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Donald L. Gautier

Publications and source records attributed to Donald L. Gautier.

At least 37 records · Page 2Linked to original sources
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

Aggregation methodology for the circum-arctic resource appraisal

This paper presents a methodology that intends to aggregate the results of a recent assessment of undiscovered conventional oil and gas resources of the Arctic by the U.S. Geological Survey. The assessment occurred in 48 geologically defined regions called assessment units. The methodology includes using assessor specified pair-wise correlations as the basis to construct a correlation matrix. Sampling from this matrix generates more realistic uncertainty estimates of aggregated resources than if assumptions of total independence or total dependence are made. The latter two assumptions result in overly narrow or overly broad estimates. Aggregation results for resources in regions north of the Arctic Circle are presented.

Mathematical Geosciences↗
USGS2010

Assessment of undiscovered oil and gas resources of the North Caspian Basin, Middle Caspian Basin, North Ustyurt Basin, and South Caspian Basin Provinces, Caspian Sea Area, 2010

The U.S. Geological Survey estimated mean volumes of technically recoverable, conventional, undiscovered petroleum resources at 19.6 billion barrels of crude oil, 243 trillion cubic feet of natural gas, and 9.3 billion barrels of natural gas liquids for the Caspian Sea area, using a geology-based assessment methodology.

Fact Sheet↗
USGS2010

Reserve growth during financial volatility in a technologically challenging world

Reserve growth (growth-to-known) is the addition of oil and gas quantities to reported proved or proved-plus-probable reserves in discovered fields. The amount of reserve growth fluctuates through time with prevailing economic and technological conditions. Most reserve additions are the result of investment in field operations and in development technology. These investments can be justified by higher prices of oil and gas, the desire to maintain cash flow, and by greater recovery efficiency in well established fields. The price/cost ratio affects decisions for field abandonment and (or) implementation of improved recovery methods. Although small- to medium-size fields might show higher percentages of reserve growth, a relatively few giant fields contribute most volumetric reserve growth, indicating that companies may prefer to invest in existing fields with low geologic and production risk and an established infrastructure in order to increase their price/cost relationship. Whereas many previous estimates of reserve growth were based on past trends of reported reserves, future reserve growth is expected to be greatly affected by financial volatility and fluctuating economic and technological conditions.

Open-File Report↗
USGS2009

Assessment of undiscovered oil and gas in the Arctic

Among the greatest uncertainties in future energy supply and a subject of considerable environmental concern is the amount of oil and gas yet to be found in the Arctic. By using a probabilistic geology-based methodology, the United States Geological Survey has assessed the area north of the Arctic Circle and concluded that about 30% of the world’s undiscovered gas and 13% of the world’s undiscovered oil may be found there, mostly offshore under less than 500 meters of water. Undiscovered natural gas is three times more abundant than oil in the Arctic and is largely concentrated in Russia. Oil resources, although important to the interests of Arctic countries, are probably not sufficient to substantially shift the current geographic pattern of world oil production.

Science↗
USGS2009

Assessment of Undiscovered Petroleum Resources of the Barents Sea Shelf

Four geologic provinces of the Barents Sea shelf were assessed for undiscovered crude oil, natural gas, and natural gas liquid or condensate resources as part of the U.S. Geological Survey's Circum-Arctic Oil and Gas Resource Appraisal. Using a geology-based methodology, the mean undiscovered, conventional, technically recoverable petroleum resources in the Barents Sea Shelf are estimated to be more than 76 billion barrels of oil equivalent, which includes approximately 11 billion barrels of crude oil, 380 trillion cubic feet of natural gas, and 2 billion barrels of natural gas liquids.

