ALBERT

Description: 〈span〉The authors of the paper “Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin” by Cao et al. (〈span〉AAPG Bulletin〈/span〉 v. 101, no. 2, 2017, p. 〈strong〉〈a href="https://pubs.geoscienceworld.org/article.aspx?volume=101&page=39"〉39–72〈span〉〈/span〉〈/a〉〈/strong〉) have informed the editor of necessary changes to this paper.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In this study, we provide new data to understand the groundwater flow patterns in the Llanos Basin and their impact on oil biodegradation and the geothermal regimes as well as how the structural styles and anthropogenic activities impact these patterns. Previous studies suggest an active flow of groundwater and variable salinities whose spatial pattern is apparently unrelated to topographically driven groundwater flow. These observations have led to different hypotheses regarding the influence of groundwater flow on Llanos Basin geothermal gradients and oil biodegradation.In this contribution, we present data regarding the hydraulic heads, salinities, geothermal gradients, and structural styles of the Llanos Basin to propose hypotheses explaining these observations. Structural cross sections and subsurface stratigraphic correlations allow us to suggest that the pattern of flow is best explained by a correlation between groundwater flow and structural styles. A basement map of the Llanos Basin confirms that the most important factor controlling geothermal gradients is the type of basement, whereas the factor of groundwater flow appears to be of secondary importance. The evolution of the basin and the frequent absence of correlation between fresh water and the more biodegraded oils support the interpretation that biodegradation is controlled by an older flow of water that started as early as the Oligocene. Finally, mass balances suggest that the temporal scales and volumes of groundwater flow are much larger than the scales observed during the development of the oil fields.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Isthmian salt basin in the southern Gulf of Mexico can be divided into the Yucatán and Campeche subbasins, separated by a base-salt high near the nose of the Yucatán platform. Despite their proximity, these two subbasins experienced radically different histories in the period immediately following salt deposition.Portions of the Yucatán subbasin are characterized by large-scale (locally as much as 60 km [37 mi]) downdip translation of salt and suprasalt sediments during the Late Jurassic. This translation produced a major detached extensional province at the updip end of the basin, which is not compensated by observed shortening downdip. We interpret this history to be a result of unconfined seaward flow of salt and its cover during basin opening, a process mirrored on the conjugate Florida margin.The Campeche subbasin, in contrast, shows no evidence of significant Late Jurassic translation detached on salt. No large-scale extensional or contractional provinces of Mesozoic age are evident, although some minor translation did occur. We suggest that salt in the Campeche subbasin was confined at its seaward end, which prevented the seaward salt flow experienced in the Yucatán subbasin. Furthermore, salt at the seaward end of the Campeche subbasin lies 2–3 km (1–2 mi) above oceanic crust, in contrast to salt lying on crust whose top sits at or below the level of oceanic crust at the seaward ends of the Tamaulipas, Yucatán, and Florida margins. The Campeche subbasin thus appears to have been perched relative to other parts of the Gulf of Mexico.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Fluvial-dominated deltas are common along modern and ancient coasts and act as important hydrocarbon reservoirs. In this paper, an integration of high-resolution three-dimensional seismic, well log, and core data are employed to investigate the seismic geomorphology, depositional facies, reservoir types, and controlling factors of fluvial-dominated delta deposition in the lower segment of the Minghuazheng Formation (N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉), Bohai Bay Basin, China. Three typical seismic facies and seismic geomorphologic units are identified. Seismic facies 1 displays discrete high-amplitude reflection and a distinct U-shape incision. In plan form, this seismic facies shows a linear, dendritic, and sinuous morphology with high root-mean-square amplitudes. Seismic facies 2 occurs interspersed with seismic facies 1 and shows low-frequency and low-amplitude reflection. Seismic facies 3 shows a continuous high-amplitude reflection and uniform sheet-like morphology covering more than 10 km〈sup〉2〈/sup〉 (〉3.86 mi〈sup〉2〈/sup〉). The N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉 was primarily deposited in the upper delta plain, lower delta plain, and delta front environments and is dominated by three major facies types: (1) distributary channel (seismic facies 1), (2) interdistributary bay (seismic facies 2), and (3) sheet sand (seismic facies 3). Among them, the distributary channel sandstones and sheet sandstones are the major reservoirs in the N〈sub〉1〈/sub〉m〈sub〉L〈/sub〉. Fluvial processes and lake level cycles were important factors in the development and distribution of reservoirs and traps in fluvial-dominated delta systems. Integration of the seismic geomorphology and a modern geomorphology investigation provide an effective way to predict the sandstone reservoirs and traps in fluvial-dominated delta systems.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Progradation of deltaic systems that reach the shelf edge is considered a primary mechanism to deliver sand to continental margins. Sediment bypass processes can dominate the outer shelf to upper slope transition, causing poor preservation of reservoir quality sandstones. Turbidites can carry the bulk of the coarse fraction downdip where a thicker sand pile can be deposited once the channel-to-lobe transition is reached. Predicting this lateral and vertical variability along the slope is challenging. This configuration can be further complicated when mixed siliciclastic–carbonate systems are present. The Roseway–Missisauga case study from Nova Scotia is used here to explore potential implications associated with the development of deep-water turbidites that are time equivalent to outer-shelf mixed siliciclastic–carbonate units. Two scenarios are possible: (1) The carbonate factory is dominant, and the development of carbonate reefs and pinnacles on the outer shelf prevents the passage of siliciclastic systems beyond the shelf break; in this case, the siliciclastic component is sequestered within the inner-outer shelf. (2) Favorable conditions for carbonate production gradually deteriorate by the activation of fluviodeltaic systems that prograde outboard reaching the slope region. In this last scenario, low relief and lateral discontinuous carbonate shoals are ubiquitous in the outer shelf representing the last outboard remnants of the carbonate factory. Shelf-edge deltas circumvent or breach these carbonate shoals, establishing sedimentary pathways on the shelf-break region that connect with deep-water turbidites. Observations suggest that this last scenario is the most likely in this part of the Scotian margin during the Late Jurassic to Early Cretaceous.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Faulted monoclinal structures incorporate folds and faults. Their displacements cause stress release of differing degrees in various areas. Furthermore, the faults commonly extend to the deep strata, which may lead to the flow of boiling inclusions and localized thermal stresses. A complex distribution of in situ stress appears in such areas, which makes it challenging to drill wellbores. In this study, we first analyzed the geological structure and the factors influencing in situ stresses of a faulted monoclinal structure in southwest Qaidam Basin. Second, based on Huang’s model, a mathematical model for calculating the horizontal principal stress of the faulted monoclinal structure was developed considering the stress release from fault and fold displacements and the outflow from boiling inclusions. Third, the magnitudes of the horizontal principal stresses of the study area were obtained using this new mathematical model, and the predicted values had an average error of 2.63% according to a comparison with the results of the hydraulic fracturing field measurements. Fourth, an in situ stress distribution in this area was established by combining the horizontal principal stresses’ magnitudes and the maximum horizontal principal stress direction. Finally, based on the in situ stress distribution of the study area, the mud density and trajectory for drilling the third stage of well Z207 were determined. The field application revealed that the design parameters met the engineering requirements satisfactorily, which indicates that this mathematical model can predict the horizontal principal stress of the faulted monoclinal structure in southwest Qaidam Basin.