Worldwide Estimates of Deep Natural Gas Resources Based on the U.S. Geological Survey World Petroleum Assessment 2000

The U.S. Geological Survey recently assessed undiscovered conventional gas and oil resources in eight regions of the world outside the U.S. The resources assessed were those estimated to have the potential to be added to reserves within the next thirty years. This study is a worldwide analysis of the estimated volumes and distribution of deep (>4.5 km or about 15,000 ft), undiscovered conventional natural gas resources based on this assessment. Two hundred forty-six assessment units in 128 priority geologic provinces, 96 countries, and two jointly held areas were assessed using a probabilistic Total Petroleum System approach. Priority geologic provinces were selected from a ranking of 937 provinces worldwide. The U.S. Geological Survey World Petroleum Assessment Team did not assess undiscovered petroleum resources in the U.S. For this report, mean estimated volumes of deep conventional undiscovered gas resources in the U.S. are taken from estimates of 101 deep plays (out of a total of 550 conventional plays in the U.S.) from the U.S. Geological Survey's 1995 National Assessment of Oil and Gas Resources. A probabilistic method was designed to subdivide gas resources into depth slices using a median-based triangular probability distribution as a model for drilling depth to estimate the percentages of estimated gas resources below various depths. For both the World Petroleum Assessment 2000 and the 1995 National Assessment of Oil and Gas Resources, minimum, median, and maximum depths were assigned to each assessment unit and play; these depths were used in our analysis. Two-hundred seventy-four deep assessment units and plays in 124 petroleum provinces were identified for the U.S. and the world. These assessment units and plays contain a mean undiscovered conventional gas resource of 844 trillion cubic ft (Tcf) occuring at depths below 4.5 km. The deep undiscovered conventional gas resource (844 Tcf) is about 17% of the total world gas resource (4,928 Tcf) based on the provinces assessed and includes a mean estimate of 259 Tcf of U.S. gas from the U.S. 1995 National Assessment. Of the eight regions, the Former Soviet Union (Region 1) contains the largest estimated volume of undiscovered deep gas with a mean resource of343 Tcf.     

The Truncated Discovery Process Model

The purpose of this paper is to describe a mathematical and computer model that has been developed by TransCanada for TransCanada Pipelines (TCPL) and for the Canadian Gas Potential Committee (CGPC) for future Canadian natural gas resource assessment work. It was developed in the contexts of developing a gas supply model for forecasting future Canadian gas supply for TCPL and of improving the CGPC's assessment methodologies and software. The model developed in this paper integrates two discovery process models used by the CGPC and solves the economic truncation problem for semi-mature to mature plays. It is based on applying techniques developed by G. M. Kaufman and J. D. Fuller and colleagues in new ways which extends the work of these authors. This model has a number of important advantages including: fast computational speed, integration of parametric and nonparametric statistical approaches, integration of the Kaufman and others model and the Arps-Roberts model, overcoming a PETRIMES limitation of a maximum of 1000 samples, providing a finding rate forecast for economic analysis and providing a fresh look at solving the economic truncation problem. The details of the new Modified Arps-Roberts Model (now known as the Truncated Discovery Process Model or TDPM for short) are discussed in this paper.     

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.     

Application of discovery process models in estimating petroleum resources at the play level in China

Discovery process modeling has gained wide acceptance in the Chinese exploration community. In recent years, a variety of discovery process models have been applied to the prediction of undiscovered petroleum resources at the play level in sedimentary basins in China. However, challenging problems have been encountered, particularly when one method alone has been applied to small plays in nonmarine sedimentary basins or in plays with an unusual order of discovery wells. This paper presents results gotten by using the lognormal discovery process model of the Geological Survey of Canada and the geoanchored method for three petroleum plays in basins with different geologic settings. Although the predicted shapes of the parentsize distributions which use these two models, were not always similar, the expected values of the total resources and the number of fields (pools) to be discovered are comparable. The combined use of two discovery process models in the same play compensates for the weaknesses in one method compared with the other and vice versa. Thus, more reliable estimates are the result.     

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.     

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.     

Israel's petroleum discovery curve

Oil exploration in Israel began in 1953. Until 1991 a total of 263 exploration wells and 122 development wells were drilled, 3 oil fields and 5 gas fields were discovered, and 4 noncommercial oil discoveries and 1 noncommercial gas discovery were made. Proven in-place reserves amount to 70 million barrels of oil equivalent (MMBOE). Exploration focused on six main plays: Syrian Arc anticlines; Mesozoic platform-edge, structural-stratigraphic traps; the Dead Sea graben; Early Mesozoic structures; Saqiye Group biogenic gas; and Hula Group biogenic gas. The more significant discoveries are associated with the first two plays. Ninety percent of the proven reserves were discovered by the first 71 wildcats, which constitute 27 percent of all wildcats drilled to date. During this phase of exploration, the average success was 7 percent, and the average discovery rate was 0.88 MMBOE per wildcat. Most of the following 192 wildcats were dry holes. If, as experts claim, significant reserves are still undiscovered, previous exploration must be deemed inefficient. The quantitative model of the discovery process also leads to such an assessment.     