Fact Sheet↗
USGS2009

Eocene total petroleum system — North and East of the Eocene West Side Fold Belt Assessment Unit of the San Joaquin Basin Province

The North and East of Eocene West Side Fold Belt Assessment Unit (AU) of the Eocene Total Petroleum System of the San Joaquin Basin Province comprises all hydrocarbon accumulations within the geographic and stratigraphic limits of this confirmed AU. Oil and associated gas accumulations occur in Paleocene through early middle Miocene marine to nonmarine sandstones found on the comparatively stable northeast shelf of the basin. The assessment unit is located north and east of the thickest accumulation of Neogene sediments and the west side fold belt. The area enclosed by the AU has been affected by only mild deformation since Eocene time. Traps containing known accumulations are mostly low-relief domes, anticlines, and up-dip basin margin traps with faulting and stratigraphic components. Map boundaries of the assessment unit are shown in figures 19.1 and 19.2; this assessment unit replaces the Northeast Shelf of Neogene Basin play 1006, the East Central Basin and Slope North of Bakersfield Arch play 1010, and part of the West Side Fold Belt Sourced by Pre-middle Miocene Rocks play 1005 considered by the U.S. Geological Survey (USGS) in their 1995 National Assessment (Beyer, 1996). Stratigraphically, the AU includes rocks from the uppermost crystalline basement to the topographic surface. In the region of overlap with the Central Basin Monterey Diagenetic Traps Assessment Unit, the North and East of Eocene West Side Fold Belt AU extends from basement rocks to the top of the Temblor Formation (figs. 19.3 and 19.4). In map view, the northern boundary of the assessment unit corresponds to the northernmost extent of Eocene-age Kreyenhagen Formation. The northeast boundary is the eastern limit of possible oil reservoir rocks near the eastern edge of the basin. The southeast boundary corresponds to the pinch-out of Stevens sand of Eckis (1940) to the south, which approximately coincides with the northern flank of the Bakersfield Arch (fig. 19.1). The AU is bounded on the southwest by the limit of major west side structural deformation and to the northwest by the San Andreas Fault and the limit of hydrocarbon-prospective strata in the Coast Ranges. As described by Gautier and others (this volume, chapter 2), existing oil fields in the San Joaquin Basin Province were assigned to assessment units based on the identified petroleum system and reservoir rocks in each field. Vallecitos oil field in the extreme northwest corner of the basin was assigned to the Eocene Total Petroleum System, because oil analyses conducted for this San Joaquin Basin assessment indicate that Eocene oil charged the reservoir rocks (Lillis and Magoon, this volume, chapter 9). Some literature classifies the Vallecitos oil field as part of the northernmost fold of the basin’s west side fold belt (see, for example, Rentschler, 1985; Bartow, 1991), but because of the oil field’s spatial separation and differing trend from the west side fold belt, Vallecitos field was considered here to be within the North and East of Eocene West Side Fold Belt Assessment Unit rather than in the other assessment unit in the Eocene Total Petroleum System, the Eocene West Side Fold Belt. Primary fields in the assessment unit are defined as those containing hydrocarbon resources greater than the USGS minimum threshold for assessment (0.5 million barrels of oil); secondary fields contain smaller volumes of oil but constitute a significant show of hydrocarbons.

California↗
USGS2008

Assessment of undiscovered oil and gas resources of the West Greenland-East Canada Province, 2008

The U.S. Geological Survey (USGS) recently assessed the undiscovered oil and gas potential of the West Greenland-East Canada Province as part of the USGS Circum-Arctic Oil and Gas Resource Appraisal effort. The West Greenland-East Canada Province is essentially the offshore area between west Greenland and east Canada and includes Baffin Bay, Davis Strait, Lancaster Sound, and Nares Strait west of and including Kane Basin. The tectonic evolution of the West Greenland-East Canada Province led to the formation of several major structural domains that are the geologic basis for the five assessment units (AU) defined in this study. The five AUs encompass the entire province. Each AU was assessed in its entirety for undiscovered, technically recoverable (assuming absence of sea ice) oil and gas resources, but the assessment results reported here are only for those portions of each AU that are north of the Arctic Circle, as that latitude defines the area of the Circum-Arctic oil and gas assessment.

