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• 1
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American Association of Petroleum Geologists (AAPG) | GeoScienceWorld
 Online: 84.2000 – (GFZ only) Print: 34(12).1950 – 93(4).2009 (Location: A17, Kompaktmagazin, 9/7 - 10/6)
Publisher: American Association of Petroleum Geologists (AAPG) , GeoScienceWorld
Print ISSN: 0016-7606 , 0149-1423
Electronic ISSN: 1943-2674
Topics: Geosciences
Keywords: GeoScienceWorld ; petrology ; Erdöl ; Erdölgeologie ; Erdölgewinnung ; Erdgas ; Erdgasgeologie
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• 2
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American Association of Petroleum Geologists (AAPG) | GeoScienceWorld | formerly Blackwell Publishing
 Online: 4.1997 – (GFZ only)
Publisher: American Association of Petroleum Geologists (AAPG) , GeoScienceWorld , formerly Blackwell Publishing
Print ISSN: 1075-9565
Electronic ISSN: 1526-0984
Topics: Geography , Geosciences
Keywords: GeoScienceWorld
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• 3
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2016-01-17
Description: The Arctic changes rapidly in response to global warming and is expected to change even faster in the future (IPCC 2001, 2007, 2013). Large areas of the shelves and continental slopes bordering the Arctic Ocean are characterized by permafrost and the presence of gas hydrates. Future global warming and potential hydrate dissociation in the Arctic Ocean challenge the slope stability of these areas. This may lead to slope failures. The first, and so far only reported, large-scale slope failure in the Arctic Ocean is the Hinlopen/Yermak Megaslide (HYM), which is located in front of the Hinlopen glacial trough north of Svalbard. During cruise MSM31 onboard the German R/V MARIA S. MERIAN we investigated this giant slope failure and the deeper structure of the Sophia Basin in detail to elucidate the potential causes of the main and following failure events as well as to test existing hypotheses on the generation of this giant submarine landslide. We studied the megaslide and the adjacent so far not failed shelf areas by means of multibeam swath bathymetry, Parasound sediment echo sounder, low- and high-resolution multichannel seismic reflection profiling. The seismic data image bottom-simulating reflectors beneath not failed areas of the slope, as well as a buried gas escape pipe. On the shelf, shallower than the gas hydrate stability zone, we observed widespread gas seepage as flares in the Parasound echo sounder data. These flares rise from a seafloor highly disturbed by iceberg scouring. Therefore, we could not identify pockmarks in the multibeam data. At one location, we sampled a flare by means of a CTD probe close to the seafloor and proofed that the emanating gas has a high methane concentration. The new data indicate that the existence of gas and gas hydrates beneath the shelf north of Svalbard was one key factor causing slope instability in the past and may also cause further slope failures in the future.
Repository Name: EPIC Alfred Wegener Institut
Type: Conference , NonPeerReviewed
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• 4
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2016-01-21
Description: The modern polar cryosphere reflects an extreme climate state with profound temperature gradients towards high-latitudes. It developed in association with stepwise Cenozoic cooling, beginning with ephemeral glaciations and the appearance of sea ice in the late middle Eocene. The polar ocean gateways played a pivotal role in changing the polar and global climate, along with declining greenhouse gas levels. The opening of the Drake Passage finalized the oceanographic isolation of Antarctica, some 40 Ma ago. The Arctic Ocean was an isolated basin until the early Miocene when rifting and subsequent sea-floor spreading started between Greenland and Svalbard, initiating the opening of the Fram Strait / Arctic-Atlantic Gateway (AAG). Although this gateway is known to be important in Earth’s past and modern climate, little is known about its Cenozoic development. However, the opening history and AAG’s consecutive widening and deepening must have had a strong impact on circulation and water mass exchange between the Arctic Ocean and the North Atlantic. To study the AAG’s complete history, ocean drilling at two primary sites and one alternate site located between 73°N and 78°N in the Boreas Basin and along the East Greenland continental margin are proposed. These sites will provide unprecedented sedimentary records that will unveil (1) the history of shallow-water exchange between the Arctic Ocean and the North Atlantic, and (2) the development of the AAG to a deep-water connection and its influence on the global climate system. The specific overarching goals of our proposal are to study: (1) the influence of distinct tectonic events in the development of the AAG and the formation of deep water passage on the North Atlantic and Arctic paleoceanography, and (2) the role of the AAG in the climate transition from the Paleogene greenhouse to the Neogene icehouse for the long-term (~50 Ma) climate history of the northern North Atlantic. Getting a continuous record of the Cenozoic sedimentary succession that recorded the evolution of the Arctic-North Atlantic horizontal and vertical motions, and land and water connections will also help better understanding the post-breakup evolution of the NE Atlantic conjugate margins and associated sedimentary basins.
Repository Name: EPIC Alfred Wegener Institut
Type: Conference , NonPeerReviewed
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• 5
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019-07-16
Description: Petroleum systems located at passive continental margins received increasing attention in the last decade mainly because of deep- and ultra‐deep-water hydrocarbon exploration and production. The high risks associated with these settings originate mainly from the poor understanding of inherent geodynamic processes. The new priority program SAMPLE (South Atlantic Margin Processes and Links with onshore Evolution), established by the German Science Foundation in 2009 for a total duration of 6 years, addresses a number of open questions related to continental breakup and post‐breakup evolution of passive continental margins. 27 sub‐projects take advantage of the exceptional conditions of the South Atlantic as a prime “Geo‐archive.” The regional focus is set on the conjugate margins located east of Brazil and Argentina on one side and west of Angola, Namibia and South Africa on the other (Figure 1) as well as on the Walvis Ridge and the present‐day hotspot of Tristan da Cunha. The economic relevance of the program is demonstrated by support from several petroleum companies, but the main goal is research on fundamental processes behind the evolution of passive continental margins.
Repository Name: EPIC Alfred Wegener Institut
Type: Book , NonPeerReviewed
Format: application/pdf
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• 6
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity–permeability transforms were generated using an extensive data set covering two oil-bearing formations in Ohio: the Clinton Sandstone in eastern Ohio and the Copper Ridge Dolomite in central Ohio. The reservoirs were selected because of their historical importance as oil producers and their potential as targets for CO〈sub〉2〈/sub〉 use for enhanced oil recovery and associated geological storage. The porosity-permeability transforms generated in this study have coefficients of determination that are nearly double those in the published literature. Methods applying other information (e.g., lithofacies type and reservoir depth) to improve the transforms are also discussed. Ultimately, it was determined that although subdividing the Clinton Sandstone data by geologically similar areas constrained the porosity and permeability values, the data for most areas were too limited to yield robust correlations. Thus, the range of possible outcomes should be determined using the transform derived from all available data. The Copper Ridge values were largely not constrained when subdivided by depth.〈/span〉
Print ISSN: 1075-9565
Electronic ISSN: 1526-0984
Topics: Geography , Geosciences
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• 7
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉
Print ISSN: 1075-9565
Electronic ISSN: 1526-0984
Topics: Geography , Geosciences
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• 8
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉In this paper, high-resolution three-dimensional seismic data are used to interpret a transpressional salt tectonic structure in the Yingxiongling area, Qaidam Basin, China. The geometries of the salt structure and the Shizigou fault system that intersects it are precisely depicted. The Shizigou fault system is composed of suprasalt and subsalt components. The suprasalt component is a Y-shaped reverse fault, and the subsalt component is a complex flower structure. In previous studies, suprasalt and subsalt components were interpreted as two independent fault systems. This paper proposes instead that the suprasalt and subsalt faults are kinematically related and decoupled across the salt layer.〈/span〉
Print ISSN: 0149-1423
Electronic ISSN: 1943-2674
Topics: Geosciences
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• 9
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field.Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.〈/span〉
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• 10
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.〈/span〉
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• 11
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.〈/span〉
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉For oil-rich shales, current solvent extraction– and thermal extraction–based methods inaccurately measure hydrocarbon-filled porosity (〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉). Moreover, the hydrocarbon composition is not characterized by either method. Here, we show how open-system programmed thermal extraction and pyrolysis, LECO total organic carbon, Archimedes bulk density, and helium pycnometry measurements are integrated to calculate oil and gas pore volumes, characterize their composition, and estimate mobility. Use of a modified multiramp, slow-heating thermal extract, and pyrolysis temperature program further subdivides the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. Saturate–aromatic–resin–asphaltene (SARA) separation and gas chromatography of solvent-extracted organic matter and thermally extracted oils are used to compositionally classify the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. The segregated bulk compositions of gas- and oil-filled porosity measured via this method are shown to overlap and are broken into the following categories: gas-filled porosity (∼C〈sub〉1〈/sub〉–C〈sub〉14〈/sub〉), light oil–filled porosity (∼C〈sub〉6〈/sub〉–C〈sub〉36〈/sub〉), and heavy oil–filled porosity (∼C〈sub〉32〈/sub〉–C〈sub〉36〈/sub〉+). Furthermore, slow-heating multiramp thermal extraction can subdivide the light oil–filled porosity into four components capturing the C〈sub〉11〈/sub〉–C〈sub〉13〈/sub〉, C〈sub〉12〈/sub〉–C〈sub〉16〈/sub〉, C〈sub〉14〈/sub〉–C〈sub〉20〈/sub〉, and C〈sub〉17〈/sub〉–C〈sub〉36〈/sub〉 ranges of the extractable organic matter. Analysis of solvent-extracted oils by SARA identifies abundant saturates and aromatics in the light oil–filled porosity and abundant resins and asphaltenes in the heavy oil–filled porosity. Low-maturity shales can be dominated by heavy (C〈sub〉32〈/sub〉+) oils rich in asphaltene and resin fractions not observed in the produced fluid. The ratios of SARA components in the C〈sub〉15〈/sub〉+ fraction of produced fluid and core extract can be used to better estimate the potentially mobile 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉.〈/span〉
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• 13
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow.Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference.The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.〈/span〉
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• 14
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.〈/span〉
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km〈sup〉2〈/sup〉 (10,000 mi〈sup〉2〈/sup〉). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.〈/span〉
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• 16
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 10〈sup〉10〈/sup〉 m〈sup〉3〈/sup〉 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10〈sup〉−13〈/sup〉 m〈sup〉2〈/sup〉/s (1.1 × 10〈sup〉−12〈/sup〉 ft〈sup〉2〈/sup〉/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of 〉10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.〈/span〉
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2019
Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.〈/span〉
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• 18
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-09-14
Description: Quartz is the principal framework mineral in clastic sediment reservoirs. In a frontier basin with sparse wells, the source of quartz in sandstones may be a predictor of the availability of medium- to coarse-grained quartz sand from plutonic sources, likely to provide good reservoirs. The Scotian Basin, offshore eastern Canada, was used to test this hypothesis because of its well-understood provenance history and geographic variability in known medium- to coarse-grained reservoir sandstones. The sources of detrital quartz in fine-grained sandstones were determined using hot-cathode cathodoluminescence (CL), supplemented by other petrographic techniques. The CL color shift for different quartz types was calibrated against the CL properties of representative source rocks in the hinterland, because generalizations in the literature do not precisely match our basin-specific observations. Grain size of sandstone exerts a strong control over quartz type, with plutonic-hypabyssal quartz and high-grade metamorphic quartz more abundant in coarse-grained sandstones and low-grade metamorphic quartz more abundant in fine-grained sandstones. Nevertheless, the analysis of fine-grained sandstones shows that plutonic-hypabyssal quartz is more abundant in fine-grained sandstones of the Sable subbasin than in those of the Abenaki subbasin. The abundance of plutonic-hypabyssal quartz correlates with the abundance of medium- to coarse-grained sandstone reservoirs in the Sable subbasin. This study suggests that, in frontier basins, the abundance of plutonic-hypabyssal quartz in fine-grained sandstones can be used as an indicator of available medium- to coarse-grained sandstone reservoir.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-09-14