Quality of the Log-Geometric Distribution Extrapolation for Smaller Undiscovered Oil and Gas Pool Size

The U.S. Geological Survey procedure for the estimation of the general form of the parent distribution requires that the parameters of the log-geometric distribution be calculated and analyzed for the sensitivity of these parameters to different conditions. In this study, we derive the shape factor of a log-geometric distribution from the ratio of frequencies between adjacent bins. The shape factor has a log straight-line relationship with the ratio of frequencies. Additionally, the calculation equations of a ratio of the mean size to the lower size-class boundary are deduced. For a specific log-geometric distribution, we find that the ratio of the mean size to the lower size-class boundary is the same. We apply our analysis to simulations based on oil and gas pool distributions from four petroleum systems of Alberta, Canada and four generated distributions. Each petroleum system in Alberta has a different shape factor. Generally, the shape factors in the four petroleum systems stabilize with the increase of discovered pool numbers. For a log-geometric distribution, the shape factor becomes stable when discovered pool numbers exceed 50 and the shape factor is influenced by the exploration efficiency when the exploration efficiency is less than 1. The simulation results show that calculated shape factors increase with those of the parent distributions, and undiscovered oil and gas resources estimated through the log-geometric distribution extrapolation are smaller than the actual values.     

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.     

Long-term implications of new U.S. gas estimates

The US Geological Survey’s 1995 estimates of domestic undiscovered plus undeveloped natural gas nearly tripled quantities estimated in its 1989 Assessment. Much of the increase came from selected unconventional resources assessed using the paradigm of continuous-type accumulations. These include such seemingly unrelated “unconventional” gas occurrences as “tight gas,” coalbed gas, gas in shales, and deep basin-center gas. Though only a small fraction of the assessed 352 trillion cubic feet is now economic, the quantity is nevertheless significant. Moreover, the lowest cost resources are close to major gas markets where competing conventional gas is modest. With continued technological improvements these resources can contribute significantly to future U.S. gas supply, even without subsidies     

Assessment of Exploration Bias in Data-Driven Predictive Models and the Estimation of Undiscovered Resources

The spatial distribution of discovered resources may not fully mimic the distribution of all such resources, discovered and undiscovered, because the process of discovery is biased by accessibility factors (e.g., outcrops, roads, and lakes) and by exploration criteria. In data-driven predictive models, the use of training sites (resource occurrences) biased by exploration criteria and accessibility does not necessarily translate to a biased predictive map. However, problems occur when evidence layers correlate with these same exploration factors. These biases then can produce a data-driven model that predicts known occurrences well, but poorly predicts undiscovered resources. Statistical assessment of correlation between evidence layers and map-based exploration factors is difficult because it is difficult to quantify the “degree of exploration.” However, if such a degree-of-exploration map can be produced, the benefits can be enormous. Not only does it become possible to assess this correlation, but it becomes possible to predict undiscovered, instead of discovered, resources. Using geothermal systems in Nevada, USA, as an example, a degree-of-exploration model is created, which then is resolved into purely explored and unexplored equivalents, each occurring within coextensive study areas. A weights-of-evidence (WofE) model is built first without regard to the degree of exploration, and then a revised WofE model is calculated for the “explored fraction” only. Differences in the weights between the two models provide a correlation measure between the evidence and the degree of exploration. The data used to build the geothermal evidence layers are perceived to be independent of degree of exploration. Nevertheless, the evidence layers correlate with exploration because exploration has preferred the same favorable areas identified by the evidence patterns. In this circumstance, however, the weights for the “explored” WofE model minimize this bias. Using these revised weights, posterior probability is extrapolated into unexplored areas to estimate undiscovered deposits.     

