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Emil D. Attanasi

Publications and source records attributed to Emil D. Attanasi.

At least 37 records · Page 2Linked to original sources
USGS2017

A database and probabilistic assessment methodology for carbon dioxide enhanced oil recovery and associated carbon dioxide retention in the United States

The U.S. Geological Survey (USGS) has developed an assessment methodology for estimating the potential incremental technically recoverable oil resources resulting from carbon dioxide-enhanced oil recovery (CO 2 -EOR) in reservoirs with appropriate depth, pressure, and oil composition. The methodology also includes a procedure for estimating the CO 2 that remains in the reservoir after the CO 2 -EOR process is complete. The methodology relies on a reservoir-level database that incorporates commercially available geologic and engineering data. The mathematical calculations of this assessment methodology were tested and produced realistic results for the Permian Basin Horseshoe Atoll, Upper Pennsylvanian-Wolfcampian Play (Texas, USA). The USGS plans to use the new methodology to conduct an assessment of technically recoverable hydrocarbons and associated CO 2 sequestration resulting from CO 2 -EOR in the United States.

Energy Procedia↗
USGS2016

Bitumen prices and structural changes in North American crude oil markets

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.

Natural Resources Research↗
USGS2015

Profiles of reservoir properties of oil-bearing plays for selected petroleum provinces in the United States

Profiles of reservoir properties of oil-bearing plays for selected petroleum provinces in the United States were developed to characterize the database to be used for a potential assessment by the U.S. Geological Survey (USGS) of oil that would be technically recoverable by the application of enhanced oil recovery methods using injection of carbon dioxide (CO 2 -EOR). The USGS assessment methodology may require reservoir-level data for the purposes of screening conventional oil reservoirs and projecting CO 2 -EOR performance in terms of the incremental recoverable oil. The information used in this report is based on reservoir properties from the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring Associates, Inc. (2012). As described by Nehring Associates, Inc., the database “covers all producing provinces (basins) in the United States except the Appalachian Basin and the Cincinnati Arch.” Under contract to the USGS, INTEK, Inc., developed and applied algorithms to estimate variables useful in projecting EOR performance at the reservoir level and to complete some partial reservoir records of the “Significant Oil and Gas Fields of the United States Database” (Nehring Associates, Inc., 2012). The augmented database is referred to here as the “Comprehensive Resource Database” (CRD). The CRD play and province classification scheme corresponds to the definitions used in the 1995 USGS National Oil and Gas Assessment (NOGA). The profiles in this report consist of a resource table and a six-part figure showing the variation of reservoir parameters selected because of their importance in the choice of a miscible or immiscible method for CO 2 -EOR and in the assessment of potential oil recovery using the EOR processes. A subset of these reservoirs may be available for either miscible- or immiscible-type flooding for CO 2 -EOR. Plays with fewer than 10 oil reservoirs were not graphed and were omitted from the province profiles. For this report and for the purposes of screening reservoirs as candidates for the application of CO 2 -EOR methods, oil reservoirs must have no more than 10,000 standard cubic feet of natural gas per barrel of oil at surface conditions. Oil-bearing plays presented in this report must contain at least one oil reservoir so defined. The profile plots allow geologists to evaluate the range of empirical and default values of the oil reservoir characteristics within a play and across plays that belong to the same province in the CRD. For most plays, the default estimates can be identified by the stacking of points at a single value on strip charts in the profiles. Reasonable default values should be within the range of the reservoir parameter values assigned by Nehring Associates, Inc. (2012), to reservoirs of that particular play. Each province profile figure consists of five strip charts and a boxplot. The five strip charts display for individual plays the following reservoir-fluid and reservoir properties: A , oil density (American Petroleum Institute [API] gravity in degrees); B , computed pseudo-Dykstra-Parsons coefficient; C , reservoir porosity (in percent); D , reservoir permeability (in millidarcies); and E , estimates of the original oil in place (OOIP) per unit volume of reservoir rock (in barrels per acre-foot). The OOIP per unit volume of reservoir rock is an indicator of the relative richness of the oil reservoir and is derived from estimates in the CRD of OOIP, reservoir acreage, and net pay. The net pay is the interval of productive reservoir rock. The same data for OOIP per unit volume are graphed as a strip chart ( E ) and a boxplot ( F ).

