EXPLORATION U.S. resource estimates give insights to key oil, gas plays

John D. Grace
Earth Science Associates
Arlington, Tex.

Analysis of the data and results provides insights into future U.S. hydrocarbon supply as well the risk and return to investment in domestic exploration.

Periodically over the last 25 years, the U.S. Department of Interior has described and analyzed remaining U.S. oil and gas resources. Its most recent estimates of undiscovered, conventional, technically recoverable hydrocarbons indicated 83 billion bbl of liquids (crude oil and natural gas liquids) and 527 tcf of natural gas.

Slightly over half of these resources is located in the federal offshore; the remainder is onshore and in state waters.

In addition to undiscovered resources, another 77 billion bbl of liquids and 361 tcf of natural gas were estimated to be added in the future to the reserves of fields that have already been discovered. These volumes, which exist beyond proved reserves, are often referred to as "field growth" or "inferred reserves." They are added through field extension, new reservoirs, and revisions of recoverable volumes in existing fields.

The government assessments were completed in 1995 by the U.S. Geological Survey for onshore and state waters and in 1996 by the Minerals Management Service for federal waters.

This three part article reviews and extends the most important findings of the 1995-96 National Oil and Gas Assessment. Analysis, maps, and graphs of onshore and state waters resources were produced with Earth Science Associates' U.S. Oil and Gas Resource System 1.0

This first article examines the U.S. conventional hydrocarbon resource base as a whole.

The second article identifies and characterizes the highest potential plays in the U.S.

The third article analyzes information made available through the National Assessment on the structure of exploration risk in the U.S. and develops a new method for pre-drill prediction of exploration success.

Production sources

The nation's resource base of conventional, technically recoverable hydrocarbon liquids and gas consists of four basic parts: cumulative production, proved reserves, future additions to discovered fields, or "field growth," and resources estimated to exist in undiscovered fields.

"Conventional resources" means those accumulations with downdip water contacts that can be extracted through traditional development practices. It does not include such resources as tar sands, oil shales, coalbed methane, or "tight" gas sands (except to the extent they are included in cumulative production or proved reserves). "Technically recoverable" refers to those volumes of resources in place that can be extracted with available technology but without special regard to cost. A subset of "technically recoverable" is "economically recoverable," which refers to those volumes of resources in place that can be profitably produced at a given price, or schedule of incremental, or marginal cost.

In Fig. 1 [19314 bytes], the four categories of these resources are divided between onshore/ state waters and the federal offshore. The most striking difference between the two regions is that slightly over half of onshore, technically recoverable hydrocarbons have been produced, where only 14% of offshore oil and gas have been brought to the surface.

Undiscovered resources constitute nearly two-thirds of total offshore resources, where that class is only 15% for onshore. Offshore field growth and reserves are also smaller fractions of total resources compared to onshore.

Whether the source is field growth or new discoveries, the supply of oil and gas ultimately depends on proved reserves. Both new discoveries and field growth augment reserves, and they are debited by production. During the last 20 years, 94% of additions to oil reserves and 88% of additions to gas reserves have come from field growth (Fig. 2 [11531 bytes]).

It is important to note that all pieces of these pies are not the same economically. Cumulative production and proved reserves either were at the time of their production, or are presently, profitable by definition. "Growth" is based on a statistical extrapolation of data on changes in field reserves as a function of time.

These forecasted additions to discovered fields would only be profitable if the future relationship between price, cost, and technology were at least as good as it has been in the past.

The volume reported as undiscovered is only the "technical" target and reflects more than the smaller volumes which would be available at today's prices and costs.

Economics favors field growth resources that enjoy both low dry hole risk and low marginal production and transportation costs, because they are additions to fields which are already on line. Despite the additions from both growth and discoveries, between 1976 and 1995, oil and gas reserves fell significantly.

Two aspects of field growth are worthy of note. First, USGS substantially increased its estimates of future field growth in the 1995-96 National Assessment compared with the last National Assessment, reported in 1989.5

In the earlier analysis, 21 billion bbl of oil and 93 tcf of gas were estimated as future additions to discovered fields.

The increase was warranted. About 85% of future oil field growth and about 133% of future gas field growth predicted in the 1989 National Assessment had occurred by the 1995-96 National Assessment. With the new estimates of ultimate field growth, if the finding rates of the past 20 years persisted, it would take 30 years to add the amount predicted for oil fields and 25 years to add the gas.

Second, there is a significant and unexplained difference between estimated field growth offshore and onshore. The USGS estimates that onshore field growth will be 273% of current liquids proved reserves and 238% for gas. MMS sees field growth offshore as 133% of proved reserves for liquids and 125% for gas. There are technologic reasons why offshore field growth might be lower than that experienced onshore, but why it would be half as much requires further investigation.

In its analysis of undiscovered resources onshore and in state waters, the USGS estimates were remarkably consistent between the 1989 and 1995 National Assessments. Accounting for new field discoveries between the two Assessments, USGS estimates for undiscovered oil rose 14% and 7% for both gas and natural gas liquids.