Description: Outcrops provide valuable information for the characterization of fracture networks. Sampling methods such as scanline sampling, window sampling, and circular scanline and window methods are available to measure fracture network characteristics in outcrops and from well cores. These methods vary in their application, the parameters they provide and, therefore, have advantages and limitations. We provide a critical review on the application of these sampling methods and apply them to evaluate two typical natural examples: (1) a large-scale satellite image from the Oman Mountains, Oman (120,000 m 2 [1,291,669 ft 2 ]), and (2) a small-scale outcrop at Craghouse Park, United Kingdom (19 m 2 [205 ft 2 ]). The differences in the results emphasize the importance to (1) systematically investigate the required minimum number of measurements for each sampling method and (2) quantify the influence of censored fractures on the estimation of fracture network parameters. Hence, a program was developed to analyze 1300 sampling areas from 9 artificial fracture networks with power-law length distributions. For the given settings, the lowest minimum number of measurements to adequately capture the statistical properties of fracture networks was found to be approximately 110 for the window sampling method, followed by the scanline sampling method with approximately 225. These numbers may serve as a guideline for the analyses of fracture populations with similar distributions. Furthermore, the window sampling method proved to be the method that is least sensitive to censoring bias. Reevaluating our natural examples with the window sampling method showed that the existing percentage of censored fractures significantly influences the accuracy of inferred fracture network parameters.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-09-20
Description: The Cretaceous rocks of Florida have been recognized as potentially suitable reservoirs for geologic carbon dioxide (CO 2 ) sequestration. Specifically, the upper member of the Upper Cretaceous Lawson Formation, together with the lower part of the Paleocene Cedar Keys Formation, is presented here as a potential composite CO 2 storage reservoir that is mainly composed of porous dolostone sealed by thick anhydrites of the overlying middle Cedar Keys Formation. Many of the porous intervals within the Cedar Keys-Lawson storage reservoir display lateral continuity and have an average porosity range of 20%–30%. The estimated CO 2 storage capacity for the reservoir is approximately 97 billion t of CO 2 , which means the Lawson and Cedar Keys Formations composite reservoir could potentially support CO 2 sequestration for hundreds of large-scale power plants in the southeastern United States for their entire 40-yr lifespan. Because most of the previous research on the Lawson Formation is concentrated in north-central and northeastern Florida and southern Georgia, this study further characterizes the formation and its CO 2 sequestration potential in south-central and southern Florida.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: The Ordovician carbonate platform at the Yijianfang outcrop of the Bachu uplift region in the western Tarim Basin contains four types of genetic facies associations developed in the calciclastic slope-fan depositional system: an olistostrome zone, fan channels, lobes, and a marginal slope. The olistostrome zone is characterized by olistoliths and slump fans, whereas the fan channels and lobes are further divided into proximal and distal facies. The marginal slope deposits constitute the background sedimentation in which the calciclastic slope fans are intercalated. From proximal to distal parts of the fan channels and lobes, their scale gradually becomes smaller, and the size and sorting of grains become finer and better, respectively. Analysis of the stratigraphic framework indicates that the fans formed in the lower strata of the Upper Ordovician Lianglitage Formation in four high-frequency sequences (i.e., Pss1–Pss4). Field paleocurrent measurements indicate northeast-southwest depositional strike for the early platform margin of the Lianglitage Formation. Sediments in the calciclastic slope fans were derived from the platform margin, and evolution of the calciclastic slope fans was generally progradational from Pss1 to Pss2 and then continuously retrogradational from Pss2 to Pss4. The calciclastic slope fans in the outcrop area are not reservoir-prone rocks, but interpretation on these fans can provide useful information about potential hydrocarbon reservoirs along the platform margin. The P -wave velocity, S -wave velocity, and density variations in each genetic facies may be used to identify the subsurface calciclastic slope-fan depositional system.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: Three aspects of basement structure and rift-related salt distribution have especially influenced the evolution of the deep-water northern Gulf of Mexico: (1) creation of a basement high (Toledo Bend flexure), separating a chain of interior basins from the central Louann salt basin, (2) segmentation of the central Louann salt basin by the Brazos transfer fault into eastern and central domains, and (3) salt provinces formed during basin opening. The Toledo Bend flexure was reactivated as a hinge during the Cenozoic uplift of the North American craton. This uplift triggered gravity gliding, forming fold belts in the seaward parts of the continental margin. The geometry of the Toledo Bend flexure influenced the position of these fold belts. The Brazos transfer fault separates the west sector of the study area from the central and east sectors. Most of the salt in the deep-water northern Gulf of Mexico lay in the central sector, which sourced most of the Sigsbee salt canopy. The western sector was narrower and was subdivided by the East Breaks basement high. Splitting the Callovian salt basin in two as the gulf opened created a southward-thinning wedge of salt at the seaward end of the northern Gulf of Mexico. We divide this wedge into a series of provinces on the basis of the geometry of the base of the deep salt. Original salt thickness influenced diapir location, the geometry of the Sigsbee canopy, the geometry and style of later compressional fold belts, and petroleum systems.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: Recent ultradeep exploration in the northern Gulf of Mexico has revealed a broad diffuse zone of salt-cored folding beneath the present continental shelf. This zone is a pillow fold belt, where salt pillows grew halokinetically and were then mildly shortened. Below the Louisiana shelf, a contractional early-to-late Miocene pillow fold belt is separated by a partly welded canopy from an overlying early Miocene–to–Pliocene extensional system. This anomalous juxtaposition raises two paradoxes: (1) Why was mid-Miocene shortening close to the Miocene shelf break, where extension is expected? and (2) Why did shortening below the canopy overlap in time with extension above the canopy? Coastal uplift can explain both paradoxes. Cenozoic uplift and exhumation of the north rim of the Gulf of Mexico created the observed coastal offlap and truncation around the rim. Uplift tilted the continental margin and overpowered the influence of the paleoshelf break, causing shortening much farther updip than before uplift. Physical models confirm that this hypothesis is mechanically sound. Our other models had two stacked detachments, each pinned in different locations. Because of this, deep shortening below the canopy was coeval with shallow extension above the canopy. The deep detachment was pinned far inland, equivalent to the uplifted continental interior. Extension above this deep detachment was partly balanced by shortening far downdip to form a pillow fold belt where a network of thrusts linked the squeezed pillows. In contrast, the shallow extensional system above the canopy was pinned farther seaward, equivalent to the upper continental slope.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: Determination of turbidite event magnitude and frequency remains subjective and difficult to define. This is because turbidite sedimentation events commonly include both sand and mud, with the mud component commonly excluded from bed thickness studies because of the inability to establish a genetic link to the turbidity current. Pelagic mudrock is defined as fine-grained marine sediment derived primarily from biogenic particles, whereas hemipelagic mudrock includes both biogenic and terrigenous particles. Unfortunately, these compositional definitions do not account for differences in depositional process. Scanning electron microscopy, field emission scanning electron microscopy, and x-ray diffraction analyses of 70 samples from El Rosario Formation outcrops (Baja California, Mexico) and core from the Woodford Shale (Oklahoma) illustrate this distinction. Furthermore, these laboratory measurements are calibrated to 192 outcrop samples to provide a robust method for field identification of clay fabric and mineralogy to define turbidite sedimentation units. Pelagites show organized layering of clay platelets, few flocculates, and a lower proportion of high-density minerals. Hemipelagites have disorganized and chaotic clay fabrics characterized by visible flocculates and contain a higher proportion of denser particles. There may also be a corresponding change in clay mineralogy, for example, smectite in pelagites versus kaolinite in hemipelagites. These results indicate a settling velocity greater than shear velocity in pelagites, whereas hemipelagites record the opposite condition. Turbidity currents support and suspend denser grains, generate disorganized and chaotic clay fabrics, and provide more time for flocculation. Discrimination between pelagites and hemipelagites has important implications in the determination of turbidite event frequency and magnitude, which affects vertical connectivity and continuity of sand, deposited from multipartite turbidity currents. In addition, distinction between pelagites and hemipelagites provides a better understanding of mudrock reservoir architecture.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-12-02
Description: Descriptions of mineralogy and textural relationships in sandstones and limestones have been used to establish a sequence of diagenetic events (epigenesis), involving mineral dissolution and precipitation, which have been interpreted to have occurred during the burial history. Published epigenetic sequences commonly imply a geochemically open system with very significant changes in the bulk chemical composition of the sediments during burial. Near-surface diagenetic reactions may be open, involving significant changes in the sediment composition and formation of secondary porosity caused by high pore-water flow rates of meteoric water or reactions with sea water near the sea floor. Calculations show that the bulk chemical composition of the sediments below the reach of high pore-water flow rates of meteoric water or hydrothermal convection should remain nearly constant during progressive burial because of limited pore-water flow. Mass transport between shales and sandstones is also limited because the pore water is, in most cases, buffered by the same minerals so that the concentration gradients are low. Recent studies show that silica released from clay-mineral reactions in mudstones has been precipitated locally as small quartz crystals and not exported to adjacent sandstones. If the geochemical constraints for mass transfer during burial diagenetic reactions are accepted, the chemical reactions involved in diagenesis can be written as balanced equations. This offers the possibility to make predictions about reservoir quality based on assumptions about primary sediment composition related to facies and provenance. Large-scale changes in the bulk composition of sandstones and mudstones during burial diagenesis have been suggested, but because such changes cannot be explained chemically and physically, no predictions can be made. Burial diagenetic processes are, in most cases, not episodic but occur as slow adjustments to increased stress and temperature, driving the sediments toward increased mechanical and thermodynamic stability. As a result, the porosity of a single lithology must decrease during progressive burial, but each lithology has a different porosity curve. This article discusses quantitative calculations and estimates that show clearly that burial diagenesis must represent geochemically nearly closed systems where mineral dissolution and precipitation must be balanced. This provides a theoretical basis for the modeling and prediction of reservoir quality.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-12-02
Description: The Yufutsu oil and gas field, located in Hokkaido, northern Japan, produces hydrocarbon from a typical fracture-type reservoir composed of very tight Cretaceous granitic basement and overlying conglomerate of the Eocene. Here, delineations of faults accompanying large open fractures are essential for optimal developments. To capture fault distribution objectively, various seismic-attribute estimates ascribed to fault distributions are derived from three-dimensional seismic data by computational procedures. However, to use the estimates properly, calibrating them with independent observations other than seismic data is important. We present a calibration scheme by coupling seismic data with microseismic data and in-situ stress data to delineate active faults under a strike-slip faulting stress regime in the Yufutsu field. Active faults are interpreted to be fluid pathways formed by shear dilation. In the calibration, two kinds of parameter sets are tuned. One controls linkages of fault responses fragmented by artificial noises caused by seismic acquisition and processing to adjust spatial continuities of fault surfaces properly. Another limits extracted fault strikes with respect to Mohr-Coulomb failure criterion to highlight active faults. The calibrated seismic-attribute estimates show a qualitative consistency with the microseismic hypocenter distribution observed during a massive hydraulic stimulation. In addition, a large difference in gas productivity observed at four wells, from very high productivity to no gas flowing, is clearly related to an existence of distinct lineation with strong magnitudes of the calibrated seismic attributes. It suggests that the calibrated estimate becomes a criterion to judge an economic viability of a well.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-11-01
