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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↗

USGS2022

Infiltration of late Palaeozoic evaporative brines in the reelfoot rift: A possible salt source for Illinois Basin formation waters and MVT mineralizing fluids

Salinities and homogenization temperatures of fluid inclusions in Mississippi Valley-type (MVT) deposits provide important insights into the regional hydrology of the Illinois basin/Reelfoot rift system in late Palaeozoic time. Although the thermal regime of this basin system has been plausibly explained, the origin of high salinities in the basin fluids remains enigmatic. Topographically driven flow appears to have been essential in forming these MVT districts, as well as many other districts worldwide. However, this type of flow is recharged by fresh water making it difficult to account for the high salinities of the mineralizing fluids over extended time periods. Results of numerical experiments carried out in this study provide a possible solution to the salinity problem presented by the MVT zinc-lead and fluorite districts at the margins of the basin system. Evaporative concentration of surface water and subsequent infiltration into the subsurface are proposed to account for large volumes of brine that are ultimately responsible for mineralization of these districts. This study demonstrates that under a range of geologically reasonable conditions, brine infiltration into an aquifer in the deep subsurface can coexist with topographically driven flow. Infiltration combined with regional flow and local magmatic heat sources in the Reelfoot rift explain the brine concentrations as well as the temperatures observed in the Southern Illinois and Upper Mississippi Valley districts.

Petroleum Geoscience↗

USGS2021

Potential Pb+2 mobilization, transport, and sequestration in shallow aquifers impacted by multiphase CO2 leakage: A natural analogue study from the Virgin River Basin in Southwest Utah

Geological carbon sequestration (GCS) is necessary to help meet emissions reduction goals, but groundwater contamination may occur if CO 2 and/or brine were to leak out of deep storage formations into the shallow subsurface. For this study, a natural analogue was investigated: in the Virgin River Basin of southwest Utah, water with moderate salinity and high CO 2 concentrations is leaking upward into shallow aquifers that contain heavy metal-bearing concretions. The aquifer system is comprised of the Navajo and Kayenta formations, which are pervasive across southern Utah and have been considered as a potential GCS injection unit where they are sufficiently deep. Numerical models of the site were constructed based on measured water chemistry and head distributions from previous studies. Simulations were used to improve understanding of the rate and distribution of the upwelling flow into the aquifers, and to assess the reactive transport processes that may occur if the upwelling fluids were to interact with a zone of iron oxide and other heavy metals, representing the concretions that are common in the area. Various mineralogies were tested, including one in which Pb +2 was adsorbed onto ferrihydrite, and another in which it was bound within a solid mixture of litharge (PbO) and hematite (Fe 2 O 3 ). Results indicate that metal mobilization depends strongly on the source zone composition and that Pb +2 transport can be naturally attenuated by gas phase formation and carbonate mineral precipitation. These findings could be used to improve risk assessment and mitigation strategies at geological carbon sequestration sites.

Utah↗

USGS2007

Geologic and anthropogenic factors influencing karst development in the Frederick region of Maryland

Karst features pervade the outcrop belts of Triassic, Ordovician, and Cambrian rocks in the Frederick Valley region of Maryland's western Piedmont. Detailed stratigraphic analysis and geologic and karst mapping demonstrate that individual stratigraphic units have differing susceptibilities of karst feature creation. Although the Triassic Leesburg Member of the Bull Run Formation and Rocky Springs Station Member of the Cambrian Frederick Formation have many surface depressions within their outcrop belts, the Lime Kiln Member of the Frederick Formation and the Ceresville, Fountain Rock, and Woodsboro members of the Ordovician Grove Formation have the greatest potential for development of catastrophic collapse sinkholes. Although these four members have the highest relative susceptibility, human activity can increase the potential for sinkhole activation in all units. Rerouting of surface drainage patterns, unlined drainage, and storm-water management areas and removal of significant overburden deposits significantly increase sinkhole development, but mainly, these units are inherently more susceptible to begin with. Copyright ?? 2007. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2010

Application of the surface azimuthal electrical resistivity survey method to determine patterns of regional joint orientation in glacial tills