Baffin Bay, Davis Strait, Kane Basin, Lancaster So↗
USGS2008

Circum-Arctic resource appraisal: Estimates of undiscovered oil and gas north of the Arctic Circle

The U.S. Geological Survey (USGS) has completed an assessment of undiscovered conventional oil and gas resources in all areas north of the Arctic Circle. Using a geology-based probabilistic methodology, the USGS estimated the occurrence of undiscovered oil and gas in 33 geologic provinces thought to be prospective for petroleum. The sum of the mean estimates for each province indicates that 90 billion barrels of oil, 1,669 trillion cubic feet of natural gas, and 44 billion barrels of natural gas liquids may remain to be found in the Arctic, of which approximately 84 percent is expected to occur in offshore areas.

Fact Sheet↗
USGS2008

Assessment of undiscovered oil and gas resources of the West Siberian Basin Province, Russia, 2008

The U.S. Geological Survey (USGS) recently assessed the undiscovered oil and gas potential of the West Siberian Basin Province in Russia as part of the USGS Circum-Arctic Resource Appraisal program. This province is the largest petroleum basin in the world and has an areal extent of about 2.2 million square kilometers. It is a large rift-sag feature bounded to the west by the Ural fold belt, to the north by the Novaya Zemlya fold belt and North Siberian Sill, to the south by the Turgay Depression and Altay-Sayan fold belt, and to the east by the Yenisey Ridge, Turukhan-Igarka uplift, Yenisey-Khatanga Basin, and Taimyr High. The West Siberian Basin Province has a total discovered oil and gas volume of more than 360 billion barrels of oil equivalent (Ulmishek, 2000). Exploration has led to the discovery of tens of giant oil and gas fields, including the Urengoy gas field with more than 3500 trillion cubic feet of gas reserves and Samotlar oil field with reserves of nearly 28 billion barrels of oil (Ulmishek, 2003). This report summarizes the results of a reassessment of the undiscovered oil and gas potential of that part of the province north of the Arctic Circle; a previous assessment that included the entire province was completed in 2000 (Ulmishek, 2000). The total petroleum system (TPS) and assessment units (AU) defined by the USGS for the assessments in 2000 were adopted for this assessment. However, only those parts of the Aus lying wholly or partially north of the Arctic Circle were assessed for this study.

West Siberian Basin Province↗
USGS2008

Engineering and Economics of the USGS Circum-Arctic Oil and Gas Resource Appraisal (CARA) Project

This Open-File report contains illustrative materials, in the form of PowerPoint slides, used for an oral presentation given at the Fourth U.S. Geological Survey Workshop on Reserve Growth of petroleum resources held on March 10-11, 2008. The presentation focused on engineering and economic aspects of the Circum-Arctic Oil and Gas Resource Appraisal (CARA) project, with a special emphasis on the costs related to the development of hypothetical oil and gas fields of different sizes and reservoir characteristics in the North Danmarkshavn Basin off the northeast coast of Greenland. The individual PowerPoint slides highlight the topics being addressed in an abbreviated format; they are discussed below, and are amplified with additional text as appropriate. Also included in this report are the summary results of a typical ?run? to generate the necessary capital and operating costs for the development of an offshore oil field off the northeast coast of Greenland; the data are displayed in MS Excel format generated using Questor software (IHS Energy, Inc.). U.S. Geological Survey (USGS) acknowledges that this report includes data supplied by IHS Energy, Inc.; Copyright (2008) all rights reserved. IHS Energy has granted USGS the permission to publish this report.