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Following recent hydrocarbon exploration activity, a new study has been carried out with the goal of defining the high-resolution biochronologic sequence stratigraphy of the Oligocene section in the offshore Nile Delta. A total of 98 samples were selected from 2 wells: Burullus 1 Memphis and Petrobel 1 Habbar. The study is based on a high-resolution microfossil biochronology including benthic and planktonic foraminifera and nannofossils as well as facies analysis and wire-line log calibration to investigate the evolution of Oligocene gas-bearing sequences in the southeastern Mediterranean region. The planktonic–benthic ratio, foraminiferal diversity, and upper depth limit of benthic foraminiferal taxa as well as the abundance of calcareous nannoplankton help in interpreting the depositional paleoenvironments of the Oligocene succession as fluvial, shallow-marine, middle- to outer-shelf, and bathyal domains. Six sequences were identified, three of which are lower Oligocene (Rupelian) (RuSeq1, RuSeq2, and RuSeq3), and the others are upper Oligocene (Chattian) (ChSeq4, ChSeq5, and ChSeq6). The sequence boundaries and flooding surfaces were correlated with the global eustatic sea-level models. Three major breaks—Eocene–Oligocene, lower–upper Oligocene, and upper Oligocene–lower Miocene boundaries—with intraformational breaks were well defined.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Woodford Shale is anecdotally assumed to be the major source of oil for plays in the Anadarko Basin, including the stacked oil and condensate play in the southcentral Oklahoma oil province (SCOOP). However, there is little published geochemical work to confirm this assumption. This study set out to identify a characteristic geochemical fingerprint for the Goddard Formation, another potential source rock in the SCOOP, to determine if the Goddard is contributing to oil accumulations within the SCOOP. The Upper Mississippian Goddard Formation has been a target for unconventional production in SCOOP since 2012. Published geochemical interpretations for the Goddard Formation are still limited, and this study represents the first detailed oil–source rock correlation for the Goddard in the SCOOP area.The most characteristic geochemical signature of the Goddard extracts is a predominance of tricyclic terpanes relative to the hopanes in the mass-to-charge ratio 191 chromatogram, possibly related to enrichment via thermal stress or a unique source signature. Additional distinctive signatures were also identified for the triaromatic steroid hydrocarbons, sesquiterpenoids, and steranes. The biomarker fingerprints of SCOOP oils are nearly identical with those of the Goddard extracts in this study. Oils in the SCOOP, therefore, appear to originate from a Mississippian source, such as the Goddard rather than the Woodford. This observation demonstrates the value of oil–source rock correlation studies and suggests that there may be effective source rocks in the Anadarko Basin that have been overlooked in the past and should be re-evaluated in detail.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉An integrated analysis of the petrographic characteristics and types and distribution of diagenetic alteration in the upper Paleozoic Benxi–Taiyuan, Shanxi, and Xiashihezi Formations provides insights into the controlling factors on variations in porosity and permeability in tight sandstones (85% of the sandstone samples display porosity values 〈10% and 90% of the samples exhibit permeability 〈1 md).Diagenetic alteration includes mesogenetic compaction, cementation by dolomite, ankerite, and quartz, dissolution of feldspar, and illitization of smectite. Eodiagenesis includes compaction, development of smectite, cementation by pore-filling quartz and disordered kaolinite, and precipitation of calcite and Fe-calcite. Chlorite and quartz preserve primary pores against damage, whereas kaolinite, illite–smectite (I/S) mixed layer, and illite significantly diminish reservoir quality via permeability reduction. Chlorite and I/S content decrease abruptly as depth increases, whereas the kaolinite content remains elevated at depth because of the complete destruction of K-feldspar. The transformation from smectite to illite provides silica ions for the widely distributed quartz overgrowths. As the depositional environment transformed from fluvial (Xiashihezi) to deltaic (Shanxi) and to epicontinental (Taiyuan and Benxi), the dissolution effect increased monotonically. Feldspar dissolution is dominant in the Shanxi Formation, whereas the Benxi and Taiyuan Formations commonly contain quartz dissolution pores. The Taiyuan Formation has markedly higher porosities than in the overlying and underlying formations, caused by strong dissolution and high silica content. The decrease in porosity in the Benxi Formation results from the extensive formation of clay minerals caused by high frequency transgressions in a transitional environment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Fractal analysis was performed on carbonate core plug samples from the Ordovician Majiagou carbonate reservoirs in the Ordos Basin using mercury intrusion capillary pressure (MICP), nuclear magnetic resonance (NMR), and the x-ray computed tomography (CT) measurements to improve our understanding of the pore structure characteristics. The relationships between pore structure parameters and the fractal dimensions were investigated. The pore systems are dominated by secondary intercrystalline pores and enlarged dissolution pores as well as microfractures. The fractal curves from MICP analysis break into two segments at the Swanson’s parameter. The small pore-throat systems can be described by the fractal theory, whereas pores connected by relatively large throats (greater than the pore-throat radius at the Pittman’s hyperbola’s apex) are not cylindrical in shape, cannot be described by a capillary tube model, and tend to have apparent fractal dimensions larger than 3.0. The fact that the entirety of the capillary curve cannot be fit by a single fractal dimension implies that there are multiple pore systems present with different fractal dimensions. The CT analysis shows that the pores are dispersed in the three-dimensional spaces mainly with elliptical shapes. The NMR measurements are sensitive to pore-body size and MICP probes pore-throat dimensions, the latter being complementary to the pore-body–size distribution. None of the CT, MICP, and NMR techniques provide “right” or “wrong” answers to the pore-throat systems, but they probe different aspects of the pore systems. This study assumes the pore shapes to be spherical in general, and then the fractal dimension is calculated from the NMR transverse relaxation time (〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉) spectrum. The fractal dimensions of all the samples are calculated, and the accuracy of the fractal model is verified by the high regression coefficients. Almost all the pore systems can be described by fractal theory, and the fractal dimensions are strongly correlated with the 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 values separating the immovable fluid and the free fluid. Microfractures may bias 〈span〉T〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 toward larger values, making it hard to derive fractal dimensions from NMR measurements. The coexistence of small pores (pore radius 〈 10 μm) and large pores (〉50 μm) results in a heterogeneous pore distribution and a high fractal dimension. Reservoir quality increases with the complexity degree of the microscopic pore structure. Conversely, samples that are dominated by small pore systems tend to have a lower fractal dimension and a less complex pore structure.