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R. M. Pollastro

Publications and source records attributed to R. M. Pollastro.

At least 19 recordsLinked to original sources
USGS2011

Assessment of undiscovered oil and gas resources of the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, 2010

The U.S. Geological Survey, using a geoscience-based assessment methodology, estimated mean technically-recoverable undiscovered continuous and conventional resources that total 495 million barrels of oil, 27.5 trillion cubic feet of natural gas, and 410 million barrels of natural gas liquids in the Anadarko Basin Province; this assessment includes the Las Animas arch area of southeastern Colorado. The province is at a mature stage of exploration and development for conventional resources. Mean undiscovered continuous resources are estimated at 79 percent of oil, 90 percent of natural gas, and 81 percent of natural gas liquids in the province.

Fact Sheet↗
USGS2011

Assessment of undiscovered oil and gas resources of the Sud Province, north-central Africa

The Sud Province located in north-central Africa recently was assessed for undiscovered, technically recoverable oil, natural gas, and natural gas liquids resources as part of the U.S. Geological Survey's (USGS) World Oil and Gas Assessment. Using a geology-based assessment methodology, the USGS estimated mean volumes of 7.31 billion barrels of oil, 13.42 trillion cubic feet of natural gas, and 353 million barrels of natural gas liquids.

Fact Sheet↗
USGS2010

2010 updated assessment of undiscovered oil and gas resources of the National Petroleum Reserve in Alaska (NPRA)

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean volumes of 896 million barrels of oil (MMBO) and about 53 trillion cubic feet (TCFG) of nonassociated natural gas in conventional, undiscovered accumulations within the National Petroleum Reserve in Alaska and adjacent State waters. The estimated volume of undiscovered oil is significantly lower than estimates released in 2002, owing primarily to recent exploration drilling that revealed an abrupt transition from oil to gas and reduced reservoir quality in the Alpine sandstone 15-20 miles west of the giant Alpine oil field. The National Petroleum Reserve in Alaska (NPRA) has been the focus of oil exploration during the past decade, stimulated by the mid-1990s discovery of the adjacent Alpine field-the largest onshore oil discovery in the United States during the past 25 years. Recent activities in NPRA, including extensive 3-D seismic surveys, six Federal lease sales totaling more than $250 million in bonus bids, and completion of more than 30 exploration wells on Federal and Native lands, indicate in key formations more gas than oil and poorer reservoir quality than anticipated. In the absence of a gas pipeline from northern Alaska, exploration has waned and several petroleum companies have relinquished assets in the NPRA. This fact sheet updates U.S. Geological Survey (USGS) estimates of undiscovered oil and gas in NPRA, based on publicly released information from exploration wells completed during the past decade and on the results of research that documents significant Cenozoic uplift and erosion in NPRA. The results included in this fact sheet-released in October 2010-supersede those of a previous assessment completed by the USGS in 2002.

Fact Sheet↗
USGS2008

Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Bakken Formation, Williston Basin, Montana and North Dakota, 2008

The U.S. Geological Survey (USGS) has completed an assessment of the undiscovered oil and associated gas resources of the Upper Devonian to Lower Mississippian Bakken Formation in the U.S. portion of the Williston Basin of Montana and North Dakota and within the Williston Basin Province. The assessment is based on geologic elements of a total petroleum system (TPS), which include (1) source-rock distribution, thickness, organic richness, maturation, petroleum generation, and migration; (2) reservoir-rock type (conventional or continuous), distribution, and quality; and (3) character of traps and time of formation with respect to petroleum generation and migration. Framework studies in stratigraphy and structural geology and modeling of petroleum geochemistry, combined with historical exploration and production analyses, were used to estimate the undiscovered, technically recoverable oil resource of the Bakken Formation. Using this framework, the USGS defined a Bakken-Lodgepole TPS and seven assessment units (AU) within the system. For the Bakken Formation, the undiscovered oil and associated gas resources were quantitatively estimated for six of these AUs.