Description: The Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics. Depositional environments were interpreted based on organic geochemical (Rock-Eval pyrolysis, extract analysis, and biomarker distributions) and organic petrological methods. Organic carbon contents range between 1.0 and 32.5 wt. %. The Khatatba shale and coaly shale samples have hydrogen index values in the range of 63 to 261 mg hydrocarbon (HC)/g total organic carbon, with mixed types 2–3 and 3 kerogens. Mean vitrinite reflectance (R o ) between 0.77 and 1.07% is in reasonably good agreement with pyrolysis T max (temperature at maximum of S 2 peak) data (438–459°C). Organic-rich sediments of the Middle Jurassic Khatatba Formation have very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The main generation products are gas with very limited liquid HCs (oil or condensate). Seven shale and coaly shale samples from Khatatba Formation were characterized using gas chromatography (GC) and GC–mass spectrometry techniques. The Khatatba samples are characterized by the predominance of C 14 -C 24 alkanes, a pristane/phytane ratio of less than 2, abundant C 27 regular steranes, and the presence of tricyclic terpanes. These are consistent with the suboxic marine-environment conditions for the Khatatba source rock. Biomarker parameters for these samples generally indicate a mixture of land- as well as marine-derived organic-matter input. The maturity indicators based on C 32 22S/(22S + 22R) homohopane and C 29 20S/(20S + 20R) and ββ/(ββ + αα) sterane ratios reveal that the Khatatba samples are thermally mature and have reached the peak oil-window maturity supporting the R o data.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-11-01
Description: The petroleum industry is increasingly using geographic information systems (GISs) for mapping and spatial database needs because they are useful for elucidating and exploiting spatial relationships between geologic and geophysical data. However, the petroleum industry, in general, does not exploit the full potential of GIS as an analysis tool. In particular, GIS offers spatial and analytical support for multicriteria evaluation (MCE) methods, which are used to combine data to show areas best fulfilling specific criteria. Petroleum explorations would benefit from an MCE method that is spatial, is flexible for combining heterogeneous data, considers the interpretive nature of the data, is geologically applicable, and is applicable for frontier areas or where little information exists regarding probabilities of the presence of petroleum. This study proposes a GIS-based MCE method for petroleum exploration based on fuzzy logic, which fulfills the previously stated requirements using 16 subcriteria and one constraint combined in tiers to produce a favorability map of potential exploration areas. A case study applied to northern South America, chosen because of its centrality to petroleum exploration, shows potential new exploration areas in the Cretaceous–Paleogene and Miocene–Holocene. The method was validated by comparing the favorability maps of one non–geologic age–specific and of two geologic age–specific favorability maps to known producing fields. We conclude that the method can be applied in an exploration setting and, as such, is applicable for other regions of the world.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-11-01
Description: Determination of the membrane seal capacity of deformation bands is critical for managing geologic reservoirs in porous sandstones. In this study, we have analyzed a cataclastic shear-band network developed in uncemented porous sandstone in Provence, France. Geometrical analyses of the bands show significant differences between three types of bands (single strand, multistrand, and band cluster), sorted by their number of strands, their amount of shear displacement, and their thicknesses. At the microscopic scale, the image-analysis porosities and the grain-size distributions allow definition of three different types of microstructural deformation: damage zone, protocataclastic, and cataclastic. Whereas damage zone and protocataclastic deformations are observed in each type of band, cataclastic strands are observed in clusters and, sometimes, in multistrands. Cataclastic strands are characterized by a porosity reduction of 10 to 25% and a permeability reduction of three to five orders of magnitude compared to the host rock. Field observations of iron hydroxide precipitations around the bands suggest that cataclastic strands were membrane seals to water flow under vadose condition. This study therefore highlights the importance of the degree of cataclasis in shear bands as membrane seals to subsurface fluid flows in sandstone reservoirs.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-11-22
Description: Open faults and fractures act as a major control of fluid flow in the subsurface, especially in fine-grained, low-permeability lithologies. These discontinuities commonly form a part of seal bypass systems, which can lead to the failure of hydrocarbon traps, CO 2 geosequestration sites, and waste and injected fluid repositories. We evaluate mesoscale variability in fracture density, morphology and the variability in elastic moduli in the Jurassic Carmel Formation, a proposed seal to the underlying Navajo Sandstone for CO 2 geosequestration. By combining mechanostratigraphic outcrop observations with elastic moduli derived from wireline-log data, we characterize the variability in fracture pattern and morphology with the observed variability in rock strength within this heterolithic top seal. Outcrop inventories of discontinuities show that fracture densities decrease as bed thickness increases and that fracture propagation morphology across lithologic interfaces vary with changing interface type. Dynamic elastic moduli, calculated from wireline-log data, show that Young's modulus ranges by as much as 40 GPa (5,801,510 psi) across depositional interfaces and by an average of 3 GPa (435,113 psi) across the reservoir-seal interface. We expect that the mesoscale changes in rock strength will affect the distributions of localized stress and thereby influence fracture propagation and fluid flow behavior within the seal. These data provide a means to closely tie outcrop observations to those derived from subsurface data and estimates of subsurface rock strength. The characterization of rock strength variability is especially important for modeling the response of caprocks to changing stress conditions associated with increased fluid pressures and will allow for better site screening and subsurface fluid management.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: Exceptional mimetic preservation of reef fabrics in a dolostone subsurface core from Vacuum field, Lea County, New Mexico, along the northwest shelf margin of the Permian Basin reveals the significant microbialite role in a calcisponge-microbialite reef of the upper San Andres Formation (lower Guadalupian [middle Permian]). The shelf-margin reef facies, which comprises more than 85% of the 175-ft (53.34-m) cored section, is bordered shelfward by crestal shelf-margin shoal facies and seaward by basinal sandstones of the Delaware Mountain Group. The thick shelf-margin reef located within 500 ft (152.4 m) of basinal sandstone facies indicates a relatively steep reefal shelf margin. Microbialite encrustations are the most important binding agent in the reef, and their major contribution to the cohesion and volume of the reef has significant implications for the growth and character of other middle Permian shelf-margin reefs. The reef facies is composed of (1) a calcisponge-dominated reef framework (Guadalupia, Lemonea, Amblysiphonella, Discosiphonella [Cystaulete], and Cystothalamia); (2) a binding biota of ubiquitous micritic, laminated, and thrombolitic microbialite, moderately common Tubiphytes (= Shamovella), and sparse Archaeolithoporella and bryozoans; (3) sparse botryoids of syndepositional radial fibrous cements; (4) sparse reef dweller biota of gastropods, brachiopods, and crinoids; and (5) reef cavities lined by banded isopachous layers of marine phreatic radiaxial cements, partly filled by geopetal sediments, and finally filled by anhydrite. The paragenetic sequence is (1) reef growth, (2) framework cavities lined by marine phreatic radiaxial cements and partially filled by geopetal sediments, (3) partial aragonite dissolution and karsting, (4) rapid reflux dolomitization, (5) localized fracturing and spalling of cavity walls before and during emplacement of anhydrite, and (6) burial and pressure solution. Patchy intraskeletal skelmoldic porosity is mostly within calcisponges. Karstic fractures and cavities in the upper reef are filled with breccia clasts, fusulinid packstone-grainstones, dark argillaceous dolomudstones, and massive anhydrite.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: Lacustrine carbonates of the Eocene Green River Formation crop out on the western margin of the Piceance Basin and the eastern margin of the Uinta Basin, in western Colorado. This area allows tracing of vertical and horizontal facies variation over hundreds of meters. Limestone beds consist of littoral to sublittoral lithofacies: bioclastic and oolitic grainstones, oolitic wackestone, intraclastic rudstone, stromatolites, and thrombolites. Facies form upward-deepening cycles that start with sharp-based grainstones and packstones followed by stromatolites or thrombolites and capped by fine-grained stromatolites and/or oil shale deposits. The vertical succession of carbonate deposits correlates with evolutionary lake stages. The succession starts with grainstone deposits rich in ostracods and gastropods that correspond to an initial freshwater lake. Thrombolites capped by laminated stromatolites or coarse-agglutinated stromatolites correlate with a higher-salinity transitional lake. Deepening-upward cycles, as much as 5 m (16 ft) thick, of thrombolites, agglutinated stromatolites, and fine-grained stromatolites occur in the highly fluctuating lake. The upper section is dominated by laminated stromatolites that correspond to a rising lake. Stable isotope 18 O and 13 C values covary and range from –8 to +0.8 and –3 to +5, respectively. The 18 O values indicate carbonate-precipitating water evolved from fresh to saline and became less saline in the upper Green River. Negative excursions of 13 C values correspond to lake level rises, and positive excursions of 13 C values occur during lake level falls. Syndepositional to burial diagenesis modified carbonate porosity. Early dissolution is followed by burial compaction and fracturing. Compaction and late calcite cements occluded primary and secondary porosity.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: An integrated field study of the microbial carbonate and associated reservoirs at Little Cedar Creek field in southwest Alabama, eastern Gulf coastal plain of the United States, provides an excellent opportunity to examine the spatial distribution of the sedimentary, petrophysical, and productivity trends in microbial reservoirs. This study includes characterizing the sedimentary, petrophysical, and hydrocarbon productivity characteristics of microbialites, developing a three-dimensional geologic reservoir model, and evaluating the hydrocarbon potential of these reservoirs. The lower reservoir comprises subtidal thrombolitic boundstone associated with microbial buildups oriented in a southwest to northeast direction over an area that encompasses 32 mi 2 (83 km 2 ). These buildups developed in clusters in the western, central, and northern parts of the field and attained thicknesses of 43 ft (13 m). The clusters are separated by interbuildup areas of microbialites of 7–9 ft (2–3 m) in thickness that are overlain by a thick section of nonreservoir microbially influenced lime mudstone and wackestone. Porosity in the microbial reservoirs includes depositional constructed void (intraframe) and diagenetic solution-enhanced void and vuggy pore types. This pore system provides for high permeability and connectivity in the reservoir beds. Permeability ranges to as much as 7953 md and porosity to as much as 20%. The microbial boundstone beds have high potential as hydrocarbon flow units; however, the buildup areas are separated by interbuildup areas associated with a thick section of low-permeability to nonreservoir beds that serve as potential baffles or barriers to flow. Much of the 17.2 million bbl oil produced from the field is from the microbial lithofacies. The results from the Little Cedar Creek field study have application in the design of improved development strategies for other fields producing from microbial carbonate reservoirs.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: Microbial carbonates have complex pore networks formed by their biological growth framework, which later may be modified by diagenetic alteration. A proper evaluation of the porous media characteristics and their evolution is essential to better characterize microbial carbonate reservoirs. However, conventional methods of fundamental rock characteristic description are insufficient to elucidate the heterogeneity of pore networks and textural shifts. X-ray computed tomography allows a better evaluation of these fundamental characteristics, which, when integrated with stratigraphic analysis, enhances the understanding of the volume and connectivity of pore networks in different microbial textures. A three-dimensional evaluation of a Holocene microbialite from Brazil provides insights about how the primary pore network is related to the textural changes in microbialite successions, which, in ancient deposits, may be reduced or enhanced by diagenesis. Conventional methods such as petrography, carbon and oxygen stable isotope analysis, and laboratory measurements for porosity and permeability were integrated with computed tomography images and three-dimensional rendering to provide a high-resolution history of the evolution of porosity and permeability within this microbialite. The pore network differences are related to microbial textural evolution driven by environmental changes. The depositional textures control petrophysical properties based on fundamental rock characteristics such as structure size, structure packing, and framework fabric. Those fundamental characteristics influence the pore volume and number of pore throats. Large structures, open packing, and chaotic framework fabric result in a better connected pore network, whereas small structures, tight packing, and organized fabric result in less connected pore networks. Comparative pore geometry analysis of the Upper Jurassic Smackover Formation thrombolites shows that their depositional textures also had high primary porosity values. If the microbial textures and petrophysical properties are environmentally controlled, their prediction in the subsurface is made possible by refined depositional models.