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Our field study examines two sites revealing the processes responsible for fault surface development and fault rock juxtaposition along normal faults in porous-sandstone–dominated formations. At the first site, we show that a cluster of cataclastic deformation bands made in an initially poorly consolidated sandstone localizes overprinting of a fault slip surface and brecciation during a subsequent tectonic episode, after a significant diagenesis of the formation induced by burial. Because the permeability of the clusters ranges between 6 × 10〈sup〉0〈/sup〉 and less than 5 × 10〈sup〉−1〈/sup〉 md and because the breccia was highly dilatant, we deduce that the fault behaved as a baffle for cross-fault fluid flow at an early age of the formation and as a conduit after significant diagenetic evolution and subsequent fault surface development. At the second site, we show that the presence of clay-rich layers as thin as 80 cm (31 in.) are responsible for the initiation of a major fault slip surface in the underlying and overlying sandstone. The propagation of the fault prevents further cataclastic deformation and cluster development in these sandstones. Fault displacement juxtaposes fault surfaces, clusters of cataclastic deformation bands, clay-rich gouges, and different sedimentary units. Because both fault rocks have low permeability, their spatial juxtaposition provides a continuous baffle for cross-fault fluid flow. Our study shows that fault surface localization is related to an increase in the contrast of mechanical behavior between the cluster and the adjacent material (diagenetic hardening of the cluster or softening of the clay-rich gouge). Lithological contrasts and diagenesis are favorable conditions for localizing faulting and fault rock juxtaposition, allowing significant three-dimensional anisotropy of permeability during and/or after deformation. These processes must, therefore, be considered for fault-seal analyses in sandstone reservoirs.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Pore pressure identification in mudrocks largely relies on indirect methods, including analyses of sonic velocity data. The magnitude of pore pressure changes that can be resolved from such data depends on the impact of fluid pressures on well log responses and on the velocity responses to lithological variations that could be mistaken for indications of pore pressure changes.Analysis of relationships between sonic velocity, mineralogy, and porosity from 11 North Sea wells demonstrated porosity variations of up to 5% from the mean value in mudrocks at any given depth between 1 and 3.5 km (3300–11,500 ft). Comparisons of these wells with seven wells from the Norwegian Sea demonstrated that the sonic velocity and density variations are influenced by the content of silica with a biogenic origin, but that they can otherwise not, in general, be related to mineralogy and pore pressure variations. The sonic velocity deviations from the mean value are of the same magnitude as those that would be caused by porosity changes of ±8% in mudrocks of uniform lithology. Furthermore, the deviations are not significantly reduced when the velocity data are compensated for changes in density (porosity).Detection limits for mechanically compacting mudrocks that are at their maximum effective stress are equivalent to static mud density changes of 0.1–0.15 g/cm〈sup〉3〈/sup〉. These numbers apply to mudrocks with similar lithological variability to those analyzed in our data set but should be much higher when significant amounts of silica with a biogenic origin are present. The impact of effective stress changes on the sonic velocities of chemically compacting as well as of mechanically unloading rocks is much less because small or no porosity changes follow from the effective stress changes in such cases. The velocity responses for mechanically unloading and stress-insensitive chemical compaction can only be identified from four-dimensional (time-lapse) seismic data unless the rocks are close to the fracturing limit. These observations imply that reasonably accurate velocity-based pore pressure identification in North Sea mudrocks requires a knowledge of local mudrock heterogeneity and compaction that cannot easily be obtained. As a result, sonic velocity data should be treated with considerable caution in pore pressure evaluation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Rock fabrics have long been recognized as a key variable influencing unconventional reservoir properties, and yet, petrofabric analysis is rarely incorporated in reservoir characterization in a quantitative and scalable manner. This work introduces anisotropy of magnetic susceptibility (AMS) coupled with handheld x-ray fluorescence to define the origin of petrofabrics in the Wolfcamp shale and examine their relationship with total organic carbon (〈span〉TOC〈/span〉) and oil saturation indices (〈span〉OSI〈/span〉). Standard paleomagnetic plugs were drilled from three vertical cores spanning the entire Wolfcamp shale in the Midland Basin, west Texas. Low-temperature magnetic experiments suggest paramagnetic minerals contribute between 93.4% and 98.6% to the low-field bulk magnetic susceptibility (〈span〉k〈/span〉〈sub〉〈span〉lf〈/span〉〈/sub〉) across all lithotypes. Scanning electron microscopy revealed frequent occurrences of paramagnetic minerals such as chlorite, illite, ferroan dolomite, marcasite, and pyrite. The Fe-rich clays such as chlorite carry the AMS signal in mudrocks with a minor contribution from ferroan dolomite. Conversely, ferroan dolomite carries the AMS signal in most carbonate facies with a minor influence from Fe-rich clays. The degree of magnetic anisotropy (〈span〉Pj〈/span〉) and shape factor (〈span〉T〈/span〉) in mudrocks are compositionally dependent and respond to changes in both clay and framework grain concentration. For carbonate facies, 〈span〉Pj〈/span〉 and 〈span〉T〈/span〉 vary widely because of changes in depositional facies and the concentration of ferroan dolomite.The 〈span〉TOC〈/span〉 correlates well with 〈span〉Pj〈/span〉 and strongly oblate magnetic fabrics. This relationship likely stems from the adsorption of organic matter (OM) to clays during deposition and may indicate that organoclay composites were responsible for delivering OM to the Midland Basin. Elevated 〈span〉OSI〈/span〉 are fabric selective, favoring low 〈span〉Pj〈/span〉 and 〈span〉T〈/span〉 fabrics, suggesting that such fabrics facilitate hydrocarbon migration more so than high 〈span〉Pj〈/span〉 and 〈span〉T〈/span〉 fabrics. Fuzzy c-means clustering provides a framework to describe AMS and geochemical transitions at the core scale and could serve as a tool to map barriers and pathways to hydrocarbon migration.Finally, Ti–Nb and 〈span〉k〈/span〉〈sub〉〈span〉lf〈/span〉〈/sub〉 data point to a mafic provenance lithotype and suggest layered intrusive complexes in the Central Basin uplift were exposed and eroded during deposition of the Wolfcamp shale. Mafic source rocks probably increased supply of micronutrients such as dissolved iron and may have enhanced productivity in the Midland Basin.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Zhang 22 well was drilled in the Ordos Basin, penetrating the Chang 7 Member of the Triassic Yanchang Formation, which, cumulatively, has more than 80 m (〉260 ft) of black organic-rich shale of oil window maturity. Using 76 samples collected every 1 m (3 ft) from the well, the effects of stratigraphic fractionation and petroleum expulsion within five intervals of the Chang 7 shale were qualitatively and quantitatively documented. The organic-rich intervals 1, 2, and 5, having an average total organic carbon (〈span〉TOC〈/span〉) of 6.79 wt. % and pyrolyzable hydrocarbon potential of 9.40 mg/g rock (i.e., the amount of hydrocarbons generated by pyrolysis between 300°C and 650°C [〈span〉S2〈/span〉]), are defined as “generative units” in the Chang 7 shale system, compared to the “in-source reservoirs” or “sweet spots” (i.e., the third and fourth intervals), which contain a lower average 〈span〉TOC〈/span〉 of 4.19 wt. % and an average 〈span〉S〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 value of 7.17 mg/g rock, but the highest amount of free oil (average total oil of 7.35 mg/g rock). Geochemical and molecular compositions display distinctive differences between samples from these source and reservoir groupings. For example, bitumens from the generative units proportionally possess lower saturated hydrocarbons (56%–66%) than those from the in-source reservoirs (up to 81%). The proportions of aromatic and polar compounds in the generative units