United States Geological Survey's Reserve-Growth Models and Their Implementation

The USGS has developed several mathematical models to forecast reserve growth of fields both in the United States (U.S.) and the world. The models are based on historical reserve growth patterns of fields in the U.S. The patterns of past reserve growth are extrapolated to forecast future reserve growth. Changes of individual field sizes through time are extremely variable, therefore, the reserve growth models take on a statistical approach whereby volumetric changes for populations of fields are used in the models. Field age serves as a measure of the field-development effort that is applied to promote reserve growth. At the time of the USGS World Petroleum Assessment 2000, a reserve growth model for discovered fields of the world was not available. Reserve growth forecasts, therefore, were made based on a model of historical reserve growth of fields of the U.S. To test the feasibility of such an application, reserve growth forecasts were made of 186 giant oil fields of the world (excluding the U.S. and Canada). In addition, forecasts were made for these giant oil fields subdivided into those located in and outside of Organization of Petroleum Exporting Countries (OPEC). The model provided a reserve-growth forecast that closely matched the actual reserve growth that occurred from 1981 through 1996 for the 186 fields as a whole, as well as for both OPEC and non-OPEC subdivisions, despite the differences in reserves definition among the fields of the U.S. and the rest of the world.     

Reserve Growth in Oil Fields of West Siberian Basin, Russia

Although reserve (or field) growth has proved to be an important contributing factor in adding new reserves in mature petroleum basins, it is a poorly understood phenomenon. Although several papers have been published on the U.S. fields, there are only a few publications on fields in other petroleum provinces. This paper explores the reserve growth in the 42 largest West Siberian oil fields that contain about 55% of the basin's total oil reserves.The West Siberian oil fields show 13-fold reserve growth 20 years after the discovery year and only about 2-fold growth after the first production year. This difference in growth is attributed to extensive exploration and field delineation activities between discovery and the first production year. Because of the uncertainty in the length of evaluation time and in reported reserves during this initial period, reserve growth based on the first production year is more reliable for model development. However, reserve growth models based both on discovery year and first production year show rapid growth in the first few years and slower growth in the following years. In contrast, the reserve growth patterns for the conterminous United States and offshore Gulf of Mexico show a steady reserve increase throughout the productive lives of the fields. The different reserve booking requirements and the lack of capital investment for improved reservoir management and production technologies in West Siberia are the probable causes for the difference in the growth patterns.The models based on the first production year predict that the reserve growth potential in the 42 largest oil fields of West Siberia for a five-year period (1998–2003) ranges from 270–330 million barrels or 0.34–0.42% per year. For a similar five-year period (1996–2001), models for the conterminous United States predict a growth of 0.54–0.75% per year.     

The space-time structure of oil and gas field growth in a complex depositional system

Shortly after the discovery of an oil and gas field, an initial estimate is usually made of the ultimate recovery of the field. With the passage of time, this initial estimate is almost always revised upward. The phenomenon of the growth of the expected ultimate recovery of a field, which is known as field growth, is important to resource assessment analysts for several reasons. First, field growth is the source of a large part of future additions to the inventory of proved reserves of crude oil and natural gas in most petroliferous areas of the world. Second, field growth introduces a large negative bias in the forecast of the future rates of discovery of oil and gas fields made by discovery process models. In this study, the growth in estimated ultimate recovery of oil and gas in fields made up of sandstone reservoirs formed in a complex depositional environment (Frio strand plain exploration play) is examined. The results presented here show how the growth of oil and gas fields is tied directly to the architectural element of the shoreline processes and tectonics that caused the deposition of the individual sand bodies hosting the producible hydrocarbon.     

A New Reserve Growth Model for United States Oil and Gas Fields

Reserve (or field) growth, which is an appreciation of total ultimate reserves through time, is a well-recognized phenomenon, particularly in mature petroleum provinces. The importance of forecasting reserve growth accurately in a mature petroleum province made it necessary to develop improved growth functions, and a critical review of the original Arrington method was undertaken. During a five-year (1992–1996), the original Arrington method gave 1.03% higher than the actual oil reserve growth, whereas the proposed modified method gave a value within 0.3% of the actual growth, and therefore it was accepted for the development for reserve growth models.During a five-year (1992–1996), the USGS 1995 National Assessment gave 39.3% higher oil and 33.6% lower gas than the actual growths, whereas the new model based on Modified Arrington method gave 11.9% higher oil and 29.8% lower gas than the actual growths. The new models forecast predict reserve growths of 4.2 billion barrels of oil (2.7%) and 30.2 trillion cubic feet of gas (5.4%) for the conterminous U.S. for the next five years (1997–2001).     

