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Natural Resources Research - Exploration ventures in frontier areas have high risks. Before committing to them, firms prepare regional resource assessments to evaluate the potential payoffs. With... 相似文献
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Emil D. Attanasi 《Natural Resources Research》2016,25(4):487-496
In an earlier report, changes in bitumen prices at Hardesty, Alberta, Canada, were modeled as the responses to changes in monthly prices of Hardesty light/medium crude oil for the period 2000–2006 with a simple error correction econometric model. This note re-examines that price relationship for the period 2009–2014. Over the period 2006–2014, there was also rapid growth in North American light oil production from low-permeability carbonate, sandstone, and shale reservoirs. During that period, Canadian raw bitumen production grew by more than 12% per year and there was significant geographical diversification in its markets. Results of the statistical analysis showed that the change in the dynamic relationships between bitumen prices and Hardesty light oil prices probably reflected, in part, the maturation of bitumen markets and closer integration with North American light oil markets. The analysis also examines the dynamic relationships between bitumen prices and West Texas Intermediate and Brent international benchmark crude oil prices. Ideally, if bitumen prices are found to be closely related to a widely traded benchmark crude oil, the benchmark crude oil price forecasts could be used as a basis for predicting bitumen prices. However, neither of international benchmark crude oils tested had high explanatory power. 相似文献
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Geologic resource assessments describe the location, general characteristics, and estimated volumes of resources, whether in situ or technically recoverable. Such compilations are only an initial step in economic resource evaluation. This paper identifies, by examples from the Illinois and Appalachian basins, the salient features of a geologic assessment that assure its usefulness to downstream economic analysis. Assessments should be in sufficient detail to allocate resources to production units (mines or wells). Coal assessments should include the spatial distribution of coal bed characteristics and the ability to allocate parts of the resource to specific mining technologies. For coal bed gas assessment, the production well recoveries and well deliverability characteristics must be preserved and the risk structure should be specified so dryholes and noncommercial well costs are recovered by commercially successful wells. 相似文献
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Prediction of Resource Volumes at Untested Locations Using Simple Local Prediction Models 总被引:1,自引:1,他引:0
This paper shows how local spatial nonparametric prediction models can be applied to estimate volumes of recoverable gas resources
at individual undrilled sites, at multiple sites on a regional scale, and to compute confidence bounds for regional volumes
based on the distribution of those estimates. An approach that combines cross-validation, the jackknife, and bootstrap procedures
is used to accomplish this task. Simulation experiments show that cross-validation can be applied beneficially to select an
appropriate prediction model. The cross-validation procedure worked well for a wide range of different states of nature and
levels of information. Jackknife procedures are used to compute individual prediction estimation errors at undrilled locations.
The jackknife replicates also are used with a bootstrap resampling procedure to compute confidence bounds for the total volume.
The method was applied to data (partitioned into a training set and target set) from the Devonian Antrim Shale continuous-type
gas play in the Michigan Basin in Otsego County, Michigan. The analysis showed that the model estimate of total recoverable
volumes at prediction sites is within 4 percent of the total observed volume. The model predictions also provide frequency
distributions of the cell volumes at the production unit scale. Such distributions are the basis for subsequent economic analyses.
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Emil D. AttanasiEmail: |
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The primary objectives of this research were to (1) investigate empirical methods for establishing regional trends in unconventional
gas resources as exhibited by historical production data and (2) determine whether or not incorporating additional knowledge
of a regional trend in a suite of previously established local nonparametric resource prediction algorithms influences assessment
results. Three different trend detection methods were applied to publicly available production data (well EUR aggregated to
80-acre cells) from the Devonian Antrim Shale gas play in the Michigan Basin. This effort led to the identification of a southeast–northwest
trend in cell EUR values across the play that, in a very general sense, conforms to the primary fracture and structural orientations
of the province. However, including this trend in the resource prediction algorithms did not lead to improved results. Further
analysis indicated the existence of clustering among cell EUR values that likely dampens the contribution of the regional
trend. The reason for the clustering, a somewhat unexpected result, is not completely understood, although the geological
literature provides some possible explanations. With appropriate data, a better understanding of this clustering phenomenon
may lead to important information about the factors and their interactions that control Antrim Shale gas production, which
may, in turn, help establish a more general protocol for better estimating resources in this and other shale gas plays. 相似文献
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If observed oil and gas field size distributions are obtained by random samplings, the fitted distributions should approximate that of the parent population of oil and gas fields. However, empirical evidence strongly suggests that larger fields tend to be discovered earlier in the discovery process than they would be by random sampling. Economic factors also can limit the number of small fields that are developed and reported. This paper examines observed size distributions in state and federal waters of offshore Texas. Results of the analysis demonstrate how the shape of the observable size distributions change with significant hydrocarbon price changes. Comparison of state and federal observed size distributions in the offshore area shows how production cost differences also affect the shape of the observed size distribution. Methods for modifying the discovery rate estimation procedures when economic factors significantly affect the discovery sequence are presented. A primary conclusion of the analysis is that, because hydrocarbon price changes can significantly affect the observed discovery size distribution, one should not be confident about inferring the form and specific parameters of the parent field size distribution from the observed distributions.This paper was presented at Emerging Concepts, MGUS-87 Conference, Redwood City, California, 13–15 April 1987. 相似文献
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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 相似文献
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A method is presented for the estimation of undiscovered oil and gas resources in partially explored areas where economic truncation has caused some discoveries to go unreported; therefore distorting the relationship between the observed discovery size distribution and the parent or ultimate field size distribution. The method is applied to the UK's northern and central North Sea provinces. A discovery process model is developed to estimate the number and size distribution of undiscovered fields in this area as of 1983. The model is also used to forecast the rate at which fields will be discovered in the future. The appraisal and forecasts pertain to fields in size classes as small as 24 million barrels of oil equivalent (BOE). Estimated undiscovered hydrocarbon resources of 11.79 billion BOE are expected to be contained in 170 remaining fields. Over the first 500 wildcat wells after 1 January 1983, the discovery rate in this areas is expected to decline by 60% from 15 million BOE per wildcat well to six million BOE per wildcat well. 相似文献
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Forecasting petroleum discoveries in sparsely drilled areas: Nigeria and the North Sea 总被引:1,自引:0,他引:1
Decline function methods for projecting future discoveries generally capture the crowding effects of wildcat wells on the discovery rate. However, these methods do not accommodate easily situations where exploration areas and horizons are expanding. In this paper, a method is presented that uses a mapping algorithm for separating these often countervailing influences. The method is applied to Nigeria and the North Sea. For an amount of future drilling equivalent to past drilling (825 wildcat wells), future discoveries (in resources found) for Nigeria are expected to decline by 68% per well but still amount to 8.5 billion barrels of oil equivalent (BOE). Similarly, for the total North Sea for an equivalent amount and mix among areas of past drilling (1322 wildcat wells), future discoveries are expected to amount to 17.9 billion BOE, whereas the average discovery rate per well is expected to decline by 71%. 相似文献