are accordingly higher than in their counterpart. The individual molecular weight distribution of sample extracts displays more light-end moieties being enriched in the generative units. By applying the compositional mass balance calculation, the overall and compound-specific expulsion efficiencies in the in-source reservoirs are abnormally negative compared to the positive values in the generative intervals. This finding, in conjunction with the effects of the preferential retention of aliphatic hydrocarbons and the differential expulsion of light molecular weight compounds in the in-source reservoirs, indicates a short-distance intrasource migration of generated petroleum into the sweet-spot intervals (intervals 3 and 4) from the overlying units (intervals 1 and 2) and the underlying interval 5. Furthermore, when quantifying the total amount of retained petroleum in the shale system, an amended assessment has been introduced to overcome the systematic misestimations if only unextracted values for the amount of thermally extractable hydrocarbons volatilized at 300°C (mg HC/g rock) were considered. Thus, the oil crossover effect, temperature at which the rate of 〈span〉S〈/span〉〈sub〉〈span〉2〈/span〉〈/sub〉 generation is at maximum shift phenomenon, and the hydrogen index being shifted to higher values after extraction all account for identifying intervals 3 and 4 as the in-source reservoirs. In this study, we have not only identified a set of promising in-source targets for shale oil exploration and production, but we also presented the chemical and molecular composition for these shale oils. We have additionally speculated for the intrasource migration model and further discussed the different expulsion efficiencies in the shale system upon the compositional mass balance calculation as well as the stratigraphic fractionation on differentiating the chemical compositions during migration. The improved oil quality by fractionation, the extra storage potential derived from microfossil quartz, the weak adsorptive affinity of oil to organic matter, and the good shale susceptibility to hydraulic fracturing all give a promising prospective for exploring and producing shale oil from the Chang 7 shale system in the Ordos Basin.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Hyperspectral systems that image drill core can capture detail mineralogical information at the millimeter scale and thus have the potential to enable investigators to characterize shale composition and heterogeneity, complementing the direct chemical and x-ray diffraction analysis of core samples and guiding detailed sampling. This method provides insight into petrophysical and geomechanical properties because these properties are significantly correlated to rock composition. We tested this approach on a continuous long core from the shale sequence of the Horn River Group in the Horn River Basin, British Columbia, sampled at a spacing of 1 m (40 in.) and analyzed for geochemical composition. These data enable the calibration of spectral imagery to rock composition and specifically predict total organic carbon (TOC) and the abundance of SiO〈sub〉2〈/sub〉, Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, K〈sub〉2〈/sub〉O, and CaO. We then imaged nine samples from the Woodford Shale from the Permian Basin, Texas, for a blind test to assess the predictive models. The models were then used to predict TOC and geochemical data over detailed imagery of 300 m (984 ft) of Horn River Group shale core and portray their spatial variability downhole as images and profiles. In its simplest form, hyperspectral imagery can be enhanced to highlight fabric in shale core that otherwise is difficult to visualize because of low brightness. In addition, we show that spectral imagery of shale can also be processed to either convey mineralogical (quartz, clay, and carbonate) or geochemical information. The resulting views can readily be used to guide the selection of samples and may provide tools for scaling reservoir properties from individual plugs to reservoir volumes.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Considerable attention has been directed to the Devonian Horn River Formation in western Canada with respect to geochemical evaluation of gas-generation and storage potential. Because organic geochemical analyses are not always useful for characterizing the type and amount of original organic matter, we surmise the original kerogen type and original hydrogen index (HIo) and subsequently estimate a reliable original total organic carbon (TOCo) based on a combination of inorganic and organic geochemical data. Productivity (SiO〈sub〉2〈/sub〉 and Ba) and terrestrial input (Al〈sub〉2〈/sub〉O〈sub〉3〈/sub〉, Hf, Nb, and Zr) proxies are used to estimate original kerogen types, which suggest that the Evie and Muskwa Members formed under conditions of high productivity and minor terrestrial input. These members also formed under reducing conditions, as indicated by the redox proxies (Mo, U, and Th/U). Under such conditions, primarily type II kerogen was preserved.By considering the fraction of biogenic silica, the estimated HIo values (400–500 mg hydrocarbon/g total organic carbon [TOC]) for the middle Otter Park Member are lower than that for Evie and Muskwa Members and higher than the upper and lower Otter Park Member. The stronger correlation between TOCo and trace elements suggests that HIo is useful for reconstructing the coherent variation in TOCo. Based on the original kerogen type and TOCo, the gas-generation and storage potentials of the Evie, middle Otter Park, and Muskwa Members are higher than those of other members. The source-rock potential is excellent for the Evie Member with an approximately 75% difference between TOCo and measured present-day TOC.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The global Precambrian–Cambrian system includes an important series of hydrocarbon-bearing strata. However, because rocks of this age are typically deeply buried, few petroleum exploration breakthroughs have been made, and the presence of source rocks remains somewhat controversial. Recently, commercial condensate and gas were discovered from the deep (∼6900 m [∼22,600 ft]) Zhongshen 1C (ZS1C) exploratory well drilled in the Tazhong uplift of the Tarim Basin, China, leading to renewed interest in the development of Cambrian source rocks in the basin. On the basis of outcrop reconnaissance and sample testing from around the Tarim Basin, we show that a set of high-quality source rocks were developed within the lower Cambrian Yuertusi Formation (Є〈sub〉1〈/sub〉y), at the base of the lower Cambrian. These rocks are black shales and typically have a total organic carbon content between 2% and 6% but extending as high as 17% in selected regions. This marine sequence is 10–15 m (33–49 ft) thick in some outcrops along the margins of the basin. Seismic data indicate that these high-quality source rocks may cover an area as large as 260,000 km〈sup〉2〈/sup〉 (100,000 mi〈sup〉2〈/sup〉). Their main organic parent material was benthic multicellular algae. On the basis of high-temperature thermal simulations conducted on these source rocks, we show that the gas composition and carbon isotopes from the ZS1C well are similar to the products generated at a thermal evolution stage corresponding to a vitrinite reflectance of between 2.2% and 2.5%. Late-stage natural gas accumulated within these rocks over time. The δ〈sup〉34〈/sup〉S correlation of organic sulfur compounds in the condensate with Cambrian sulfates provides further evidence for a Є〈sub〉1〈/sub〉y source rock origin of the ZS1C condensate and gas. The Cambrian dolomites in association with a salt seal exhibit favorable geological conditions for large-scale hydrocarbon accumulation. A new set of deep exploration strata can, therefore, be developed, guiding future deep Cambrian hydrocarbon exploration in the Tarim Basin.