Open-File Report↗
USGS2007

Total petroleum system assessment of undiscovered resources in the giant Barnett Shale continuous (unconventional) gas accumulation, Fort Worth Basin, Texas

Undiscovered natural gas having potential for additions to reserves in the Mississippian Barnett Shale of the Fort Worth Basin, north-central Texas, was assessed using the total petroleum system assessment unit concept and a cell-based methodology for continuous-type (Unconventional) resources. The Barnett-Paleozoic total petroleum system is defined in the Bend arch-Fort Worth Basin as encompassing the area in which the organic-rich Barnett is the primary source rock for oil and gas produced from Paleozoic carbonate and clastic reservoirs. Exploration, technology, and drilling in the Barnett Shale play have rapidly evolved in recent years, with about 3500 vertical and 1000 horizontal wells completed in the Barnett through 2005 and more than 85% of the them completed since 1999. Using framework geology and historical production data, assessment of the Barnett Shale was performed by the U.S. Geological Survey using vertical wells at the peak of vertical well completions and before a transition to completions with horizontal wells. The assessment was performed after (1) mapping critical geological and geochemical parameters to define assessment unit areas with future potential, (2) defining distributions of drainage area (cell size) and estimating ultimate recovery per cell, and (3) estimating future success rates. Two assessment units are defined and assessed for the Barnett Shale continuous gas accumulation, resulting in a total mean undiscovered volume having potential for additions to reserves of 26.2 TCFG. The greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit represents a core-producing area where thick, organic-rich, siliceous Barnett Shale is within the thermal window for gas generation (Ro ??? 1.1%) and is overlain and underlain by impermeable limestone barriers (Pennsylvanian Marble Falls Limestone and Ordovician Viola Limestone, respectively) that serve to confine induced fractures during well completion to maximize gas recovery. The extended continuous Barnett Shale gas assessment unit, which had been less explored, defines a geographic area where Barnett Shale is (1) within the thermal window for gas generation, (2) greater than 100 ft (30 m) thick, and (3) where at least one impermeable limestone barrier is absent. Mean undiscovered gas having potential for additions to reserves in the greater Newark East assessment unit is estimated at 14.6 tcf, and in the less tested extended assessment unit, a mean resource is estimated at 11.6 TCFG. A third hypothetical basin-arch Barnett Shale oil assessment unit was defined but not assessed because of a lack of production data. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2007

Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch-Fort Worth Basin, Texas

This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as "assessment units," the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch-Fort Worth Basin area and is also one of the most significant gas-producing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch-Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (Ro) measurements show little correlation with present-day burial depth. Contours of equal Ro values measured from Barnett Shale and typing of produced hydrocarbons indicate significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells-Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (???300 ft; ???91 m) Barnett Shale that is within the gas-generation window (Ro ??? 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2007

Oil and gas geochemistry and petroleum systems of the Fort Worth Basin

Detailed biomarker and light hydrocarbon geochemistry confirm that the marine Mississippian Barnett Shale is the primary source rock for petroleum in the Fort Worth Basin, north-central Texas, although contributions from other sources are possible. Biomarker data indicate that the main oil-generating Barnett Shale facies is marine and was deposited under dysoxic, strong upwelling, normal salinity conditions. The analysis of two outcrop samples and cuttings from seven wells indicates variability in the Barnett Shale organic facies and a possibility of other oil subfamilies being present. Light hydrocarbon analyses reveal significant terrigenous-sourced condensate input to some reservoirs, resulting in terrigenous and mixed marine-terrigenous light hydrocarbon signatures for many oils. The light hydrocarbon data suggest a secondary, condensate-generating source facies containing terrigenous or mixed terrigenous-marine organic matter. This indication of a secondary source rock that is not revealed by biomarker analysis emphasizes the importance of integrating biomarker and light hydrocarbon data to define petroleum source rocks. Gases in the Fort Worth Basin are thermogenic in origin and appear to be cogenerated with oil from the Barnett Shale, although some gas may also originate by oil cracking. Isotope data indicate minor contribution of biogenic gas. Except for reservoirs in the Pennsylvanian Bend Group, which contain gases spanning the complete range of observed maturities, the gases appear to be stratigraphically segregated, younger reservoirs contain less mature gas, and older reservoirs contain more mature gas. We cannot rule out the possibility that other source units within the Fort Worth Basin, such as the Smithwick Shale, are locally important petroleum sources. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2001

Petroleum systems and assessment of the South Florida Basin

This CD-ROM contains coverages that define and outline the geographic boundaries of petroleum systems and assessment units and text that describes the geology and reasoning to support the assessment of undiscovered oil and gas resources in the South Florida Basin for a forecast period of 30 years. This assessment was performed by using the best geological information and scientific theory available to the USGS; however, the USGS did not have access to seismic survey data for the South Florida Basin.