Open-File Report↗
USGS2014

Evaluation of development options for Alaska North Slope viscous and heavy oil

Current estimates of discovered viscous and heavy oil in Alaska’s North Slope are 12 billion barrels of oil-in-place and 12–18 billion barrels of oil-in-place, respectively (see Appendix 1 for conversion to SI units). Since the early 1990s to the end of 2010, cumulative viscous oil production has amounted to 150 million barrels, and there has been no commercial production of heavy oil. During the last three decades, the industry has been challenged to develop technologies to commercially produce these untapped oil resources in this Arctic environment. In this paper, the general locations and geologic properties of the viscous oil-bearing West Sak/Schrader Bluff and heavy oil-bearing Ugnu stratigraphic intervals are described first. The geologic variability within these deposits and the evolution of technology have forced an incremental development approach, requiring costly field testing at the pilot scale of innovative extraction techniques. Although viscous oil is currently produced, its development is not mature, and firms appear to be still spending large sums on new approaches to improve recovery. The analysis specifies a representative viscous oil project and then applies a “real options” framework using simulation to determine whether the risked expected project value is sufficient to fund required expenditures on extraction process research and field testing. Computations show available field test funds to be highly sensitive to the operator’s hurdle rate of return as well as the range in magnitude of potential State revenues. The contribution of the paper is solving this problem using an approach where the extreme low return and high scenarios need only be specified, and where the uncertainties are modeled with beta distributions based on historical data or expert opinion.

Alaska↗
USGS2012

Role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia’s future demand for gas imports

Demand for natural gas is increasing more rapidly than anticipated in Far East markets because (1) China has modified its policies in order to increase reliance on gas, in part to mitigate the growth in its coal consumption (which now stand at almost half of world coal production), (2) Japan has announced its intention to eventually shutdown its nuclear power industry, and (3) India, which currently has more than 400 million people without electricity, desires to accelerate electrification. This analysis investigates the potential role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia's future demand for gas imports. It initially surveys the discovered or known gas in stranded gas accumulations in Central Asia, Russia, Australia, Indonesia, and Malaysia. It then examines the primary gas import markets of China, India, Japan, and South Korea by describing energy use, gas demand trends, and domestic gas supplies to establish boundaries that encompass the wide variation in gas import demands in these markets during the two decades following 2020. Then the cost of developing and delivering gas through overland pipelines from selected stranded gas fields in Central Asia and Russia to China is examined. Analysis shows that for the Shanghai market in China, the costs of developing and delivering Russia's stranded gas from the petroleum provinces of eastern Siberia are competitive with costs estimated for stranded gas from Central Asia. However, for the Western Siberian Basin, delivered gas costs are at least 3 US dollars per thousand cubic feet (USD/Mcf) higher than delivered gas from Central Asia. The extraction and transport costs to a liquefaction plant for gas from stranded gas fields located in Australia, Indonesia, Malaysia, and the basins of eastern Siberia are then evaluated. The resource cost functions presented show development and extraction costs as a function of the volume of stranded gas developed for each country. The analysis demonstrates that, although the Russian fields in areas of eastern Siberia are large with relatively low extraction costs, distances to a potential liquefaction plant at Vladivostok make them initially the high cost suppliers of the liquefied natural gas (LNG) market. For the LNG markets examined, Australia and Malaysia are initially the lowest cost suppliers. For the Shanghai market, a comparison of the cost of supplying gas by pipeline with the cost of supplying LNG shows that the pipeline costs from areas of eastern Siberia and Central Asia are generally lower than delivered cost of gas as LNG from the LNG supply sources considered.

