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The Williston Basin has proven to be a global super basin. Initially, development across this basin was dominated by conventional production from the Madison Group and Ordovician oil systems; however, with the development of unconventional play opportunities, the biggest resource in the Williston Basin is now the Middle Member of the Bakken Formation. The Middle Member was not pursued as a reservoir because of its low porosity and permeability, the low thermal maturity of the juxtaposed Bakken shales, low resistivity, and perceived lack of oil saturation. This paper will review how geochemical data were used to challenge and explain those initial assumptions with particular focus on the discovery and development of the Parshall field. Unconventional and hybrid plays are complex systems, and although much of the geochemical focus details organofacies or maturity concerns, numerous other processes including sorption, alteration, mixing, and evaporative fractionation can and commonly will influence the interpretation of the results and therefore must be considered. The geochemical techniques discussed in this paper are used to calculate oil saturation and more appropriately, mobile oil saturation, from core data requiring accounting for oil evaporative losses to fully define the workings of the Bakken petroleum system and the Middle Member as the key reservoir.

Understanding and predicting the main controls on the sealing capacity of carbonate cap rocks is of great significance for ultradeep carbonate reservoir exploration and production. This study focuses on revealing the pore networks and sealing capacity of the Ordovician carbonate cap rocks in the Tarim Basin by analyzing samples from outcrop analogues using optical and scanning electron microscopy and a combination of mercury intrusion capillary pressure and nitrogen gas adsorption. Three classes of cap rocks are defined here according to their pore-throat structure, fractal dimension, and sealing capacity. These carbonate cap rocks are dominated by limestones and dolomitic limestones. Four pore types are identified: microfractures, intragranular, intercrystalline, and intracrystalline. Six pore structure types show multiscale variability from macropores to micropores. The pore structures present multiple fractal behaviors, with fractal dimensions showing an increasing trend as the pore diameter decreases. The cover coefficient, a parameter that allows characterization of the caprock sealing performance, shows an increasing trend along with increasing the fractal dimension of pore structure. The average cover coefficients of six pore structure types not only show good correlations (either exponential or linear) with certain fractal dimensions, but they also demonstrate a strong positive correlation with the average fractal dimension. These results suggest that the sealing capacity of the studied rocks increases with increasing fractal dimension. The sealing performance of cap rocks significantly decreases with an increasing amount of macropores. This work provides a relevant case study for further understanding of pore structures and sealing capacity of carbonate cap rocks.

The oils of Shuntuoguole low uplift of Tarim Basin in western China have high contents of saturated hydrocarbons and a high loss of light hydrocarbon components because of volatilization. These oils are characterized by low abundance of hopanes and high abundance of C28–30 tricyclic terpanes and dibenzothiophenes and relative high abundance of C20–23 terpanes, C21–22 5α-steranes, and diasteranes in the oils. Quantitative analysis of carbon isotope and biomarkers show that the oils in the Ordovician carbonate rocks are sourced by deep Cambrian and Ordovician marine shales and marls. Geochemistry of the oils indicates that the reservoir has undergone multistage accumulations, with the late-stage oils obscuring traces of biodegradation of paleo-oils charged in the early stage. The concentration of methyl adamantanes and steranes demonstrates that oils occurred in an early stage of intense oil-to-gas cracking. Most of the gases are wet, with dryness lower than 90%, and geochemical analysis suggests that they are mainly from thermal degradation of kerogen. This study suggests that in addition to oils sourced by deeper source rocks in the Shuntuoguole low uplift in situ, there are oils that migrated from the Manjiaer depression into the Shuntuoguole low uplift.

It is difficult to determine flow pathways of paleofluids in sedimentary basins. Petrography, fluid inclusion, and isotopic compositions from different phases of calcite veins in the Ordovician in the Tazhong area were studied. Our results reveal a complex diagenesis process with two importantly crossformational fluid movements, coupled with three phases of calcite veins (C1, C2, and C3) precipitation and thermochemical sulfate reduction by hydrocarbons. Fluids that precipitated C2 and C3 calcites were saline and enriched in 18O and thus may have originated from underlying evaporates, whereas fluid that precipitated C3 had an additional contribution from 87Sr-rich, Ba-rich, and Zn-rich Precambrian basinal clastic units. Fluid inclusion homogenization temperatures, salinities, and δ18Owater values of C2 veins show decreasing trends with increasing distances from strike-slip faults. This may indicate that C2 fluid might migrate into Ordovician carbonate reservoirs through strike-slip faults within 6 km during late Hercynian orogeny (late Permian). The similarly decreasing trends are observed in C3 veins, indicating that the eastern part of No. 1 fault seemed to be the main fluid-flow pathway for C3 calcite precipitation during Himalayan orogeny. Hydrocarbon may have migrated along the similar pathways as supported by (1) abundant primary hydrocarbon-bearing fluid inclusions in the C2 and C3 calcites and (2) well-documented hydrocarbon migration and mixing. This is an ideal case showing how spatial variation in geochemical data from fracture fillings can be used to trace paleowater and likely hydrocarbon flows in sedimentary basins; it thus may be useful in predicting fluid flow and distribution of hydrocarbons in the Tarim Basin and other basins.

Based on limited geophysical and outcrop data, shortening of the strata in the Appalachian Plateau above the Silurian salt detachment was interpreted to have occurred by layer-parallel shortening (LPS) plus gentle folding. Recently acquired high-quality, three-dimensional seismic reflection and well data reveal that strata from the Silurian Salina Group and the Devonian Marcellus Shale shortened through a variety of macroscale mechanisms in the Appalachian Plateau region of Lycoming County, Pennsylvania. Geometries evident in the seismic reflection profiles and repeated stratigraphy in gamma-ray log surveys indicate north- and south-dipping wedge-style thrust faults with offsets ranging from 60 to 550 m (195 to 1800 ft). Through kinematically restored and balanced cross sections, we show that the 10%–15% LPS calculated from the rocks exposed at the surface of the Appalachian Plateau is equal to the magnitude of interpreted macroscale shortening in the Silurian–Lower Devonian units immediately above the Silurian Salina Group. Previously collected seismic reflection profiles extending south of the Nittany anticlinorium into the Valley and Ridge reveal wedge-style thrust faulting in Ordovician through Silurian units and wedging of the northernmost horses (a volume of rock completely enclosed by thrust faults) of the Cambrian–Ordovician duplex of the fold–thrust belt under the southern plateau edge. These structures allow us to interpret a pathway of triangle zones (a combination of two thrusts with the same detachment and with opposing vergence such that they form a triangular zone) that transfer slip from the basal decollement in the Cambrian Waynesboro Formation to the overlying Ordovician Reedsville detachment and then to the Silurian salt detachment in the Appalachian Plateau.

The TZ-No1 gas field in the Tarim Basin is the largest condensate field in China; however, it has not developed efficiently because of low and unpredictable production during the past 20 yr. Cores, logging interpretation, seismic descriptions, fluid properties, and production data indicate that this Ordovician carbonate field is different from conventional stratigraphic oil and gas fields as follows: (1) the hydrocarbon-bearing area covers a large region of 2000 km2; (2) matrix reservoirs have low porosity ( 20% per year). An examination of the carbonate reservoir and hydrocarbon accumulation history suggests that this large-scale stratigraphic accumulation formed during hydrocarbon emplacement in the early Paleozoic, with the reservoirs gradually evolving into tight reservoirs as a result of intense diagenesis. Variable amounts of Neogene gas charged the tight carbonate reservoirs and formed unconventional accumulations. The TZ-No1 gas field is characterized by a strongly heterogeneous tight matrix reservoir with a superimposed fracture-cave reservoir and a complicated unconventional fluid distribution, which provides insights into the exploitation challenges of unconventional carbonate resources.