Florida↗
USGS2000

Maps showing geology, oil and gas fields, and geologic provinces of Iran

This digitally compiled map includes geology, oil and gas field centerpoints, geologic provinces, and major faults of Iran with some of these components extended into geographically adjacent areas. This digital compilation is an interim product of the U.S. Geological Survey's World Energy Project (WEP) and part of a series on CD-ROM. The goal of the WEP is to assess the undiscovered, technically recoverable oil and gas resources of the world and report the result of this assessment in the year 2000. For data management purposes, the world was divided into eight energy regions corresponding approximately to the economic regions of the world as defined by the U.S. Department of State.

Open-File Report↗
USGS1999

Ghaba salt basin province and Fahud salt basin province, Oman; geological overview and total petroleum systems

Three Total Petroleum Systems each consisting of one assessment unit have been identified in the Ghaba and Fahud Salt Basin Provinces of north-central Oman. One Total Petroleum System and corresponding assessment unit, the North Oman Huqf/`Q'? Haushi(!) Total Petroleum System (201401) and Ghaba-Makarem Combined Structural Assessment Unit (20140101), were identified for the Ghaba Salt Basin Province (2014). In the Fahud Salt Basin Province, however, two overlapping Total Petroleum Systems (TPS) were recognized: 1) the North Oman Huqf ? Shu'aiba(!) TPS (201601); Fahud-Huqf Combined Structural Assessment Unit (20160101), and 2) the Middle Cretaceous Natih(!) TPS (201602); Natih-Fiqa Structural/Stratigraphic Assessment Unit (20160201). The boundary for each Total Petroleum System also defines the boundary of the corresponding assessment unit and includes all trap styles and hydrocarbon producing reservoirs within the petroleum system. In both the Ghaba and Fahud Salt Basin Provinces, hydrocarbons were generated from several deeply-buried source rocks within the Infracambrian Huqf Supergroup. One general `North Oman Huqf' type oil is dominant in the Fahud Salt Basin. Oils in the Ghaba Salt Basin are linked to at least two distinct Huqf source-rock units based on oil geochemistry: a general North Oman Huqf-type oil source and a more dominant `questionable unidentified-source' or `Q'-type Huqf oil source. These two Huqf-sourced oils are commonly found as admixtures in reservoirs throughout north-central Oman. Hydrocarbons generated from Huqf sources are produced from a variety of reservoir types and ages ranging from Precambrian to Cretaceous in both the Ghaba and Fahud Salt Basin Provinces. Clastic reservoirs of the Gharif and Al Khlata Formations, Haushi Group (M. Carboniferous to L. Permian), dominate oil production in the Ghaba Salt Basin Province and form the basis for the Huqf/`Q' ? Haushi(!) TPS. In contrast, the Lower Cretaceous Shu'aiba and Middle Cretaceous Natih limestones account for most of the production in the Fahud Salt Basin with about 50 percent of the basin's production from porous, fractured Shu'aiba limestones in Yibal field, thus the name North Oman Huqf ? Shu'aiba(!) TPS. Deep gas is produced mainly from Middle Cambrian to Lower Ordovician clastic reservoirs of the Haima Supergroup. Traps in nearly all hydrocarbon accumulations of these petroleum systems are mainly structural and were formed by one or more mechanisms. These trap-forming mechanisms were mainly periodic halokinesis of the thick Cambrian Ara Salt and consequent folding and faulting from basin loading, rifting, or other major tectonic events, particularly those events forming the Oman Mountains and associated foreland-basin system during the Late Cretaceous and Late Tertiary. Many of the future new-field targets will likely be low-relief, subtle structures, as many of the large structures have been drilled. Oman's recent interest and commitments to liquid natural gas export make deep gas a primary objective in the two North Oman Huqf petroleum systems. New-field exploration of deep gas and exploring deeper targets for gas in existing fields will likely identify a significant gas resource in the next thirty years. Moreover, salt-diapir flank traps in these two North Oman Huqf petroleum systems and salt basin provinces have gone essentially untested and will likely be targeted in the near-future. The Middle Cretaceous Natih(!) TPS is a small efficient system of the Fahud Salt Basin. Natih source rocks are only mature in the Late Cretaceous/Tertiary foredeep and production is primarily from Natih reservoirs; minor production from the Shu'aiba limestone is documented along fault-dip structures. Most traps are structural and are related to development of the foreland basin and formation of the Oman Mountains. Future targets of the Natih TPS will be less obvious than those of Fahud and Natih fields and likely includ

Open-File Report↗
USGS1987

Mineralogy and petrology of the Cretaceous- Tertiary boundary clay bed and adjacent clay-rich rocks, Raton Basin, New Mexico and Colorado.