Joints within unconsolidated material such as glacial till can be primary avenues for the flow of electrical charge, water, and contaminants. To facilitate the siting and design of remediation programs, a need exists to map anisotropic distribution of such pathways within glacial tills by determining the azimuth of the dominant joint set. The azimuthal survey method uses standard resistivity equipment with a Wenner array rotated about a fixed center point at selected degree intervals that yields an apparent resistivity ellipse. From this ellipse, joint set orientation can be determined. Azimuthal surveys were conducted at 21 sites in a 500-km2 (193 mi2) area around Milwaukee, Wisconsin, and more specifically, at sites having more than 30 m (98 ft) of glacial till (to minimize the influence of underlying bedrock joints). The 26 azimuthal surveys revealed a systematic pattern to the trend of the dominant joint set within the tills, which is approximately parallel to ice flow direction during till deposition. The average orientation of the joint set parallel with the ice flow direction is N77??E and N37??E for the Oak Creek and Ozaukee tills, respectively. The mean difference between average direct observation of joint set orientations and average azimuthal resistivity results is 8??, which is one fifth of the difference of ice flow direction between the Ozaukee and Oak Creek tills. The results of this study suggest that the surface azimuthal electrical resistivity survey method used for local in situ studies can be a useful noninvasive method for delineating joint sets within shallow geologic material for regional studies. Copyright ?? 2010 The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2009

Characterization of the Helderberg Group as a geologic seal for CO 2 sequestration

The Midwest Regional Carbon Sequestration Partnership recognizes that both the Devonian Oriskany Sandstone and the Silurian Salina Group offer potential for subsurface carbon dioxide storage in northern West Virginia. The Silurian-Devonian Helderberg Group lies stratigraphically between these two units, and consequendy, its potential as a geologic seal must be evaluated. Predominantly a carbonate interval with minor interbedded siliciclastics and chert, the Helderberg Group was deposited in an ancient epeiric sea. Although most previous investigations of this unit have concentrated on outcrops in eastern West Virginia, new information is available from an injection well drilled along the Ohio River at First Energy's R. E. Burger electric power plant near Shadyside, Ohio. Geophysical, seismic, and core data from this well have been combined with existing outcrop information to evaluate the Helderberg Group's potential as a seal. The data collected suggest that only secondary porosity remains, and permeability, if it exists, most likely occurs along faults or within fractures. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2009

Assessing spatial uncertainty in reservoir characterization for carbon sequestration planning using public well-log data: A case study

Mapping and characterization of potential geologic reservoirs are key components in planning carbon dioxide (CO 2 ) injection projects. The geometry of target and confining layers is vital to ensure that the injected CO 2 remains in a supercritical state and is confined to the target layer. Also, maps of injection volume (porosity) are necessary to estimate sequestration capacity at undrilled locations. Our study uses publicly filed geophysical logs and geostatistical modeling methods to investigate the reliability of spatial prediction for oil and gas plays in the Medina Group (sandstone and shale facies) in northwestern Pennsylvania. Specifically, the modeling focused on two targets: the Grimsby Formation and Whirlpool Sandstone. For each layer, thousands of data points were available to model structure and thickness but only hundreds were available to support volumetric modeling because of the rarity of density-porosity logs in the public records. Geostatistical analysis based on this data resulted in accurate structure models, less accurate isopach models, and inconsistent models of pore volume. Of the two layers studied, only the Whirlpool Sandstone data provided for a useful spatial model of pore volume. Where reliable models for spatial prediction are absent, the best predictor available for unsampled locations is the mean value of the data, and potential sequestration sites should be planned as close as possible to existing wells with volumetric data. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2009

Reservoir uncertainty, Precambrian topography, and carbon sequestration in the Mt. Simon Sandstone, Illinois Basin