Lower–Middle Ordovician platform carbonates are important oil and gas reservoir rocks in the Ordos Basin of the North China craton (NCC). In recent years, numerous cores have been recovered from these units, but the depositional environments and facies architecture of this large carbonate platform system have not yet been reported in detail. This study integrates sedimentological and magnetic fabric data collected from outcrops and cores to document variation in microfacies and facies associations within the Shanganning carbonate platform (SCP), infer paleowind directions and the paleogeographic location of the SCP, and evaluate tectonic and paleogeographic controls on platform development. This analysis documented 25 microfacies belonging to 7 microfacies fabric and sediment types: carbonate mudstone, wackestone, packstone–grainstone, evaporite, bindstone–framestone, siliciclastics, and dolostone. Microfacies can be grouped into facies associations that represent tidal-flat, open-platform, restricted-platform, evaporite-platform, platform-margin, slope, and deep-basinal depositional environments. These environments are mainly distributed zonally around the L-shaped Qingyang paleo-uplift on the western and southern margins of the SCP. Anisotropy of magnetic susceptibility measurements at five platform-margin locales yielded paleocurrent directions of (all approximately) 318°–348°, 51°–81°, 42°–72°, 80°–110°, and 54°–84° from paleo-north after correction for a 120°–150° clockwise rotation of the NCC since the Ordovician. The depositional architecture of the SCP depended on a combination of tectonic and paleogeographic (wind) influences. Local tectonic movements controlled the spatial distribution of facies associations around the Qingyang paleo-uplift, which was characterized by open, restricted, and evaporite-platform facies in the platform interior and mainly slope and basinal facies on the outer-platform margin (to the west and south of the Qingyang paleo-uplift). Vertical tectonic movements resulted in cyclic submergence and emergence of the platform over its approximately 20-m.y.-long formation history. Paleo–trade winds influenced aspects of facies zonation across the platform, including growth of metazoan reefs on the windward platform margin and formation of oolitic grainstone and microbial reefs on the leeward platform margin. The facies model for the SCP developed in this study should provide a useful reference framework for future carbonate oil and gas exploration in Lower–Middle Ordovician units of the Ordos Basin. Furthermore, this study makes innovative use of magnetic anisotropy data, in combination with standard petrographic, core, and field data, to discern facies patterns and controls on a paleo-carbonate platform, which is an integrated methodology that may serve as a model for future studies of other carbonate platforms.

The Ordovician–Silurian organic-rich shales in the Wufeng and Longmaxi Formations are widespread in southern China and are the most important shale gas producers in China. The shales display varying total organic carbon content ranging from 0.2% to 6% and are composed of black siliceous mudstone, shelly limestone, siliceous clay-rich mudstone, gray silty–shaly interlaminated mudstone, gray argillaceous mudstone, and calcareous or dolomitic mudstone. Detailed stratigraphic correlation of these formations was achieved, and a high-resolution sequence stratigraphy was constructed based on the integration of well-log data, mineralogical, geochemical, and petrophysical analyses. The Wufeng Formation and the Guanyinqiao Bed were interpreted to be a condensed section with four cycles of sea-level fluctuation. The Longmaxi Formation consists of three members. The Long-1 Member was interpreted to be a third-order depositional sequence that can be subdivided into a transgressive systems tract, an early highstand systems tract, and a late highstand systems tract. Within the constructed isochronal stratigraphic framework, the characteristics and genetic mechanism of different shale lithofacies were studied. The deposition of black siliceous mudstone of high total organic carbon in the Wufeng Formation and the Long-1 transgressive systems tract was likely influenced by volcanic activity. The Guanyinqiao shelly limestone or calcareous mudstone was associated with the Ordovician–Silurian transition when glaciation and mass extinction took place. The gray silty–shaly interlaminated mudstone of moderate total organic carbon in the Long-1 early highstand systems tract was the product of bottom flow intrusion. The deposition of gray argillaceous mudstone and calcareous or dolomitic mudstone with low total organic carbon in the Long-1 late highstand systems tract resulted from enhanced terrigenous input from peripheral uplifts. The distribution pattern of different lithofacies varies greatly in the Upper Yangtze area, and this difference is a result of dissimilar sediment provenances and variable hydraulic restriction levels that were controlled by basin geometry. A better understanding of the distribution pattern and depositional history of the Wufeng and Longmaxi Formations might provide guidance for future profitable shale gas exploration.

Giant petroleum accumulations worldwide with burial depths more than 7000 m (>23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (>6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.

This paper investigates the temperature and pressure distribution characteristics and their evolution in the Upper Ordovician strata in the Tazhong area, Tarim Basin, northwestern China. Based on hundreds of temperature data from boreholes, the present-day temperature ranges from 100°C to 130°C, increasing from the southeast to the northwest and having a “cool” belt in the central fault horst. Pore pressures in the Upper Ordovician reservoirs range from 35 to 62 MPa (5076 to 8992 psi). Overpressures developed in the southwestern region and along the eastern segment of the central fault horst to the northern slope. The Lower Ordovician reservoirs in the east reached 140°C during the Late Ordovician, but those in the west heated continuously and reached the maximum temperature (>130°C) during present day. Paleopressures reconstructed from fluid inclusion data indicate that overpressures caused by hydrocarbon generation were formed in the areas away from fault belts but were absent in the area around the no. 1 fault belt. The temperature evolution indicates that the middle−lower Cambrian source rocks reached gas generation stage (vitrinite reflectance [Ro] > 2.0%) at the end of the Ordovician, whereas the Middle−Upper Ordovician source rocks are still in the high-maturity stage (Ro < 1.3%) at the present day. Deep oil and gas migration is driven by overpressure, and commercial reservoirs are predominantly distributed in the normally pressured zones along the no. 1 fault belt. The formation of gas condensate is controlled by specific temperature and pressure characteristics.

Thick marine shales occur in the Wufeng Formation and Longmaxi Formation of Sanquan Town of the Nanchuan District, Chongqing Municipality, which is located on the southeast margin of the Sichuan Basin. However, few details of the characteristics of the Wufeng–Longmaxi shales in this area have been reported. In this study, a well approximately 100 m (∼328 ft) deep was drilled. A high-quality shale (total organic carbon [TOC] >2.0 wt. %, clay

The Sichuan Basin, China, is commonly considered to contain the world’s most abundant shale gas resources. Although its Paleozoic marine shales share many basic characteristics with successful United States gas shales, numerous geologic uncertainties exist, and Sichuan Basin shale gas production is nascent. Gas retention was likely compromised by the age of the shale reservoirs, multiple uplifts and orogenies, and migration pathways along unconformities. High thermal maturities raise questions about gas storage potential in lower Paleozoic shales. Given these uncertainties, a new look at Sichuan Basin shale gas resources is advantageous. As part of a systematic effort to quantitatively assess continuous oil and gas resources in priority basins worldwide, the US Geological Survey (USGS) completed an assessment of Paleozoic shale gas in the Sichuan Basin in 2015. Three organic-rich marine Paleozoic shale intervals meet the USGS geologic criteria for quantitative assessment of shale gas resources: the lower Cambrian Qiongzhusi Formation, the uppermost Ordovician Wufeng through lowermost Silurian Longmaxi Formations (currently producing shale gas), and the upper Permian Longtan and Dalong Formations. This study defined geologically based assessment units and calculated probabilistic distributions of technically recoverable shale gas resources using the USGS well productivity–based method. For six assessment units evaluated in 2015, the USGS estimated a mean value of 23.9 tcf (677 billion cubic meters) of undiscovered, technically recoverable shale gas. This result is considerably lower than volumes calculated in previous shale gas assessments of the Sichuan Basin, highlighting a need for caution in this geologically challenging setting.

The temporal evolution of hydrocarbons (∼500 million bbl) and its relationship to the orogenic events of the Longmen Shan thrust belt have been extensively debated. The hydrocarbons occur as solid bitumen, as dykes and/or coatings within/along faults/fractures, and as present-day oil seeps. Here, utilizing organic geochemistry, we demonstrate that all of the bitumen exhibit similar organo-geochemical characteristics, and were sourced from the upper Neoproterozoic–lower Cambrian Doushantuo and Qiongzhusi Formations. In contrast, the organic geochemistry of the present-day oil seeps are distinct from that of the bitumen, and suggest that the source is the Permian Dalong Formation. Bitumen Re-Os data indicate that the upper Neoproterozoic–lower Cambrian Doushantuo and Qiongzhusi Formations underwent two temporally distinct oil-generation events; initial oil generation occurred during the Late Cambrian/Early Ordovician prior to the Caledonian orogeny, and secondly during the Jurassic (∼165 Ma) coinciding with the Indosinian-Yanshan orogenies. In contrast, the Re-Os data of the present-day oil seeps are too similar to yield a meaningful age, although the source is considered to have undergone hydrocarbon maturation between the Triassic and Jurassic. The temporal hydrocarbon evolution in the Longmen Shan thrust belt also provides an understanding of the hydrocarbon evolution and future exploration of the adjacent petroliferous Sichuan Basin.