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: Static three-dimensional (3-D) reservoir analog models were constructed for the Miocene terminal carbonate complex (TCC) in southeastern Spain. The models used field data collected from two areas containing exceptional 3-D exposures (La Molata; La Rellana-Ricardillo). Four TCC sequences in each area are composed of oolite, microbialite (thrombolites, stromatolites), bioclastic sands, and coralgal reefs deposited over paleotopographic relief of 33–76 m (108–249 ft). The models integrate field, laboratory, and petrophysical data with results providing a workflow and reservoir analogs useful in evaluating oolilte and microbialite reservoir characteristics in relation to paleotopography and sea level change. Results from this study reveal favorable reservoir-quality values with the potential for substantial hydrocarbon storage for many lithofacies. Flow and baffle facies were distinguished for the models based on thickness, lateral distribution, porosity, and permeability values. Trough cross-bedded ooid grainstone is volumetrically the most abundant lithofacies within both models, is laterally extensive across the entirety of sequences, has large storage capacities with good permeability, and has good connectivity with other flow facies. This facies represents the best reservoir-quality facies and would be the primary target for hydrocarbon exploitation. Microbialites act both as reservoir and baffle facies. Thrombolites, in particular, are concentrated downslope and in a more restricted embayment but vary between porous and nonporous facies. Stromatolites and fenestral ooid grainstones are concentrated at sequence boundaries and would create laterally extensive baffles with significant thicknesses at the sequence boundaries. Sea level interacting with both paleotopography and paleogeography were identified as the main controls on sequence development and reservoir heterogeneity. An understanding of these controls can aid in exploitation and identification of oolite-microbialite sequences.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-03
Description: Bacteria are responsible for the precipitation and accumulation of some significant carbonate deposits; prime examples are hot spring travertine accumulations. Bacteria induce precipitation of carbonate minerals immediately surrounding their cell walls and, in doing so, entomb themselves within the crystals. Subsequently, a generation of abiotically precipitated clear spar commonly cements cell colonies as well as the initial bacterially induced carbonate. The relatively rapid decay of the bacterial fossils, consequently, results in localized abundances of unconnected microporosity. This submicron- to micron-size porosity is not normally detected by standardized porosity evaluations. These pore systems, which are especially abundant in hot spring travertine deposits, can influence density measurements and, therefore, any calculations in which density is a factor. The pores have been found to be abundant within different bacterially induced features, such as shrubs, peloids, and oncoids. Other forms of porosity common in hot spring travertines include shelter porosity, foam rock, and some highly irregular early dissolution of the carbonate caused by the abundance of nonmarine waters coursing through these rocks.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-09-14
Description: The three-dimensional (3-D) geometry of fractures and fault-related dolomite is difficult to access with classical subsurface prospection tools. Therefore, we have investigated an outcrop to improve the subsurface prediction for complex dolomite bodies. This outcrop is located in the Etoile massif (southeastern France) within a fault-bend anticline. The sedimentary units are of Upper Triassic to lower Barremian age. The fold results from the Pyreneo-Provençal shortening during the Late Cretaceous to the Eocene. The anticline hosts three types of dolomite bodies: (1a) massive dolomite of middle to late Oxfordian age, (1b) syndepositional stratabound dolomite of Tithonian age, and (2) isolated dolomite bodies associated with fractures and faults. Large-scale geometries of fault-related dolomite bodies have been modeled in 3-D. The 3-D geometries of these bodies show diapir-, finger- and wall-like structures. These bodies are located close to the main thrusts, in strata of middle Oxfordian to early Barremian age and are linked to the compressive fold-bending phase during the Late Cretaceous. Fault-related dolomitization occurred because of magnesium removal from the hydraulic brecciation and the pressure solution of type 1 dolomite with overpressured fluids. These fluids flushed upward along the main thrust and laterally by following the reservoir property contrasts in the host rocks. Fault-related dolomite bodies are either spread far apart from faults in grainy limestones with good initial reservoir properties or are restricted to fault vicinity in muddy limestones with poor initial reservoir properties. The study of the structural and stratigraphic framework was essential in the understanding of the dolomitization process.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-09-20
Description: Geochemical reactions that may occur on CO 2 injection into a sandstone formation in Missouri (MO) were investigated by means of geochemical modeling. Five possible injection sites were considered: two in the northwestern part of the state, two in the northeastearn part, and one in the southwestern part. The Geochemist Workbench software was used to investigate solubility trapping and mineral precipitation. Modeling was performed for two periods: an injection period of 10 yr and a postinjection period where the reactions proceeded to equilibrium. The work presented substantial challenges. Among them are uncertainty in kinetic constants for the dissolution and precipitation of minerals on CO 2 injection. Model results include equilibrium values for CO 2 stored via solubility trapping ranging from 49-g CO 2 /kg free formation water in Northeast MO to 78-g CO 2 /kg free formation water for Southwest MO. Mineral trapping is significantly lower, between 2.6- and 18.4-g CO 2 /kg free formation water. The model shows siderite and dawsonite as the major carbonate minerals formed, in this order. On a volumetric basis, northwest MO sequestration values were slightly greater than those obtained for northeast MO because of the somewhat greater depth and higher injection pressure at the injection target (Lamotte Sandstone) at the northwestern sites. However, the greater thickness of the aquifer for the northeastern sites provided overall greater sequestration capacity. Greene County was altogether unfit for sequestration because of the low total dissolved solids value of the formation water.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-08-03
Description: Prolific hydrocarbon discoveries in the subsalt, commonly known as the "presalt," section of Brazil and the conjugate African margin have created a business imperative to predict reservoir quality in lacustrine carbonates. Geothermal convection is a style of groundwater flow known to occur in rift settings, which is capable of diagenetic modification of reservoir quality. We simulated variable density groundwater flow coupled with chemical reactions to evaluate the potential for diagenesis driven by convection in subsalt carbonates. Rates of calcite diagenesis are critically controlled by temperature gradient and fluid flux following the principles of retrograde solubility. Simulations predict that convection could operate in rift carbonates prior to salt deposition, but with rates of dissolution in the reservoir interval only on the order of 0.01 vol. %/m.y., which is too low to significantly modify reservoir quality. The exception is around permeable fault zones and/or unconformities where flow is focused and dissolution rates are amplified to 1 to 10 vol. %/m.y. and could locally modify reservoir quality. After salt deposition, simulations also predict convection with a critical function for salt rugosity. The greatest potential for dissolution at rates of 0.1 to 1 vol. %/m.y. occurs where salt welds, overlying permeable carbonates thin to 500 m (1640 ft) or less. With tens of million years residence times feasible, convection under these conditions could locally result in reservoir sweet spots with porosity modification of 1% to 10% and potentially an order of magnitude or more in reservoir permeability. Integrating quantitative model-derived predictive diagenetic concepts with traditional subsurface data sets refines exploration to production scale risking of carbonate reservoir presence and quality.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-08-03
Description: Sequence stratigraphy and coal cycles based on accommodation trends were investigated in the coal-bearing Lower Cretaceous Mannville Group in the Lloydminster heavy oil field, eastern Alberta. The study area is in a low accommodation setting on the cratonic margin of the Western Canada sedimentary basin. Geophysical log correlation of coal seams, shoreface facies, and the identification of incised valleys has produced a sequence-stratigraphic framework for petrographic data from 3 cored and 115 geophysical-logged wells. Maceral analysis, telovitrinite reflectance, and fluorescence measurements were taken from a total of 206 samples. Three terrestrial depositional environments were interpreted from the petrographic data: ombrotrophic mire coal, limnotelmatic mire coal, and carbonaceous shale horizons. Accommodation-based coal (wetting- and drying-upward) cycles represent trends in depositional environment shifts, and these cycles were used to investigate the development and preservation of the coal seams across the study area. The low-accommodation strata are characterized by a high-frequency occurrence of significant surfaces, coal seam splitting, paleosol, and incised-valley development. Three sequence boundary unconformities are identified in only 20 m (66 ft) of strata. Coal cycle correlations illustrate that each coal seam in this study area was not produced by a single peat-accumulation episode but as an amalgamation of a series of depositional events. Complex relations between the Cummings and Lloydminster coal seams are caused by the lateral fragmentation of strata resulting from the removal of sediment by subaerial erosion or periods of nondeposition. Syndepositional faulting of the underlying basement rock changed local accommodation space and increased the complexity of the coal cycle development. This study represents a low-accommodation example from a spectrum of stratigraphic studies that have been used to establish a terrestrial sequence-stratigraphic model. The frequency of changes in coal seam quality is an important control on methane distribution within coalbed methane reservoirs and resource calculations in coal mining. A depositional model based on the coal cycle correlations, as shown by this study, can provide coal quality prediction for coalbed methane exploration, reservoir completions, and coal mining.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-06-01
Description: Two azimuthal resistivity surveys were completed using the square array within the Mamu Formation, Enugu area, Nigeria, to characterize the orientation and porosity of fractures. The target consists of a shallow (〈30 m [98 ft]) fracture zone that corresponds to the average completion depth for the water supply wells in the study area. Fracture orientation, fracture porosity, and coefficient of anisotropy of the investigated media were determined from the azimuthal resistivity data. Results of the survey data indicate that the fractures trend generally in the northwest–southeast direction at depths of 7.1, 10.0, 20.0, and 28.3 m (23.3, 32.8, 65.6, and 92.8 ft). The fracture porosity ranged between 0.68% and 17%. The coefficient of anisotropy () ranges between 1.00 and 1.12. Fractures at localities with relatively high values of possess relatively high fracture porosity and relatively low specific surface area and thus are more likely to be permeable. These interpretations were in agreement with the information collected at bedrock outcrops during this and previous studies. It is therefore true that the data obtained from this study will enhance the understanding of the permeable zone, fluid migration pattern, and vulnerability of the groundwater to mine drainage problems in the Enugu area.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-06-01
Description: With the exploration and the production of the Marcellus Shale come inevitable unavoidable environmental impacts to the surface of the Earth and associated waters of the United States including wetlands and streams. Environmental impact assessment includes measurement of impacts to aquatic resources, much of which is associated with the production and transportation of Marcellus Shale gas to market. The Commonwealth of Pennsylvania has prepared a rapid resource condition assessment protocol that will be applied to determine the existing quality of Pennsylvania streams to assess impacts to those streams and to quantify appropriate compensatory mitigation for impacts to these water resources. This protocol, advanced by the Bureau of Waterways Engineering and Wetlands of the Pennsylvania Department of Environmental Protection, builds on prior work of the U.S. Army Corps of Engineers Norfolk District and the Unified Stream Methodology of the Virginia Department of Environmental Quality to provide a consistent and rapid condition assessment for projects to obtain water obstruction and encroachment permits, for water quality certifications, as well as general permits that affect waterways, floodways, and/or floodplains.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-06-03