Central Asia, Southeast Asia↗
USGS2012

Role of stranded gas from Central Asia and Russia in meeting Europe’s future import demand for gas

Stranded gas is natural gas in discovered fields that is currently not commercially producible for either physical or economic reasons. This study examines stranded gas from Russia and Central Asia and the role it can play in addressing Europe’s growing demand for imported natural gas requiring additional volumes of gas in excess of 130 trillion cubic feet. We find sufficient volumes of stranded gas in fields in the Central Asian state of Turkmenistan in the Amu-Darya Basin and in Russian fields in the West Siberian Basin. The analysis focused on the estimated cost of extraction and delivery to a single market location for various concentrations of gas in stranded gas fields in Central Asia and Russia. At import prices of $10 per million British thermal units (MMBTU), there are sufficient gas resources in stranded fields that can be commercially developed and delivered to the European market. If, however, imported gas prices fall below $7 per MMBTU, most of the stranded gas evaluated from West Siberia will not be commercial. The costs of delivering gas from the largest stranded gas fields in Turkmenistan and Azerbaijan were calculated to be greater than 30% below the costs of delivering gas from the largest stranded gas fields in Russia, which are located in the Yamal Peninsula. Central Asian gas producers, particularly those east of the Caspian Sea, have limited market options due to the near monopoly position that Gazprom holds in transporting pipeline gas from east of Europe. This study examines several additional options to supply gas to Europe by reviewing expected delivered costs from North African and Atlantic basin suppliers.

Natural Resources Research↗
USGS2011

Empirical methods for detecting regional trends and other spatial expressions in antrim shale gas productivity, with implications for improving resource projections using local nonparametric estimation techniques

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.

Michigan↗
USGS2011

New U.S. Geological Survey method for the assessment of reserve growth

Reserve growth is defined as the estimated increases in quantities of crude oil, natural gas, and natural gas liquids that have the potential to be added to remaining reserves in discovered accumulations through extension, revision, improved recovery efficiency, and additions of new pools or reservoirs. A new U.S. Geological Survey method was developed to assess the reserve-growth potential of technically recoverable crude oil and natural gas to be added to reserves under proven technology currently in practice within the trend or play, or which reasonably can be extrapolated from geologically similar trends or plays. This method currently is in use to assess potential additions to reserves in discovered fields of the United States. The new approach involves (1) individual analysis of selected large accumulations that contribute most to reserve growth, and (2) conventional statistical modeling of reserve growth in remaining accumulations. This report will focus on the individual accumulation analysis. In the past, the U.S. Geological Survey estimated reserve growth by statistical methods using historical recoverable-quantity data. Those statistical methods were based on growth rates averaged by the number of years since accumulation discovery. Accumulations in mature petroleum provinces with volumetrically significant reserve growth, however, bias statistical models of the data; therefore, accumulations with significant reserve growth are best analyzed separately from those with less significant reserve growth. Large (greater than 500 million barrels) and older (with respect to year of discovery) oil accumulations increase in size at greater rates late in their development history in contrast to more recently discovered accumulations that achieve most growth early in their development history. Such differences greatly affect the statistical methods commonly used to forecast reserve growth. The individual accumulation-analysis method involves estimating the in-place petroleum quantity and its uncertainty, as well as the estimated (forecasted) recoverability and its respective uncertainty. These variables are assigned probabilistic distributions and are combined statistically to provide probabilistic estimates of ultimate recoverable quantities. Cumulative production and remaining reserves are then subtracted from the estimated ultimate recoverable quantities to provide potential reserve growth. In practice, results of the two methods are aggregated to various scales, the highest of which includes an entire country or the world total. The aggregated results are reported along with the statistically appropriate uncertainties.

Scientific Investigations Report↗
USGS2010

Economic basis of resource information systems: The case of streamflow network design

A general method for the economic design of natural resource information systems is presented for a certain class of natural phenomena. The system design is determined by the interaction of the technical input‐output relationship, i.e., the production function, the set of resource constraints, and an economic loss function defined in terms of parameter uncertainty. An application of the proposed method to streamflow network design is presented. Results of this analysis indicate that the method is fairly robust with respect to the assumptions. Observations are made which suggest extensions to flood measurement networks, long‐term precipitation networks, and seismic observation network design.