MMS, however, undertook a major revision of its estimates of undiscovered liquids and gas, particularly in the Alaska federal waters. Its 1996 National Assessment placed an additional 27.7 billion bbl of liquids offshore, a 155% increase. Of this volume, 20.5 billion bbl are in Alaska.

MMS raised its gas estimates by 123 tcf, 85% higher than 1989. Of this volume, 109 tcf was in Alaska. MMS cites improved methodology and data for the increase, although the needed explanation is absent. Lack of exploration success in the Chukchi Sea also raises questions about such a sharp upward revision.

At the rates of new field discoveries from 1976-95, it would take 615 years to discover the estimated undiscovered, conventional, technically recoverable oil in the U.S. and 301 years for the gas. This curious result raises the importance of more detailed investigation of the economics of exploration and production in the National Assessment process.

The term "technically recoverable" may have outlived its usefulness if it generates estimates of volumes, some of which would not be expected to contribute to supply for several centuries.

Resource distribution

Geographically, slightly over half the nation's endowment of undiscovered, technically recoverable conventional oil and gas is located in two regions (Fig. 3 [30170 bytes] and Table 1 [23021 bytes]). The richest is Alaska, where most of the undiscovered oil and gas is in North Slope and adjacent Beaufort and Chukchi Sea plays.

Economic recovery from arctic fields must support very high exploration, production, and transportation costs relative to those in the rest of the country. For instance, drilling costs run from a low of $204/ft onshore for production wells around Prudhoe Bay to more than $2,000/ft offshore for an exploratory well in the Chukchi Sea. This is 2.5 to over 20 times the national average of $79/ft.6

Nevertheless, the arctic realm is expected to hold not only the largest volumes of undiscovered oil and gas, but also the largest remaining fields. Economies of scale in production and ability to use existing infrastructure and transportation at Prudhoe Bay offset costs that would make many projects uneconomic on a stand-alone basis. As a result, the region supports a low level of exploration activity that yields discoveries critically important because of their sizes. In 1995, 19% of U.S. hydrocarbon liquids production came from Alaska.

In second place is the Gulf Coast. A surprising amount of estimated federal offshore undiscovered liquids and gas in the Gulf of Mexico federal offshore is expected from the broad, well-explored shelf in water depths to 200 m (Fig. 4 [13885 bytes]).

In deepwater environments (beyond 900 m), the density of undiscovered fields is expected to drop, but average field size is larger and liquid content is higher. In 1995, one of every four cubic feet of U.S. natural gas and one of every eight bbl of liquids production came from the Gulf of Mexico federal offshore.

Exploration potential of the Pacific region comes in third. While it holds a large portion of the national resource base, regulation and urbanization have put a significant share of these resources beyond practical exploration plans.

The remaining three areas of the country have about equal endowments of undiscovered liquids and gas, with 11-13 billion BOE in each area, almost evenly split between oil and gas. The most important provinces within these areas are the Permian Basin and the northern Rocky Mountains, both for oil and gas, and the Anadarko basin for gas.

Range of estimates

In order to represent the inherent uncertainty involved in assessing undiscovered resources, USGS and MMS expressed their estimates as probability distributions.

The means of those distributions are the standard measures reflecting the expectation of the volumes to be found. However, the variance of the estimates, expressed here as ranges, conveys important information about the certainty of the analysis, as well as the "upside" and "downside."

The mean undiscovered volume of hydrocarbon liquids in the U.S. is 83 billion bbl. On the low side, USGS/MMS scientists evaluated a 95% chance that there are at least 74 billion bbl of undiscovered liquids. At the other end, they evaluated a 5% chance of at least 92 billion bbl of liquids.

For undiscovered gas, the mean is 527 tcf. The low estimate (95% probability) is that there is at least 476 tcf of gas, and the high (5% probability) is 580 tcf. In the cases of both liquids and gas, these ranges are rather small.

Individual play and province estimates of undiscovered resources also include ranges that reflect uncertainty. Large ranges, logically, are associated with those areas where drilling densities are low. Onshore, many of the largest of these are located in Alaska and the Basin and Range province; offshore, they are in Alaska and the Pacific.

Large uncertainties at the play level are associated with hypothetical plays-those not demonstrated by discoveries. Examples include the Precambrian Midcontinent rift play, the Devonian-Mississippian hinterland oil play in the Arkoma basin, or the Devonian-Mississippian Endicott-Chukchi platform play of the Chukchi Sea. The smallest ranges are for highly mature areas, such as those of the onshore Gulf Coast and Permian Basin.

Estimated field sizes

The data and analyses released by the two agencies, particularly the USGS, provide a wealth of information on both discovered and undiscovered oil and gas resources. Of high economic importance is the expected size distribution of undiscovered fields.

The size distribution of undiscovered fields, hence of exploration targets, is a critical determinant in ranking plays. Along with well flow rates, reservoir depth, and reserves per well, it is one of the key factors that makes a prospect, or a discovery, economic or not.