U.S. department of the interior U.S. geological survey: Fractal lognormal percentage analysis of the U.S. geological survey’s 1995 national assessment of conventional oil and gas resources

The U.S. Geological Survey periodically makes appraisals of the oil and gas resources of the Nation. In its 1995 National Assessment the onshore areas and adjoining State waters of the Nation were assessed. As part of the 1995 National Assessment, 274 conventional oil plays and 239 conventional nonassociated-gas plays were assessed. The two datasets of estimates studied herein are the following: (1) the mean, undiscovered, technically recoverable oil resources estimated for each of the 274 conventional oil plays, and (2) the mean, undiscovered, technically recoverable gas resources estimated for each of the 239 conventional nonassociatedgas plays. It was found that the two populations of petroleum estimates are both distributed approximately as lognormal distributions. Fractal lognormal percentage theory is developed and applied to the two populations of petroleum estimates. In both cases the theoretical percentages of total resources using the lognormal distribution are extremely close to the empirical percentages from the oil and nonassociated-gas data. For example, 20% of the 274 oil plays account for 73.05% of the total oil resources of the plays if the lognormal distribution is used, or for 75.52% if the data is used; 20% of the 239 nonassociated-gas plays account for 76.32% of the total nonassociated-gas resources of the plays if the lognormal distribution is used, or for 78.87% if the data is used     

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.     

Estimates of Number of Undiscovered Deposits of Gold,Silver, Copper,Lead, and Zinc in the United States

Estimates of the number of undiscovered deposits offer a unique perspective on the nation's undiscovered mineral resources. As part of the 1998 assessment of undiscovered deposits of gold, silver, copper, lead, and zinc, estimates of the number of deposits were made for 305 of the 447 permissive tracts delineated in 19 assessment regions of the country. By aggregating number of undiscovered deposits by deposit type and by assessment region, a picture of the nation's undiscovered resources has emerged. For the nation as a whole, the mean estimate for the number of undiscovered deposits is 950. There is a 90% chance there are at least 747 undiscovered deposits and a 10% chance there are as many as 1,160 undiscovered deposits. For Alaska, the mean estimate for the number of undiscovered deposits is 281. There is a 90% chance there are at least 168 undiscovered deposits and a 10% chance there are as many as 402 undiscovered deposits. Assuming that the majority of deposits used to create the grade and tonnage models that formed the basis for estimating the number of undiscovered deposits are significant deposits, there remain about as many undiscovered deposits as have already been discovered. Consideration of the number of undiscovered deposits as part of national assessments carried out on a recurring basis serves as a leading indicator of the nation's total mineral resources.     

Haynesville Shale Well Performance and Development Potential

Louisiana’s Haynesville Shale is one of several unconventional gas plays that have been discovered in the U.S. in recent years and promise to dramatically change the course of future domestic energy development. The Haynesville Shale is the deepest, hottest, and highest pressured shale among the big four plays in the U.S. with drilling and completion cost ranging between 7 and7 and 10 million per well. The average Haynesville well has an initial production rate of 10 MMcfd and declines rapidly, producing 80% of its expected recovery during the first 2 years of production. The purpose of this article is to describe the productivity characteristics of Haynesville wells, project future production from the inventory of active wells, and assess production potential based on drilling scenarios. We offer statistical analysis of the wells drilled to date and construct type profiles to characterize the play. We estimate that the current inventory of Haynesville wells will produce 3 Tcf over their lifecycles, and within the next 3 years, cumulative build-out in the region will range between 3 and 9 Tcf. To maintain current gas production levels in the state, we estimate that about 550 shale gas wells per year will need to be brought online over the next 3 years.     

Comparison of Methods Used to Estimate Conventional Undiscovered Petroleum Resources: World Examples

Various methods for assessing undiscovered oil, natural gas, and natural gas liquid resources were compared in support of the USGS World Petroleum Assessment 2000. Discovery process, linear fractal, parabolic fractal, engineering estimates, PETRIMES, Delphi, and the USGS 2000 methods were compared. Three comparisons of these methods were made in: (1) the Neuquen Basin province, Argentina (different assessors, same input data); (2) provinces in North Africa, Oman, and Yemen (same assessors, different methods); and (3) the Arabian Peninsula, Arabian (Persian) Gulf, and North Sea (different assessors, different methods). A fourth comparison (same assessors, same assessment methods but different geologic models), between results from structural and stratigraphic assessment units in the North Sea used only the USGS 2000 method, and hence compared the type of assessment unit rather than the method. In comparing methods, differences arise from inherent differences in assumptions regarding: (1) the underlying distribution of the parent field population (all fields, discovered and undiscovered), (2) the population of fields being estimated; that is, the entire parent distribution or the undiscovered resource distribution, (3) inclusion or exclusion of large outlier fields; (4) inclusion or exclusion of field (reserve) growth, (5) deterministic or probabilistic models, (6) data requirements, and (7) scale and time frame of the assessment. Discovery process, Delphi subjective consensus, and the USGS 2000 method yield comparable results because similar procedures are employed. In mature areas such as the Neuquen Basin province in Argentina, the linear and parabolic fractal and engineering methods were conservative compared to the other five methods and relative to new reserve additions there since 1995. The PETRIMES method gave the most optimistic estimates in the Neuquen Basin. In less mature areas, the linear fractal method yielded larger estimates relative to other methods. A geologically based model, such as one using the total petroleum system approach, is preferred in that it combines the elements of petroleum source, reservoir, trap and seal with the tectono-stratigraphic history of basin evolution with petroleum resource potential. Care must be taken to demonstrate that homogeneous populations in terms of geology, geologic risk, exploration, and discovery processes are used in the assessment process. The USGS 2000 method (7th Approximation Model, EMC computational program) is robust; that is, it can be used in both mature and immature areas, and provides comparable results when using different geologic models (e.g. stratigraphic or structural) with differing amounts of subdivisions, assessment units, within the total petroleum system.     