This study presents new data for the identification of the source and assessment of the thermal maturity of oils based on the diamondoid indices of oils from the Tazhong and Luntai uplifts in the Tarim Basin in northwest China. The oil samples were divided into three groups according to biomarker characteristics and the abundance and distribution of diamondoids. Group I oils are located along the Tazhong No. 1 fault zone, which contained abundant diamondoids and are of high thermal maturity, suggesting they are late-charged hydrocarbons that were derived from a Middle–Upper Ordovician source. Group II oils are mainly located in blocks close to the Tazhong No. 1 fault zone and are dominated by early formed hydrocarbons from Cambrian–Lower Ordovician source rocks. Group III lacustrine oils comprise relatively low concentrations of diamondoids compared with group I and group II oils. Group III oils were sourced from Jurassic or possibly Triassic units and are hosted by the low-relief Yingmaili section of the Luntai uplift. The thermal maturity of the oils in each group was evaluated using diamondoid parameters; a few group I oils exhibit intense thermal cracking. To estimate the extent of oil cracking using the concentrations of diamondoids in oils, this study proposes a practical approach that facilitates the determination of baseline 4- and 3-methyldiamantane concentrations. Application of this method indicates that the Tarim Basin marine oils contain a baseline concentration of approximately 69 ppm.

The correlation of lower Paleozoic marine source rocks with reservoired oils by biomarkers is complex because of the uniform early Phanerozoic biomass (bacteria and algae) and the lack of land plant and animal input. Accordingly, the main source rocks for the most prolific oil province in the Baltic Basin are still a matter of debate. The 10 source rocks and 15 oil samples from 5 northern European countries bordering the Baltic Sea Basin were analyzed by gas chromatography (GC) with flame ionization detector, GC–mass spectrometry (GCMS), and GCMS/MS to detect acyclic isoprenoids and aliphatic, aromatic, and nitrogen, sulfur, and oxygen biomarkers. Chemometric tools were applied to screen for meaningful source- and age-related biomarkers and to highlight genetics. Extended tricyclic terpane ratios, C24 tetracyclic terpane/C26 tricyclic terpane ratios, and relative C29 sterane concentrations are considered the most promising biomarkers in differentiating Llandovery shales from Cambrian to Ordovician Alum Shale and for correlation with expelled oil. The uranium irradiation–related C26–C28 triaromatic-steroid concentrations provide possible distinguishing criteria for the source potential of the different Alum Shale units. Enhanced oil maturation by volcanic intrusion is highlighted by sterane biomarkers and polycyclic aromatic hydrocarbons. The Alum Shale is here considered the main source rock for oil accumulations in lower Paleozoic reservoirs of the Baltic Basin. Oil seepage occurring in Ordovician limestone was mainly generated by the Middle Cambrian Alum Shale, and Middle Cambrian sandstone reservoirs were mainly sourced by Upper Cambrian and Lower Ordovician Alum Shale with higher maturity. Considerations about the assessment of migration distance are based on carbazole concentrations and C29 sterane isomerization. Advanced studies to unravel detailed lower Paleozoic oil–source-rock correlations are based on meaningful biomarkers, offer approaches to significantly reduce the exploration risk in this area, and could be applied to similar early Paleozoic petroleum systems in other basins.

The Upper Ordovician Red River Formation has been a prolific producer of oil and gas in the Williston Basin, where it has cumulatively produced more than 750 million bbl of oil equivalent over the past half century. Previous studies have recognized petroleum source beds, referred to as kukersites, in the Red River Formation but have not determined their complete extent or hydrocarbon generation significance. Examination and analysis of 28 cores and greater than 300 wireline logs have revealed 10 distinct kukersites in the Red River D zone that can be correlated individually for tens to hundreds of miles (tens to hundreds of kilometers) across the western quarter of North Dakota. Although each Red River kukersite is typically thin (1–2 ft [0.3–0.7 m] thick), they combine to reach net thicknesses of greater than 12 ft (3.7 m) with average present day total organic carbon (TOC) values of typically 3–6 wt. %. Hydrogen index (HI) values from kukersite samples range from primarily greater than 800 mg hydrocarbons (HC)/g TOC within the northern flank of the basin to systematically decreasing to less than 100 mg HC/g TOC within the basin center. This systematic decrease in HI is interpreted to be a function of increased thermal maturity, where hydrocarbon generation has depleted kukersite organic richness. Preliminary calculations of hydrocarbon volumes generated from Red River kukersites, based on a previously developed method that calculates the volumetric decrease in original to present-day kerogen content, total approximately 66 billion bbl (1.05 × 1010 m3) of oil equivalent. This approximate generation total is more than enough to account for cumulative Red River production and supports the idea that the Red River is a self-sourced petroleum system with potentially significant remaining exploration potential.

The lower section of the lower Silurian Qusaiba Member, Qalibah Formation, is characterized by regionally developed organic-rich shales that have sourced many of the large Paleozoic petroleum systems of Saudi Arabia. In northern Saudi Arabia, these high–total organic carbon (TOC) horizons are being assessed for their unconventional shale-gas potential. The initial phase of exploration drilling, which resulted in a quadrupling of the number of penetrations in northern Saudi Arabia, had the dual purpose of (1) assessing the high-TOC horizons as an unconventional resource play and (2) acquiring the fundamental data required to understand the geologic development of the zones of interest within the lower Qusaiba. The availability of numerous new cores from across northern Saudi Arabia enabled an extensive refinement of the existing biostratigraphy and enhanced integration between graptolite and palynomorph biozonation systems. In cores from the study area, four distinct sedimentary facies are recognized, (1) pyritic siltstone, (2) black mudstone, (3) black chert, and (4) gray shale, representing distinct paleoenvironmental conditions related to the stepped latest Ordovician and early Silurian Gondwanan deglaciation. The failure of the Gondwanan ice sheet was not a simple, short-lived, consistent melting and associated flooding of a flat continental shelf. This study highlights the complex interplay of sea-floor topography, ocean currents, sediment supply, and variations in the rate of melting of the ice sheet. With the associated rising ambient temperatures there are (1) increasing clay concentrations associated with intensifying chemical weathering of the exposed land mass and (2) progressive lowering of the carbonate compensation depth as water temperatures rise, enabling the preservation of carbonate shell material.

Huge, high gas–oil ratio, hydrogen sulfide (H2S)-bearing gas condensate accumulations were recently discovered in the Ordovician carbonate reservoirs of the Tazhong uplift in the Tarim Basin, northwest China. Distinct differences exist between the eastern and western condensates in terms of chemical and isotopic compositions. Condensates from the western part of the uplift were characterized by high dibenzothiophenes (generally >500 μg/g), a high H2S concentration (∼7%, vol./vol.), and relatively depleted 13C methane (δ13C1 = −55.5‰ to −36‰). The H2S concentration in the Tazhong gas condensates shows a positive correlation to Mg2+ concentration in the formation water. Formation water in Lower Ordovician–Cambrian strata in the Tazhong uplift is rich in Mg2+, which facilitates the thermochemical sulfate reduction (TSR) of sulfate contact ion pairs (CIPs) to produce H2S and dibenzothiophenes. A detailed comparison of the chemical compositions of the formation waters in different strata indicates that a high H2S concentration in the Tazhong gas condensates originates from the TSR of sulfate CIPs in the Lower Ordovician–Cambrian strata, where a primary oil accumulation may have existed. The concentrations of 3- and 4-methyldiamantanes in the western condensates (80 to 150 μg/g) are relatively lower than those from the eastern part of the uplift. Also, the δ13C1 in the western H2S-bearing gas condensates was more negative, and the δ13C2 − δ13C1 value was larger than that from typical TSR-altered gases. These features indicate that the western Tazhong samples had just entered the initial stage of TSR. According to the pressure, volume, temperature (PVT) phase diagram, the lower Paleozoic section was quickly buried after the Tortonian. High-H2S hydrocarbon inclusions formed during the last 10 m.y. when paleotemperatures reached 140°C (284°F). Because the reaction rate of the sulfate CIPs oxidation was relatively slower than that of H2S autocatalysis during the entire TSR process, advanced TSR has not been accomplished yet. It is also inferred that the Tortonian was the key period for accumulation of secondary H2S-bearing gas condensates, resulting from abundant gas washing along deep fractures and charging in the early reservoirs. An increased aromaticity parameter (toluene/n-heptane) and an increased fractionation index from east to west indicate an intensified degree of gas washing. Different gas-washing intensities in the eastern and western gas condensates led to diverse PVT states as well. Deep strata in the Tazhong uplift were characterized by multiple charges and mixing, coupled with periodic TSR, leading to the occurrence of variable H2S-bearing gas condensates.

