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Richard M Pollastro - One of the best experts on this subject based on the ideXlab platform.

  • total Petroleum System assessment of undiscovered resources in the giant barnett shale continuous unconventional gas accumulation fort worth basin texas
    AAPG Bulletin, 2007
    Co-Authors: Richard M Pollastro
    Abstract:

    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.

  • geologic framework of the mississippian barnett shale barnett paleozoic total Petroleum System bend arch fort worth basin texas
    AAPG Bulletin, 2007
    Co-Authors: Richard M Pollastro, Daniel M Jarvie, Ronald J Hill, Craig W Adams
    Abstract:

    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.

Craig J. Wandrey - One of the best experts on this subject based on the ideXlab platform.

  • Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System, Assam Geologic Province, India
    2004
    Co-Authors: Craig J. Wandrey
    Abstract:

    The Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System (TPS) (803401) is located in the Assam Province in northeasternmost India and includes the Assam Shelf south of the Brahmaputra River. The area is primarily a southeastdipping shelf overthrust by the Naga Hills on the southeast and the Himalaya Mountain range to the north. The rocks that compose this TPS are those of the Sylhet-Kopili/Barail-Tipam composite Petroleum System. These rocks are those of the Eocene-Oligocene Jaintia Group Sylhet and Kopili Formations, the Oligocene Barail Group, and the Oligocene-Miocene Surma and Tipam Groups. These groups include platform carbonates, shallow marine shales and sandstones, and the sandstones, siltstones, shales, and coals of deltaic and lagoonal facies. Source rocks include the Sylhet and Kopili Formation shales, Barail Group coals and shales, and in the south the Surma Group shales. Total organic carbon content is generally low, averaging from 0.5 to 1.8 percent; it is as high as 9 percent in the Barail Coal Shales. Maturities are generally low, from Ro (vitrinite reflectance) 0.45 to 0.7 percent where sampled. Maturity increases to the southeast near the Naga thrust fault and can be expected to be higher in the subthrust. Generation began in early Pliocene. Migration is primarily updip to the northwest (< 5 to 15 kilometers) along the northeast-trending slope of the Assam Shelf, and vertical migration occurs through reactivated basement-rooted faults associated with the plate collisions. Reservoir rocks are carbonates of the Sylhet Formation, interbedded sandstones of the Kopili Formation and sandstones of the Barail, Surma, and Tipam Groups. Permeability ranges from less than 8 mD (millidarcies) to as high as 800 mD in the Tipam Group. Porosity ranges from less than 7 percent to 30 percent. Traps are primarily anticlines and faulted anticlines with a few subtle stratigraphic traps. There is also a likelihood of anticlinal traps in the subthrust. Seals include interbedded Oligocene and Miocene shales and clays, and the thick clays of the Pliocene Gurjan Group. Introduction Among the 76 priority provinces identified by the U.S. Geological Survey World Energy Assessment Team (2000) was the Assam geologic province. Located in northeastern India, Assam geologic province is an onshore province covering approximately 74,000 km2 (figs. 1 and 2). The geologic province is bounded on the north and west by the Brahmaputra River, and on the south and east by the Indo-Burman Ranges and the Central Burma Basin (fig. 3). Major features within the Assam geologic province include the Assam Shelf, Brahmaputra River valley, Shillong Plateau, Mirkir Hills, and a foreland portion of the Indian Shield. The Assam Shelf consists of a portion of the Paleocene to Eocene continental shelf of the Indian plate which became emergent and which is being overthrust by the Himalayas on the northwest and by the Burma micro-plate on the southeast. Structurally, the Assam geologic province consists of two primary, subparallel features trending southwest to northeast, which developed just prior to, and as a result of plate collision. The northernmost structural feature is the Assam Shelf, which is presently being subducted beneath both the Eurasian plate to the north and the Burma plate to the southeast. The southernmost feature consists of en-echelon folds of the Naga Hills overthrust belt and northernmost Indo-Burman Ranges, which are continually developing as the shelf is subducted. At present, most hydrocarbon production is northwest of, and parallel to, the Naga thrust fault. Figure 2 shows Brahmaputra River flowing from east (right) to west (left) and tributaries flowing from the Himalayan ranges at the top of the view (north) and from the Naga Hills in the bottom of the view (south). The producing area lies south of the Brahmaputra River. Acknowledgments Insight into the geology and data presented in this report were provided by scientists of the Oil and Natural Gas Corporation (ONGC), Dehra Dun, India. Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System, Assam Geologic Province, India