Description: We study the effects of planform dome shape on fault patterns developing with and without concurrent regional extension oriented oblique to the long axis of the dome. The motivation was the need to understand fault and fracture patterns in two adjacent mature hydrocarbon fields in the Middle East: one, an elliptical dome, and one, an irregularly shaped dome. The largest faults have throws of approximately 30 m (~98 ft), which is close to the resolution limit of older two-dimensional seismic reflection data. The known fault trends are not parallel to the highest transmissivity direction but could form compartment boundaries. Fault and fracture patterns developed over the modeled domes provide insight into the populations of faults and fractures that are likely to exist in the reservoirs but have been undetected because they are at or below the resolution limit of reflection seismic data. Major domal structural elements, crestal fault systems, end splay systems, and radial faults are observed in modeled domes rising both with and without concurrent regional extension. Experimental results indicate that fault and fracture patterns are influenced by the effects of dome shape, regional extension, and relative timing of uplift with respect to regional extension. The expression of particular sets of faults and fractures associated with concurrent doming and regional extension depends on the interaction among regional extension, outer arc extension over the dome, and tangential extension around the dome margins. Our results also indicate that the two adjacent natural domes possibly experienced different kinematic histories from those previously interpreted.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: We present a new hypothesis for the Jurassic plate-tectonic evolution of the Gulf of Mexico basin and discuss how this evolution influenced Jurassic salt tectonics. Four interpretations, some based on new data, constrain the hypothesis. First, the limit of normal oceanic crust coincides with a landward-dipping basement ramp near the seaward end of the salt basin, which has been mapped on seismic data. Second, the deep salt in the deep-water Gulf of Mexico can be separated into provinces on the basis of position with respect to this ramp. Third, paleodepths in the postsalt sequence indicate that salt filled the Gulf of Mexico salt basin to near sea level. Fourth, seismic data show that postsalt sediments in the central Louann and the Yucatan salt basins exhibit large magnitudes of Late Jurassic salt-detached extension not balanced by equivalent salt-detached shortening. In our hypothesis, Callovian salt was deposited in preexisting crustal depressions on hyperextended continental and transitional crust. After salt deposition ended, rifting continued for another 7 to 12 m.y. before sea-floor spreading began. During this phase of postsalt crustal stretching, the salt and its overburden were extended by 100 to 250 km (62–155 mi), depending on location. Sea-floor spreading divided the northern Gulf of Mexico into two segments, separated by the northwest-trending Brazos transform. The eastern segment opened from east to west, leaving the Walker Ridge salient in the center of the basin as the final area to break apart. In some areas, salt flowed seaward onto new oceanic crust, first concordantly over the basement as a parautochthonous province, then climbing up over stratigraphically younger strata as an allochthonous province.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: The process and mechanisms of secondary hydrocarbon migration in the Tazhong uplift, Tarim Basin, were investigated based on the analysis of the regional structure and by integrating geologic, hydrodynamic, and geochemical parameters. Parameters successfully analyzed included the fluid potential, fluid properties, production outputs, and diamantane index. The results indicated that hydrocarbons migrated into the Tazhong uplift from the northern part of the Manjiaer depression through a series of injection points (IPs) during four orogenies, that is, the early Caledonian (510 Ma), the late Caledonian (439 Ma), the late Hercynian–Indosinian (290 Ma), and the Yanshanian–Himalayan (208 Ma). A total of six IPs were identified at the intersections of the northeast-trending faults and the northwest-trending flower strike faults. The hydrocarbons migrated from the IPs into traps along regional trends from northwest to southeast and from northeast to southwest. The hydrocarbon migration process and patterns determined the distribution of hydrocarbon properties and production rates in the Tazhong uplift. With increasing distance from the IPs, daily hydrocarbon production decreases, and the hydrocarbons become progressively heavier and display lower gas:oil ratios.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-10-04
Description: The evolution of porosity in shales with increasing maturity was examined in a suite of five New Albany Shale samples spanning a maturity range from immature (vitrinite reflectance, R o 0.35%) to postmature (R o 1.41%). Devonian to lower Mississippian New Albany Shale samples from the Illinois Basin used in this study contain marine type II kerogen having total organic carbon contents from 1.2 to 13.0 wt. %. Organic petrology, CO 2 and N 2 low-pressure adsorption, and mercury intrusion capillary pressure techniques were used to quantify pore volumes, pore sizes, and pore-size distributions. Increasing maturity of the New Albany Shale is paralleled by many changes in the characteristics of porosity. The total porosity of 9.1 vol. % in immature New Albany Shale decreases to 1.5 vol. % in the late mature sample, whereas total pore volumes decrease from 0.0365 to 0.0059 cm 3 /g in the same sequence. Reversing the trend at even higher maturity, the postmature New Albany Shale exhibits higher porosity and larger total pore volumes compared to the late mature sample. With increasing maturity, changes in total porosity and total pore volumes are accompanied by changes in pore-size distributions and relative proportions of micropores, mesopores, and macropores. Porosity-related variances are directly related to differences in the amount and character of the organic matter and mineralogical composition, but maturity exerts the dominant control upon these characteristics. We conclude that organic matter transformation due to hydrocarbon generation and migration is a pivotal cause of the observed porosity differences.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-01-03
Description: Data derived from core and well-logs are essentially one-dimensional and determining eolian system type and likely dimensions and orientation of architectural elements present in subsurface eolian reservoir successions is typically not possible from direct observation alone. This is problematic because accurate predictions of the three-dimensional distribution of interdune and dune-plinth elements that commonly form relatively low-permeability baffles to flow, of net:gross, and of the likely distribution of elements with common porosity-permeability properties at a variety of scales in eolian reservoirs is crucial for effective reservoir characterization. Direct measurement of a variety of parameters relating to aspects of the architecture of eolian elements preserved as ancient outcropping successions has enabled the establishment of a series of empirical relationships with which to make first-order predictions of a range of architectural parameters from subsurface successions that are not observable directly in core. In many preserved eolian dune successions, the distribution of primary lithofacies types tends to occur in a predictable manner for different types of dune sets, whereby the pattern of distribution of grain-flow, wind-ripple, and grain-fall strata can be related to set architecture, which itself can be related back to original bedform type. Detailed characterization of individual eolian dune sets and relationships between neighboring dune and interdune elements has been undertaken through outcrop studies of the Permian Cedar Mesa Sandstone and the Jurassic Navajo Sandstone in southern Utah. The style of transition between lithofacies types seen vertically in preserved sets, and therefore measurable in analogous core intervals, enables predictions to be made regarding the relationship between preserved set thickness, individual grain-flow thickness, original bedform dimensional properties (e.g., wavelength and height), the likely proportion of the original bedform that is preserved to form a set, the angle of climb of the system, and the likely along-crest variability of facies distributions in sets generated by the migration of sinuous-crested bedforms. A series of graphical models depict common facies arrangements in bedsets for a suite of dune types and these demonstrate inherent facies variability.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-01-03
Description: Analog outcrops are commonly used to develop predictive reservoir models and provide quantitative parameters that describe the architecture and facies distribution of sedimentary deposits at a subseismic scale, all of which aids exploration and production strategies. The focus of this study is to create a detailed geological model that contains realistic reservoir parameters and to apply nonlinear acoustic full-waveform prestack seismic inversion to this model to investigate whether this information can be recovered and to examine which geological features can be resolved by this process. Outcrop data from the fluviodeltaic sequence of the Book Cliffs (Utah) are used for the geological and petrophysical two-dimensional model. Eight depositional environments are populated with average petrophysical reservoir properties adopted from a North Sea field. These units are termed lithotypes here. Synthetic acoustic prestack seismic data are then generated with the help of an algorithm that includes all internal multiples and transmission effects. A nonlinear acoustic full-waveform inversion is then applied to the synthetic data, and two media parameters, compressibility (inversely related to the square of the compressional wave velocity v P ) and bulk density, , are recovered at a resolution higher than the shortest wavelength in the data. This is possible because the inversion exploits the nonlinear nature of the relationship between the recorded data and the medium contrast properties. In conventional linear inversion, these details remain masked by the noise caused by the nonlinear effects in the data. Random noise added to the data is rejected by the nonlinear inversion, contributing to improved spatial resolution. The results show that the eight lithotypes can be successfully recovered at a subseismic scale and with a low degree of processing artifacts. This technique can provide a useful basis for more accurate reservoir modeling and field development planning, allowing targeting of smaller reservoir units such as distributary channels and lower shoreface sands.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-01-03
Description: In prospective basins affected by exhumation, uncertainty commonly exists regarding the maximum burial depths of source, reservoir, and seal horizons. One such basin is the Otway Basin, an important gas province in southeastern Australia, which has witnessed several exhumation events. Here, we present estimates of net exhumation magnitudes for 110 onshore and offshore petroleum wells based on the sonic transit time analyses of Lower Cretaceous fluvial shales. Our results show significant post-Albian net exhumation in the eastern onshore Otway Basin (〉1500 m [~4920 ft]) and a generally minor net exhumation (〈200 m [~655 ft]) elsewhere in the Otway Basin, consistent with estimates based on thermal history data. The distribution of net exhumation magnitudes in relation to mid-Cretaceous and Neogene compressional structures indicates that exhumation was dominantly controlled by short-wavelength basin inversion driven by plate-boundary forces. Deeper burial coupled with high geothermal gradients in the onshore eastern Otway Basin and along the northern basin margin during the early Cretaceous have rendered Lower Cretaceous source rocks mostly overmature, with any remaining hydrocarbons from the initial charge likely to be trapped in tightly compacted reservoirs and/or secondary (fracture-related) porosity. However, the embrittlement of these reservoirs during their deeper burial may present opportunities for the development of low-permeability plays through hydraulic fracturing where smectite clay minerals are illitized. Source rocks at near-maximum burial at present day are at temperatures suitable for gas generation, with key controls on prospectivity in these areas including the sealing potential of faulted traps and the relationship between charge and trap development.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-01-03
Description: The Tarim Basin is one of the most important hydrocabon-bearing evaporite basins in China. Four salt-bearing sequences, the Middle and Lower Cambrian, the Mississippian, the Paleogene, and the Neogene, have various thickness and areal distribution. They are important detachment layers and intensely affect the structural deformation in the basin. The Kuqa depression is a subordinate structural unit with abundant salt structures in the Tarim Basin. Salt overthrusts, salt pillows, salt anticlines, salt diapirs, and salt-withdrawal basins are predominant in the depression. Contraction that resulted from orogeny played a key function on the formation of salt structures. Growth strata reveal that intense salt structural deformation in the Kuqa depression occurred during the Himalayan movement from Oligocene to Holocene, with early structural deformation in the north and late deformation in the south. Growth sequences also record at least two phases of salt tectonism. In the Yingmaili, Tahe, and Tazhong areas, low-amplitude salt pillows are the most common salt structures, and these structures are commonly accompanied by thrust faults. The faulting and uplifting of basement blocks controlled the location of salt structures. The differences in the geometries of salt structures in different regions show that the thickness of the salt sequences has an important influence on the development of salt-cored detachment folds and related thrust faults in the Tarim Basin. Salt sequences and salt structures in the Tarim Basin are closely linked to hydrocarbon accumulations. Oil and gas fields have been discovered in the subsalt, intrasalt, and suprasalt strata. Salt deformation has created numerous potential traps, and salt sequences have provided a good seal for the preservation of hydrocarbon accumulations. Large- and small-scale faults related with salt structures have also given favorable migration pathways for oil and gas. When interpreting seismic profiles, special attention needs to be paid to the clastic and carbonate interbeds within the salt sequences because they may lead to incorrect structural interpretation. In the Tarim Basin, the subsalt anticlinal traps are good targets for hydrocarbon exploration.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-04-03