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The effects of reservoir heterogeneity on the development of submarine channel fields are still poorly understood because of lack of direct evidence for fluid flow. This study uses integrated well logs and three-dimensional seismic data from the Niger Delta Basin to characterize the previously undocumented spatial distribution of shale units and permeability contrasts within a submarine channel system. Combining these data with four-dimensional (4-D) seismic data facilitates the exploration of the controls of reservoir heterogeneity on fluid flow during development. The results show that the studied submarine channel system consists of multiple vertically stacked channel complex sets (CCSs) from CCS1 (oldest) to CCS5 (youngest), which are separated from each other by continuous shale barriers. The CCS2–CCS4, which are located in the stratigraphic middle of the channel system, are the main development layers because of their higher permeabilities and lower permeability contrasts. The 4-D seismic responses validate that the presence of shale barriers between vertically adjacent CCSs can hinder the flow of fluids between CCSs. Fluid flow between vertically adjacent CCSs barely occurs except in localized erosional locations where the sand fills of different CCSs are vertically connected. Each CCS consists of multiple individual channels, which can be separated by inclined shale baffles if they laterally migrate in one direction. As the 4-D seismic responses demonstrate, such inclined shale baffles can hinder fluid flow between adjacent individual channels and help to form multiple narrow flow paths in map view. The absence of inclined shale baffles also produces prominent permeability contrasts within each CCS, which are characterized by relatively high–permeability zones that are parallel to the channel axis. Comparison of this permeability distribution and the 4-D seismic responses shows that injected water preferentially sweeps along relatively high–permeability zones, which can help to form single wide flow paths with higher sweep efficiency or single narrow flow paths with lower sweep efficiency.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Source-to-sink analyses show that northern Gulf of Mexico (GOM) Wilcox Group siliciclastic deep-water systems are linked to transport of sediments from the Laramide tectonic belt into the deep basin. Less is known, however, about southern GOM sedimentation. New drilling and discoveries in the Mexican deep water have generated considerable interest since the opening of Mexico to international exploration. To investigate Paleogene deposition in Mexico’s offshore areas, a three-phased approach was employed: (1) seismic mapping of deep-water depocenters, (2) regional stratigraphic analysis of potential basin entry points, and (3) prediction of submarine-fan dimensions using empirical scaling relationships. Isochore and structural mapping of the Wilcox depocenters used available well and seismic data. Potential basin entry points were identified by evaluation of Wilcox fluvial–deltaic systems and tectonic elements. Empirical scaling relationships previously established between fluvial and deep-water segments provide first-order predictions of submarine-fan dimensions.Paleogene Wilcox source-to-sink systems of the greater GOM basin change north to south as a function of varied tectonics and sedimentary accommodation. The United States sector was a passive margin: continental-scale drainage systems fed a broad, gently dipping shelf. By contrast, the southern GOM basin was a tectonically active margin: smaller-scale fluvial systems sourced from the Hidalgoan uplands flowed directly into foreland basins located on the slope. Results presented here indicate that several systems rimming the southern GOM were able to effectively transfer sediment from the mountain belt into the basin. Regional observations and semiquantitative predictions of fan dimensions provide a context for future detailed work based on new well and seismic information.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Sequence stratigraphy based on wire-line logs, cores, and outcrops is entering its fourth decade of mainstream usage in industry and academia. The technique has proved to be an invaluable tool for improving stratigraphic analyses in both clastic and carbonate settings. Here we present a simple quantitative technique to support sequence stratigraphic interpretations in clastic shallow marine systems. The technique uses two pieces of data that are readily available from every subsurface field or outcrop study: (1) parasequence thickness (T) and (2) parasequence sandstone fraction (SF). The key assumptions are that parasequence thickness can be used as a proxy for accommodation at the time of deposition and parasequence sandstone fraction can be used as a proxy for sediment supply. This means that quantitative proxies for rates of accommodation development and sediment supply can be acquired from wire-line logs, cores, and outcrop data. Vertical trends in parasequence thickness divided by sandstone fraction (T/SF) approximate trends expected in systems tracts for changes in ratios of rate of accommodation development to rate of sediment supply. The technique, termed “TSF analysis,” can also be applied at lower-order sequence and composite sequence scales. It provides a quantitative and objective methodology for determining rank and order of sequence stratigraphic surfaces and units. Absolute T/SF values can be used to determine shoreline, stacked shoreline, and shelf-margin trajectories. Four case studies are presented, which demonstrate the robustness of the technique across a range of different data sets. Implications and potential future applications of TSF analyses are discussed.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Eagle Ford Formation has attracted considerable industry attention as a self-sourced unconventional shale reservoir. The productive interval in the Eagle Ford Formation is the transgressive systems tract, which contains parasequences whose lithologic content varies upward with increasing proportions of limestones. Optimum success in both exploration and production depends on the adequate characterization of fracture systems as a function of lithology. The outcrops present along US Highway 90 in Val Verde and Terrell Counties, Texas, provide considerable insight into the regional natural fracture system of the Eagle Ford Formation. Fracture-orientation analysis reveals two sets of conjugate hybrid shear fractures and two sets of regional fractures. Abutting relationships suggest that hybrid shear fractures formed first, followed by the thoroughgoing northeast-striking fracture set, and finally by a northwest-striking set, which tends to be confined to individual mechanical units. The orientation of these fractures suggests that they formed during post-Laramide stress relaxation and progressive exhumation. Spacing-frequency distribution analysis of the fracture population reveals a mature hypersaturated fracture system that likely formed at depth by overburden load and/or fluid pressure near maximum burial. Our results indicate that the Eagle Ford Formation displays a well-developed fracture network regionally distributed in the Val Verde Basin, and likely present in the productive Eagle Ford play. These observations provide evidence for pathways and vertical connectivity for potential fluid pathways throughout the Eagle Ford Formation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉We document a novel approach to balanced three-dimensional structural restoration based on an adaptation of the GeoChron model. Conventionally, the GeoChron model defines a transformation of a geological model to a flattened space (U-V-T), with paleogeographic coordinates defined by the horizontal axes (U-V) and geologic time on the vertical axis (T). In our new balanced structural restoration scheme, the complete stratigraphy is restored using a transformation constrained only by the datum horizon. Scaling the vertical “T” axis to depth in a manner that preserves volume or layer thickness results in a geometric restoration that approximately minimizes strain globally. This restoration provides a geometrically plausible representation of the geologic structure at the time when the datum horizon was deposited. Restoration is independent of mechanical rock properties and is thus most applicable to regions in which mechanical rock properties are approximately homogeneous. Restoration kinematics may be constrained by growth strata if present.We validate the method with kinematic forward models and a laboratory sandbox model and apply it to two natural examples to demonstrate its capabilities for model validation and palinspastic restoration.We identify four criteria for assessing the validity of a structural model using the results of restoration: (1) anomalous fault throw, (2) timing of fault activity, (3) fault compliance, and (4) restoration strain. Analysis of the sandbox results and limitations of volume conservation derived from uncertainties in compaction states suggest accuracy of the method to be in the 5%–20% range.