  • sylhet kopili barail tipam composite total Petroleum System assam geologic province india
    Bulletin, 2004
    Co-Authors: Craig J. Wandrey
    Abstract:

    The Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System (TPS) (803401) is located in the Assam Province in northeasternmost India and includes the Assam Shelf south of the Brahmaputra River. The area is primarily a southeastdipping shelf overthrust by the Naga Hills on the southeast and the Himalaya Mountain range to the north. The rocks that compose this TPS are those of the Sylhet-Kopili/Barail-Tipam composite Petroleum System. These rocks are those of the Eocene-Oligocene Jaintia Group Sylhet and Kopili Formations, the Oligocene Barail Group, and the Oligocene-Miocene Surma and Tipam Groups. These groups include platform carbonates, shallow marine shales and sandstones, and the sandstones, siltstones, shales, and coals of deltaic and lagoonal facies. Source rocks include the Sylhet and Kopili Formation shales, Barail Group coals and shales, and in the south the Surma Group shales. Total organic carbon content is generally low, averaging from 0.5 to 1.8 percent; it is as high as 9 percent in the Barail Coal Shales. Maturities are generally low, from Ro (vitrinite reflectance) 0.45 to 0.7 percent where sampled. Maturity increases to the southeast near the Naga thrust fault and can be expected to be higher in the subthrust. Generation began in early Pliocene. Migration is primarily updip to the northwest (< 5 to 15 kilometers) along the northeast-trending slope of the Assam Shelf, and vertical migration occurs through reactivated basement-rooted faults associated with the plate collisions. Reservoir rocks are carbonates of the Sylhet Formation, interbedded sandstones of the Kopili Formation and sandstones of the Barail, Surma, and Tipam Groups. Permeability ranges from less than 8 mD (millidarcies) to as high as 800 mD in the Tipam Group. Porosity ranges from less than 7 percent to 30 percent. Traps are primarily anticlines and faulted anticlines with a few subtle stratigraphic traps. There is also a likelihood of anticlinal traps in the subthrust. Seals include interbedded Oligocene and Miocene shales and clays, and the thick clays of the Pliocene Gurjan Group. Introduction Among the 76 priority provinces identified by the U.S. Geological Survey World Energy Assessment Team (2000) was the Assam geologic province. Located in northeastern India, Assam geologic province is an onshore province covering approximately 74,000 km2 (figs. 1 and 2). The geologic province is bounded on the north and west by the Brahmaputra River, and on the south and east by the Indo-Burman Ranges and the Central Burma Basin (fig. 3). Major features within the Assam geologic province include the Assam Shelf, Brahmaputra River valley, Shillong Plateau, Mirkir Hills, and a foreland portion of the Indian Shield. The Assam Shelf consists of a portion of the Paleocene to Eocene continental shelf of the Indian plate which became emergent and which is being overthrust by the Himalayas on the northwest and by the Burma micro-plate on the southeast. Structurally, the Assam geologic province consists of two primary, subparallel features trending southwest to northeast, which developed just prior to, and as a result of plate collision. The northernmost structural feature is the Assam Shelf, which is presently being subducted beneath both the Eurasian plate to the north and the Burma plate to the southeast. The southernmost feature consists of en-echelon folds of the Naga Hills overthrust belt and northernmost Indo-Burman Ranges, which are continually developing as the shelf is subducted. At present, most hydrocarbon production is northwest of, and parallel to, the Naga thrust fault. Figure 2 shows Brahmaputra River flowing from east (right) to west (left) and tributaries flowing from the Himalayan ranges at the top of the view (north) and from the Naga Hills in the bottom of the view (south). The producing area lies south of the Brahmaputra River. Acknowledgments Insight into the geology and data presented in this report were provided by scientists of the Oil and Natural Gas Corporation (ONGC), Dehra Dun, India. Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System, Assam Geologic Province, India