Open-File Report↗
USGS2008

A four-dimensional petroleum systems model for the San Joaquin Basin Province, California: Chapter 12 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

A calibrated numerical model depicts the geometry and three-dimensional (3-D) evolution of petroleum systems through time (4-D) in a 249 x 309 km (155 x 192 mi) area covering all of the San Joaquin Basin Province of California. Model input includes 3-D structural and stratigraphic data for key horizons and maps of unit thickness, lithology, paleobathymetry, heat flow, original total organic carbon, and original Rock-Eval pyrolysis hydrogen index for each source rock. The four principal petroleum source rocks in the basin are the Miocene Antelope shale of Graham and Williams (1985; hereafter referred to as Antelope shale), the Eocene Kreyenhagen Formation, the Eocene Tumey formation of Atwill (1935; hereafter referred to as Tumey formation), and the Cretaceous to Paleocene Moreno Formation. Due to limited Rock-Eval/total organic carbon data, the Tumey formation was modeled using constant values of original total organic carbon and original hydrogen index. Maps of original total organic carbon and original hydrogen index were created for the other three source rocks. The Antelope shale was modeled using Type IIS kerogen kinetics, whereas Type II kinetics were used for the other source rocks. Four-dimensional modeling and geologic field evidence indicate that maximum burial of the three principal Cenozoic source rocks occurred in latest Pliocene to Holocene time. For example, a 1-D extraction of burial history from the 4-D model in the Tejon depocenter shows that the bottom of the Antelope shale source rock began expulsion (10 percent transformation ratio) about 4.6 Ma and reached peak expulsion (50 percent transformation ratio) about 3.6 Ma. Except on the west flank of the basin, where steep dips in outcrop and seismic data indicate substantial uplift, little or no section has been eroded. Most petroleum migration occurred during late Cenozoic time in distinct stratigraphic intervals along east-west pathways from pods of active petroleum source rock in the Tejon and Buttonwillow depocenters to updip sandstone reservoirs. Satisfactory runs of the model required about 18 hours of computation time for each simulation using parallel processing on a Linux-based cluster.

California↗
USGS2008

Miocene Total Petroleum System -- Southeast Stable Shelf Assessment Unit of the San Joaquin Basin Province: Chapter 13 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

The confirmed stratigraphic and structural-stratigraphic Southeast Stable Shelf Assessment Unit (AU) of the Miocene Total Petroleum System (San Joaquin Basin Province) comprises all hydrocarbon accumulations within the geographic limits of the AU. Traps typically display low dip angles, gentle folds, and normal faults. Reservoirs, which range in age from fractured Mesozoic basement rocks to Holocene nonmarine rocks, are mainly Oligocene to Miocene sandstones from the uppermost slope and adjacent shelf of the San Joaquin Basin, shallow marine shelf sandstones mainly of Miocene age, and nonmarine sandstones and conglomerates mostly of Pliocene- Pleistocene age. Faults have relatively small vertical displacements. Map boundaries of the assessment unit are shown in figures 13.1 and 13.2; this assessment unit replaces the Southeast Stable Shelf play 1002 considered by the U.S. Geological Survey (USGS) in its 1995 National Assessment (Beyer, 1996). Stratigraphically, the AU extends from the uppermost crystalline basement to the topographic surface (fig. 13.3). The AU is bounded on the west by the approximate location of the shelfslope break of the San Joaquin Basin in late Miocene time, thus excluding reservoirs in the deep-water Stevens sand of Eckis (1940). The eastern boundary of the AU is the edge of onlap of Neogene sedimentary sequences on crystalline basement rocks of the Sierra Nevada. The northern AU boundary is placed at the approximate northern extent of oils in shelf-facies reservoirs known to be sourced by the Miocene Total Petroleum System. This northern boundary explicitly excludes the Deer Creek and Jasmin fields, which were included in the corresponding earlier (1995) USGS play (Beyer, 1996), but which are now known to contain oil generated from Eocene source rocks. The White Wolf Fault bounds the AU on the south.