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The pore structure of shale has a significant effect on hydrocarbon migration and the long-term gas supply of shale gas wells. The present study investigates the spontaneous imbibition characteristics to evaluate the pore connectivity and wettability of marine Longmaxi shale samples from the southeastern Chongqing area and continental Yanchang shale samples from the Ordos Basin. The pore-size distribution obtained from N〈sub〉2〈/sub〉 adsorption and mercury intrusion porosimetry, field emission–scanning electron microscopy, and focused ion beam–scanning electron microscopy photos are used to interpret the imbibition behaviors. Our results show that the difference in dominant pore type between marine and continental samples, which is dominated by thermal maturity, controls on their imbibition behaviors as well as their wettability. Organic matter (OM) pores within Yanchang samples are poorly developed because of their low thermal maturity, and a large amount of water-wet inorganic pores are preserved in these samples because of relatively weak compaction. Oil-wet OM pores are well developed in Longmaxi samples with higher thermal maturity, and inorganic pores have been largely eliminated because of strong compaction. The low pore connectivity to water for both the Longmaxi and Yanchang samples is indicated by the low water imbibition slopes. Furthermore, the more oil-wet property of the Longmaxi samples and more water-wet characteristics of the Yanchang samples are obtained by comparing the directional water/oil imbibition slopes. In addition, the positive meaning of quartz in the protection of pore spaces is found in both the Longmaxi and the Yanchang samples used in this study.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Multiple natural gas fields have been discovered in the Baiyun depression and the adjoining Panyu lower uplift in the Pearl River Mouth Basin, northern South China Sea. The natural gases are associated with condensate and are characterized by relatively heavy carbon isotopes, with methane and ethane δ〈sup〉13〈/sup〉C values ranging from –44.2‰ to –33.6‰ and –30.0‰ to –25.4‰, respectively. Nearly all methane and ethane are derived from oil-prone type II kerogen in the Wenchang Formation source rock, whereas the heavy hydrocarbon gases (propane, butanes, and pentanes) are derived from both the Wenchang and Enping (type III kerogen) Formations, based on an integrated comparison of carbon isotopic compositions of the natural gases, typical type I/II and type III kerogen-derived gases, and the Enping and Wenchang kerogens. The gases from the eastern parts of the Baiyun depression and the Panyu lower uplift mainly originate from secondary oil cracking and primary kerogen cracking, respectively. The gases from the northern slope of the Baiyun depression are a mixture of oil-cracking and kerogen-cracking gases. Both oil-cracking and kerogen-cracking gases were mainly generated from the Wenchang Formation source rock in the maturity range of 1.5%–2.5% vitrinite reflectance, with a corresponding present-day depth range of 5400–6500 m (17,700–21,300 ft). The apparent contribution of the Wenchang Formation to the discovered gas accumulations demonstrates that it is the most important source rock in the area, instead of the Enping Formation. The search for more gas derived from oil cracking will be the next natural gas exploration direction in the Baiyun depression.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The northern Appalachian Basin depocenter of Pennsylvania represents one of the most economically important hydrocarbon-producing areas in the United States, yet the thermal conditions that promoted hydrocarbon formation within the basin are only marginally constrained. The prolific coal, oil, and natural gas fields of Pennsylvania are the direct result of thermal maturation of once deeply buried organic-rich sediment. Understanding how, why, and where thermal maturation occurred in the Appalachian Basin requires high-quality heat flow and thermal conductivity measurements, as well as paleotemperature estimates and basin modeling. To improve the understanding of heat flow, we present, to our knowledge, the first direct measurements of (1) thermal conductivity on Devonian core samples and (2) equilibrium temperature versus depth logs for the northern Appalachian Basin depocenter. Results from three well sites demonstrate that heat flow is conductive and nearly uniform, averaging 34 ± 2.5 mW/m〈sup〉2〈/sup〉, with an average thermal gradient of 29 ± 4°C/km. The new heat-flow measurements are significantly lower (30%–50% less) than previously published estimates that used nonequilibrium bottomhole temperature values and empirically derived thermal conductivity estimates. Our analysis indicates that previous studies correctly estimated the regional thermal gradient using bottomhole temperatures but overestimated heat flow in this region by as much as 50% because of inaccurate extrapolation of thermal conductivity. The results highlight the importance of directly measuring thermal conductivity to accurately quantify heat flow in deep sedimentary basins. Ultimately, additional paleotemperature data are necessary to improve our understanding of Appalachian Basin thermal evolution.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Shale samples of the Marcellus Shale from a well drilled in northeastern Pennsylvania were used to study diagenetic effects on the mineral and organic matter and their impact on petrophysical response. We analyzed an interval of high gamma ray and anomalously low electrical resistivity from a high thermal maturity (mean maximum vitrinite reflectance 〉 4%) part of the shale‐gas play. A suite of microanalytical techniques was used to study features of the shale down to the nanoscale and assess the level of thermal alteration of the mineral and organic phases.The samples are organic rich, with total organic carbon contents of 3–7 wt. %; the vast majority of the organic matter was identified as highly porous pyrobitumen. Matrix porosity is also present, especially within the clay aggregates and at the interface between rigid clasts and clay minerals.Mineral- and organic-based thermal maturity indices suggest that during burial the sediment had been exposed to temperatures as high as 285°C (545°F). Under these conditions, the residual, migrated organic matter assumed a partially crystalline habit as confirmed by the identification of turbostratic structures via electron microscopy imaging. Experimental dielectric measurements on organic matter–rich samples confirm that the anomalous electrical properties observed in the wire-line logs can be ascribed to the presence of an electrically conductive interconnected network of partially graphitized organic matter. The preservation of porosity suggests that this organic network can contribute not only to the electrical properties but also to the gas flow properties within the Marcellus Shale.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Understanding natural fracture networks in the subsurface is highly challenging, as direct one-dimensional borehole data are unable to reflect their spatial complexity, and three-dimensional seismic data are limited in spatial resolution to resolve individual meter-scale fractures.Here, we present a prototype workflow for automated fracture detection along horizontal scan lines using terrestrial light detection and ranging (t-LIDAR). Data are derived from a kilometer-scale Pennsylvanian (locally upper Carboniferous) reservoir outcrop analog in the Lower Saxony Basin, northwestern Germany. The workflow allows the t-LIDAR data to be integrated into conventional reservoir-modeling software for characterizing natural fracture networks with regard to orientation and spatial distribution. The analysis outlines the lateral reorientation of fractures from a west–southwest/east–northeast strike, near a normal fault with approximately 600 m (∼1970 ft) displacement, toward an east–west strike away from the fault. Fracture corridors, 10–20 m (33–66 ft) wide, are present in unfaulted rocks with an average fracture density of 3.4–3.9 m〈sup〉−1〈/sup〉 (11.2–12.8 ft〈sup〉−1〈/sup〉). A reservoir-scale digital outcrop model was constructed as a basis for data integration. The fracture detection and analysis serve as input for a stochastically modeled discrete fracture network, demonstrating the transferability of the derived data into standard hydrocarbon exploration-and-production-industry approaches.The presented t-LIDAR workflow provides a powerful tool for quantitative spatial analysis of outcrop analogs, in terms of natural fracture network characterization, and enriches classical outcrop investigation techniques. This study may contribute to a better application of outcrop analog data to naturally fractured reservoirs in the subsurface, reducing uncertainties in the characterization of this reservoir type at depth.