Water Resources Research↗
USGS2010

Natural bitumen and extra-heavy oil

Natural bitumen and extra-heavy oil are characterised by high viscosity, high density (low API gravity), and high concentrations of nitrogen, oxygen, sulphur, and heavy metals. These characteristics result in higher costs for extraction, transportation, and refining than are incurred with conventional oil. Despite their cost and technical challenges, major international oil companies have found it desirable to acquire, develop, and produce these resources in increasing volumes. Large in-place resource volumes provide a reliable long-term flow of liquid hydrocarbons and provide substantial payoff for any incremental improvements in recovery. High oil prices during 2007 and 2008 spurred new development and production which, in turn, have intensified concern about environmental effects of production increases. Natural bitumen and extra-heavy oil are the remnants of very large volumes of conventional oils that have been generated and degraded, principally by bacterial action. Chemically and texturally, bitumen and extra-heavy oil resemble the residuum generated by refinery distillation of light oil. The resource base of natural bitumen and extra-heavy oil is immense and not a constraint on the expansion of production. These resources can make an important contribution to future oil supply if they can be extracted and transformed into usable refinery feedstock at sufficiently high rates and at costs that are competitive with alternative sources.

Book chapter↗
USGS2009

World petroleum resource estimates and production forecasts: Implications for government policy

Resource estimates alone will not give advance warning of encroaching production difficulties. An analysis of the general stages in the evolution of petroleum production and discovery and of industry statistics provides an estimate of when the stage characterised by increasing production in the market economy countries outside the United States and Canada will end. The analysis indicates that the year of maximum production will be in the 1990s. Economic growth aggravates the difficulties accompanying the production decline by advancing the date of peak production and by increasing the adjustments that must be made as oil production declines.

Natural Resources Forum↗
USGS2009

Petroleum industry drilling in industrialized and developing areas

International drilling statistics show significant differences in target depths as well as the mix between onshore and offshore wells. Unlike the USA, where most of the drilling has been concentrated in depths to 5000 f (shallow depths), the preponderance of wildcat wells drilled in South America and Africa reach much deeper horizons. Offshore wildcat drilling represents less than 4% of total US wildcat drilling. However, more than half of the wildcat wells in Africa and two-fifths of the wildcat wells in South America in 1982 were offshore. In this paper, these differences are traced, in part, to the economic factors that drive petroleum exploration in these areas. Factors such as product markets, drilling costs (rig availability), product transportation systems, and business risk determine the minimum commercial size of hydrocarbon discoveries and the type of operator that can profitably develop discoveries: The plan of the paper is as follows; first, drilling statistics and trends for several areas are discussed. After this, the differences in economic factors that account for the different patterns of exploration are identified. In the concluding section, some strategies are suggested to encourage development of marginally commercial oil and gas fields located at shallow depths

Natural Resources Forum↗
USGS2009

Alternative natural gas contract and pricing structures and incentives of the LNG industry

Gas conversion to liquefied gas (LNG) and transport by LNG tankers is one option for meeting expanding gas consumption and for gas traded internationally. This paper examines the impact of the traditional gas contract provisions of indefinite pricing, market out price ceilings, and take‐or‐pay requirements on the profitability of LNG projects in the context of markets characterized by price and quantity uncertainty. Simulation experiments are used to examine and calibrate the effects of those provisions. The results provide guidance to operators, host countries and purchasers in structuring such contracts. The paper also assesses prospects of future expansion of world LNG capacity.

Natural Resources Forum↗
USGS2009

Economics of undiscovered oil and gas in the North Slope of Alaska: Economic update and synthesis

The U.S. Geological Survey (USGS) has published assessments by geologists of undiscovered conventional oil and gas accumulations in the North Slope of Alaska; these assessments contain a set of scientifically based estimates of undiscovered, technically recoverable quantities of oil and gas in discrete oil and gas accumulations that can be produced with conventional recovery technology. The assessments do not incorporate economic factors such as recovery costs and product prices. The assessors considered undiscovered conventional oil and gas resources in four areas of the North Slope: (1) the central North Slope, (2) the National Petroleum Reserve in Alaska (NPRA), (3) the 1002 Area of the Arctic National Wildlife Refuge (ANWR), and (4) the area west of the NPRA, called in this report the 'western North Slope'. These analyses were prepared at different times with various minimum assessed oil and gas accumulation sizes and with slightly different assumptions. Results of these past studies were recently supplemented with information by the assessment geologists that allowed adjustments for uniform minimum assessed accumulation sizes and a consistent set of assumptions. The effort permitted the statistical aggregation of the assessments of the four areas composing the study area. This economic analysis is based on undiscovered assessed accumulation distributions represented by the four-area aggregation and incorporates updates of costs and technological and fiscal assumptions used in the initial economic analysis that accompanied the geologic assessment of each study area.