Intracratonic sag basins commonly have relatively simple tectonic histories; however, later tectonic activity involving exhumation can make reconstructing the burial history a challenging task. This is important because the relative timing of hydrocarbon generation and trap formation can be a key factor in risk assessment. If trap formation postdates peak hydrocarbon generation, exploration plays are typically downgraded. Mechanisms for charge in such exhumed basins are critical factors for understanding exploration risk. This study uses data collected from an Ordovician gas-condensate field in the Illizi Basin of Algeria to document the charging of a trap formed, or modified, during exhumation of the basin following maximum burial. Integrated analysis of sonic compaction data, thermal history indicators, and stratigraphic well data was used to constrain the burial and thermal history of the region. Hydrocarbon generation in the lower Silurian source rock is interpreted to have occurred during the Carboniferous (prior to Hercynian exhumation) and during the Late Cretaceous–early Eocene maximum burial (prior to Eocene exhumation). Structural reconstructions indicate that the field was initially located on the southern flank of a long-lived, intrabasinal, Paleozoic paleohigh. The large, low-relief structural closure that defines the present-day accumulation formed as a result of northward tilting of the Illizi Basin during Eocene uplift of the Hoggar massif. The study demonstrates that the timing of trap formation at the Ordovician field postdates the main local hydrocarbon generation events within the basin, suggesting that alternative hydrocarbon charge mechanisms are required. This study indicates considerable potential to charge updip traps on the flanks of exhumed petroliferous basins via redistribution of the preexisting hydrocarbons within the basin.

Hydrocarbon exploration in the Berkine–Ghadames Basin in southern Tunisia has generally followed global economic trends. In recent years, improvements in seismic data acquisition combined with experience gained in log interpretation in low-resistivity reservoirs have resulted in oil and gas discoveries in the Upper Silurian Acacus Formation, enriching the hydrocarbon potential of the Berkine–Ghadames Basin in southern Tunisia. Presently, the Tunisian daily oil production is approximately 43,000 bbl, about half of which comes from the fields located in southern Tunisia and is produced from the Acacus Formation. The Berkine–Ghadames Basin is an intracratonic basin formed during the Pan-African Orogeny. It covers an area of approximately 350,000 km2 (135,135 mi2) and extends into Algeria, Libya, and Tunisia. The sedimentary section within the basin ranges from Cambrian to present and is approximately 7000 m (23,000 ft) thick in the depocenter. The basin has experienced several tectonic events, which have modified its architecture and affected the petroleum systems and hydrocarbon pathways. In this study, the main elements of the petroleum geology systems are described. With the geochemical modeling results, the petroleum potential, hydrocarbon generation, expulsion time, and quantity of hydrocarbon are assessed. The main petroleum systems are also defined. They are represented by the Silurian Tannezuft hot shale source rock with Ordovician Djeffara and Silurian Acacus reservoirs, by Silurian Tannezuft hot shale with Kirchaou reservoirs, and by the Devonian Aouinette Ouinine Formation Member III source rock with Kirchaou reservoirs. The hydrocarbon traps in the area are mainly structural types. The study describes and emphasizes the hydrocarbon migration pathway mechanism from source rocks to traps. To predict and derisk future drilling locations, fairway maps are generated for the three plays: Ordovician, Silurian, and Triassic. Although the paper focuses on southern Tunisia, an attempt is made to introduce Libyan and Algerian knowledge to evaluate the basin in a regional context.

The Hudson Bay Basin is the largest intracratonic basin in North America, although it is the only one without any proven hydrocarbon reserves. The stratigraphic succession that fills the basin consists mainly of Paleozoic strata, with a maximum preserved thickness of about 2500 m (8202 ft). The Paleozoic succession includes Ordovician to Devonian shallow marine carbonates, reefs, and shales with locally thick Devonian evaporites. The Paleozoic strata are locally unconformably overlain by a thin Mesozoic and Cenozoic cover of nonmarine and marine strata. From 1964 to 1985, over 46,000 line-km (28,600 mi) of seismic reflection data were acquired, and four onshore and five offshore exploration wells were drilled. The data acquired at that time led to pessimistic conclusions on source rocks and the thermal rank of the basin and resulted in the stoppage of exploration activities. However, hydrocarbon shows or indicators were identified in well log data and seismic reflection profiles. The likelihood of an active petroleum system has also been recently supported by recognition of pockmarks on the seafloor and possible marine oil slicks identified on satellite images. New studies of geological, geophysical, and biostratigraphic data reveal that the Hudson Bay Basin had an irregular subsidence and uplift history. Syntectonic deposition occurred during the Late Ordovician(?) to Early Devonian and sag-basin deposition during the Middle to Late Devonian. The basin contains four unconformity-bounded sequences, with significant depocenter migration over time. Analyses of petroleum-system data indicate the Hudson Bay Basin has higher petroleum potential than previously considered. Porous platform limestones, reefs, hydrothermal dolomites, and siliciclastics form potential hydrocarbon reservoirs. Upper Ordovician organic-rich shales with type II-S organic matter are recognized at several locations in the basin. Newly acquired organic matter reflectance and Rock-Eval data indicate Ordovician–Silurian strata locally reached the oil window. Basin modeling demonstrates significant potential for oil generation and expulsion from Ordovician source rocks. Five petroleum play types are identified in the Hudson Bay Basin, including an untested fault-sag or hydrothermal dolomite play. The synthesis of the petroleum system information indicates that the Hudson Bay Basin is, at least locally, prospective for oil accumulations.

The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at , indicating marine algal organic matter. Rock-Eval and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Basin-scale correlations in the subsurface generally rely on lithostratigraphic information synthesized from wireline logs, and, in some cases, well cuttings, and cores. However, lithostratigraphic boundaries are often diachronous, and, as such, the correlations based upon them may not provide reliable timelines. In this paper, we use data from well cuttings and a core to generate chronostratigraphic logs of Late Ordovician strata spanning the Black River Group, Trenton Group, and Utica Shale across the subsurface of New York State. Although particular values may be impacted by (primary) variability in local dissolved inorganic carbon reservoirs and/or (secondary) diagenetic alteration, it is possible to identify spatially and stratigraphically coherent patterns in , which can be used to effectively correlate time-equivalent strata on a basin-wide (or even global) scale, including across lithologies (e.g., between limestone and calcareous shale). The present study emphasizes the use of well cuttings, as these are commonly collected during drilling and can provide the maximum lateral resolution for subsurface correlation. Parallel geochemical (percent carbonate and total organic carbon) and isotopic ( and ) data are used to understand the origin of stratigraphic and spatial variability in the signal and to identify diagenetic alteration. Stratigraphically coherent trends across New York were used to identify six isotopically distinct packages of time-equivalent strata within these formations. Pairing chemostratigraphic and lithostratigraphic data improves our ability to document the diachronous nature of lithologic contacts, including the base of the Utica Shale, which is progressively younger moving west through New York.

The Upper Ordovician Montoya Group crops out in southern New Mexico and westernmost Texas and records predominantly subtidal deposition on a gently dipping carbonate ramp that was subsequently almost entirely dolomitized. The Montoya Group is a third-order composite sequence composed of six regionally correlative, shallowing-upward, third-order depositional sequences (M0–M5). Sequence M0 has sandstone at its base that is overlain by skeletal packstone-grainstone. Sequence M0 occurs only locally and was likely deposited in a topographic low formed during regional development of the unconformity following El Paso Group deposition. Sequence M1, marking the initial widespread transgression over the Ellenburger unconformity, consists of sandstone updip that passes downramp into skeletal packstone. The highstand systems tract (HST) of M1 consists of a prograding skeletal grainstone that was subaerially exposed upramp. Sequence M2, which contains the second-order maximum flooding surface, has abundant subtidal cherty carbonate at its base, which shallows upward into a widespread, prograding coral packstone-grainstone in the HST. Sequence M3 also contains abundant downramp chert that passes upramp into an aggrading crinoidal shoal and farther upramp into peritidal mudstone. Sequence M4 records an extensive basinward shift in facies as peritidal burrowed and cryptalgalaminated mudstone prograded over subtidal carbonate. Sequence M5 is only locally developed downramp and consists of crinoidal grainstone with abundant evidence of subaerial exposure. A regional unconformity separates the Montoya Group from the Silurian Fusselman Dolostone or younger units. Parasequences (meter-scale cycles) recording low- to moderate-amplitude relative sea level fluctuations are ubiquituous features at individual outcrops but are difficult to correlate regionally. The abundance of syn- or early depositional chert in the subtidal facies indicates that the Montoya Group was deposited within a region of strong regional upwelling along southern Laurentia. This early formed chert was the reservoir facies in a successful Upper Ordovician gas play in Ward and Reeves Counties, Texas.