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Using cores, well logs, and other borehole data, the results of this study show that the shallow-water lacustrine delta has its own unique depositional characteristics of the third member of Oligocene Dongying Formation (Ed〈sub〉3〈/sub〉) in the Baxian sag, Bohai Bay Basin, eastern China. During the Ed〈sub〉3〈/sub〉 stage, the rift–thermal basin subsidence transition stage, the paleoslope was divided into multilevel slopes by faults along the Wen’an slope with slope angles from approximately 0.19° to 2.02°. The paleogeographic conditions, low-discharge channel, and low accommodation controlled the sedimentary characteristics. The distributions of the shallow-water delta system were controlled by multilevel flexure slopes. The delta plain was distributed on the first- and second-level slope belts, and the delta front was distributed on the third-level slope belt. The high-sinuosity fluvial channel of the delta plain was the dominant facies in the whole shallow-water delta. Most sand was deposited in these channels along the second-level slope belt. Therefore, not enough sand was present to be transported into the lake (shallow water) to form mouth bars in the delta front. Therefore, mouth bars of the shallow-water delta front were few, and the sand beds were thin. Additionally, no more sand was available to be supplied right along to deep lake, the lacustrine basin was small, and there was insufficient accommodation and sand to develop a subaqueous fan in the delta front.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Three-dimensional reservoir modeling is an important aspect to determine the heterogeneity of organic-rich shale reservoirs, an area of study that continues to be explored and refined. A large proportion of data acquired from horizontal wells causes issues in the structural and property modeling for shale reservoirs. Since horizontal wells are designed to drill into a specific, narrow zone, their horizontal section tends to parallel or nearly parallel formation surfaces. As a result, formation surfaces have a much more complex spatial location relationship with horizontal wellbores than with vertical wellbores. The existing algorithms are not good at addressing this issue during structural modeling. The major problem of using horizontal well data in property modeling is the biased data set because their horizontal section tends to stay within a narrow zone. The property distribution feature estimated from this biased data set, as a significant, default input of geostatistical simulation algorithms, causes the constructed property models to deviate away from the real case in the subsurface. A method to infer more formation tops in pseudovertical wells according to a series of assumptions was developed to provide more constraint points for structural modeling within the areas of the horizontal well section. To use the biased database from horizontal wells, distribution function and trend model methods were developed for continuous property modeling, and percentage and probability trend models were developed for discrete property modeling. The Longmaxi–Wufeng shale in the Fuling gas field of Sichuan Basin was used as an example to express and verify these methods.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉An integrated approach to detect new areas of potential interest associated with stratigraphic traps in mature basins is presented. The study was carried out in the Middle Magdalena Valley basin, Colombia. The workflow integrates outcrop and subsurface interpretations of facies, activity of faults, and distribution of depocenters and paleocurrents and makes use of them to construct a three-dimensional exploration-scale geocellular facies model of the basin. The outcrop and well log sedimentological analysis distinguished facies associations of alluvial fan, overbank, floodplain, and channel fill, the last one constituting the reservoir rock. The seismic analysis showed that tectonic activity was coeval with the deposition of the productive units in the basin and that the activity ended earlier (before the middle Miocene) along the western margin than along the eastern margin. Paleogeographic reconstructions depict transverse and longitudinal fluvial systems, alluvial fans adjacent to the active basin margins, and floodplain facies dominating the structural highs and the southwestern depositional limit. These reconstructions provided statistical data (lateral variograms) to construct the model. The exploration-scale facies model depicts the complete structure of the basin in three dimensions and the gross distribution of the reservoir and seal rocks. The predictive capability of the model was evaluated positively, and the model was employed to detect zones of high channel fill facies probability that form bodies that are isolated or that terminate upward in pinchouts or are truncated by a fault. Our approach can prove helpful in improving general exploration workflows in similar settings.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Knowledge of in situ stress distribution is fundamental for coalbed methane production; however, it is poorly understood in the eastern Yunnan region, South China. In this study, the horizontal maximum (〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉) and minimum (〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉) principal stress and vertical stress (〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉) were systematically analyzed for the first time. The results indicated that the magnitudes of 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉, 〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉, and 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 showed positive correlations with burial depth. In general, three types of in situ stress fields were determined: (1) 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉 in shallow layers with burial depths less than approximately 600 m (∼1970 ft) below ground level (bgl), indicating a dominant strike-slip faulting stress regime; (2) in medium layers approximately 600–800 m (∼1970–2625 ft) bgl, the in situ stress state followed multiple relationships, suggesting that the in situ stress regime was transformed; and (3) 〈span〉S〈/span〉〈sub〉〈span〉v〈/span〉〈/sub〉 〉 〈span〉S〈/span〉〈sub〉〈span〉Hmax〈/span〉〈/sub〉 〉〈span〉S〈/span〉〈sub〉〈span〉hmin〈/span〉〈/sub〉 in deep layers with burial depths greater than approximately 800 m (∼2625 ft) bgl, indicating a dominant normal faulting stress regime. Coal permeabilities obtained from injection–falloff well tests showed that they were widely distributed, and no obvious relationships were found between coal permeability and effective in situ stress magnitude. In the study area, the development and orientation of previously generated natural fractures combined with the present-day in situ stress distribution controlled the permeability in coal reservoirs. Differential stress and presence of natural fractures significantly affected the geometry and pattern of hydraulic fractures. In addition, in the eastern Yunnan region, locations with relatively deep depths in vertical wells and approximately west–northwest/east–southeast-trending horizontal wells suffered high potential of borehole instability because of the high differential stress.