A petroleum discovery-rate forecast revisited—The problem of field growth

A forecast of the future rates of discovery of crude oil and natural gas for the 123,027-km² Miocene/Pliocene trend in the Gulf of Mexico was made in 1980. This forecast was evaluated in 1988 by comparing two sets of data: (1) the actual versus the forecasted number of fields discovered, and (2) the actual versus the forecasted volumes of crude oil and natural gas discovered with the drilling of 1,820 wildcat wells along the trend between January 1, 1977, and December 31, 1985. The forecast specified that this level of drilling would result in the discovery of 217 fields containing 1.78 billion barrels of oil equivalent; however, 238 fields containing 3.57 billion barrels of oil equivalent were actually discovered. This underestimation is attributed to biases introduced by field growth and, to a lesser degree, the artificially low, pre-1970's price of natural gas that prevented many smaller gas fields from being brought into production at the time of their discovery; most of these fields contained less than 50 billion cubic feet of producible natural gas.     

The Evolution of Giant Oil Field Production Behavior

The giant oil fields of the world are only a small fraction of the total number of fields, but their importance is huge. Over 50% of the world’s oil production came from giants by 2005 and more than half of the world’s ultimate reserves are found in giants. Based on this, it is reasonable to assume that the future development of the giant oil fields will have a significant impact on the world oil supply. In order to better understand the giant fields and their future behavior, one must first understand their history. This study has used a comprehensive database on giant oil fields in order to determine their typical parameters, such as the average decline rate and life-times of giants. The evolution of giant oil field behavior has been investigated to better understand future behavior. One conclusion is that new technology and production methods have generally led to high depletion rates and rapid decline. The historical trend points towards high decline rates of fields currently on plateau production. The peak production generally occurs before half the ultimate reserves have been produced in giant oil fields. A strong correlation between depletion-at-peak and average decline rate is also found, verifying that high depletion rate leads to rapid decline. Our result also implies that depletion analysis can be used to rule out unrealistic production expectations from a known reserve, or to connect an estimated production level to a needed reserve base.     

A Bootstrap Approach to Computing Uncertainty in Inferred Oil and Gas Reserve Estimates

This study develops confidence intervals for estimates of inferred oil and gas reserves based on bootstrap procedures. Inferred reserves are expected additions to proved reserves in previously discovered conventional oil and gas fields. Estimates of inferred reserves 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 US onshore and State offshore areas. When the same computational methods used in the 1995 Assessment are applied to more recent data, the 80-year (from 1997 through 2076) inferred reserve estimates for pre-1997 discoveries located in the lower 48 onshore and state offshore areas amounted to a total of 39.7 billion barrels of oil (BBO) and 293 trillion cubic feet (TCF) of gas. The 90% confidence interval about the oil estimate derived from the bootstrap approach is 22.4 BBO to 69.5 BBO. The comparable 90% confidence interval for the inferred gas reserve estimate is 217 TCF to 413 TCF. The 90% confidence interval describes the uncertainty that should be attached to the estimates. It also provides a basis for developing scenarios to explore the implications for energy policy analysis.     

Econometric and learning curve estimation of U.S. potential oil supply

This study employs (1) a simple econometric model to generate a time series of drilling footage to the year 2040 and (2) learning models to estimate the oil reserve additions from that drilling, given scenarios of oil price and projected U.S. population. Reserve additions are estimated separately for the lower 48 states and Alaska regions by estimating separate drilling footage and learning models for each region. Generally, the estimates of potential supply from undiscovered oil fields and from extensions of known fields are more optimistic than recent estimates by others. For a $1989 price of about $20/barrel (bbl), which is similar to recent prices, the potential supply of oil is estimated to be approximately 60.7 billion bbl, with 95-percent confidence bounds of 54.3 and 67.1 billion bbl. For a price of $25.50/bbl, potential supply is estimated to be approximately 82 billion bbl, with 95-percent confidence bounds of 74.5 and 89.5 billion bbl. Although estimates of potential oil supply for the entire United States are more optimistic than other recent estimates, the part of that supply estimated to be forthcoming from Alaska is smaller than other recent estimates: 2.3 and 3.3 billion bbl for prices of about $20 and $25.50 per barrel, respectively. Thus, reserve additions from the lower 48 states through development drilling and through improved recovery and production technologies will become increasingly important to future U.S. oil supply.     