The Cretaceous-Tertiary (K-T) boundary is preserved in a sequence of coal-bearing, fluvial rocks in the lower part of the Raton Formation (Late Cretaceous and Paleocene) at several sites in the east-central part of the Raton Basin. The K-T boundary occurs at the top of a kaolinitic claystone layer, commonly referred to as the "boundary clay layer," in an interval of coal and carbonaceous shale. The boundary is defined by the disappearance of certain fossil-pollen taxa. The boundary clay layer also contains shocked quartz grains and abundance anomalies of iridium, chromium, and other elements. Each of these characteristics support the hypothesis of an asteroid impact at the end of the Cretaceous. Small goyazite spheres were also found in the boundary clay bed; however, their origin is uncertain. X-ray powder diffraction (XRD), scanning electron microscopy (SEM), and thin-section petrography have shown that the boundary clay bed exhibits unique mineralogic and petrologic characteristics not possessed by other clay-rich beds in coal-bearing rocks of the Raton Basin. The boundary clay bed is composed primarily of well-crystallized kaolinite but also contains subordinate, randomly interstratified, mixed-layer illite/smectite, both of which appear to have been formed by the alteration of vitreous material in a coal-swamp environment. The bulk mineralogy of the boundary clay bed is similar to that of other kaolinite-rich clay beds (tonsteins) that altered in coal swamps from airfall volcanic ash. The alteration process and diagenetic products of the host material in the boundary clay bed, however, differed from those of the tonsteins, resulting in a unique petrographic fabric. The boundary clay bed is characterized by an overall imbricate fabric that may reflect an original vitreous material that included shards, bubbles, and spheres. The original fallout material of the boundary clay bed first altered to "cabbage-like" microspherules, indicating a halloysite or allophane precursor, and then to well-crystallized kaolinite; the well-crystallized kaolinite is the diagenetic stable phase for these rocks at their maximum burial conditions. In comparison, the vitreous components of the tonsteins were altered directly to coarse vermicular and platey kaolinite. Alteration of the original fallout material in the boundary bed was probably rapid, leading to hydrated, disordered, fine-grained clay minerals that formed into curled spherical or tubular shapes. The factors that produced these unique fabrics in the boundary clay bed existed at all K-T sites in the Raton Basin and were much different from those that formed the coarse platey and vermicular fabrics of ordinary tonsteins. The distinctive character of the boundary clay may be due to the unique nature and chemistry of the fallout material and (or) physical or chemical conditions existing shortly after its deposition.

Journal of Sedimentary Petrology↗
USGS1985

Mineral, chemical and textural relationships in rhythmic-bedded, hydrocarbon-productive chalk of the Niobrara Formation, Denver Basin, Colorado ( USA).

The types of hydrocarbons produced from these chalks are determined by the level of thermal maturity associated with present-day burial or paleoburial conditions. Detailed analyses of deeply-buried chalk from core of the Smoky Hill Chalk Member of the Niobrara Formation in the Champlin Petroleum 2 Boxelder Farms well combined with core data from other Niobrara wells have helped identify many depositional and diagenetic relationships. Porosity of the chalk is proportional to maximum burial depth and inversely proportional to the amount of non-carbonate material (acid- insoluble residue content) in the chalk. Total organic carbon content in the chalk is proportional to the amount of acid-insoluble residue and relative abundance of pyrite in the acid-insoluble fraction. Quartz is inversely proportional to the amount of insoluble material, and the amount of clay tends to increase as insolubles increase, suggesting that detritus in these chalks is greatly influenced by reworked, altered, volcanic products rather than siliceous clastics.-from Authors

Mountain Geologist↗
USGS1982

A recommended procedure for the preparation of oriented clay-mineral specimens for X-ray diffraction analysis; modifications to Drever's filter-membrane peel technique

Extremely well-oriented clay mineral mounts for X-ray diffraction analysis can be prepared quickly and without introducing segregation using the filter-membrane peel technique. Mounting problems encountered with smectite-rich samples can be resolved by using minimal sample and partial air-drying of the clay film before transfer to a glass slide. Samples containing small quantities of clay can produce useful oriented specimens if Teflon masks having more restrictive areas are inserted above the membrane filter during clay deposition. War]page and thermal shock of glass slides can be controlled by using a flat, porous, ceramic plate as a holding surface during heat treatments.

Open-File Report↗