Outcrop studies of sedimentary and stratigraphic features of microbial buildups are important in developing conceptual models for exploration of potential microbialite reservoirs. This study examines the occurrence and distribution of Lower Ordovician microbial fabrics in central Missouri and Kansas. The units studied include the Roubidoux, Jefferson City, and Cotter Formations of the Arbuckle Group. To determine the depositional environments suitable for microbialite development, micro-, meso-, and macroscale features were examined, and their stratigraphic relationships were established to the surrounding lithofacies. Microscopic-scale analysis reveals heavy dolomitization of strata; however, remnant depositional features provide vital clues about the microbialite development. The occurrence of microbial structures is placed within a cycle stratigraphic framework. The microbialites occurred within cyclical shallow-marine deposits and are grouped into three cycle types. Type 1 deposits include subtidal mudstones to packstones that grade into intertidal stromatolites. Type 2 deposits are composed of subtidal mudstones and packstones with thrombolite fabrics that grade into supratidal facies. Type 3 deposits include intertidal or supratidal facies that grade into supratidal facies.

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.

Geologic sequestration of anthropogenic carbon dioxide (CO2) is one of the most promising approaches to safely and effectively reduce emissions of CO2 created through the oxidation of fossil fuels. Methods used by the petroleum industry in the characterization of hydrocarbon accumulations can be used to assess potential subsurface traps for sequestration purposes. In this article, we use these approaches to evaluate the characteristics of a naturally occurring accumulation of CO2 in western Wyoming. The Moxa arch is a 200-km (124-mi)-long basement-involved anticline. The Mississippian Madison Formation and the Ordovician Bighorn Dolomite contain the most CO2 within the structure. Relict anhydrite in these and other Paleozoic units was an important factor in evolving hydrocarbons into CO2 through inorganic thermal sulfate reduction and, more importantly, in creating a seal to hold large columns of buoyant gas. Fluid-inclusion data sets have been particularly useful in understanding the sealing characteristics of the units within the Moxa arch and affirming that the Devonian Jefferson, Mississippian Amsden, and Triassic Dinwoody and Woodside formations have been very effective seals. Existing pressure data reveal that the two gas columns in the Madison and Bighorn formations lie on a similar gradient and share a common gas-water contact, yet are likely not in hydraulic communication. Currently, all available data suggest that both reservoirs share a fault-dependent spill point. By reconciling the spill points of the gas in the Madison and Bighorn reservoirs, their compositions, their initial and current pressures, their seal, and the uncertainties associated with injection of CO2 can be identified and potentially derisked with additional information. If the Madison and Bighorn are filled to their fault-dependent spill point, it implies that additional storage capacity in the reservoir can only be obtained by production of the original gas column. This uncertainty may be abated if data from future drilling demonstrates that neither the Madison Formation nor the Bighorn Dolomite have a fault-dependent spill point, suggesting that these structures are underfilled with respect to their closure and possess additional storage capacity.

High-quality three-dimensional seismic data acquired in the central Tabei Uplift, Tarim Basin, western China, provide a rare opportunity to characterize in exceptional detail the three-dimensional geomorphology of a deeply buried (5500–6500 m [18,045–21,325 ft]) Ordovician unconformity and the related paleokarst drainage system. An integrated approach was applied that emphasized integration of seismic data with available conventional core, wireline logs, and age-equivalent outcrops. The exceptional quality of the seismic data allowed a seismic detection limit of karstified features of less than 75 75 m (246 246 ft) horizontally and 6 m (20 ft) vertically. Interpreted geomorphologic and depositional elements include fluvial channels and canyons, fluvial valleys, sinkholes, and tower karsts and hills. The modern tower karst-drainage system in Guilin, China, is very similar to the mapped Ordovician karst-drainage system and is used as a modern analog. The interaction between the surface karst-drainage system and the shallow-subsurface cave-passage system is evidenced by the observation that surface canyons appear to initiate in areas associated with intense sinkhole development. Also, surface river valleys tend to correspond to dip-oriented surface depressions partly related to near-surface cave collapse. During burial into the deeper subsurface, the combination of intrastratal collapse (karstified strata) and suprastratal collapse (postkarst-deposited strata) created large damage zones hundreds of meters thick and kilometers wide. Coalesced-collapsed paleocave systems can be interpreted from the unique circular pattern of faults (observed in map view) that are associated with seismic bright spots.

We use the integration of gravity, magnetic, and 3-dimensional (3-D) seismic data to map sedimentary features and study the relationships between sedimentary and basement features in the Osage County area of northeast Oklahoma. The prominent gravity and magnetic anomaly studied within this region are related to the mid-continent rift system. However, we cannot substantiate this conclusion with geochronological age–dating data at this time. Prominent dipping Precambrian reflectors seen on seismic section suggest that extension occurred before emplacement of shallow basement. A regional episode of extension possibly occurred early in the development of the 1400 to 1340 Ma magmatic province. Thus, we interpret the structure we see to be a basin that might have formed during this interval. We use volumetric seismic attributes such as coherence and curvature derived from seismic data to better characterize subtle features such as collapse features and faulting and fracturing within the Mississippian and Ordovician carbonate deposits that are difficult to detect on conventional 3-D seismic data displays. Blended seismic images of these carbonate reservoirs reveal polygonal, highly coherent, and high-amplitude lineaments, which trend northeast and northwest. The northeast-striking lineaments are related to the late Paleozoic Nemaha tectonics, whereas the northwest lineaments are interpreted to be related to the inherent basement fabric or the draping of the Mississippian over a cockpit karst terrain. Although a one-to-one correlation between the basement structures and the carbonate reservoirs cannot be established, basement structure lineaments are parallel in orientation to those seen within the Mississippian chert and the Arbuckle Group.

This article integrates three-dimensional (3-D) seismic attributes and log data to determine porosity distribution of the Ordovician Trenton-Black River groups within the Rochester field, southern Ontario. The rocks are composed of tight limestone, parts of which were dolomitized to form porous reservoir rock. Previous studies of the Trenton-Black River dolomite reservoirs have indicated a close relationship between faulting and reservoir development, but few published studies have attempted to examine these relationships using 3-D seismic data. This study explores the stratigraphy and structure of the Rochester fault-related dolomite reservoir using 3-D seismic data and neural networks to predict porosity. By predicting porosity using seismic attributes, vertical and lateral distributions of porosity that can be used to guide development and exploration drilling for optimal hydrocarbon recovery were obtained. The sites of highest porosity were found to be along and within the fault zones. Faults extending from the basement into overlying Paleozoic rocks are composed of several short-plane, vertical, and subvertical fault segments. However, some of these faults appear to have originated and died within the Paleozoic rocks; they cannot be traced to the basement because of little or no offset where they penetrate the basement. Although the five identified attributes are considered important in exploration for fault-related dolomite reservoirs, the single most important attribute to employ is the amplitude envelope because the other attributes are mathematically related to it. Furthermore, the sags that are seen in the Rochester field are due to the combined effects of low-velocity pushdown and faulting. Methods and results presented in this study can be used to explore and develop fault-related dolomite reservoirs elsewhere in similar geologic settings.

Solid bitumen was identified within the Mississippian Chester sandstone reservoir in the Hitch field, southwest Kansas. The adjacent Etzold field has similar reservoir properties but lacks solid bitumen, although the Hitch and Etzold fields were thought to be in pressure communication and have common source rocks. Hitch and Etzold crude oils and core extracts were characterized geochemically to gain a better understanding of the reservoir-filling history and geological and geochemical controls on solid bitumen formation in the Hitch reservoir. Based on a variety of geochemical characteristics, we propose that the Hitch and Etzold oils are mixtures derived from Ordovician and Late Devonian–early Mississippian (Woodford Shale) source rocks. The solid bitumen in the Hitch reservoir probably results from mixing of oils having different geochemical compositions, which filled the reservoir over an extended period. No evidence of severe biodegradation or thermal alteration is observed. A reservoir-filling scenario is proposed in an effort to explain why the Hitch oils are geochemically more heterogeneous than Etzold oils. Furthermore, gas de-asphalting and regional pressure drops as a result of post-Laramide orogeny may have contributed to a phase change in the reservoir fluid and deposition of solid materials by disturbance of thermodynamic equilibrium. The major significance of this study is related to improving our knowledge on the occurrence of the presence of solid bitumen in reservoirs that can introduce barriers into the reservoir, complicating waterflood operations and leading to erroneous oil-in-place calculations and subsequently lower than expected oil recovery.