  • Patala-Nammal Composite Total Petroleum System, Kohat-Potwar Geologic Province, Pakistan
    2004
    Co-Authors: Craig J. Wandrey, B.e. Law, Haider Ali Shah
    Abstract:

    This report describing the Petroleum resources within a total Petroleum System in Pakistan was prepared as part of the World Energy Assessment Project of the U.S. Geological Survey. For this project, the world was divided into 8 regions and 937 geologic provinces, which were then ranked according to the discovered oil and gas volumes within each (Klett and others, 1997). Of these, 76 ‘‘priority’’ provinces (exclusive of the United States and chosen for their high ranking) and 26 ‘‘boutique’’ provinces (exclusive of the United States and chosen for their anticipated Petroleum richness or special regional economic importance) were selected for appraisal of oil and gas resources. The Petroleum geology of these priority and boutique provinces is described in this series of reports. The purpose of the World Energy Project is to assess the quantities of oil, gas, and natural gas liquids that have the potential to be added to reserves within the next 30 years. These volumes either reside in undiscovered fields whose sizes exceed the stated minimum-field-size cutoff value for the assessment unit (variable, but must be at least 1 million barrels of oil equivalent) or occur as reserve growth of fields already discovered. The total Petroleum System constitutes the basic geologic unit of the oil and gas assessment. The total Petroleum System includes all genetically related Petroleum that occurs in shows and accumulations (discovered and undiscovered) and that (1) has been generated by a pod or by closely related pods of mature source rock, and (2) exists within a limited, mappable geologic space, along with the other essential, mappable geologic elements (reservoir, seal, and overburden) that control the fundamental processes of generation, expulsion, migration, entrapment, and preservation of Petroleum. The minimum Petroleum System is that part of a total Petroleum System encompassing discovered shows and accumulations along with the geologic space in which the various essential elements have been proved by these discoveries. An assessment unit is a mappable part of a total Petroleum System in which discovered and undiscovered fields constitute a single, relatively homogenous population such that the chosen methodology of resource assessment based on estimation of the number and sizes of undiscovered fields is applicable. A total Petroleum System may equate to a single assessment unit, or it may be subdivided into two or more assessment units if each unit is sufficiently homogeneous in terms of geology, exploration considerations, and risk to assess individually. A graphical depiction of the elements of a total Petroleum System is provided in the

Stephan A Graham - One of the best experts on this subject based on the ideXlab platform.

  • integrating strike slip tectonism with three dimensional basin and Petroleum System analysis of the salinas basin california
    AAPG Bulletin, 2019
    Co-Authors: Tess Menotti, Allegra Hosford Scheirer, Kristian E Meisling, Stephan A Graham
    Abstract:

    The Salinas Basin is a strike-slip basin in central California with stratigraphy dominantly composed of Miocene Monterey Formation. Despite a long history of oil production, aspects of Petroleum System development in the basin remain poorly understood. Of the seven main oil fields, one—San Ardo field—has produced more than 500 million bbl of oil or 99% of all oil found in the basin. The evolution of this basin was profoundly influenced by strike-slip movement on the Rinconada Fault, which bisected the depocenter beginning circa 15 Ma. To address the influence of strike-slip motion on Petroleum System development, we constructed a three-dimensional (3-D) basin and Petroleum System model that incorporates strike-slip displacement. Seismic reflection profiles from a 3-D survey reveal four main tectonic stages that correspond to events in Petroleum System evolution. Petroleum generation from type II kerogen source rock began circa 11 Ma, approximately 4 m.y. after strike-slip faulting began to offset a once-contiguous sedimentary depocenter. Two separate Petroleum provinces—an eastern one and a western one—developed, and the fault zone likely was a conduit for Petroleum, if nonsealing. Most accumulated Petroleum was derived from the eastern pod of active source rock because of greater sedimentary burial east of the fault. Our model roughly replicates the skewed distribution in oil-field size. Factors controlling field size distribution include trap size and connectivity to source.

