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D. L. Gautier

Publications and source records attributed to D. L. Gautier.

At least 19 recordsLinked to original sources
USGS2022

Reserve growth in oil fields of the North Sea

The assessment of petroleum resources of the North Sea, as well as other areas of the world, requires a viable means to forecast the amount of growth of reserve estimates (reserve growth) for discovered fields and to predict the potential fully developed sizes of undiscovered fields. This study investigates the utility of North Sea oil field data to construct reserve-growth models. Oil fields of the North Sea provide an excellent dataset in which to examine the mechanisms, characteristics, rates and quantities of reserve growth because of the high level of capital investments, implementation of sophisticated technologies and careful data collection. Additionally, these field data are well reported and available publicly. Increases in successive annual estimat es of recoverable crude oil volumes indicate that oil fields in the North Sea, collectively and in each country, experience reserve growth. Specific patterns of reserve growth are observed among countries and primary producing reservoir-rock types. Since 1985, Norwegian oil fields had the greatest volume increase; Danish oil fields increased by the greatest percentage relative to 1985 estimates; and British oil fields experienced an increase in recoverable oil estimates for the first ten years since 1985, followed by a slight reduction. Fields producing primarily from clastic reservoirs account for the majority of the estimated recoverable oil and, therefore, these fields had the largest volumetric increase. Fields producing primarily from chalk (limestone) reservoirs increased by a greater percentage relative to 1985 estimates than did fields producing primarily from clastic reservoirs. Additionally, the largest oil fields had the greatest volumetric increases. Although different reserve-growth patterns are observed among oil fields located in different countries, the small number of fields in Denmark precludes construction of reserve-growth models for that country. However, differences in reserve-growth patterns among oil fields that produce from primarily clastic and primarily chalk reservoirs, in addition to a greater number of fields in each of the two categories, allow separate reserve-growth models to be constructed based on reservoir-rock type. Reserve-growth models referenced to the date of discovery and to the date of first production may be constructed from North Sea field data. Years since discovery or years since first production are used as surrogates for, or measures of, field-development effort that is applied to promote reserve growth. Better estimates of recoverable oil are made as fields are developed. Because much of the field development occurs some time later than the field discovery date, reserve-growth models referenced to the date of first production may provide a more appropriate measure of development than does date of discovery. ?? 2005 EAGE/Geological Society of London.

Petroleum Geoscience↗
USGS2012

Compaction of basin sediments: Modeling based on time-temperature history

Porosity decrease of sandstones, carbonates, and shales during burial is modeled here in terms of time-temperature exposure rather than in terms of depth. Loss of porosity (ϕ) in the subsurface is represented by a power function, ϕ = A ( M ) B , where A and B are constants and M is a measure of integrated time-temperature history. Regression lines of carbonate and sandstone porosity upon Lopatin's time-temperature index of thermal maturity (TTI) generally fall within a rather narrow envelope whose axis is approximated by ϕ = 30(TTI) −0.33 . This equation is useful for regional modeling of carbonate and sandstone compaction. Dependence of porosity upon integrated time-temperature history implies that basin sediments are not in equilibrium but compact through geologic time. Calculations show that subsidence resulting from the loss of porosity with increasing time-temperature exposure (as opposed to deeper burial) can produce a second-stage, passively formed basin containing many hundreds of meters of sediments.