Description: The estimated ultimate recovery (EUR) is one of the most significant properties of tight-gas sandstone reservoirs, but it remains difficult to predict. Estimated ultimate recovery is dependent on the success of stimulation by hydraulic fracturing, the existence and connectivity of natural fractures, and as illustrated in this article, the pore structure of the matrix. Here, we analyze the lab measurements that are indicative of the pore structure, and then we predict the effect of pore structure on producibility. We develop a relationship between the EUR of tight-gas sandstones and their petrophysical properties measured by drainage and imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. We use the ratio of residual mercury saturation after mercury withdrawal ( S gr ) to initial mercury saturation ( S gi ), which is the saturation at the start of withdrawal, as a measure of gas likely to be trapped in the matrix during production and, hence, a proxy for EUR. A multitype pore space model is required to explain mercury intrusion capillary pressures in these rocks. Implications of this model are supported by other available laboratory measurements. The model comprises a conventional network model and a treelike pore structure (an acyclic network) that mimic the intergranular and intragranular void spaces, respectively. The notion of the treelike pore structure is introduced here for the first time in the context of tight-gas sandstones. Applying the multitype model to porous plate data, we classify the pore spaces of rocks into intergranular dominant, intermediate, and intragranular dominant. This pore space classification is topological and is not based on scale or size. These classes have progressively less drainage and imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from intragranular porosity than intergranular porosity. Available field data (production logs) corroborate the higher producibility of intervals with intragranular porosity, although the data are not sufficient to eliminate the possible contribution of other factors such as size and shape of the volume contacted by hydraulic fractures or the presence and attributes of natural fractures. The superior recovery of hydrocarbon from intragranular-dominant pore structures is despite its inferior initial production rate.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-04-03
Description: Multiple techniques are available to construct three-dimensional reservoir models. This study uses comparative analysis to test the impact of applying four commonly used stochastic modeling techniques to capture geologic heterogeneity and fluid-flow behavior in fluvial-dominated deltaic reservoirs of complex facies architecture: (1) sequential indicator simulation; (2) object-based modeling; (3) multiple-point statistics (MPS); and (4) spectral component geologic modeling. A reference for comparison is provided by a high-resolution model of an outcrop analog that captures facies architecture at the scale of parasequences, delta lobes, and facies-association belts. A sparse, pseudosubsurface data set extracted from the reference model is used to condition models constructed using each stochastic reservoir modeling technique. Models constructed using all four algorithms fail to match the facies-association proportions of the reference model because they are conditioned to well data that sample a small, unrepresentative volume of the reservoir. Simulated sweep efficiency is determined by the degree to which the modeling algorithms reproduce two aspects of facies architecture that control sand-body connectivity: (1) the abundance, continuity, and orientation of channelized fluvial sand bodies; and (2) the lateral continuity of barriers to vertical flow associated with flooding surfaces. The MPS algorithm performs best in this regard. However, the static and dynamic performance of the models (as measured against facies-association proportions, facies architecture, and recovery factor of the reference model) is more dependent on the quality and quantity of conditioning data and on the interpreted geologic scenario(s) implicit in the models than on the choice of modeling technique.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-04-03
Description: The Boat Harbour Formation constitutes the upper part of the Lower Ordovician St. George Group on the Northern Peninsula, western Newfoundland. It ranges in thickness from 140 m (459 ft) at Main Brook to 96 m (315 ft) at Daniel's Harbour. Dolomitization of the carbonate sequence is more pervasive in the lower 30 to 40 m (98 to 131 ft) at Main Brook, whereas at Daniel's Harbour, the section is entirely dolomitized. Petrography suggests that the Boat Harbour Formation has been affected by three phases of dolomitization. The earliest (near surface or synsedimentary) phase is D1 dolomicrite (4–55 μm), which exhibits dull to no luminescence. It commonly occurs as laminae-capping cycles and as breccias in the younger dolomite phases. It has low Sr (228 ± 30 ppm) and an average 18 O value of –6.0 ± 0.8 (Vienna Peedee belemnite [VPDB]) in the Main Brook section but more depleted signatures for 18 O of –8.8 ± 1 (VPDB) and lower Sr contents (45 ± 8 ppm) in the Daniel's Harbour section. The geochemical composition suggests that D1 was developed from fluids of a mixture of meteoric and marine waters. The midburial phase D2 dolomite consists of coarse planar subeuhedral crystals (30–400 μm) that show concentric cathodoluminescence zoning and are also crosscut by microstylolites. Its 18 O values range between –6.6 ± 1.3 (VPDB) at Main Brook and –9.0 ± 0.5 (VPDB) at Daniel's Harbour. This dolomite likely precipitated from fluids that circulated through crustal rocks with progressive burial ( T h value of 114°C ± 11°C and salinity value of 23 ± 1.8 eq. wt. % NaCl). The late-stage D3 dolomite has large and coarse nonplanar crystals (125 μm–7 mm) that exhibit sweeping extinction under crossed polars, which is characteristic of saddle dolomite and also sometimes shows thin brightly luminescent rims. It was likely precipitated during deeper burial in pulses and from hot fluids ( T h values of 148°C ± 19°C and 115°C ± 19.6°C and mean salinities of 23 ± 2 and 22 ± 2 eq. wt. % NaCl at Main Brook and Daniel's Harbour, respectively). This is also supported by their relatively more depleted 18 O (–11.1 ± 1.2 and –12.3 ± 1.4 VPDB, respectively) and low Sr contents (88 ± 36 and 38 ± 5.9 ppm, respectively). Porosity in the Boat Harbour Formation is mainly associated with the midburial D2 dolomite. Intercrystalline porosity is the dominant type, and it ranges in the formation from less than 1% to 8% at Main Brook and from 7% to 12% at Daniel's Harbour. Vugs are less common but are associated with D3 dolomite. The porous zone in the formation at Main Brook starts approximately 10 to 15 m (33 to 49 ft) below the lower Boat Harbour disconformity and extends down to the lower formational boundary, whereas porous zones in the formation at Daniel's Harbour are indiscriminately distributed throughout the section.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-04-03
Description: The style of faulting in offshore Louisiana, Gulf of Mexico, is characterized by short, arcuate regional and counterregional growth faults, which commonly form complex transfer zones above shallow, Miocene level salt bodies. South Timbalier Block 54 (ST54) constitutes one such area where a basinward-dipping regional and a landward-dipping counterregional growth fault form a convergent transfer zone. Structural interpretation using three-dimensional (3-D) seismic and well data reveals that the eastern and western flanks of the structure contain salt in the footwalls of the main regional and counterregional faults. The salt rises to a much shallower stratigraphic level in the central part of the transfer zone, forming a symmetric salt diapir. Secondary antithetic and synthetic faults adjacent to the two main faults and extending into the transfer zone accommodate slip between the main faults. Kinematic restoration of a series of north–south-trending cross sections across the structure show that upslope evacuation of salt is the result of sediment loading and growth fault movement, and the location of the transfer zone is possibly controlled by the allochthonous salt. The entire area is characterized by down-to-basin movement, with the major regional and counterregional faults displaying footwall and hanging-wall fixed deformation, respectively. The presence of the crestal graben above the salt high and the timing of maximum salt evacuation from the flanks suggest that active or reactive diapirism occurred during part of the deformation history. A 3-D structural model using depth-converted horizons, balanced cross sections, and well tops accurately portrays the subsurface structure. Understanding the evolution of the structure in ST54 provides insight on similar structures in other areas in offshore Louisiana and the relationship between salt evacuation and transfer zone development.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: Sandstone pressures follow the hydrostatic gradient in Miocene strata of the Mad Dog field, deep-water Gulf of Mexico, whereas pore pressures in the adjacent mudstones track a trend from well to well that can be approximated by the total vertical stress gradient. The sandstone pressures within these strata are everywhere less than the bounding mudstone pore pressures, and the difference between them is proportional to the total vertical stress. The mudstone pressure is predicted from its porosity with an exponential porosity-versus-vertical effective stress relationship, where porosity is interpreted from wireline velocity. Sonic velocities in mudstones bounding the regional sandstones fall within a narrow range throughout the field from which we interpret their vertical effective stresses can be approximated as constant. We show how to predict sandstone and mudstone pore pressure in any offset well at Mad Dog given knowledge of the local total vertical stress. At Mad Dog, the approach is complicated by the extraordinary lateral changes in total vertical stress that are caused by changing bathymetry and the presence or absence of salt. A similar approach can be used in other subsalt fields. We suggest that pore pressures within mudstones can be systematically different from those of the nearby sandstones, and that this difference can be predicted. Well programs must ensure that the borehole pressure is not too low, which results in borehole closure in the mudstone intervals, and not too high, which can result in lost circulation to the reservoir intervals.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: The origin of thermogenic natural gas in the shallow stratigraphy of northeastern Pennsylvania is associated, in part, with interbedded coal identified in numerous outcrops of the Upper Devonian Catskill and Lock Haven Formations. Historically documented and newly identified locations of Upper Devonian coal stringers are shown to be widespread, both laterally across the region and vertically throughout the stratigraphic section of the Catskill and Lock Haven Formations. Coal samples exhibited considerable gas source potential with total organic carbon as high as 44.40% by weight, with a mean of 13.66% for 23 sample locations analyzed. Upper Devonian coal is thermogenically mature; calculated vitrinite reflectances range from 1.25% to 2.89%, with most samples falling within the dry-gas window. Source potential is further supported by gas shows observed while drilling through shallow, identifiable coal horizons, which are at times located within fresh groundwater aquifers. Thermogenic gas detected in area water wells during predrill baseline sampling is determined not only to be naturally occurring, but also common in the region.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: We present a method of using fault displacement-distance profiles to distinguish fault-bend, shear fault-bend, and fault-propagation folds, and use these insights to guide balanced and retrodeformable interpretations of these structures. We first describe the displacement profiles associated with different end-member fault-related folding models, then provide examples of structures that are consistent with these model-based predictions. Natural examples are imaged in high-resolution two- and three dimensional seismic reflection data sets from the Niger Delta, Sichuan Basin, Sierras Pampeanas, and Cascadia to record variations in displacement with distance updip along faults (termed displacement-distance profiles). Fault-bend folds exhibit constant displacement along fault segments and changes in displacement associated with bends in faults, shear fault-bend folds demonstrate an increase in displacement through the shearing interval, and fault-propagation folds exhibit decreasing displacement toward the fault tip. More complex structures are then investigated using this method, demonstrating that displacement-distance profiles can be used to provide insight into structures that involve multiple fault-related folding processes or have changed kinematic behavior over time. These interpretations are supported by comparison with the kinematics inferred from the geometry of growth strata overlying these structures. Collectively, these analyses illustrate that the displacement-distance approach can provide valuable insights into the styles of fault-related folding.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-03-04
Description: Offshore sequences of volcaniclastic rocks (such as hyaloclastite deposits) are poorly understood in terms of their rock properties and their response to compaction and burial. As petroleum exploration targets offshore volcanic rifted margins worldwide, understanding of volcanic rock properties becomes important both in terms of drilling and how the rocks may behave as seals, reservoirs, or permeability pathways. The Hawaiian Scientific Drilling Project phase II in 2001 obtained a 3 km-(2-mi)-long core of volcanic and volcaniclastic rocks that records the emergence of the largest of the Hawaiian islands. Core recovery of 2945 m (9662 ft) resulted in an unparalleled data set of volcanic and volcaniclastic rocks. Detailed logging, optical petrology, and major element analysis of two sections at depths 1831–1870 and 2530–2597 m (6007–6135 and 8300–8520 ft) are compared to recovered petrophysical logs (gamma ray, resistivity, and P-wave velocity). This study concludes deviation in petrophysical properties does not seem to correlate to changes in grain size or clast sorting, but instead correlates with alteration type (zeolite component) and bulk mineralogy (total olivine phenocryst percentage component). These data sets are important in helping to calibrate well-log responses through hyaloclastite intervals in areas of active petroleum exploration such as the North Atlantic (e.g., Faroe-Shetland Basin, United Kingdom, and Faroe Islands, the Norwegian margin and South Atlantic margins bordering Brazil and Angola).
