E.D. Attanasi, R.F. Mast, D.H. RootInferred reserves, defined as expected additions to proved reserves in fields already discovered-are observed as "field growth." They accounted for 65% of the total oil and 34% of the total gas assessed in the U.S. Geological Survey's 1995 National Assessment of oil and gas in onshore and state offshore areas.1
U.S. Geological Survey
Specifically, the USGS predicted that the known recovery of pre-1992 discoveries in the Lower 48 states will grow by 47 billion bbl of oil and 290 tcf of dry gas (304 tcf of wet gas) from 1992 through 2071.
This article compares observed "field growth" for the period from 1992 through 1996 with the USGS's predicted field growth for the same period.
Inferred reserves constitute the single largest source of oil and gas assessed in the 1995 National Assessment. In its evaluation of the Kyoto protocol, the Energy Information Administration (EIA) assumed the bulk of expansion of gas production required to meet the emissions goals will come from the Lower 48 onshore areas.2 Hence, an evaluation of the field growth projections is important.
For purposes of this discussion, known field recovery or field size is defined as the sum of past cumulative field production and the field's proved reserves. Proved reserves are estimated quantities of hydrocarbons which geologic and engineering data demonstrate with reasonable certainty to be recoverable from known fields under existing economic and operating conditions.3
Because proved reserves are reported in financial statements, commercial transactions, legal contracts, and in response to regulatory mandates by government, the technical definition reflects a high degree of certainty about the economically recoverable volumes of hydrocarbons in identified fields. Proved reserve estimates calculated with this definition are typically conservative.
When fields are grouped by year of field discovery, the sum of their estimates of known recovery tends to increase systematically over time. This is known as the "field growth phenomenon." The modeling approach used by the USGS to characterize this phenomenon is statistical rather than geologic in nature.
Proved reserves increase with normal field development:
- As boundaries of proved areas are extended by drilling;
- As new pay zones, pools, or reservoirs are found and confirmed by drilling;
- As new infill wells (vertical and horizontal) or well stimulation procedures contact previously inaccessible hydrocarbons, and
- With the introduction of a waterflood or other fluid injection programs.
Field growth projectionsProportional changes in estimates of known field recovery over time are characterized analytically with cumulative field growth functions. These functions show the estimated field size at age n (n years after discovery) as a multiple of the field's initially estimated size (Fig. 1) [64,231 bytes].
These functions were calibrated with annual estimates from 1977 through 1991 of known recovery of conventional fields located in onshore and state offshore areas of the Lower 48 states. The "growth factors" derived from the cumulative growth functions then were applied to the 1991 field size estimates to project annual "field growth" over the next 80 years.
Data used for calibrating cumulative growth functions typically consist of short time-series (6 to 15 years) of estimates of known field recovery for sets of fields grouped by discovery year. For example, with such a series the expected percent field growth for a field going from age 19 to 20 is computed using estimates of known recovery for all those fields that passed from age 19 to 20 during the sample period.
An entirely different set of fields may be used in calculating expected field growth from age 4 to age 5. Field size estimates of fields discovered 1901 through 1991 were from EIA's proprietary Oil and Gas Integrated Field File (OGIFF) released in 1993.
Inferred reserves for Alaska were estimated apart from the Lower 48 analysis.4 The form of the cumulative growth function assumed that the annual rate of growth of older fields will not exceed that of younger fields and that pre-1992 discoveries would continue to "grow" to 90 years after discovery. Implicit in the application of the calibrated cumulative growth function is the assumption that the rate of technological improvement and economic conditions occurring during the observation period will prevail in the future.
Attanasi and Root5 found a small number of fields that exhibit substantially different or "outlier" field growth patterns. These fields tended to grow as much as six times the rate of fields that follow patterns shown in Fig. 1. Many of the fields exhibiting "outlier" behavior were later recognized to be unconventional. In the 1995 National Assessment unconventional oil and gas in continuous-type accumulations were assessed as a distinct class of resources with separate procedures.
Because the location, boundaries, and the degree of development of the continuous-type accumulations are known their assessment consisted of extrapolation of the developed portions of the accumulation to the undeveloped areas. Separate treatment of the unconventional resources in continuous-type accumulations allowed their economic evaluation.6
Unconventional resources in continuous-type accumulations include oil and gas resources that exist as geographically extensive accumulations in coals (as coalbed gas), sandstones, and shales that generally lack well-defined oil/water or gas/water contacts.7
Fields where production is primarily from unconventional resources in continuous-type accumulations were excluded from the inferred reserve analysis and field growth projections in the 1995 Assessment.
Cumulative growth functions were calibrated for each of the seven regions (Fig. 2) [84,254 bytes] and the Lower 48 states as a whole. Because the sum of the projections made with independently calibrated regional growth functions does not add exactly to the projection computed with the aggregate growth function, the regional projections were standardized so their sum equaled the aggregate Lower 48 projection. The sums of the regional projections of inferred reserves are 42.7 billion bbl of oil and 247 tcf of dry gas compared to 47 billion bbl and 290 tcf projected with the aggregate Lower 48 cumulative growth function.
Fields were classified as oil or gas. Gas fields had a wet gas-to-liquids ratio of at least 20,000 cu ft of gas/bbl of recoverable liquids (oil plus condensate). Growth functions were calculated for primary commodities, that is, for oil plus condensate in oil fields and for wet gas in gas fields. Secondary products like associated-dissolved gas in oil fields and liquids in gas fields were assumed to grow proportionally to primary products.