Journal of Geophysical Research Solid Earth↗
USGS2011

U.S. Geological Survey circum-arctic resource appraisal

Among the greatest uncertainties in future energy supply is the amount of oil and gas yet to be found in the Arctic. Using a probabilistic geology-based methodology, the U.S. Geological Survey has assessed the area north of the Arctic Circle. The Circum-Arctic Resource Appraisal (CARA) consists of three parts: (1) Mapping the sedimentary sequences of the Arctic (Grantz and others 2009), (2) Geologically based estimation of undiscovered technically recoverable petroleum (Gautier and others 2009, discussed in this presentation) and (3) Economic appraisal of the cost of delivering the undiscovered resources to major markets (also reported at this conference by White and others). We estimate that about 30% of the world's undiscovered gas and about 13% of the world's undiscovered oil may be present in the Arctic, mostly offshore under less than 500m of water. Billion BOE-plus accumulations of gas and oil are predicted at a 50% probability in the Kara Sea, Barents Sea, offshore East and West Greenland, Canada, and Alaska. On a BOE basis, undiscovered natural gas is three times more abundant than oil in the Arctic and is concentrated in Russian territory. Oil resources, while critically important to the interests of Arctic countries, are probably not sufficient to significantly shift the current geographic patterns of world oil production. Copyright 2011, Offshore Technology Conference.

Conference Paper↗
USGS2008

Assessment of undiscovered oil and gas resources of the Timan-Pechora Basin Province, Russia, 2008

The U.S. Geological Survey (USGS) recently assessed the undiscovered oil and gas potential of the Timan-Pechora Basin Province in Russia as part of the USGS Circum-Arctic Oil and Gas Resource Appraisal program. Geologically, the Timan-Pechora Basin Province is a triangular-shaped cratonic block bounded by the northeast-southwest trending Ural Mountains and the northwest-southeast trending Timan Ridge. The northern boundary is shared with the South Barents Sea Province (fig.1). The Timan-Pechora Basin Province has a long history of oil and gas exploration and production. The first field was discovered in 1930 and, after 75 years of exploration, more than 230 fields have been discovered and more than 5,400 wells have been drilled. This has resulted in the discovery of more than 16 billion barrels of oil and 40 trillion cubic feet of gas.

Timan-Pechora Basin Province↗
USGS2007

Circum-Arctic petroleum systems identified using decision-tree chemometrics

Source- and age-related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55??N latitude. A unique, multitiered chemometric (multivariate statistical) decision tree was created that allowed automated classification of 31 genetically distinct circumArctic oil families based on a training set of 622 oil samples. The method, which we call decision-tree chemometrics, uses principal components analysis and multiple tiers of K-nearest neighbor and SIMCA (soft independent modeling of class analogy) models to classify and assign confidence limits for newly acquired oil samples and source rock extracts. Geochemical data for each oil sample were also used to infer the age, lithology, organic matter input, depositional environment, and identity of its source rock. These results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2006

Oil resources - Estimates and uncertainties

Oil reserves are reasonably well known, but they are not a reliable indicator of longterm supply. Future oil availability will depend upon reserve additions, which are highly uncertain. New reserves will come from three sources: 1) new field discoveries, 2) growth of reserves in existing fields, and 3) development of unconventional resources. U.S. Geological Survey estimates of global undiscovered conventional oil have a mean value of about 650 billion barrels, but the estimates range from a few hundred billion barrels to 1100 billion and more if the possibility of successful exploration in remote, untested basins is included. Reserve growth in existing fields, which has added more than 250 billion barrels to reserves in the last two decades, is equally uncertain; global estimates of future growth range from tens of billions to 1000 billion barrels or more. Unconventional resources, particularly heavy oil and tar, may also add many hundreds of billions of barrels to reserves, but at unknown rates and costs. Thus estimated future additions to oil reserves range over an order of magnitude, from a few hundred to a few thousand billion barrels. Given the importance of oil to human activity, planners might want to retain the flexibility to adapt to a range of possible scenarios of future oil supply.