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-03-04
Description: The petroleum trap for the Athabasca oil sands has remained elusive because it was destroyed by flexural loading of the Western Canada Sedimentary Basin during the Late Cretaceous and Paleocene. The original trap extent is preserved because the oil was biodegraded to immobile bitumen as the trap was being charged during the Late Cretaceous. Using well and outcrop data, it is possible to reconstruct the Cretaceous overburden horizons beyond the limit of present-day erosion. Sequential restoration of the reconstructed horizons reveals a megatrap at the top of the Wabiskaw-McMurray reservoir in the Athabasca area at 84 Ma (late Santonian). The megatrap is a four-way anticline with dimensions 285 x 125 km (177 x 78 mi) and maximum amplitude of 60 m (197 ft). The southeastern margin of the anticline shows good conformance to the bitumen edge for 140 km (87 mi). To the northeast of the anticline, bitumen is present in a shallower trap domain in what is interpreted to be an onlap trap onto the Canadian Shield; leakage along the onlap edge is indicated by tarry bitumen outliers preserved in basement rocks farther to the northeast. Peripheral trap domains that lie below the paleospillpoint, in northern, southern, and southwestern Athabasca, and Wabasca, are interpreted to represent a late charge of oil that was trapped by bitumen already emplaced in the anticline and the northeastern onlap trap. This is consistent with kimberlite intrusions containing live bitumen, which indicate that the northern trap domain was charged not before 78 Ma. The trap restoration has been tested using bitumen-water contact well picks. The restored picks fall into groups that are consistent both with the trap domains determined from the top reservoir restoration and the conceptual charge model in which the four-way anticline was filled first, followed by the northeastern onlap trap, and then the peripheral trap domains.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-03-04
Description: Diagenesis significantly impacts mudstone lithofacies. Processes operating to control diagenetic pathways in mudstones are poorly known compared to analogous processes occurring in other sedimentary rocks. Selected organic-carbon-rich mudstones, from the Kimmeridge Clay and Monterey Formations, have been investigated to determine how varying starting compositions influence diagenesis. The sampled Kimmeridge Clay Formation mudstones are organized into thin homogenous beds, composed mainly of siliciclastic detritus, with some constituents derived from water-column production (e.g., coccoliths, S-depleted type-II kerogen, as much as 52.6% total organic carbon [TOC]) and others from diagenesis (e.g., pyrite, carbonate, and kaolinite). The sampled Monterey Formation mudstones are organized into thin beds that exhibit pelleted wavy lamination, and are predominantly composed of production-derived components including diatoms, coccoliths, and foraminifera, in addition to type-IIS kerogen (as much as 16.5% TOC), and apatite and silica cements. During early burial of the studied Kimmeridge Clay Formation mudstones, the availability of detrital Fe(III) and reactive clay minerals caused carbonate- and silicate-buffering reactions to operate effectively and the pore waters to be Fe(II) rich. These conditions led to pyrite, iron-poor carbonates, and kaolinite cements precipitating, preserved organic carbon being S-depleted, and sweet hydrocarbons being generated. In contrast, during the diagenesis of the sampled Monterey Formation mudstones, sulfide oxidation, coupled with opal dissolution and the reduced availability of both Fe(III) and reactive siliciclastic detritus, meant that the pore waters were poorly buffered and locally acidic. These conditions resulted in local carbonate dissolution, apatite and silica cements precipitation, natural kerogen sulfurization, and sour hydrocarbons generation. Differences in mud composition at deposition significantly influence subsequent diagenesis. These differences impact their source rock attributes and mechanical properties.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-23
Description: The West Virginia Division of Energy is currently evaluating several deep saline formations in the Appalachian Basin of West Virginia that may be potential carbon dioxide (CO 2 ) sequestration targets. The Silurian Newburg Sandstone play, developed in the 1960s and 1970s, primarily involved natural-gas production from reservoir rock with well-developed porosity and permeability. High initial pressures encountered in early wells in the Newburg indicated that the overlying Silurian Salina Formation provides a competent seal. Because of the large number of CO 2 point sources in the region and the favorable reservoir properties of the formation (including an estimated 300 bcf of natural-gas production), the Newburg Sandstone was evaluated for the potential geologic storage of CO 2 . Within the Newburg play, there are several primary fields separated geographically and geologically by saltwater contacts and dry holes. Previous studies have determined the storage potential within these individual fields. This study shows that the Newburg is more suitable for small-scale injection tests instead of large-scale regional storage operations.
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Electronic ISSN: 1526-0984
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-11-23
Description: Shales are becoming the most important source of natural gas in North America, and replacement of coal by natural gas is reducing CO 2 emissions and improving air quality. Nevertheless, shale gas is facing strong opposition from environmental nongovernmental organizations. Although these organizations have greatly exaggerated the potential negative environmental impacts of shale gas and shale oil, methane leakage and contamination of groundwater and surface water by flowback and produced waters are serious concerns. These contamination pathways are not unique to shale gas and shale oil, and they are manageable.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-12-03
Description: Size fractions (〈0.4 and 0.4–1.0 μm) of Brent Group sandstones from the northern North Sea contain mostly illite-smectite mixed layers with kaolinite, whereas the same size fractions of Fulmar Formation sandstones from the south-central North Sea consist of illite-smectite mixed layers with minor chlorite. Transmission electron microscope observations show elongated illite laths or agglomerates consisting of small laths when larger individual laths are lacking. The K-Ar data of the fractions less than 0.4 μm of Brent Group samples plot on two arrays in a 40 Ar/ 36 Ar vs. 40 K/ 36 Ar diagram that have isochron characteristics with ages of 76.5 ± 4.2 and 40.0 ± 1.5 Ma, and initial 40 Ar/ 36 Ar ratios of 253 ± 16 and 301 ± 18, respectively. For the Fulmar Formation samples, the data points of the fractions less than 0.2 and less than 0.4 μm also fit two isochrons with ages of 76.6 ± 1.4 and 47.9 ± 0.5 Ma and initial 40 Ar/ 36 Ar ratios of 359 ± 52 and 304 ± 2, respectively. Some of the coarser 0.4–1.0-μm fractions also plot on the two isochrons, but most plot above indicating the presence of detrital components more than 0.4 μm. The almost identical ages obtained from illite-type crystals of sandstones with different deposition ages that are located about 600 km (373 mi) apart record two simultaneous illitization episodes. These events were not induced by local burial conditions, but are related to episodic pressure and/or temperature increases in the studied reservoirs, probably induced by hydrocarbon injection. This interpretation is indirectly supported by notably different K-Ar illite ages from cores of a nearby reservoir at hydrostatic pressure. Illite is not as well crystallized as expected for potential crystallization temperatures above 160°C measured by fluid-inclusion determinations. In both the northern and south-central North Sea, the two illite generations remain unaffected after crystallization despite continued burial, suggesting notably higher crystallization temperatures than those estimated from geothermal gradients. No recent illite crystallization or alteration is recorded in the K-Ar ages, despite a dramatic regional acceleration of the subsidence in the southern North Sea.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-12-03
Description: Field analogs allow a better characterization of fracture networks to constrain naturally fractured reservoir models. In analogs, the origin, nature, geometry, and other attributes of fracture networks can be determined and can be related to the reservoir through the geodynamic history. In this article, we aim to determine the sedimentary and diagenetic controls on fracture patterns and the genetic correlation of fracture and diagenesis with tectonic and burial history. We targeted two outcrops of Barremian carbonates located on both limbs of the Nerthe anticline (southeastern France). We analyzed fracture patterns and rock facies as well as the tectonic, diagenetic, and burial history of both sites. Fracture patterns are determined from geometric, kinematic, and diagenetic criteria based on field and lab measurements. Fracture sequences are defined based on crosscutting and abutting relationships and compared with geodynamic history and subsidence curves. This analysis shows that fractures are organized in two close-to-perpendicular joint sets (i.e., mode I). Fracture average spacing is 50 cm (20 in.). Fracture size neither depends on fracture orientation nor is controlled by bed thickness. Neither mechanical stratigraphy nor fracture stratigraphy is observed at outcrop scale. Comparing fracture sequences and subsidence curves shows that fractures existed prior to folding and formed during early burial. Consequently, the Nerthe fold induced by the Pyrenean compression did not result in any new fracture initiation on the limbs of this fold. We assume that the studied Urgonian carbonates underwent early diagenesis, which conferred early brittle properties to the host rock.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-12-03
Description: The Marcellus Shale is considered to be the largest unconventional shale-gas resource in the United States. Two critical factors for unconventional shale reservoirs are the response of a unit to hydraulic fracture stimulation and gas content. The fracture attributes reflect the geomechanical properties of the rocks, which are partly related to rock mineralogy. The natural gas content of a shale reservoir rock is strongly linked to organic matter content, measured by total organic carbon (TOC). A mudstone lithofacies is a vertically and laterally continuous zone with similar mineral composition, rock geomechanical properties, and TOC content. Core, log, and seismic data were used to build a three-dimensional (3-D) mudrock lithofacies model from core to wells and, finally, to regional scale. An artificial neural network was used for lithofacies prediction. Eight petrophysical parameters derived from conventional logs were determined as critical inputs. Advanced logs, such as pulsed neutron spectroscopy, with log-determined mineral composition and TOC data were used to improve and confirm the quantitative relationship between conventional logs and lithofacies. Sequential indicator simulation performed well for 3-D modeling of Marcellus Shale lithofacies. The interplay of dilution by terrigenous detritus, organic matter productivity, and organic matter preservation and decomposition affected the distribution of Marcellus Shale lithofacies distribution, which may be attributed to water depth and the distance to shoreline. The trend of normalized average gas production rate from horizontal wells supported our approach to modeling Marcellus Shale lithofacies. The proposed 3-D modeling approach may be helpful for optimizing the design of horizontal well trajectories and hydraulic fracture stimulation strategies.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2013-12-03
Description: Oil degradation in the Gullfaks field led to hydrogeochemical processes that caused high CO 2 partial pressure and a massive release of sodium into the formation water. Hydrogeochemical modeling of the inorganic equilibrium reactions of water-rock-gas interactions allows us to quantitatively analyze the pathways and consequences of these complex interconnected reactions. This approach considers interactions among mineral assemblages (anorthite, albite, K-feldspar, quartz, kaolinite, goethite, calcite, dolomite, siderite, dawsonite, and nahcolite), various aqueous solutions, and a multicomponent fixed-pressure gas phase (CO 2 , CH 4 , and H 2 ) at 4496-psi (31-mPa) reservoir pressure. The modeling concept is based on the anoxic degradation of crude oil (irreversible conversion of n-alkanes to CO 2 , CH 4 , H 2 , and acetic acid) at oil-water contacts. These water-soluble degradation products are the driving forces for inorganic reactions among mineral assemblages, components dissolved in the formation water, and a coexisting gas at equilibrium conditions. The modeling results quantitatively reproduce the proven alteration of mineral assemblages in the reservoir triggered by oil degradation, showing (1) nearly complete dissolution of plagioclase; (2) stability of K-feldspar; (3) massive precipitation of kaolinite and, to a lesser degree, of Ca-Mg-Fe carbonate; and (4) observed uncommonly high CO 2 partial pressure (61 psi [0.42 mPa] at maximum). The evolving composition of coexisting formation water is strongly influenced by the uptake of carbonate carbon from oil degradation and sodium released from dissolving albitic plagioclase. This causes supersaturation with regard to thermodynamically stable dawsonite. The modeling results also indicate that nahcolite may form as a CO 2 -sequestering sodium carbonate instead of dawsonite, likely controlling CO 2 partial pressure.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-03-04