Deep Natural Gas Resources

From a geological perspective, deep natural gas resources generally are defined as occurring in reservoirs below 15,000 feet, whereas ultradeep gas occurs below 25,000 feet. From an operational point of view, deep may be thought of in a relative sense based on the geologic and engineering knowledge of gas (and oil) resources in a particular area. Deep gas occurs in either conventionally trapped or unconventional (continuous-type) basin-center accumulations that are essentially large single fields having spatial dimensions often exceeding those of conventional fields.Exploration for deep conventional and continuous-type basin-center natural gas resources deserves special attention because these resources are widespread and occur in diverse geologic environments. In 1995, the U.S. Geological Survey estimated that 939 TCF of technically recoverable natural gas remained to be discovered or was part of reserve appreciation from known fields in the onshore areas and state waters of the United States. Of this USGS resource, nearly 114 trillion cubic feet (Tcf) of technically recoverable gas remains to be discovered from deep sedimentary basins. Worldwide estimates of deep gas also are high. The U.S. Geological Survey World Petroleum Assessment 2000 Project recently estimated a world undiscovered conventional gas resource outside the U.S. of 844 Tcf below 4.5 km (about 15,000 feet).Less is known about the origins of deep gas than about the origins of gas at shallower depths because fewer wells have been drilled into the deeper portions of many basins. Some of the many factors contributing to the origin and accumulation of deep gas include the initial concentration of organic matter, the thermal stability of methane, the role of minerals, water, and nonhydrocarbon gases in natural gas generation, porosity loss with increasing depth and thermal maturity, the kinetics of deep gas generation, thermal cracking of oil to gas, and source rock potential based on thermal maturity and kerogen type. Recent experimental simulations using laboratory pyrolysis methods have provided much information on the origins of deep gas.Technologic problems are among the greatest challenges to deep drilling. Problems associated with overcoming hostile drilling environments (e.g. high temperatures and pressures, and acid gases such as CO₂ and H₂S) for successful well completion, present the greatest obstacles to drilling, evaluating, and developing deep gas fields. Even though the overall success ratio for deep wells (producing below 15,000 feet) is about 25%, a lack of geological and geophysical information continues to be a major barrier to deep gas exploration.Results of recent finding-cost studies by depth interval for the onshore U.S. indicate that, on average, deep wells cost nearly 10 times more to drill than shallow wells, but well costs and gas recoveries differ widely among different gas plays in different basins.Based on an analysis of natural gas assessments, deep gas holds significant promise for future exploration and development. Both basin-center and conventional gas plays could contain significant deep undiscovered technically recoverable gas resources.     

Application of the modified Arps-Roberts discovery proces model to the 1995 U.S. National Oil and Gas Assessment

ARDS (version 4.01), a modified version of the Arps-Roberts discovery process model, was used to forecast the remaining oil and gas resources in more than 50 provinces, super-exploration plays, and individual plays in the onshore and offshore United States for the 1995 National Oil and Gas Assessment. The size distribution of oil and gas fields was estimated for the underlying distribution of fields; the size distribution for the remaining fields was calculated to be the difference between this distribution and that of discovered fields. The guidelines that govern the 1995 National Assessment require the underlying size distribution of fields to be estimated by using only data from two standard commercial data files (the NRG Associates field file and the Petroleum Information Inc. well file). However, a variety of situations required further modification of the discovery process modeling system; for example, multiple exploration plays that occurred nearly simultaneously and also displaced each other in time, and the phenomenon of field growth introduced a large bias in the forecasts produced by the discovery process models for some provinces.     

Phosphate rock demand into the next century: Impact on wolld food supply

A vital and indisputable link exists between phosphate rock and world food supply. Phosphate rock is the source of phosphorus used to make phosphatic fertilizers, essential for growing the food needed by humans in the world today and in the future. We modeled the depletion of the known reserves and reserve base (which includes reserves) of phosphate rock based on various scenarios for increasing population and future demand for phosphate. Using these scenarios, the presently known reserves will be depleted within about 50 years, and the remainder of the reserve base will be depleted within the next 100 years. For this model, we used rates of growth of demand for phosphate rock of between 1 and 1.7 percent annually. We also examined demand rates that decrease over time toward demand stasis. Growthrate scenarios that stabilize demand at the year 2100 are little different from unconstrained growth. Demand stabilization by 2025 extends the reserve base by only about 50 years. Additional considerations could affect these depletion scenarios, causing them to be substantially too high or too low. Nonetheless, the incluctable conclusion in a world of continuing phosphate demand is that society, to extend phosphate rock reserves and reserve base beyond the approximate 100 year depletion date, must find additional reserves and/ or reduce the rate of growth of phosphate demand in the future. Society must: 91) increase the efficiency of use of known resources of easily minable phosphate rock; (2) discover new, economically-minable resources; or (3) develop the technology to economically mine the vast but currently uneconomic resources of phosphate rock that exist in the world. Otherwise, the future availability of present-cost phosphate, and the cost or availability of world food will be compromised, perhaps substantially.     