North American Natural Gas: Data Show Supply Problems

Natural gas is increasingly the fuel of choice for domestic and industrial use and for electric power generation. With pipelines in all 50 states, gas now fuels more than one-half of United States homes. Demand for all uses is projected to rise. United States production peaked in 1971, and is in decline. The United States in 2002 imported 15% of its gas from Canada, which amount was 56% of Canada's production. However, Canada's production now also is in decline. Mexico's production declined from 1999 to 2002 against rising demand. Mexico is increasingly a net gas importer from the United States. In both the United States and Canada, intensive drilling is being offset by high depletion rates. Frontiers for more production include deep basin drilling, improved exploration and reservoir development technology, increased coalbed methane exploitation, and access to lands not now accessible because of environmental and other restrictions. Stranded gas in Arctic regions of the United States and Canada offer some potential for additional supplies, but pipeline access is at least five years to ten years or more away. Additional LNG landing facilities are needed, and are planned, but these are several years away in significant numbers. For the immediate future, rationing of available gas by the market mechanism of higher prices seems the only option. In the longer term, it seems North America will be increasingly dependent on LNG.     

An analytical approximation of the distribution of total hydrocarbon discoveries as a function of discovery number

Recently, Manly's method has been successfully applied to hydrocarbon exploration modeling in order to approximate the expected value and the standard deviation of the total amount of hydrocarbons discovered. This method is much faster than running prolonged simulations normally required by the probabilistic model of the hydrocarbon discovery process, and the results are very accurate. This paper extends the usefulness of the approximation method by developing an approximate analytical model of the whole probability distribution of the total volume of hydrocarbons discovered. The mean and the standard deviation from Manly's approximation are used to help set the parameters of a family of beta distributions, to represent the distributions of the total amount of hydrocarbons discovered from the beginning to the end of the exploration process in an area. Three real datasets—the Nova Scotian Shelf from offshore northeastern Canada, the Bistcho Play, and the Zama Play from northwestern Canada—are chosen to verify the methodology developed. Confidence intervals of the forecast for each number of discovered fields are constructed from the analytical approximation and compared with confidence intervals generated by the simulation. Sensitivity analyses are performed to show that the idea of using a family of beta distributions is a robust approximation.     

Estimation of undiscovered deposits in quantitative mineral resource assessments—examples from Venezuela and Puerto Rico

Quantitative mineral resource assessments used by the United States Geological Survey are based on deposit models. These assessments consist of three parts: (1) selecting appropriate deposit models and delineating on maps areas permissive for each type of deposit; (2) constructing a grade-tonnage model for each deposit model; and (3) estimating the number of undiscovered deposits of each type. In this article, I focus on the estimation of undiscovered deposits using two methods: the deposit density method and the target counting method.In the deposit density method, estimates are made by analogy with well-explored areas that are geologically similar to the study area and that contain a known density of deposits per unit area. The deposit density method is useful for regions where there is little or no data. This method was used to estimate undiscovered low-sulfide gold-quartz vein deposits in Venezuela.Estimates can also be made by counting targets such as mineral occurrences, geophysical or geochemical anomalies, or exploration plays and by assigning to each target a probability that it represents an undiscovered deposit that is a member of the grade-tonnage distribution. This method is useful in areas where detailed geological, geophysical, geochemical, and mineral occurrence data exist. Using this method, porphyry copper-gold deposits were estimated in Puerto Rico.     

Geologic risk, economic assessment, and optimal decision making of petroleum plays in the Bohaiwan Basin, northern China

A system of play (trap) assessment based on the analysis of geological characteristics of five different types of petroleum plays in the Bohaiwan Basin, northern China, is proposed. The system makes use of conditional probability, fuzzy logic, and Monte Carlo simulation to assess geologic risk for estimating the undiscovered petroleum resources in a region. Combining the estimates of undiscovered resources with the subsequent economic evaluation of discovered resources by using techniques of optimization, the expected monetary value can be estimated to determine the overall benefits of an investment. A software program has been developed to carry out the calculations.