  • Petroleum System modeling of the east coast basin hawke bay new zealand
    AAPG Bulletin, 2018
    Co-Authors: Blair Burgreenchan, Stephan A Graham
    Abstract:

    This study evaluates the Petroleum prospectivity of the East Coast Basin, an element of the Hikurangi convergent margin of New Zealand. The basin tectonic environment changed from a dormant convergent margin to convergent margin around the early Miocene, likely causing a decrease in the basin thermal regime. Two end-member paleoheat flow scenarios were used to evaluate thermal maturation of two key source rocks, the Waipawa Black Shale and Whangai Formation, based on calibration to six wells across the basin using vitrinite–inertinite reflectance and fluorescence analysis, as well as Rock-Eval Tmax (the temperature at which the maximum rate of hydrocarbon generation occurs during pyrolysis analysis), thermal alteration index, apatite fission track analysis, and present-day temperatures. This study finds that paleobasal heat flow ranged between 40 and 55 mW/m−2 and decreased to 30 mW/m−2 between 15 and 5 Ma, as bracketed by the two end-member heat flow scenarios. The heat flow scenarios were applied to a palinspastically reconstructed basin and Petroleum System model across Hawke Bay. We find that the two distinct heat flow scenarios cause a 3–6.5 m.y. difference in the relative timing of hydrocarbon generation across the basin. Structural events in the basin associated with convergent margin tectonics act as the main control on the timing of generation. Modeling results show transformation of kerogen to hydrocarbons began between early and late Miocene for both source rocks depending on the structural regime in the basin. The structural control on source rock maturation highlights the need for robust palinspastic reconstructions in addition to paleothermometric data to evaluate the Petroleum prospectivity of convergent margin basins.

  • basin and Petroleum System modelling of the east coast basin new zealand a test of overpressure scenarios in a convergent margin
    Basin Research, 2016
    Co-Authors: Blair Burgreenchan, Kristian E Meisling, Stephan A Graham
    Abstract:

    In the East Coast Basin (ECB), an active convergent margin of the North Island, New Zealand, the smectite-rich Eocene Wanstead Formation forms an effective regional seal, creating high overpressure in the underlying Cretaceous through Palaeocene units due to disequilibrium compaction. This study examines the evolution of pore pressure and porosity in Hawke Bay of the ECB based on stepwise structural reconstruction of a stratigraphic and structural framework derived from interpretation of a regional two-dimensional seismic line. This framework is incorporated into a basin and Petroleum System model to predict the generation, distribution, and dissipation of overpressure, and examine the influence of faults, erosion, structural thickening, and seal effectiveness of the Wanstead Formation on pore pressure evolution. We find that natural hydraulic fracturing is likely occurring in sub-Wanstead source rocks, which makes it a favourable setting for potential shale gas plays. We use poroelastic modelling to investigate the impact of horizontal bulk shortening due to tectonic compression on pore pressure and the relative order of principal stresses. We find that shortening modestly increases pore pressure. When 5% or greater shortening occurs, the horizontal stress may approach and exceed vertical stress in the last 4 Myr of the basin’s history. Shortening impacts both the magnitude and relative order of principal stresses through geological time. Due to the overpressured nature of the basin, we suggest that subtle changes in stress regime are responsible for the significant changes in structural deformational styles observed, enabling compressional, extensional, and strike-slip fault regimes to all occur during the tectonic history and, at times, simultaneously.

Sierd Cloetingh - One of the best experts on this subject based on the ideXlab platform.