Conference Paper↗
USGS2005

An evaluation of the U.S. Geological Survey World Petroleum Assessment 2000

This study compares the additions to conventional crude oil and natural gas reserves as reported from January 1996 to December 2003 with the estimated undiscovered and reserve-growth volumes assessed in the U.S. Geological Survey World Petroleum Assessment 2000, which used data current through 1995. Approximately 28% of the estimated additions to oil reserves by reserve growth and approximately 11% of the estimated undiscovered oil volumes were realized in the 8 yr since the assessment (27% of the time frame for the assessment). Slightly more than half of the estimated additions to gas reserves by reserve growth and approximately 10% 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 ratio of 3:1. The greatest amount of reserve growth for crude oil occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in sub-Saharan Africa. The greatest amount of reserve growth for natural gas occurred in the Middle East and North Africa, whereas the greatest contribution from new-field discoveries occurred in the Asia Pacific region. On an energy-equivalent basis, volumes of new gas-field discoveries exceeded new oil-field discoveries. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

USGS assessment of oil and gas resource potential of the San Joaquin Basin, California

The assessment of oil and gas resource potential of the San Joaquin Basin, California, by the U.S. Geological Survey, is discussed. Two categories of future additions to reserves were evaluated, first was resource in undiscovered accumulations and second was growth of reserves in already discovered accumulations. The mean estimate of undiscovered oil resources is 393 barrels. The greatest potential for oil accumulations larger than 10 million barrels is probably in Miocene and Eocene reservoirs of the westside of the basin and in deep basin south of the Bakersfield Arch.

Conference Paper↗
USGS1987

Isotopic composition of pyrite: Relationship to organic matter type and iron availability in some North American cretaceous shales

The S isotope composition of pyrite in Cretaceous shales from the Western Interior of North America is related to organic C abundance, kerogen type and Fe availability. Both calcareous and noncalcareous rocks show a correlation between S and C, but noncalcareous rocks are relatively enriched in S with a higher S/C ratio. This higher ratio probably shows that pyrite formation was Fe limited in the calcareous rocks. Organic-carbon-rich noncalcareous shales accumulated slowly beneath anoxic bottom waters. The anoxic bottom waters allowed hydrogen-rich organic matter to be preserved. Such shales have a narrow range of 34 S-depleted sulfide and have Fe/S ratios like stoichiometric pyrite, suggesting that pyrite formation in organic-rich shales was also limited by Fe availability. Conversely, organic-poor shales commonly accumulated at comparatively high rates, contain hydrogen-poor and refractory organic matter, and have a wide range of pyrite-S isotopic compositions. These organic-poor shales contain post-sulfidic authigenic minerals such as siderite and have excess reactive Fe rather than pyrite stoichiometry. Evidently Fe played a large role in early diagenesis and determined the course of post-sulfidic diagenesis. Fe availability was, however, mainly controlled by provenance, by the rates of sediment accumulation, and by the oxygen content of the depositional environment.

Chemical Geology: Isotope Geoscience Section↗
USGS1987

Median-porosity contour maps of the J Sandstone, Dakota Group, in the Denver Basin, Colorado, Nebraska, and Wyoming

The Lower Cretaceous J sandstone of the Dakota Group is present in the Denver basin in eastern Colorado, southeastern Wyoming, and southwestern Nebraska. Deposited during a regression of the Cretaceous epicontinental sea, this informally named unit is composed primarily of sandstone and shale of deltaic and near shore-marine origin. The J sandstone can be divided into an upper transgressive sand, a middle marginal-marine and deltaic facies, and a lower prodelta sequence (Clark, 1978). The depth from the surface to the top of the J sandstone increases from about 4,000 ft on the gently-dipping eastern flank of the basin to more than 8,000 ft at the basin ax is near the steeply-dipping western flank. Porosity data compiled in this study were determined from J sandstone cores from 134 widely spaced boreholes. Porosity in areas of poor core coverage was determined from neutron density logs from an additional 20 boreholes ( corrected to core average grain density). Median, rather than average, porosity was used in order to minimize the statistical effect of anomalously high and low porosity values. Thirty-five oil companies and independent operators supplied core porosity data. Core porosities were determined by means of helium porosimetry, primarily by Core Laboratories of Denver, Colo.

Colorado, Nebraska, Wyoming↗