Description: Organic-carbon–rich shales of the lower Marcellus Formation were deposited at the toe and basinward of a prograding clinothem associated with a Mahantango Formation delta complex centered near Harrisburg, Pennsylvania. Distribution of these organic-carbon–rich shales was influenced by shifts in the delta complex driven by changes in rates of accommodation creation and by a topographically high carbonate bank that formed along the Findlay-Algonquin arch during deposition of the Onondaga Formation. Specifically, we interpret the Union Springs member (Shamokin Member of the Marcellus Formation) and the Onondaga Formation as comprising a single third-order depositional sequence. The Onondaga Formation was deposited in the lowstand to transgressive systems tract, and the Union Springs member was deposited in the transgressive, highstand, and falling-stage systems tract. The regional extent of parasequences, systems tracts, and the interpreted depositional sequence suggest that base-level fluctuations were primarily caused by allogenic forcing—eustasy, climate, or regional thermal uplift or subsidence—instead of basement fault reactivation as argued by previous workers. Paleowater depths in the region of Marcellus Formation black mudrock accumulation were at least 330 ft (100 m) as estimated by differences in strata thickness between the northwestern carbonate bank and basinal facies to the southeast. Geochemical analysis indicates anoxic to euxinic bottom-water conditions. These conditions were supported by a deep, stratified basin with a lack of circulation.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-03-04
Description: Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated. The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density. These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: As the pace of drilling activity in the Marcellus Formation in the northern Appalachian Basin has increased, so has the number of alleged incidents of stray natural gas migration to shallow aquifer systems. For this study, more than 2300 gas and water samples were analyzed for molecular composition and stable isotope compositions of methane and ethane. The samples are from Neogene- to Middle Devonian-age strata in a five-county study area in northeastern Pennsylvania. Samples were collected from the vertical and lateral sections of 234 gas wells during mud gas logging (MGL) programs and 67 private groundwater-supply wells during baseline groundwater-quality testing programs. Evaluation of this geochemical database reveals that microbial, mixed microbial and thermogenic, and thermogenic gases of different thermal maturities occur in some shallow aquifer systems and throughout the stratigraphy above the Marcellus Formation. The gas occurrences predate Marcellus Formation drilling activity. Isotope data reveal that thermogenic gases are predominant in the regional Neogene and Upper Devonian rocks that comprise the potable aquifer system in the upper 305 m (1000 ft) (average 13 C 1  = –43.53; average 13 C 2  = –40.95; average DC 1  = –232.50) and typically are distinct from gases in the Middle Devonian Marcellus Formation (average 13 C 1  = –32.37; average 13 C 2 = –38.48; average DC 1  = –162.34 ). Additionally, isotope geochemistry at the site-specific level reveals a complex thermal and migration history with gas mixtures and partial isotope reversals ( 13 C 1  〉  13 C 2 ) in the units overlying the Marcellus Formation. Identifying a source for stray natural gas requires the synthesis of multiple data types at the site-specific level. Molecular and isotope geochemistry provide evidence of gas origin and secondary processes that may have affected the gases during migration. Such data provide focus for investigations where the potential sources for stray gas include multiple, naturally occurring, and anthropogenic gases.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: The influence of moisture, temperature, coal rank, and differential enthalpy on the methane (CH 4 ) and carbon dioxide (CO 2 ) sorption capacity of coals of different rank has been investigated by using high-pressure sorption isotherms at 303, 318, and 333 K (CH 4 ) and 318, 333, and 348 K (CO 2 ), respectively. The variation of sorption capacity was studied as a function of burial depth of coal seams using the corresponding Langmuir parameters in combination with a geothermal gradient of 0.03 K/m and a normal hydrostatic pressure gradient. Taking the gas content corresponding to 100% gas saturation at maximum burial depth as a reference value, the theoretical CH 4 saturation after the uplift of the coal seam was computed as a function of depth. According to these calculations, the change in sorption capacity caused by changing pressure, temperature conditions during uplift will lead consistently to high saturation values. Therefore, the commonly observed undersaturation of coal seams is most likely related to dismigration (losses into adjacent formations and atmosphere). Finally, we attempt to identify sweet spots for CO 2 -enhanced coalbed methane (CO 2 -ECBM) production. The CO 2 -ECBM is expected to become less effective with increasing depth because the CO 2 -to-CH 4 sorption capacity ratio decreases with increasing temperature and pressure. Furthermore, CO 2 -ECBM efficiency will decrease with increasing maturity because of the highest sorption capacity ratio and affinity difference between CO 2 and CH 4 for low mature coals.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2014-02-03
Description: Thirty-seven mudstone samples were collected from the uppermost Lower Mudstone Member of the Potrerillos Formation in El Gordo minibasin within La Popa Basin, Mexico. The unit is exposed in a circular pattern at the earth's surface and is intersected by El Gordo diapir in the northeast part of the minibasin. Vitrinite reflectance (R o ) results show that samples along the eastern side of the minibasin (i.e., south of the diapir) are mostly thermally immature to low maturity (R o ranges from 0.53% to 0.64%). Vitrinite values along the southern, western, and northwestern part of the minibasin range between 0.67% and 0.85%. Values of R o immediately northwest of the diapir are the highest, reaching a maximum of 1.44%. The results are consistent with two different possibilities: (1) that the diapir plunges to the northwest, or (2) that a focused high-temperature heat flow existed along just the northwest margin of the diapir. If the plunging diapir interpretation is correct, then the thermally immature area south of the diapir was in a subsalt position, and the high-maturity area northwest of the diapir was in a suprasalt position prior to Tertiary uplift and erosion. If a presumed salt source at depth to the northwest of El Gordo also fed El Papalote diapir, which is located just to the north of El Gordo diapir, then the tabular halokinetic sequences that are found only along the east side of El Papalote may be subsalt features. However, if the diapir is subvertical and the high-maturity values northwest of the diapir are caused by prolonged, high-temperature fluid flow along just the northwestern margin of the diapir, then both of these scenarios are in disagreement with previously published numerical models. This disagreement arises because the models predict that thermal anomalies will extend outward from a diapir a distance roughly 1.5 times the radius of the diapir, but the results reported here show that the anomalous values on one side of the diapir are about two times the radius, whereas they are as much as five times the radius on the other side of the diapir. The results indicate that strata adjacent to salt margins may experience significantly different heat histories adjacent to different margins of diapirs that result in strikingly different diagenetic histories, even at the same depth.
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-08-01
Description: Lower Triassic platforms in the Nanpanjiang Basin contain extensive oolites. Interior oolites are stacked in meter-scale cycles arranged into larger coarsening-upward sequences. Oolites thicken toward margins to include grainstones up to 50 m (164 ft) thick and contain giant ooids (up to 1 cm [0.4 in.]) and composite coated grains. Cross-bedding, ripples, and abraded ooids indicate deposition in high-energy shoals. Apparent layer-cake correlation across interiors indicates amalgamation of shoals. Thinner interior lenses represent spillover lobes. Ooids are interpreted to have originally been bimineralic with cortices of radial or micritic fabrics (high-magnesium calcite), alternating with coarse pseudospar or brickwork (originally aragonite). Distorted ooids formed by brittle compaction of micritic cortices around voids are interpreted to have been dissolved aragonite. Abundant potential nuclei indicate that limited supply was not a factor contributing to the large ooid size. High-energy and abnormally high–seawater CaCO 3 saturation are interpreted to be causes of the giant ooids. Most previous reports of giant ooids come from the Neoproterozoic, a period of increasing surface-water oxygenation and high CaCO 3 saturation caused by a minimal skeletal carbonate precipitation. We interpret similar seawater chemistry in the aftermath of the end-Permian extinction to explain the genesis of the giant ooids in the Early Triassic. The genesis of bimineralic ooids during an Early Triassic period of rapidly increasing pCO 2 and low $${\hbox{ SO }}_{4}^{2-}$$ indicates that an increasing Ca/Mg ratio was the primary mechanism driving the change from aragonite to calcite seas. The architecture, textures, and diagenesis of the Lower Triassic oolites of the Nanpanjiang Basin provide useful analogs for coeval reservoirs in Sichuan and the Middle East.
Print ISSN: 0149-1423
Electronic ISSN: 0149-1423
Topics: Geosciences
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-08-01
Description: This study compares the results of the petroleum resources of China evaluated in the U.S. Geological Survey World Petroleum Assessment 2000 ( USGS WPA 2000 ) with those evaluated in the China National Petroleum Assessment 2007 ( CNPA 2007 ). The USGS WPA 2000 reported the mean undiscovered petroleum resources of China to be 12.12 BBO and 85.79 TCFG, which is a much lower estimate than the 107.38 BBO and 692.13 TCFG assessment reported in the CNPA 2007 . Six major factors, including petroleum resource classification systems, data sources, assessment scopes, unit divisions, assessment methods, and assessment parameters, contributed to the differences in these two assessments. Reserve growth and undiscovered resources are two independent parts of total petroleum resources according to the definition in the USGS WPA 2000 , whereas undiscovered resources of the CNPA 2007 included estimates of reserve growth. The USGS WPA 2000 showed a much higher minimum field size than the CNPA 2007 did, and only six Chinese basins were covered in the former, whereas 115 Chinese basins were evaluated in the latter. For the same basins, unit divisions of the USGS WPA 2000 also differed from those of the CNPA 2007 because of their different data sources and exploration and exploitation experiences. Different methods used by these two agencies also affected their assessment results to some degree.
Print ISSN: 0149-1423
Electronic ISSN: 0149-1423
Topics: Geosciences
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-08-01
Description: As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term "shale" does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, R o = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output ( T max ) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.
Print ISSN: 0149-1423
Electronic ISSN: 0149-1423
Topics: Geosciences
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American Association of Petroleum Geologists (AAPG)
Publication Date: 2012-08-01
Description: The lower Pennsylvanian Jackfork Group in Arkansas has been the subject of studies, field trips, and publications for many years because of excellent outcrop exposures of different deep-water architectural elements. This latest study is focused on the Baumgartner Quarry located near Kirby, Arkansas, which exposes a series of vertical walls in three dimensions. This quarry has not been as well documented as other popular exposures, although three-dimensional (3-D) quarry faces exist, and the quarry strata comprise part of a complete 600-m (1970-ft)-thick near-continuous Jackfork stratigraphic sequence not unlike younger deep-water stratigraphic exploration targets in the Gulf of Mexico and elsewhere. Subsurface problems including reservoir uncertainties and reservoir performance of lobe versus channel-fill deposits are addressed based on our work in the quarry. A 3-D sequence-stratigraphic model was developed using a correlation of seven measured stratigraphic sections in the quarry. The 180-m (590-ft)-thick quarry strata consist of a lower lowstand systems tract (LST) (lower sandstones) dominated by channel-fill sandstones, overlain by a shaly transgressive systems tract (condensed section), and then by an upper LST (upper sandstones) dominated by sheet or lobe sandstones. This model was translated into an updip against salt field, which is analogous to some deep-water Gulf of Mexico reservoirs. Performance simulation was conducted on the model using a one-injector water well and two vertical producing wells, one of which was connected to the injector via a channel sandstone and the other of which was offset from the channel sandstone. Results yielded 60% more production from the connected injector-producer pair than from the nonconnected pair. Comparison between the lower (channel-prone) sandstones and the upper (sheet-prone) sandstones revealed that the sheet-prone sandstone is more sustainable, whereas the channel-prone sandstone exhibits a larger drop in production rate during a 10-yr production period. These results illustrate the value of 3-D outcrop models for reservoir performance simulation for development planning of deep-water fields with limited data control, such as in the deep-water Gulf of Mexico.