Alaska↗
USGS2008

Economic decision making and the application of nonparametric prediction models

Sustained increases in energy prices have focused attention on gas resources in low-permeability shale or in coals that were previously considered economically marginal. Daily well deliverability is often relatively small, although the estimates of the total volumes of recoverable resources in these settings are often large. Planning and development decisions for extraction of such resources must be areawide because profitable extraction requires optimization of scale economies to minimize costs and reduce risk. For an individual firm, the decision to enter such plays depends on reconnaissance-level estimates of regional recoverable resources and on cost estimates to develop untested areas. This paper shows how simple nonparametric local regression models, used to predict technically recoverable resources at untested sites, can be combined with economic models to compute regional-scale cost functions. The context of the worked example is the Devonian Antrim-shale gas play in the Michigan basin. One finding relates to selection of the resource prediction model to be used with economic models. Models chosen because they can best predict aggregate volume over larger areas (many hundreds of sites) smooth out granularity in the distribution of predicted volumes at individual sites. This loss of detail affects the representation of economic cost functions and may affect economic decisions. Second, because some analysts consider unconventional resources to be ubiquitous, the selection and order of specific drilling sites may, in practice, be determined arbitrarily by extraneous factors. The analysis shows a 15-20% gain in gas volume when these simple models are applied to order drilling prospects strategically rather than to choose drilling locations randomly. Copyright ?? 2008 Society of Petroleum Engineers.

SPE Reservoir Evaluation and Engineering↗
USGS2007

Prediction of resource volumes at untested locations using simple local prediction models

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. ?? Springer Science+Business Media, LLC 2007.

Natural Resources Research↗
USGS2007

Statistics of petroleum exploration in the world outside the United States and Canada through 2001

Future oil and gas supplies depend, in part, on the reserves that are expected to be added through exploration and new discoveries. This Circular presents a summary of the statistics and an analysis of petroleum exploration in the world outside the United States and Canada (the study area) through 2001. It updates U.S. Geological Survey Circular 1096 (by E.D. Attanasi and D.H. Root, 1993) and expands coverage of the statistics to areas where drilling and discovery data have recently become available. These new areas include China, the formerly Communist countries of Eastern Europe, and the countries that once were part of the former Soviet Union in Europe and Asia. Data are presented by country but are organized by petroleum provinces delineated by the U.S. Geological Survey World Energy Assessment Team (USGS Digital Data Series DDS?60, published in 2000). The data and analysis are presented in maps and graphs, providing a visual summary of the exploration maturity of an area. The maps show the delineated prospective areas and explored areas through 2001; explored areas have a drilling density that would rule out the occurrence of undetected large petroleum accumulations. Graphs summarize the exploration yields in terms of cumulative recoverable discovered oil and gas by delineated prospective area. From 1992 through 2001 in areas outside the United States and Canada, the delineated prospective area expanded at a rate of about 50,000 square miles per year while the explored area grew at the rate of about 11,000 square miles per year. The delineated prospective area established by 1970 contains about 75 percent of the oil discovered to date in the study area. This area is slightly less than 40 percent of the delineated prospective area established through 2001. Maps and graphs show the extension of the delineated prospective area to deepwater areas offshore of Brazil and West Africa. From 1991 through 2000, offshore discoveries accounted for 59 percent of the oil and 77 percent of the gas discovered in the study area. The petroleum industry's decision to incur the greater costs of moving offshore and into deeper waters appears to be a response to the absence of onshore prospects of comparable quality. Where natural gas can be commercially developed and marketed, data show an expansion of exploration to target gas-prone areas.

Circular↗