Khazzan is a giant tight-gas accumulation located in northern Oman. The accumulation is associated with Cambrian Barik Sandstone Member reservoirs, in a semiregional combination (stratigraphic-structural) trap. This article outlines the background to the discovery of Khazzan and describes our understanding of its geology and petroleum systems and the study work used to support screening, appraisal, and development strategies for the Khazzan accumulation. The stratigraphic element of the trap is associated with a northerly thinning and transition of continental, fluvial braid-plain and shoreface sandstones into offshore mud rocks. The structural element of the trap formed as a result of the compactional drape of these reservoir units and the later structuring associated with an underlying, long-lived intrabasin high. The integration of multiple correlation techniques (well-log correlation, recognition of changes in core facies and ichnofacies and magnetostratigraphy) has helped to define an intrareservoir correlation framework for the Barik Sandstone Member, with a resolution of approximately less than or equal to 1 m.y., allowing detailed insights into stratigraphic and areal controls on hydrocarbon compositional variations, trapping mechanisms, reservoirs, and reservoir connectivity. Fluvial sandstones within the Khazzan stratigraphic pinch-out form better reservoirs. The stratigraphic framework developed indicates that these fluvial units are associated with discrete, geographically extensive, progradation events. The association of production with discrete reservoir levels and areas allows a robust semipredictive regional model for targeting better reservoirs and highlights a scope for an additional intra-Barik stratigraphic trapping potential regionally. Enhanced reservoir quality within the more productive reservoirs is attributed to depositional and possibly hydrocarbon charge controls on secondary porosity, and it is complex. Subtle crest-to-flank compositional variations in hydrocarbon type across the gas accumulation hint at complex hydrocarbon charge and mixing between two structural domains and petroleum systems before and during Barik deposition. John Millson holds a B.Sc. (honors geology) degree and a Ph.D. from Aston University in Birmingham, United Kingdom and the University of Wales, Abersytwyth. Joining the oil industry as a petroleum geologist in 1985, he has worked in the United Kingdom, Nigeria, Netherlands, and Oman, with some 11 years of working on various aspects of the geology of Oman. His main interests include tectonostratigraphy and unconventional hydrocarbon resources. Jamie Quin is a geologist for Statoil-Hydro. Since joining the oil industry in 2001, he has worked on assets in Oman (for Badley Ashton and Associates), Libya (for Repsol YPF), and Norway (Statoil). He holds a B.Sc. degree from the University of Glasgow, an M.Sc. degree from Royal Holloway, University of London, and a Ph.D. from Trinity College Dublin. Erdem Idiz is currently a global exploration adviser for Exploration New Ventures with Shell International Exploration and Production in the Netherlands. He received his M.Sc. degree in geology (1981) and Ph.D. in geochemistry (1987) from the University of California, Los Angeles (UCLA). After a postdoctorate at the Institut Francais du Petrole, he joined Shell in 1988, working in research and applications as a geochemist and basin modeler in the Netherlands, Germany, and Canada. His research interests are petroleum systems analysis, biomarkers, and stable isotopes. Peter Turner holds degrees from Cardiff and Leicester Universities and was a reader in earth sciences at the University of Birmingham in the United Kingdom from 1988 to 2006 where he was head of the Petroleum Geoscience Group. His research includes paleomagnetism, sedimentology, and hydrocarbon reservoirs, and since retiring from university life, he has worked as a full-time consultant focusing on exploration in north and west Africa and China. No details available.

Three-dimensional seismic data reveal numerous subcircular sag structures in the northern Fort Worth Basin. The structures are defined by concentric faults that extend vertically upward 760–1060 m (2500–3500 ft) from the Lower Ordovician Ellenburger Group. The largest structures remained active into the lower Desmoinesian Strawn Group. Criteria are outlined for defining seismically resolvable sag structures, and a detailed quantitative analysis of the geometries of these circular features was undertaken. Results are compared and contrasted, with reviews of subsurface collapse mechanisms and strike-slip processes that are known to produce subsurface circular to subcircular sag geometries in plan view. In this manner, we develop several constraints for differentiating collapse-related sag structures from strike-slip–related sag structures. Qualitative analyses indicate that the geometries observed are strongly analogous to subsurface collapse features where material is removed at depth to create a void, into which the overburden subsequently sags and collapses. Quantitative analyses support the formation of these features by incremental collapse and suprastratal deformation above a linked system of coalesced, collapsed paleocaves within the Ellenburger Group. Observations and criteria presented herein provide valuable information in defining seismically resolvable collapse features worldwide and help distinguish sag features of collapse affinity from those of other origins.

Petroleum occurring in lower Paleozoic rocks is known to be present in southern Scandinavia, northern Poland, and the Baltic states. Oil has been produced from lower Paleozoic reservoirs in Sweden; northern Poland; and the Baltic countries Lithuania, Latvia, and the Russian exclave area of Kaliningrad. The sources for this petroleum are marine, organic-rich muds deposited in the Cambrian, Ordovician, and Silurian. This article concerns geochemical analysis of oils extracted from sandstones and carbonates from the Norwegian Oslo Graben rift and locations in Sweden and describes, in addition, insoluble bitumens collected from lower Paleozoic rocks in the Oslo Graben, locations in Sweden, and from upper Paleozoic rocks in a Norwegian North Sea well. The oils in this study have several geochemical characteristics shared with oils from the Baltic states and northern Poland, and the maturities of the oils are, in general, low. The occurrences of bitumen and migrated petroleum in the Oslo Graben lead us to believe that petroleum also has been generated and expelled in the related offshore Skagerrak Graben, indicating that a Paleozoic petroleum system operated in the Skagerrak Graben. This potential petroleum system has not suffered the degree of uplift, erosion, and destruction of reservoirs experienced by the onshore Oslo Graben, making preservation of any petroleum accumulations in the Skagerrak Graben more plausible. Although speculative, these considerations should interest anyone involved in petroleum exploration in the Skagerrak and the Norwegian-Danish Basin, not the least because of the proximity of Skagerrak and major energy markets in Europe.

Two distinct groups of fractures in an Ellenburger Group reservoir in Barnhart field, Reagan County, west Texas, were identified. The oldest fractures (FBR) are the most numerous; have irregular shapes, sediment, and baroque dolomite fill, and no preferred orientation; and have been attributed by previous workers to brecciation associated with the collapse of Lower Ordovician paleocave systems. Younger, subvertical, opening-mode fractures (FY) that have consistent east-southeast and south-southwest strikes postdate the baroque dolomite cement. FY fractures therefore formed during the late stages or after the Pennsylvanian Ouachita orogeny. We analyzed FY fracture orientation, intensity, and openness using well image logs, oriented rotary-drilled sidewall cores, and a full-diameter core. FY fracture aperture sizes range from several micrometers to a few millimeters, and the fracture intensity is consistent within and between the wells studied at 1.8–4.0 102 fractures/mm2 for fractures 1 mm (0.04 in.) wide. Dolomite cement that is synchronous with FY fracture opening seals fractures in some locations, but is limited to fracture linings and mineral bridges in other places. Calcite, which grew after FY fractures stopped opening, is variably present and postdates dolomite cements. Where present, calcite occludes most remaining FY fracture porosity. Diagnosing the presence of postkinematic calcite is therefore an important step in being able to predict open fractures and was done for part of Barnhart field using rotary-drilled sidewall cores.

Ordovician carbonates near the Wisconsin arch represent the type locality in ancient rocks for the Dorag, or mixing-zone, model for dolomitization. Field, petrographic, and geochemical evidence suggests a genetic link between the pervasive dolomite, trace Mississippi Valley–type (MVT) minerals, and potassium (K)-silicate minerals in these rocks, which preserve a regional hydrothermal signature. Constraints were placed on the conditions of water-rock interaction using fluid-inclusion methods, cathodoluminescence and plane-light petrography, stable isotopic analyses, and organic maturity data. Homogenization temperatures of two-phase aqueous fluid inclusions in dolomite, sphalerite, and quartz range between 65 and 120C. Freezing data suggest a Na-Ca-Mg-Cl-H2O fluid with salinities between 13 and 28 wt.% NaCl equivalent. The pervasive dolomitization of Paleozoic rocks on and adjacent to the Wisconsin arch was the result of water-rock interaction with dense brines at elevated temperatures, and it was coeval with regional trace MVT mineralization and K-silicate diagenesis. A reevaluation of the Dorag (mixing-zone) model for dolomitization, in conjunction with convincing new petrographic and geochemical evidence, has ruled out the Dorag model as the process responsible for pervasive dolomitization along the Wisconsin arch and adds to the abundant body of literature that casts serious doubt about the viability of the Dorag model in general.