Sequestration sites are evaluated by studying the local geological structure and confirming the presence of both a reservoir facies and an impermeable seal not breached by significant faulting. The Cambrian Mt. Simon Sandstone is a blanket sandstone that underlies large parts of Midwest United States and is this region's most significant carbon sequestration reservoir. An assessment of the geological structure of any Mt. Simon sequestration site must also include knowledge of the paleotopography prior to deposition. Understanding Precambrian paleotopography is critical in estimating reservoir thickness and quality. Regional outcrop and borehole mapping of the Mt. Simon in conjunction with mapping seismic reflection data can facilitate the prediction of basement highs. Any potential site must, at the minimum, have seismic reflection data, calibrated with drill-hole information, to evaluate the presence of Precambrian topography and alleviate some of the uncertainty surrounding the thickness or possible absence of the Mt. Simon at a particular sequestration site. The Mt. Simon is thought to commonly overlie Precambrian basement granitic or rhyolitic rocks. In places, at least about 549 m (1800 ft) of topographic relief on the top of the basement surface prior to Mt. Simon deposition was observed. The Mt. Simon reservoir sandstone is thin or not present where basement is topographically high, whereas the low areas can have thick Mt. Simon. The paleotopography on the basement and its correlation to Mt. Simon thickness have been observed at both outcrops and in the subsurface from the states of Illinois, Ohio, Wisconsin, and Missouri. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2007

Geologic characteristics of the central stretch of the Ticona Channel, north-central Illinois

The Ticona Channel is located in north-central Illinois and occurs in Grundy, LaSalle, and Putnam counties. It is a buried bedrock valley that served as the principal paleodrainage system in north-central Illinois during the Illinoian and pre-Illinoian. This study focused on the part of the Ticona Channel within the Leonore 7.5??? Quadrangle. The geometry and stratigraphy of sediments that fill the Ticona Channel were investigated using high-resolution, shallow seismic reflection profiling, traditional field geologic mapping techniques, borehole data, and water-well-log data. The valley is about 2 km (1 mi) wide and approximately 60 m (200 ft) deep. The U-shape channel is straight, trends east-west, and has only one mappable tributary. The valley is carved into the Pennsylvanian Carbondale Formation in the eastern part of the study area; it has incised into the Ordovician Prairie du Chien Group in the west. At its base, the Ticona Channel is filled with the Pearl Formation, which is coarse-grained sand and gravel that was deposited during the Illinoian glaciation. The Pearl Formation is overlain by Illinoian till of the Glasford Formation and is capped by Wedron Group sediments from the Wisconsinan stage. Copyright ?? 2007. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2010

Use of the azimuthal resistivity technique for determination of regional azimuth of transmissivity

Many bedrock units contain joint sets that commonly act as preferred paths for the movement of water, electrical charge, and possible contaminants associated with production or transit of crude oil or refined products. To facilitate the development of remediation programs, a need exists to reliably determine regional-scale properties of these joint sets: azimuth of transmissivity ellipse, dominant set, and trend(s). The surface azimuthal electrical resistivity survey method used for local in situ studies can be a noninvasive, reliable, efficient, and relatively cost-effective method for regional studies. The azimuthal resistivity survey method combines the use of standard resistivity equipment with a Wenner array rotated about a fixed center point, at selected degree intervals, which yields an apparent resistivity ellipse from which joint-set orientation can be determined. Regional application of the azimuthal survey method was tested at 17 sites in an approximately 500 km2 (193 mi2) area around Milwaukee, Wisconsin, with less than 15m (50 ft) overburden above the dolomite. Results of 26 azimuthal surveys were compared and determined to be consistent with the results of two other methods: direct observation of joint-set orientation and transmissivity ellipses from multiple-well-aquifer tests. The average of joint-set trend determined by azimuthal surveys is within 2.5?? of the average of joint-set trend determined by direct observation of major joint sets at 24 sites. The average of maximum of transmissivity trend determined by azimuthal surveys is within 5.7?? of the average of maximum of transmissivity trend determined for 14 multiple-well-aquifer tests. Copyright ?? 2010 The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2008

Citronelle Dome: A giant opportunity for multizone carbon storage and enhanced oil recovery in the Mississippi Interior Salt Basin of Alabama