A Scenario-Based Hydrocarbon Production Forecast for Louisiana

Conventional oil and gas productions in Louisiana has been in decline for four decades, but in recent years, new technology and capital investment have opened up a significant new resource play in the Haynesville shale, reversing Louisiana’s gas production decline. The need for long-term forecasting has become more important for state planning and for facilitating efficient regulatory development and incentive programs, as the largest oil and gas fields diminish in productivity and the promise of unconventional resources are realized. The purpose of this article is to present a hydrocarbon production forecast for Louisiana using disaggregate resource classes and a transparent analytic framework. A field-level evaluation is employed for producing fields categorized by primary product, resource category, geographic area, and production class. Undiscovered fields are classified according to conventional and unconventional categories and are modeled using a probabilistic and scenario-based forecast. The analytic framework is described along with a discussion of the model results and limitations of the analysis. Louisiana is in the early stages of transitioning to a primarily gas-producing state, and the manner in which the Haynesville shale develops will play a critical role in deliverability and economic prospects in the future.     

Annotated bibliography of methodology for assessment of undiscovered oil and gas resources

An annotated bibliography of methodology of assessment of undiscovered oil and gas resources is presented as a useful reference for those engaged in resource assessment. The articles that are included deal only with quantitative assessment of undiscovered or inferred resources. the articles in this bibliography are classified largely according to the major assessment method that was applied in each situation. Major assessment methods include areal and volumetric yield methods, field size distributions, historical extrapolation, deposit modeling, organic geochemical mass balance methods, and direct expert assessment. Other categories include mathematical tools, reserve growth/confirmation, quantitative characterization of undiscovered resources, and general topics. For the purpose of future updates, we solicit contributions of articles that may have been missed in the preparation of this bibliography.     

Correlation between assessments of undiscovered oil and gas resources

There is an inbuilt correlation between estimated quantities of oil and gas produced by probabilistic assessments of undiscovered oil and gas resources. Correlation between assessed quantities of oil and gas occurs at every level, whether prospects, plays, basins, continents, or the world. Providing that the oil and gas are assessed in the same run of the computer program, the correlation can be calculated using the paired values of the undiscovered oil and gas volumes calculated in each of the Monte Carlo simulations. It can be seen in the shape and density of a point plot of these paired values. Alternatively, the correlation can be calculated theoretically using an equation written in terms of the data input to the assessment program. These commonly include distributions for the number of accumulations (N), the success rate (s), the accumulation sizes (V), an oil to gas conversion factor, and a proportion of oil to oil plus gas (P _OOG). The cause of the correlation is investigated and explained using point plots and equations for a variety of input distributions. The shape and density of each plot are determined by the pattern of the numbers of oil and gas accumulations, the sizes of the accumulations, and the proportions of oil to oil plus gas. The correlation is caused by the dispersion or spread of the input distributions. It may be positive or negative, tending toward positive as the dispersions ofN, s, andV increase and the dispersion ofP _OOG decreases. The correlation indicates that there is a relationship between the undiscovered oil and gas resources that may be described by fitting a linear regression to a plot of the paired values of the total oil and gas resources. The relationship should be quoted as part of the assessment and might be used to make a better estimate of the value of the undiscovered resources.     