Langhorne “Taury” Smith heads the Reservoir Characterization Group at the New York State Museum. He holds a B.S. degree from Temple University, a Ph.D. from Virginia Tech, and did postdoctoral work at the University of Miami. He also worked for Chevron as a development geologist, and current research interests are focused on carbonate reservoir characterization and hydrothermal alteration of carbonate reservoirs. Graham Davies received his B.Sc. (honors) degree and Ph.D. from the University of Western Australia. His doctoral thesis was on modern carbonates in Shark Bay, Western Australia (published in AAPG Memoir 13). After a postdoctoral fellowship with James Lee Wilson at Rice University, he joined the Geological Survey of Canada (GSC) in Calgary. After 7 years with the GSC, Graham co-founded and became principal owner of AGAT (Applied Geoscience and Technology) Consultants/Laboratories. Since 1983, he has operated through GDGC Ltd. He has published about 70 papers on the geology of Australia and Canada, and has authored or coauthored more than 600 consulting reports. Graham received the CSPG Douglas Medal in 2002 for his work on Arctic Paleozoic carbonates and evaporites, and on the Triassic and other aspects of western Canadian geology. His principal current interest is in hydrothermal dolomites. This issue of the AAPG Bulletin is dedicated to structurally controlled hydrothermal alteration of carbonate rocks and reservoirs. This type of alteration covers the spectrum of carbonate-hosted sulfide ore deposits to hydrothermal dolomite to leached limestones, and in many cases has a major impact on reservoir type, geometry, quality, and distribution. Hydrothermal dolomite (HTD) reservoirs have a long history of exploration and development in North America, extending from the earliest discoveries in the Ordovician Lima-Indiana and other trends of the northeastern United States (Hurley and Budros, 1990; Wickstrom et al., 1992), and continuing today with the Trenton–Black River play …

Oil and gas reservoirs of the Ordovician Trenton–Black River interval in the Appalachian Basin are commonly associated with fault-related hydrothermal dolomites. However, relationships between porosity development and fault geometry in these fields are poorly documented. In this article, we integrate three-dimensional (3-D) seismic and wire-line data from the Trenton–Black River interval at Saybrook field in northeastern Ohio to study relationships between faulting and porosity development there. Faults were mapped using a combination of amplitude and coherency versions of the seismic data, and a 3-D porosity volume was generated for the Trenton–Black River interval by integrating attributes derived from the seismic data with log-based measures of porosity. The productive trend in the Trenton–Black River interval at Saybrook is controlled by a 3.4-mi (5.5-km)-long, northwest-southeast–oriented basement fault that was probably reactivated during the Taconic orogeny (i.e., Late Ordovician). Strike-slip movement along the fault generated en echelon synthetic shear faults that branch at least 1350 ft (411.5 m) upward into the Trenton–Black River interval. The best porosity is developed in areas between overlapping synthetic shear faults. Antithetic shear faults probably formed at these locations and, when combined with minor dip-slip movement, created conduits for subsequent porosity-generating fluids. Circular collapse structures associated with localized extension between overlapping shear faults are the primary drilling targets, and horizontal wells running parallel to the strike of the fault would have the best chances of intercepting good porosity development.

In the past decade, more than 20 new natural gas fields have been discovered in laterally discontinuous dolomites of the Upper Ordovician Black River Group in south-central New York. The dolomites form around basement-rooted wrench faults that are detectable on seismic data. Most fields occur in and around elongate fault-bounded structural lows interpreted to be negative flower structures. Away from these faults, the formation is composed of impermeable limestone and forms the lateral seal for the reservoirs. In most cases, the faults die out within the overlying Trenton Limestone and Utica Shale. Most porosity occurs in saddle dolomite-coated vugs, breccias, and fractured zones. Matrix porosity is uncommon in the Black River cores described for this study. The patchy distribution around basement-rooted faults and geochemical and fluid-inclusion analyses supports a fault-related hydrothermal origin for the saddle and matrix dolomites. This play went for many years without detection because of its unconventional structural setting (i.e., structural lows versus highs). Using the appropriate integrated structural-stratigraphic-diagenetic model, more hydrothermal dolomite natural gas reservoirs are likely to be discovered in the Black River of New York and in carbonates around the world.

Large-scale relational databases and geographic information system tools are used to integrate temperature, pressure, and water geochemistry data from numerous wells to better understand regional-scale geothermal and hydrogeological regimes of the lower Paleozoic aquifer systems in the mid-continent and to evaluate their potential for geologic CO2 sequestration. The lower Paleozoic (Cambrian to Mississippian) aquifer systems in Kansas, Missouri, and Oklahoma comprise one of the largest regional-scale saline aquifer systems in North America. Understanding hydrologic conditions and processes of these regional-scale aquifer systems provides insight to the evolution of the various sedimentary basins, migration of hydrocarbons out of the Anadarko and Arkoma basins, and the distribution of Arbuckle petroleum reservoirs across Kansas and provides a basis to evaluate CO2 sequestration potential. The Cambrian and Ordovician stratigraphic units form a saline aquifer that is in hydrologic continuity with the freshwater recharge from the Ozark plateau and along the Nemaha anticline. The hydrologic continuity with areas of freshwater recharge provides an explanation for the apparent underpressure in the Arbuckle Group.

The Permian basin of west Texas and southeast New Mexico remains an important oil-producing province, accounting for 17% of United States production (327 million bbl) in 2002. With a resource base of such size, increased understanding of reservoir geology and improved use of enhanced-recovery practices in the basin can have a substantial impact on United States oil production. Thirty-two oil plays covering both the Texas and New Mexico portions of the Permian basin were defined on the basis of reservoir stratigraphy, lithology, depositional environment, and structural and tectonic setting. One thousand three hundred and thirty-nine significant-sized reservoirs (cumulative production of 1 million bbl [1.59 105 m3] of oil through 2000) were assigned to a geologic play. Cumulative production from these reservoirs was 28.9 billion bbl (4.59 109 m3), or 95% of the basin's total. Examples of successful reservoir-development practices are listed by play because methods demonstrated to work well in one reservoir should be applicable to other reservoirs in the play. The Permian basin is dominantly a carbonate province. Carbonate reservoirs account for 75% of total oil production; clastics, 14%; mixed clastics and carbonates, 8%; and chert, 3%. The plays having the largest cumulative production are the Northwest shelf San Andres platform carbonate play (4.0 billion bbl; 6.31 108 m3), the Leonard restricted platform carbonate play (3.3 billion bbl; 5.25 108 m3), the Pennsylvanian and Lower Permian Horseshoe atoll carbonate play (2.7 billion bbl; 4.29 108 m3), and the San Andres platform carbonate play (2.2 billion bbl; 3.42 108 m3). The Permian system dominates production, accounting for 73% of cumulative production, followed by the Pennsylvanian (13%) and the Ordovician (6%). The estimated remaining reserves from that component of the resource base that is already discovered and producing is 3.25 billion bbl (5.17 108 m3).

The Ordos basin is the oldest and still an important hydrocarbon province in central China. It is a typical cratonic basin developed on the Archean granulites and lower Proterozoic greenschists of the North China block. The development of the Ordos basin during the Paleozoic–Mesozoic can be divided into three evolutionary stages: Cambrian–Early Ordovician cratonic basin with divergent margins; Middle Ordovician–Middle Triassic cratonic basin with convergent margins; and Late Triassic–Early Cretaceous intraplate remnant cratonic basin. Two hydrocarbon systems are present in the basin: the Paleozoic gas and Mesozoic oil systems. In the Paleozoic gas system, the Lower Ordovician marine carbonates and Pennsylvanian–Lower Permian coal measures serve as source rocks. The Lower Ordovician karst-modified dolomites and Pennsylvanian bauxitic mudstones form a significant reservoir-seal association, and the Pennsylvanian–Lower Permian deltaic sandstones and Upper Permian lacustrine mudstones form another effective reservoir-seal association. In the Mesozoic oil system, the Upper Triassic lacustrine mudstones are mature source rocks. The Upper Triassic deltaic sandstones and overlying shallow-lacustrine and swamp mudstones form a reservoir-seal association, and the Lower Jurassic fluvial sandstones and overlying shallow-lacustrine and swamp mudstones form another reservoir-seal association. In both hydrocarbon systems, the stratigraphic variations provide the principal traps. The Ordos basin is characterized by a stable tectonic setting that controlled the distribution of depositional systems and the development of erosional surfaces and ultimately governed the distribution of oil and gas fields and trap types.