The Citronelle Dome is a giant, salt-cored anticline in the eastern Mississippi Interior Salt Basin of southern Alabama that is located near several large-scale, stationary, carbon-emitting sources in the greater Mobile area. The dome forms an elliptical, four-way structural closure containing opportunities for CO2-enhanced oil recovery (CO2-EOR) and large-capacity saline reservoir CO2 sequestration. The Citronelle oil field, located on the crest of the dome, has produced more than 169 million bbl of 42-46?? API gravity oil from sandstone bodies in the Lower Cretaceous Rodessa Formation. The top seal for the oil accumulation is a thick succession of shale and anhydrite, and the reservoir is underfilled such that oil-water contacts are typically elevated 30-60 m (100-200 ft) above the structural spill point. Approximately 31-34% of the original oil in place has been recovered by primary and secondary methods, and CO2-EOR has the potential to increase reserves by up to 20%. Structural contour maps of the dome demonstrate that the area of structural closure increases upward in section. Sandstone units providing prospective carbon sinks include the Massive and Pilot sands of the lower Tuscaloosa Group, as well as several sandstone units in the upper Tuscaloosa Group and the Eutaw Formation. Many of these sandstone units are characterized by high porosity and permeability with low heterogeneity. The Tuscaloosa-Eutaw interval is capped by up to 610 m (2000 ft) of chalk and marine shale that are proven reservoir seals in nearby oil fields. Therefore, the Citronelle Dome can be considered a major geologic sink where CO2 can be safely stored while realizing the economic benefits associated with CO2-EOR. Copyright ?? 2008. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Environmental Geosciences↗

USGS2005

Environmental issues of petroleum exploration and production: Introduction

Energy is the lifeblood of our planet Earth, an essential commod- ity that powers the expanding global economy. Starting in the 1950s, oil and natural gas became the main sources of primary energy for the increasing world population, and this dominance is expected to continue for several more decades (Edwards, 1997; Energy Information Administration (EIA), 2004). In the United States, petroleum production started in 1859 when Drake's well was drilled near Titusville, Pennsylvania, and oil and natural gas currently supply approximately 63% of the energy consumption; forecasts indicate that by 2025, their use will increase by about 40% to 28.3 million bbl/day and to 31.4 tcf/yr (EIA, 2004). The clear benefits of petroleum consumption, however, can carry major environmental impacts that may be regional or global in scale, in- cluding air pollution, global climate change, and oil spills. This vol- ume of Environmental Geosciences, covering environmental impacts of petroleum exploration and production, does not address these major impacts directly because air pollution and global warming are issues related primarily to petroleum and coal uses, and major oil spills are generally attributed to marine petroleum transportation, such as the Exxon Valdez's 1989 spill of 260,000 bbl of oil into Prince William Sound, Alaska. Exploration for and production of petroleum, however, have caused local detrimental impacts to soils, surface and groundwa- ters, and ecosystems in the 36 producing states in the United States (Richter and Kreitler, 1993; Kharaka and Hanor, 2003). These im- pacts arose primarily from the improper disposal of some of the large volumes (presently estimated at 20 billion bbl/yr total pro- duced) of saline water produced with oil and gas, from accidental hydrocarbon and produced-water releases, and from abandoned oil wells that were orphaned or not correctly plugged (Kharaka et al., 1995; Veil et al., 2004). Impacts and ground-surface disturbances, in the order of several acres per well, can also arise from related activities such as site clearance, construction of roads, tank bat- teries, brine pits and pipelines, and other land modifications nec- essary for the drilling of exploration and production wells and construction of production facilities. The cumulative impacts from these operations are high, because a total of about 3.5 million oil.

Environmental Geosciences↗

USGS2006

Petroleum system modeling capabilities for use in oil and gas resource assessments