Data were from the OGIFF prepared by EIA. The file provided estimates of field size, in terms of crude oil and wet natural gas, for each field in the U.S. Other field level data include the discovery date, state, and county in which the field is located. OGIFF field data do not include geologic information. Fields producing mostly unconventional resources from continuous-type accumulations were identified by geologists and excluded before analysis.
The OGIFF file issued in November 1998 includes data through 1996 yielding up to 20 estimates for each of the fields listed. While most of the fields have retained their unique identification codes, there are 178 fewer entries of fields discovered prior to 1992 in the 1998 version than in the 1993 version. Field consolidations can affect the analysis of field growth because resources in younger eliminated fields may appear as field growth in old retained fields. The magnitude of these effects is not known at this time.
Comparative analysisWithout excluding unconventional field entries, the 1998 OGIFF showed 4.6 billion bbl of oil and 66.8 tcf of gas added to the known recovery of pre-1992 discoveries in Lower 48 onshore and state offshore areas from 1992 through 1996. Overall, growth in fields thought to be conventional was 4.45 billion bbl and 50.3 tcf. Table 1 [69,607 bytes] shows the projected and actual field growth at the national and regional levels.
Nationally, oil reserve additions from field growth fell short of projected amounts by about 2.1 billion bbl or 33%.
Regionally, the Pacific Coast was below projection by about 0.8 billion bbl, the Rocky Mountains by 0.3 billion bbl, West Texas and Eastern New Mexico 1.2 billion bbl, and the Midcontinent and Eastern regions were together lower about 0.3 billion bbl.
Gulf Coast oil reserve additions from field growth exceeded projection by 0.7 billion bbl.
Nationally, gas reserve additions from field growth exceeded projection by about 10 tcf or about 25%.
The Gulf Coast Region alone exceeded projection by about 10 tcf. About 3.2 tcf of this 10 tcf was from growth in oil fields, and the rest was from conventional nonassociated gas fields.
All of the 2 tcf shortfall in the Pacific Coast region was associated gas in oil fields that failed to grow as projected. For West Texas and Eastern New Mexico actual growth of gas exceeded the projection by 0.9 tcf.
In summary, over the 5 year period oil additions to reserves from "field growth" in pre-1992 discoveries fell short of projection by 33%, and gas additions exceeded expectations by 25%.
Market price undoubtedly influenced the industry's willingness to make marginal improvements in recovery (Fig. 3) [59,779 bytes]. For the 5 years after 1991, real oil prices were well below the 1991 price levels, while except for one year, gas prices substantially exceeded their 1991 levels.
Regional projections over a short time frame were not very reliable predictors of field growth. National projections over this same time frame were much better. We believe, over longer time periods, both the regional and national projections will be more reliable provided economic conditions remain reasonably comparable.
In addition to the 4.5 billion bbl and 50 tcf of growth in the Lower 48 onshore and state offshore areas, for this same period, pre-1992 discoveries in Gulf of Mexico federal waters grew by 2 billion bbl of oil and 19.1 tcf of wet gas. Pre-1992 discoveries in Alaska grew by 1.9 billion bbl of oil and 2.0 tcf of gas.
- U.S. Geological Survey National Oil and Gas Resource Assessment Team, 1995 National Assessment of United States Oil and Gas Resource Assessment, U.S. Geological Survey Circular. 1118, 1995, 20 p.
- Energy Information Administration, Impacts of the Kyoto Protocol on U.S. energy markets and economic activity, SR/OIAF/98-03, 1998, 227 p.
- Energy Information Administration, U.S. oil and gas reserves by year of field discovery, DOE/EIA-0534, 1990, 137 p.
- Root, D.H., Attanasi, E.D., Mast, R.F., and Gautier, D.L., Estimates of inferred reserves for the 1995 National Oil and Gas Resource Assessment, U.S. Geological Survey Open-File Report 95-75-L, 1996, 29 p.
- Attanasi, E.D., and Root, D.H., The enigma of oil and gas field growth, AAPG Bull, Vol. 78, No. 3, 1994, pp. 321-332.
- Attanasi, E.D., and Schmoker, J.W., Long-term implications of new gas estimates, Non-renewable Resources, Vol. 6., No. 1, 1997, pp. 53-62.
- Schmoker, J.W., Method for assessing continuous-type (unconventional) hydrocarbon accumulations, in Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds., 1996, 1995 national assessment of United States oil and gas resources-results, methodology, and supporting data: CD-ROM, U.S. Geological Survey Digital Data Series DDS-30, release 2, one CD-ROM, 1995.
- Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0384(97), 1998, 391p.
Emil D. Attanasi is an economist. Since 1973 he has been with the USGS working on development of resource assessment methods and the integration of economics into USGS oil and gas assessments. He received a BA degree in mathematics from Evangel College and a PhD degree in economics from the University of Missouri. E-mail: [email protected]
Richard F. Mast was with the Illinois State Geological Survey from 1955-73 and the USGS from 1973-94. Now emeritus with the USGS in Denver, he led the 1989 USGS National Oil and Gas Assessment. He received a BS degree in geology and an MS degree in mining engineering from the University of Illinois.
David H. Root retired in 1997 from the USGS, where he had worked on the statistics of nonrenewable resources, particularly oil and gas, participating in four national oil and gas assessments. He received a PhD degree in mathematics from the University of Washington in Seattle.
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