Oil- and gas-resource assessment in certain South American Basins—An application of ARDS (Ver. 5.0) to complex exploration and discovery histories

The modified Arps-Roberts Discovery Process Modeling System [ARDS (Ver. 4.01)] has recently been upgraded [ARDS (Ver. 5.0)] and applied to a wide variety of field discovery and wildcat drilling data with differing characteristics. ARDS is designed to forecast the number and sizes of undiscovered fields in an exploration play or basin by using historical drilling and discovery data. Fields used as input may be grown or ungrown. Two models for field growth—one offshore and the other onshore—have been implemented (Schuenemeyer and Drew, 1996). Uncertainty attributable to field growth is estimated via simulation. This upgrade of ARDS has been designed to handle situations when the data cannot be partitioned into homogeneous regions, but where estimation of the number of remaining oil and gas fields is still meaningful. In this upgrade of ARDS, many restrictions, which include those on the number of fields and wildcat wells required to forecast the size distribution of the oil and gas fields that remain to be discovered in an exploration play, a basin, or other target area, have been removed. In addition, flexibility has been gained by reforming the criteria for convergence of the model. In all, 32 basins and subbasins in South America were examined, 18 of which had sufficient data to be amenable to forecasting the field-size distribution of undiscovered oil and gas resources directly by using the Petroconsultants Inc. (1993) field discovery and wildcat drilling data. Overall, ARDS (Ver. 5.0) performed well in estimating the field-size distribution of undiscovered oil and gas resources in the 18 basins and subbasins. The aggregate volume of undiscovered petroleum resources was characterized by using histograms of the distribution of resources and the following five statistics: the mean, the 80% trimmed mean, and the 10,50 (median), and 90 quantiles. More than 38 billion barrels of oil equivalent (BOE) in fields that contain more than one million BOE individually were forecast as remaining to be discovered. The largest basin, the Campos (Brazil), is forecast to contain nearly 10 billion BOE undiscovered resources. The East Venezuela Basin (excluding the Furrial Trend) is forecast to contain about 8 billion BOE; the Austral-Magallanes Basin (Argentina and Chile), about 7 billion BOE; and the Napo (Colombia and Ecuador) and the Neuquen (Argentina) Basins, between 3 billion and 4 billion BOE. A subset of these basins that illustrate the increased flexibility of ARDS are discussed.     

A Royalty Revenue Forecast Model for Louisiana

Louisiana receives royalty revenue when minerals are produced on state-owned lands and water bottoms, federal properties within the state, and offshore fields underlying federal and state jurisdiction within 3–6 nautical miles from the coastline. Royalty revenue on oil and gas production has averaged $465 million per year and has contributed 3–7% of the state general revenue over the past decade. The purpose of this article is to develop a royalty revenue forecast model to assist in state budgeting and planning purposes. Producing fields are evaluated within a probabilistic framework to capture the uncertainty associated with future capital outlays and operational changes, and a discovery model is used to generate production from fields expected to be discovered in the future. The forecasts are combined with commodity price scenarios and royalty rate assumptions to generate a royalty revenue outlook for the state. We estimate that cumulative royalty revenue during 2012–2017 will range from $704 million to $1,408 million for oil production and from $286 million to $1,145 million for gas production for commodity prices of 60–120 $/bbl and 2–8 $/Mcf. At $80/bbl and $4/Mcf, cumulative royalty receipts from 2012 to 2017 are estimated at $1,510 million.     

The Geology and Petroleum Resources of Kansas: A Review From Alpha to Omega or From the Pleistocene to the Precambrian

The geological story of Kansas is told through the rocks that are present. It is a simple story in generalities but complex in detail. Knowing the story, gives insight into understanding the occurrence and location of possible economic valuable minerals, such as petroleum. This is a brief review of Kansas geology with respect to the known occurrence of oil and gas. Kansas is part of the Midcontinent oil province with oil having been discovered 150 years ago and commercial production commencing in 1873. Although many prospects remain in Kansas, the state has gone from the number 1 producer in the U.S. in 1916 to 8th today. Exploration for new oil and gas production therefore is going to have to be more imaginative and utilize new approaches and techniques to find the elusive petroleum. There are possibilities however for the prospector who can search diligently. Although the big fields probably have been discovered, the prospects today are deeper, in more undetectable traps, and in essentially untested places.     

Assessment Methodology and Results From the Canadian Gas Potential Committee 2001 Report