Summary: Petroleum resource assessments are among the most highly visible and frequently cited scientific products of the U.S. Geological Survey. The assessments integrate diverse and extensive information on the geologic, geochemical, and petroleum production histories of provinces and regions of the United States and the World. Petroleum systems modeling incorporates these geoscience data in ways that strengthen the assessment process and results are presented visually and numerically. The purpose of this report is to outline the requirements, advantages, and limitations of one-dimensional (1-D), two-dimensional (2-D), and three-dimensional (3-D) petroleum systems modeling that can be applied to the assessment of oil and gas resources. Primary focus is on the application of the Integrated Exploration Systems (IES) PetroMod? software because of familiarity with that program as well as the emphasis by the USGS Energy Program on standardizing to one modeling application. The Western Canada Sedimentary Basin (WCSB) is used to demonstrate the use of the PetroMod? software. Petroleum systems modeling quantitatively extends the 'total petroleum systems' (TPS) concept (Magoon and Dow, 1994; Magoon and Schmoker, 2000) that is employed in USGS resource assessments. Modeling allows integration of state-of-the-art analysis techniques, and provides the means to test and refine understanding of oil and gas generation, migration, and accumulation. Results of modeling are presented visually, numerically, and statistically, which enhances interpretation of the processes that affect TPSs through time. Modeling also provides a framework for the input and processing of many kinds of data essential in resource assessment, including (1) petroleum system elements such as reservoir, seal, and source rock intervals; (2) timing of depositional, hiatus, and erosional events and their influences on petroleum systems; (3) incorporation of vertical and lateral distribution and lithologies of strata that compose the petroleum systems; and (4) calculations of pressure-volume-temperature (PVT) histories. As digital data on petroleum systems continue to expand, the models can integrate these data into USGS resource assessments by building and displaying, through time, areas of petroleum generation, migration pathways, accumulations, and relative contributions of source rocks to the hydrocarbon components. IES PetroMod? 1-D, 2-D, and 3-D models are integrated such that each uses the same variables for petroleum systems modeling. 1-D burial history models are point locations, mainly wells. Maps and cross-sections model geologic information in two dimensions and can incorporate direct input of 2-D seismic data and interpretations using various formats. Both 1-D and 2-D models use data essential for assessments and, following data compilation, they can be completed in hours and retested in minutes. Such models should be built early in the geologic assessment process, inasmuch as they incorporate the petroleum system elements of reservoir, source, and seal rock intervals with associated lithologies and depositional and erosional ages. The models can be used to delineate the petroleum systems. A number of 1-D and 2-D models can be constructed across a geologic province and used by the assessment geologists as a 3-D framework of processes that control petroleum generation, migration, and accumulation. The primary limitation of these models is that they only represent generation, migration, and accumulation in two dimensions. 3-D models are generally built at reservoir to basin scales. They provide a much more detailed and realistic representation of petroleum systems than 1-D or 2-D models because they portray more fully the temporal and physical relations among (1) burial history; (2) lithologies and associated changes through burial in porosity, permeability, and compaction; (3) hydrodynamic effects; and (4) other parameters that influence petroleum gen

Open-File Report↗

USGS2002

History of the recognition of organic geochemistry in geoscience

The discipline of organic geochemistry is an outgrowth of the application of the principles and methods of organic chemistry to sedimentary geology. Its origin goes back to the last part of the nineteenth century and the first part of the twentieth century concurrent with the evolution of the applied discipline of petroleum geochemistry. In fact, organic geochemistry was strongly influenced by developments in petroleum geochemistry. Now, however, organic geochemistry is considered an umbrella geoscience discipline of which petroleum geochemistry is an important component.

Organic Geochemistry↗

USGS2013

Assessment of undiscovered conventional oil and gas resources of the Western Canada Sedimentary Basin, Canada, 2012

The U.S. Geological Survey recently completed a geoscience-based assessment of undiscovered oil and gas resources of provinces within the Western Canada Sedimentary Basin. The Western Canada Sedimentary Basin primarily comprises the (1) Alberta Basin Province of Alberta, eastern British Columbia, and the southwestern Northwest Territories; (2) the Williston Basin Province of Saskatchewan, southeastern Alberta, and southern Manitoba; and (3) the Rocky Mountain Deformed Belt Province of western Alberta and eastern British Columbia. This report is part of the U.S. Geological Survey World Petroleum Resources Project assessment of priority geologic provinces of the world. The assessment was based on geoscience elements that define a total petroleum system (TPS) and associated assessment unit(s). These elements include petroleum source rocks (geochemical properties and petroleum generation, migration, and accumulation), reservoir description (reservoir presence, type, and quality), and petroleum traps (trap and seal types, and timing of trap and seal formation relative to petroleum migration). Using this framework, the Elk Point-Woodbend Composite TPS, Exshaw-Fernie-Mannville Composite TPS, and Middle through Upper Cretaceous Composite TPS were defined, and four conventional assessment units within the total petroleum systems were quantitatively assessed for undiscovered resources in the Western Canada Sedimentary Basin.