Frontier areas are different from the far better-explored areas of Lower 48 onshore/state waters plays. Among Alaskan and federal offshore plays, the estimated mean size of undiscovered fields ranges as high as 168 million BOE onshore and 572 million BOE offshore. The forecasted sizes of the largest undiscovered fields in a play are as high as 6 billion bbl in the Eastern Thrust onshore and 9.4 tcf in the Sand Apron-North Chukchi high play of the Chukchi Sea.

For the Lower 48 onshore and state waters plays, the size distribution for remaining fields is much smaller. While there are some plays where expected field sizes are large, the mean size of undiscovered fields in the Lower 48, onshore/state waters is 3 million BOE. This calculation even excludes from consideration future discoveries with less than 1 million BOE in reserves. The plays with the largest resources and undiscovered fields are the topic of the second article.

The mean size of all estimated undiscovered Lower 48 fields, including small fields, is 585,000 bbl for all oil fields and 6.7 bcf for all gas fields.

Finally, there is the contribution of small fields themselves. The USGS estimates that 15% of the conventional, technically recoverable undiscovered oil and gas are contained in accumulations of less than 1 million bbl of oil or 6 bcf of gas. These fields are generally not exploration targets; they represent discoveries made on the expectation of finding larger fields. To the extent that they can be economically produced, the good news is that tens of thousands of them are left.

Age of reservoirs

One of the most interesting geologic views of the National Assessment data is to divide oil and gas resources by the geologic age of the reservoirs in which they are trapped.

Fig. 5 [75754 bytes] shows this distribution for discovered and estimated undiscovered liquids and gas (but not including field growth).

The largest volume of hydrocarbons is concentrated in Tertiary reservoirs. This applies to both discovered and undiscovered hydrocarbons. The former arises principally from the contributions of the Gulf Coast and California. The latter come not only from the Gulf Coast but heavily from onshore and offshore arctic Alaska.

After the Tertiary, the next most prominent grouping is in Upper Paleozoic rocks, reflecting the region shown in Fig. 3 as Central Interior, which is almost exclusively Paleozoic. Mesozoic rocks are widely distributed between the Gulf Coast, Western Interior, and Alaska.

While distribution by reservoir age imparts useful information, without examining entire petroleum systems, from the source rock to trap, it is impossible to draw grand conclusions about the relative oil and gas productivity of given geologic ages.

In some cases, rocks reservoir oil and gas because they are simply high in the section, catching hydrocarbons generated from far older rocks. In others, the rocks of an entire petroleum system occur within the bounds of a single geologic system.

Conclusions

Based on the data and analysis provided in the 1995-96 National Oil and Gas Assessment, a broad picture can be drawn of the U.S. conventional oil and gas resource base:

1. About half of the conventional oil and gas estimated to exist in the U.S. has been produced. Of the half that remains, about half of those volumes is in already-discovered fields, either as proved reserves or expected future field growth. The other half of what remains is estimated technically recoverable oil and gas in undiscovered fields.

2. Onshore/state waters resources compared with the federal offshore provides a stark contrast. In the latter, almost two thirds of technically recoverable resources remain to be found. Onshore, the undiscovered share is only 15%. Onshore field growth represents half of unproduced, technically recoverable hydrocarbons, where it is only 10% of unproduced gas and liquids offshore.

3. In recent decades, growth of already-discovered fields has been the largest source of new reserves in the U.S. This trend will continue. After underestimating in the 1989 National Assessment, USGS substantially increased its estimates for future field growth.

4. The greatest concentration of undiscovered, conventional, technically recoverable liquid and gas hydrocarbons is in Alaska, most of it in the arctic. Arctic resources are evenly split between oil and gas (which is not presently economic), with more offshore in the Beaufort and Chukchi seas than onshore.

MMS significantly raised offshore Alaskan undiscovered oil and gas estimates in 1996 in comparison with the 1989 National Assessment with little explanation of the revision or how it is reconciled with recent lack of exploratory success in the Chukchi Sea.

5. The next largest volume of undiscovered oil and gas is in the Gulf Coast basin, on and offshore. These resources are expected mainly to be gas and natural gas liquids. Discoveries in the last 10 years in deep water have demonstrated not only its overall potential but rich liquids potential. After the Gulf Coast comes the onshore and offshore basins of the Pacific coast, where access is a limiting practical condition.

6. Plays with estimated large undiscovered oil and gas volumes also are associated with the largest mean field sizes, as well as the best chance at very large discoveries. Most of these are in the frontier areas of Alaska, the Pacific offshore and deepwater Gulf of Mexico ( 900 m). For Lower 48 onshore and state waters plays, the estimated mean size of future discoveries is 3 million BOE, considering only fields of at least 1 million BOE.

7. Tertiary age reservoirs hold the largest volume of hydrocarbons in the U.S., mainly because of Gulf Coast, California, and arctic Alaskan resources. The next most important systems are of Late Paleozoic age, because of the resources of the Central Interior region of the U.S.

Next: The highest potential plays in the U.S.

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