  • Relating Petroleum System and play development to basin evolution: Brazilian South Atlantic margin
    Petroleum Geoscience, 2012
    Co-Authors: Suzanne E. Beglinger, Harry Doust, Sierd Cloetingh
    Abstract:

    We review the structural genesis and evolutionary history of basins along the Brazilian South Atlantic margin from the Sergipe-Alagoas (north) to the Pelotas basin (south), and demonstrate the links with Petroleum System and play development. In our approach, we first break basins down into their tectonostratigraphic megasequences and define their characteristics, particularly focused on the development of characteristic source- and reservoir-rock intervals. We then compare these megasequences with similar types of megasequences in other basins, thereby providing a means to learn through a greater population of analogues. We demonstrate, using trajectory plots, that these basins experienced a similar tectonostratigraphic basin evolution, resulting in the deposition of many analogue potential source- and reservoir-rock intervals. These give rise to the development of similar types of potential Petroleum Systems and play (level)s. Although the area is currently being actively explored, large areas remain poorly understood, with unknown source-rock maturity distributions and many unknown/untested reservoirs/plays. This approach allows us to make analogue comparisons between the Brazilian marginal basins in order to evaluate and predict the presence of potential, yet undiscovered or under-explored, hydrocarbon accumulations. Supplementary material: Published source-rock and play properties used in this analysis are available at http://www.geolsoc.org.uk/SUP18536

  • relating Petroleum System and play development to basin evolution west african south atlantic basins
    Marine and Petroleum Geology, 2012
    Co-Authors: Suzanne E. Beglinger, Harry Doust, Sierd Cloetingh
    Abstract:

    Abstract Sedimentary basins can be classified according to their structural genesis and evolutionary history and the latter can be linked to Petroleum System and play development. We propose an approach in which we use the established concepts in a new way: breaking basins down into their natural basin cycle division, then defining the characteristics of each basin cycle (including the type of Petroleum Systems and plays they may contain) and comparing them with similar basin cycles in other basins, thereby providing a means to learn through a greater population of (perhaps not immediately obvious) analogues. Furthermore, we introduce the use of the trajectory plot as a new tool in such an analysis. This methodology has been applied to the West African South Atlantic marginal basins between Cameroon and Angola, and we demonstrate that the similar tectonostratigraphic evolution of the individual basins along this margin has led to the development of similar types of Petroleum Systems and play (level)s. Consequently, we can make analogue comparisons among these basins in order to evaluate and predict the presence of potential, yet undiscovered, hydrocarbon accumulations in less well explored parts of the margin.

G. Bacoccoli - One of the best experts on this subject based on the ideXlab platform.

  • Petroleum Systems of the Brazilian South Atlantic margin
    AAPG Bulletin, 1996
    Co-Authors: M. R. Mello, Eduardo A. M. Koutsoukos, Webster Ueipass Mohriak, G. Bacoccoli
    Abstract:

    The characterization of a major Petroleum System in the Sergipe Basin, NE Brazil, was undertaken using a multidisciplinary approach. The Lura-Muriboca (!) Petroleum System, taken as a representative example for the proto-marine evaporitic stage in the South Atlantic margin, comprises the Carmopolis oil field, which is the largest onshore oil field in Brazil, with about 1.2 MM bbl of oil in place. The hydrocarbons sourced by the proto-marine Aptian marls and calcareous black shales, started migration during the Paleocene, reaching the maximum at the late Oligocene continuing up to now in some parts of the basin. The hydrocarbons were mainly accumulated in Lower Cretaceous alluvial fans/fan deltas coarse clastics reservoirs, and fractured Precambrian basement. The reservoirs trapping were structured during the Cretaceous. Seals are the evaporates and marine shales deposited during the Aptian and Albian times. Mapping the geographic extent of the Petroleum System emphasizes the association of the Carmopolis oil field with the proposed offshore pod of active Aptian source rocks. The integration of these data with a geochemical modelling allowed the prediction and characterization, in time and space, of the Petroleum pathways from source to trap in the basin.