California↗
USGS2008

Miocene Total Petroleum System -- Lower Bakersfield Arch Assessment Unit of the San Joaquin Basin Province: Chapter 14 in Petroleum systems and geologic assessment of oil and gas in the San Joaquin Basin Province, California

The Lower Bakersfield Arch Assessment Unit (AU) of the Miocene Total Petroleum System (San Joaquin Basin Province) is primarily defined by the distribution of hydrocarbons generated from biosiliceous shale of the Monterey Formation and by the distribution of basinal-facies sandstones of the Stevens sand of Eckis (1940; hereafter referred to as Stevens sand). Traps are principally stratigraphic and structural/stratigraphic, with most discovered accumulations occurring in deep-sea channel, fan, and braided submarine channel deposits of the late Miocene Stevens sand. Smaller and fewer accumulations are found in older sandstones such as the Vedder and Jewett Sands of Oligocene to Miocene age. Compared to the west side of the basin, the AU is largely unstructured, except for localized down-to-the-basin normal faults. Map boundaries of the assessment unit are shown in figures 14.1 and 14.2; this assessment unit supersedes the Lower Bakersfield Arch play 1003 considered by the U.S. Geological Survey (USGS) in the 1995 National Assessment (Beyer, 1996). Stratigraphically, the AU extends from the uppermost crystalline basement to the topographic surface (fig. 14.3). The AU is bounded on the east and north by the limit of basinal- facies sandstones of the Stevens sand; this eastern boundary corresponds to the approximate location of the shelf-slope break of the San Joaquin Basin in late Miocene time. The western boundary of the AU is the approximate eastern limit of structural deformation on the basin’s west side. The White Wolf Fault bounds the AU on the south.

California↗
USGS2007

Executive Summary — Assessment of undiscovered oil and gas resources of the San Joaquin Basin Province of California, 2003

In 2003, the U.S. Geological Survey (USGS) completed an assessment of the oil and gas resource potential of the San Joaquin Basin Province of California (fig. 1.1). The assessment is based on the geologic elements of each Total Petroleum System defined in the province, including hydrocarbon source rocks (source-rock type and maturation and hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five total petroleum systems and ten assessment units within these systems. Undiscovered oil and gas resources were quantitatively estimated for the ten assessment units (table 1.1). In addition, the potential was estimated for further growth of reserves in existing oil fields of the San Joaquin Basin.

California↗
USGS2007

An Evaluation of the USGS World Petroleum Assessment 2000 - Supporting Data

Introduction In June 2000, the U.S. Geological Survey (USGS) published the results of a world petroleum assessment (exclusive of the United States), based on data current through 1995 (U.S. Geological Survey World Energy Assessment Team, 2000). The assessment included the volumes of undiscovered crude oil and natural gas estimated to have the potential to be added to reserves in a 30-year time frame (to 2025). Klett and others (2005) compared the actual additions to reserves as reported from January 1996 to December 2003 (IHS Energy, 2003) with those estimates, apportioned to the 1996-2003 period (27 percent of the 30-year time frame). The present report (1) provides tabular data, not included in the 2005 report by Klett and others, that support the graphical displays and (2) briefly summarizes the interpretations and conclusions presented in the 2005 report. Approximately 28 percent of the additions to oil reserves by reserve growth and approximately 11 percent of the estimated undiscovered oil volumes that were estimated for the World Petroleum Assessment 2000 (U.S. Geological Survey World Energy Assessment Team, 2000) were realized in the 8 years since that assessment. Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10 percent of the estimated undiscovered gas volumes were realized. Between 1995 and 2003, growth of oil reserves in previously discovered fields exceeded new-field discoveries as a source of global additions to reserves of conventional oil by a factor of about 3 to 1. The greatest amount of reserve growth for crude oil was in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries was in Sub-Saharan Africa. The greatest amount of reserve growth for natural gas was in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries was in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas field discoveries exceeded new oil field discoveries. The graphs are based on the data listed in tables 1 and 2.

Open-File Report↗