The three-dimensional, interwell-scale architecture of a Lower Ordovician Ellenburger coalesced, collapsed-paleocave system was constructed through the integration of ground-penetrating radar (GPR), shallow-core, and outcrop data. The data were collected near Marble Falls in central Texas over an area (800 1000 m [2600 3300 ft]) that could cover several oil-well locations (160 ac; 0.65 km2) typical of a region such as west Texas. Integration of core-based facies descriptions with GPR-reflection response identified several paleocave facies that can be recognized and mapped with GPR data alone: (1) continuous reflections image the undisturbed strata, (2) relatively continuous reflections (over tens of meters) characterized by faults and folds image the disturbed strata, and (3) chaotic reflections having little to no perceptible continuity image heterogeneous, cave-related brecciated facies recognized in core that cannot be individually resolved with the GPR data. These latter facies include the highly disturbed strata, coarse-clast chaotic breccia, fine-clast chaotic breccia, and sediment fill.The three-dimensional architecture of the coalesced, collapsed-paleocave system based on core and GPR data indicates that there are trends of brecciated bodies that are as much as 350 m (1100 ft) wide, greater than 1000 m (3300 ft) long, and tens of meters high. These brecciated bodies are coalesced, collapsed paleocaves. Between the brecciated bodies are areas of disturbed and undisturbed host rock that are jointly as much as 200 m (660 ft) wide.As a cave system is buried, many structural features form by mechanical compaction. These features include folds, sags, and faults. The folds and sags measure from a few meters to several hundred meters wide. The collapse-related faults are numerous and can have several meters of displacement. Most are normal faults, but reverse faults also occur.

The Upper Ordovician Midale field is located in the northern Williston basin in southeast Saskatchewan, Canada. Hydrocarbons are hosted mainly in the dolomite reservoirs with burrowed textures in the upper Yeoman Formation. These reservoirs are characterized by intercrystalline porosity in the dolomitized matrix, with variable amounts of vugs and fractures, and can be divided into four zones. Reservoir zones 1 and 2, typically 6–10 m (20–33 ft) thick in total, are situated in the upper part of the traps and commonly bear oil. Although the underlying zones 3 and 4 are thicker, they commonly contain only water because they are located below the spillpoint of the hydrocarbon traps.The seismic reflection of the Red River reservoirs in the Midale field is characterized by a weak- to medium-amplitude trough immediately above the positive reflection of the Winnipeg shale. Where all four zones are present, an additional peak occurs on the seismic profile above the original reservoir reflection. This additional peak, however, disappears where reservoir zones 3 and 4 pinch out. Where there is an increase in the thickness of reservoir zones 1 and 2 or amalgamation of zone 1 with zone 2, the Red River reservoirs are characterized by high-amplitude and high-frequency reflections on seismic profiles.The Ordovician oil pools in the Midale area are associated with low-relief anticline structures. These low-relief structures are interpreted as the compactional drape of Red River strata over local Precambrian basement highs. The source of hydrocarbons in the Red River reservoirs is Ordovician kukersites. A wide range of API fractions for the oils from the Midale pools suggests a mixing of low-maturity oils, sourced from local kukersite beds, and high-maturity oils that migrated over a long distance from the south. The hydrocarbon production from Red River Midale pools is characterized by the fast rise of water cut and high water output, which can be attributed to the small pool size and the fracture systems connecting oil and water zones.

Low-permeability sandstones of the Lower Silurian regional oil and gas accumulation cover about 45,000 mi2 (117,000 km2) of the Appalachian basin and may contain as much as 30 tcf of recoverable gas resources. Major reservoirs consist of the "Clinton" sandstone and Medina Group sandstones. The stratigraphically equivalent Tuscarora Sandstone increases the area of the Lower Silurian regional accumulation (LSRA) by another 30,000 mi2 (78,000 km2). Approximately 8.7 tcf of gas and 400 million bbl of oil have been produced from the Clinton/Medina reservoirs since 1880.The eastern predominantly gas-bearing part of the LSRA is a basin-center gas accumulation, whereas the western part is a conventional oil and gas accumulation with hybrid features of a basin-center accumulation. The basin-center accumulations have pervasive gas saturation, water near irreducible saturation, and generally low fluid pressures. In contrast, the hybrid-conventional accumulations have less-pervasive oil and gas saturation, higher mobile-water saturation, and both normal and abnormally low fluid pressures.High mobile-water saturation in the hybrid-conventional reservoirs form the updip trap for the basin-center gas creating a broad transition zone, tens of miles wide, that has characteristics of both end-member accumulation types. Although the Tuscarora Sandstone part of the basin-center gas accumulation is pervasively saturated with gas, most of its constituent sandstone beds have low porosity and permeability. Commercial gas fields in the Tuscarora Sandstone are trapped in naturally fractured, faulted anticlines.The origin of the LSRA includes (1) generation of oil and gas from Ordovician black shales, (2) vertical migration through an overlying 1000-ft (305-m)-thick Ordovician shale; (3) abnormally high fluid pressure created by oil-to-gas transformation; (4) updip displacement of mobile pore water by overpressured gas; (5) entrapment of pervasive gas in the basin center; (6) postorogenic uplift and erosion, causing gas leakage and a marked reduction in fluid pressure.Most future natural-gas production in the Clinton/Medina sandstones is anticipated to come from the basin-center accumulation. The Tuscarora Sandstone has additional gas resources but typically low reservoir porosity and permeability, and the likelihood of low-energy (in British thermal units) gas reduce the incentive to explore for it.

The Knox Dolomite (Cambrian-Ordovician) in Ohio consists of a mixed carbonate-siliciclastic sequence deposited in a tidal-flat to shallow-marine environment along a broad continental shelf. Knox hydrocarbon production occurs in porous sandstone and dolomite reservoirs in the Copper Ridge dolomite, Rose Run sandstone, and Beekmantown dolomite. In Ohio, historical Knox exploration and development have been focused on paleogeomorphic traps within the prolific Morrow Consolidated field, and more recently, within and adjacent to the Rose Run subcrop. Although these paleogeomorphic traps have yielded significant Knox production, structural and stratigraphic traps are being largely ignored. Three Knox-producing pools demonstrate structural and stratigraphic traps: the Birmingham-Erie pool in southeastern Erie and southwestern Lorain counties, the South Canaan pool in northern Wayne County, and the East Randolph pool in south-central Portage County. Enhanced porosity and permeability from fractures, as evident in the East Randolph pool, are also an underexplored mechanism for Knox hydrocarbon accumulation. An estimated 800 bcf of gas from undiscovered Knox resources makes the Knox one of the most attractive plays in the Appalachian basin.

After 35 years of exploration, creaming of the conventional plays in Oman is nearly complete, and consequently, the search has commenced for new, less obvious plays. Many of the new opportunities occur beyond the known hydrocarbon provinces and are considered to have significant charge risks. To define these risks, extensive basin modeling studies have been conducted in recent years. Modeling and empirical data show that Mesozoic and Cenozoic kitchen areas are restricted to western north Oman, the only areas currently buried at their maximum temperature. Large parts of north and central Oman depend on lateral migration from these kitchens for their charge. Progressive uplift of the east flank and basin inversion since the middle Paleozoic provides favorable conditions for long-distance migration in the post-Carboniferous interval. In central Oman, geochemical tracer molecules (benzocarbazoles) suggest that a north-south-trending, reactivated basement grain has funneled charge up to 300 km southeastward. Charge risks increase in the deeper sequence, in which eastward migrating hydrocarbons have to traverse the Ghaba salt basin, a pronounced syncline at depths greater than 3 km. The south Oman salt basin is currently cool because of shallow depths and hydrodynamic fluid-flow activity. The shallow post-Cambrian reservoirs rely on storage of early (Cambrian-Ordovician) charge by the Ara salt (Cambrian) sequence, followed by release of hydrocarbons as the salt edge retreats through time. Basin modeling has outlined the extent of the different petroleum systems and provided us with risk maps to guide our next exploration phase. It has revitalized some of the mature plays, for instance the Gharif Formation, where oil exploration is now focused along Late Cretaceous and Tertiary migration paths. Deeper sections are envisaged to have significant scope for gas.

Quantitative analysis of depth-converted reflection times defines long-term differential motion across individual structures in a central Appalachian interior basin known as the Rome trough. Differential motion decreases exponentially with time. Rotation about a hinge defining the trough's west margin reached approximately 37% of total displacement in about 63-78 million years (m.y.). Displacement across the trough's faulted east margin occurred more rapidly and reached 37% of the total in 13-51 m.y. A major fault in the interior of the trough developed rapidly with 37% of total displacement reached in from 16 to 23 m.y. Longer term rotation across the west margin may be due to its participation in the overall subsidence of the craton during the Paleozoic. The time spanned by the formation of the East-Margin and Interior faults was restricted to the Cambrian in the northern part of the area, but to the south, movement along the East-Margin fault continued through the Middle Ordovician.