oil is the higher value product. Depending on reservoir characteristics, non-associated gas can be produced at faster rates than oil. Sometimes as much as one-fifth of the remaining recoverable gas can be produced in one year (R/P = 5/1). Average proved reserve/production ratios for entire regions that are undergoing intense gas development may range between 7/1 and 10/1. Large fields, with high permeability, can be produced at near maximum rates, while smaller fields, commonly with lower permeability, must be produced at slower rates. The average R/P ratio of a region is indicative of its developmental maturity, because it will consist of a combination of low R/P ratios for older, depleting fields and higher R/P ratios for newer fields that are still undergoing development. Because the larger fields are commonly found early in the

exploration cycle, they will dominate production, and with depletion, tend to decrease the overall R/P ratio of the region, commonly to less than 10/1. Conversely, any proved reserves that are shut in (not being produced) or produced below their optimum production rate tend to increase the average regional R/P ratio. A regional R/P ratio much above 12/1 commonly indicates a province in which significant new discoveries are still being made and/or one in which production is not occurring at the maximum potential rate, either for technical or economic reasons.

Inferred reserves do not have as direct a relation to production as proved reserves. However, as fields grow, inferred reserves are converted to proved reserves and, as such, support production. Similarly, as undiscovered resources are converted to proved reserves, they also support production. New technology may increase the portion of in-place resources that is recoverable. If crude oil and natural gas prices rise, the increased value of the resource may encourage the utilization of more expensive production technologies, thus increasing the percentage of the resource that is recovered. Also, increased value of the resource will allow crude oil and natural gas wells to be produced for a longer time under low recovery rates, thereby increasing the total recovery.