Fact Sheet↗

USGS2006

Organic geochemistry - A retrospective of its first 70 years

Organic geochemistry had its origin in the early part of the 20th century when organic chemists and geologists realized that detailed information on the organic materials in sediments and rocks was scientifically interesting and of practical importance. The generally acknowledged "father" of organic geochemistry is Alfred E. Treibs (1899-1983), who discovered and described, in 1936, porphyrin pigments in shale, coal, and crude oil, and traced the source of these molecules to their biological precursors. Thus, the year 1936 marks the beginning of organic geochemistry. However, formal organization of organic geochemistry dates from 1959 when the Organic Geochemistry Division (OGD) of The Geochemical Society was founded in the United States, followed 22 years later (1981) by the establishment of the European Association of Organic Geochemists (EAOG). Organic geochemistry (1) has its own journal, Organic Geochemistry (beginning in 1979) which, since 1988, is the official journal of the EAOG, (2) convenes two major conferences [International Meeting on Organic Geochemistry (IMOG), since 1962, and Gordon Research Conferences on Organic Geochemistry (GRC), since 1968] in alternate years, and (3) is the subject matter of several textbooks. Organic geochemistry is now a widely recognized geoscience in which organic chemistry has contributed significantly not only to geology (i.e., petroleum geochemistry, molecular stratigraphy) and biology (i.e., biogeochemistry), but also to other disciplines, such as chemical oceanography, environmental science, hydrology, biochemical ecology, archaeology, and cosmochemistry.

Conference Paper↗

USGS1980

Computational methods for a three-dimensional model of the petroleum-discovery process

A discovery-process model devised by Drew, Schuenemeyer, and Root can be used to predict the amount of petroleum to be discovered in a basin from some future level of exploratory effort: the predictions are based on historical drilling and discovery data. Because marginal costs of discovery and production are a function of field size, the model can be used to make estimates of future discoveries within deposit size classes. The modeling approach is a geometric one in which the area searched is a function of the size and shape of the targets being sought. A high correlation is assumed between the surface-projection area of the fields and the volume of petroleum. To predict how much oil remains to be found, the area searched must be computed, and the basin size and discovery efficiency must be estimated. The basin is assumed to be explored randomly rather than by pattern drilling. The model may be used to compute independent estimates of future oil at different depth intervals for a play involving multiple producing horizons. We have written FORTRAN computer programs that are used with Drew, Schuenemeyer, and Root's model to merge the discovery and drilling information and perform the necessary computations to estimate undiscovered petroleum. These program may be modified easily for the estimation of remaining quantities of commodities other than petroleum. ?? 1980.

Computers & Geosciences↗

USGS2009

Unraveling the stratigraphy of the Oriskany Sandstone: A necessity in assessing its site-specific carbon sequestration potential

The widespread distribution, favorable reservoir characteristics, and depth make the Lower Devonian Oriskany Sandstone a viable sequestration target in the Appalachian Basin. The Oriskany Sandstone is thickest in the structurally complex Ridge and Valley Province, thins toward the northern and western basin margins, and is even absent in other parts of the basin (i.e., the no-sand area of northwestern Pennsylvania). We evaluated four regions using petrographic data, core analyses, and geophysical log analyses. Throughout the entire study area, average porosities range from 1.35 to 14%. The most notable porosity types are primary intergranular, secondary dissolution, and fracture porosity. Intergranular primary porosity dominates at stratigraphic pinch-out zones near the Oriskany no-sand area and at the western limit of the Oriskany Sandstone. Secondary porosity occurs from dissolution of carbonate constituents primarily in the combination-traps natural gas play extending through western Pennsylvania, western West Virginia, and eastern Ohio. Fracture porosity dominates in the central Appalachian Plateau Province and Valley and Ridge Province. Based on average porosity, the most likely regions for successful sequestration in the Oriskany interval are (1) updip from Oriskany Sandstone pinch-outs in eastern Ohio, and (2) western Pennsylvania, western West Virginia, and eastern Ohio where production occurs from a combination of stratigraphic and structural traps. Permeability data, where available, were used to further evaluate the potential of these regions. Permeability ranges from 0.2 to 42.7 md. Stratigraphic pinch-outs at the northern and western limits of the basin have the highest permeabilities. We recommend detailed site assessments when evaluating the sequestration potential of a given injection site based on the variability observed in the Oriskany structure, lithology, and reservoir characteristics. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Ceosciences. All rights reserved.

Environmental Geosciences↗