Since 1991 volunteers from the Canadian Gas Potential Committee (CGPC) have conducted assessments of undiscovered gas potential in Canada. Reports were published in 1997 and 2001. The 2001 CGPC report assessed all established and some conceptual exploration plays in Canada and incorporated data from about 29,000 discovered gas pools and gas fields. Mainly year-end 1998 data were used in the analysis of 107 established exploration plays. The CGPC assessed gas in place without using economic cut offs. Estimates of nominal marketable gas were made, based on the ratio between gas in place and marketable gas in discovered pools. Only part of the estimated nominal marketable gas actually will be available, primarily because of restrictions on access to exploration and the small size of many accumulations. Most plays were assessed using the Petrimes program where it could be applied. Arps-Roberts assessments were made on plays where too many discovered pools were present to use the Petrimes program. Arps-Roberts assessments were corrected for economic truncation of the discovered pool sample. Several methods for making such corrections were tried and examples of the results are shown and compared with results from Petrimes. In addition to assessments of established plays, 12 conceptual plays, where no discoveries have been made, were assessed using Petrimes subjective methodology. An additional 65 conceptual plays were recognized, discussed, and ranked without making a quantitative assessment. No nominal marketable gas was attributed to conceptual plays because of the high risk of failure in such plays. Nonconventional gas in the form of coalbed methane, gas hydrates, tight gas, and shale gas are discussed, but no nominal marketable gas is attributed to those sources pending successful completion of pilot study projects designed to demonstrate commercially viable production. Conventional gas resources in Canada include 340 Tcf of gas in place in discovered pools and fields and 252 Tcf of undiscovered gas in place. Remaining nominal marketable gas includes 96 Tcf in discovered pools and fields and 138 Tcf of undiscovered nominal marketable gas. The Western Canada Sedimentary Basin holds 61% of the remaining nominal marketable gas. Future discoveries from that area will be mainly in pools smaller than 2.5 Bcf of marketable gas and increasing levels of exploratory drilling will be required to harvest this undiscovered resource. A pragmatic, geologically focussed approach to the assessment of undiscovered gas potential by the CGPC provides a sound basis for future exploration and development planning. Peer reviewed assessment on a play-by-play basis for entire basins provides both detailed play information and the ability to evaluate new exploration results and their impact on overall potential.     

Large-area urban growth observations—a hierarchical kernel approach based on image texture

Geografisk Tidsskrift, Danish Journal of Geography 105(2):39–47, 2005

A multi-scale classification algorithm based entirely on computation of image texture in moving windows is presented and discussed. The rationale for using kernel-based methods as opposed to segment-based methods for texture-based land cover classification is discussed, as well as, the need for identifying strategies that may limit the effects of the inherent weaknesses of the kernel-based methods. Part of the proposed solution to this problem is to omit the search for an optimum kernel size and rather use different sizes concurrently followed by a weighted summary overlay process based on associated scores. The spatial growth pattern of the city of Accra, Ghana, is assessed over a 17 years period using the algorithm. Land-cover maps showing the extension of the new residential areas on the fringe of Accra are produced from Landsat ETM satellite imagery. These areas constitute the rapidly expanding frontier of urban Accra into its rural surroundings. The classification discriminates between new residential areas that have a distinct urban appearance and areas that are in a transition phase between rural and urban use. Finally, comparisons are made to a previous satellite-based study of land cover changes for the period 1985–1991.     

Guiding Principles of USGS Methodology for Assessment of Undiscovered Conventional Oil and Gas Resources

During the last 30 years, the methodology for assessment of undiscovered conventional oil and gas resources used by the Geological Survey has undergone considerable change. This evolution has been based on five major principles. First, the U.S. Geological Survey has responsibility for a wide range of U.S. and world assessments and requires a robust methodology suitable for immaturely explored as well as maturely explored areas. Second, the assessments should be based on as comprehensive a set of geological and exploration history data as possible. Third, the perils of methods that solely use statistical methods without geological analysis are recognized. Fourth, the methodology and course of the assessment should be documented as transparently as possible, within the limits imposed by the inevitable use of subjective judgement. Fifth, the multiple uses of the assessments require a continuing effort to provide the documentation in such ways as to increase utility to the many types of users. Undiscovered conventional oil and gas resources are those recoverable volumes in undiscovered, discrete, conventional structural or stratigraphic traps. The USGS 2000 methodology for these resources is based on a framework of assessing numbers and sizes of undiscovered oil and gas accumulations and the associated risks. The input is standardized on a form termed the Seventh Approximation Data Form for Conventional Assessment Units. Volumes of resource are then calculated using a Monte Carlo program named Emc2, but an alternative analytic (non-Monte Carlo) program named ASSESS also can be used. The resource assessment methodology continues to change. Accumulation-size distributions are being examined to determine how sensitive the results are to size-distribution assumptions. The resource assessment output is changing to provide better applicability for economic analysis. The separate methodology for assessing continuous (unconventional) resources also has been evolving. Further studies of the relationship between geologic models of conventional and continuous resources will likely impact the respective resource assessment methodologies.