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In carbonate rock reservoirs, spatial distribution models and elastic properties are complex because of diagenetic processes and mineralogical composition, which together directly interfere with variations in pore shape and interconnectivity. The main objective of this paper is to propose a workflow to aid in three-dimensional quantitative carbonate reservoir characterization of the Quissamã Formation (Macaé Group) in the Pampo field of the Campos Basin, offshore Brazil. Model-based seismic inversion, sequential Gaussian simulation with cokriging for porosity modeling, and truncated Gaussian simulation with trend for facies modeling were used to characterize the carbonate reservoirs. Our results show that the carbonate platform is located between the upper Aptian and lower Albian seismic surfaces. Interpretation of a new surface, called the intra-Albian, was possible via acoustic-impedance (AI) analysis. Our workflow facilitated identification of low AI, high porosity, and best facies areas in structural highs where the most productive wells have been drilled. Facies modeling suggests that intercalation of facies with high and low porosities is connected to shallowing-upward cycles. Finally, several debris facies with low AI and high porosities were identified in an area that could be targeted for new exploration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉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 〈40%) interval that was approximately 24 m (∼79 ft) thick with an average TOC value of 3.0 wt. % mainly occurs in the Ordovician Wufeng Formation (Katian and Hirnantian) and base of the Silurian Longmaxi Formation (Rhuddanian). Shales with higher TOC values commonly have a higher porosity and specific surface area. Tectonic movements may also have been very important factors that influenced the petrophysical properties of the shales. For example, a detachment layer that resulted from complex tectonic movements is extensive in the Wufeng Formation. The cracks and microcracks in the detachment layer can result in good pore connectivity. Consequently, the detachment layer can be an effective migration pathway. The Longmaxi–Wufeng shales of Sanquan Town are also compared with those of the famous Jiaoye 1 well in the Jiaoshiba shale gas field in the eastern Sichuan Basin. Although the shales in Sanquan Town have considerable shale gas generation potential, the shale gas resource potential in Sanquan Town is probably poor because the escape of shale gas may be accelerated by the detachment layer in destroyed anticlines and synclines.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The ability to accurately predict the probability of fluid migration from depth through existing wells based on known well properties, such as age and depth, would be enormously helpful in understanding how migration pathways develop and the identification of potential migration without extensive field tests. The presence of fluid pathways is an important environmental issue because such pathways allow gas, either naturally occurring methane or sequestered CO〈sub〉2〈/sub〉, to move into the atmosphere. In this paper, we explore the ability of various predictive models to forecast gas migration at existing wells in Alberta, Canada, based upon the characteristics of existing deep wells. Alberta was selected as a case study because of the availability of data in an area that has required wells to be tested for pathway development after rig release since 1995. Wells that do not demonstrate pathway development require no further testing until the well is abandoned. We show that accurately predicting fluid migration requires detailed information on well construction, production, and fluid properties, and even then, the models considered in this study misclassify a large number of wells. This suggests other factors may contribute to pathway formation. Of the models investigated, random forests provide the best results on this data set, correctly identifying 78% of the wells used.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This study aims to decipher the groundwater status of the parts of Tigray area, Ethiopia using an integrated methodology of remote sensing and geographic information systems (GIS). Digitized vector maps of the study area, that is, geology, land use and/or cover, and drainage, were generated and converted to raster data. The theme weight and class weights were assigned to the raster maps of the respective parameters. Weight age to the layers was assigned using an analytical hierarchy process and further overlay analysis was carried out in the ArcGIS environment to decipher the groundwater resources of the study area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The present contribution aims for a characterization of microstructure and pore-space distribution of upper Visean Rudov beds, considered the main source rock for conventional oil deposits in the Ukrainian Dneiper–Donets Basin and a prospect for unconventional hydrocarbon production in recent years. Broad ion beam–scanning electron microscopy (SEM) mapping revealed a remarkably heterogeneous microstructure controlled by diagenetic precipitates (Fe/Mg carbonates, albite). Formation of these precipitates is likely triggered by organic matter decomposition and represents an important influencing factor for overall porosity and permeability. Furthermore, shale diagenesis also influences mechanical properties, as suggested by nanoindentation tests. The SEM-visible organic matter porosity is restricted to solid bitumen; although pores less than 2–3 nm in vitrinites of overmature samples are indicated by focused ion beam–SEM results, they cannot be resolved clearly by this method. Pore generation in solid bitumen that likely formed in situ in primary amorphous organic matter already starts at the early oil window in samples from the basinal oil-prone organofacies, whereas most porous solid bitumen at peak oil maturity was interpreted as relicts of primary oil migration, representing an earlier oil phase that predominantly accumulated in quartz-rich layers and became nanoporous during secondary cracking. In the terrestrially dominated transitional to marginal organofacies, pore generation in pyrobitumen resulting from gas generation occurs significantly later and is less intense. Formation of authigenic clay and carbonate minerals within pyrobitumen is likely related to organic acids formed during bitumen decomposition and implies the presence of an aqueous phase even in pores that are apparently filled exclusively with solid bitumen.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Ahdeb oil field is located in the Mesopotamian Basin of central Iraq within a northwest–southeast-trending anticline. Seven oil-bearing layers exist in the eastern area in the field, but there is only one oil-bearing layer in the western area. This study reveals that the reservoir filling process resulted from the difference in the elements in the petroleum system, the oil generation and migration process, and the formation of the structural trap. Most oils in the field, with pristane/phytane 〈 1 and a high relative abundance of hopanes exceeding C〈sub〉30〈/sub〉, were generated from the Upper Jurassic–Lower Cretaceous Chia Gara Formation, whereas some oils were generated from the Lower Cretaceous Ratawi and Zubair Formations. The mid-Upper Cretaceous reservoirs in the field are composed of lime grainstones, packstones, and wackestones.The main oil accumulation occurred during the Maastrichtian, coinciding with peak oil generation from the Chia Gara Formation with a 50% transformation ratio from organic matter to oil. The reservoirs of the eastern structural trap in the field were filled with large amounts of medium to heavy oils. After the formation of two structural traps in the western area in the mid-Miocene, oils pre-existing in the second layer of the Khasib Formation in the east began migrating toward the structural traps in the west during the late Miocene, as verified by relatively higher 1-/4-methylcarbazole and 1,8-/2,7-dimethycarbazole ratios of oils in the west than that in the east and residual solid bitumen in the east. The strike-slip fault might also have restricted oil or gas migration during the Miocene, limiting oil accumulation in the west.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The success of hydraulic fracturing and increasing use of basin-modeling packages drive the need to understand the effects of hydrocarbon (HC) generation on the mechanical properties of source rocks. A better understanding of relationships among geological, geochemical, and geomechanical parameters can potentially reduce the uncertainties associated with conventional and unconventional prospect evaluation.We present a simulation of microcrack growth based on a three-dimensional source-rock system. Upon thermal maturation, the kerogen transforms into lighter products, most of which are HCs. The generated products exert excessive pore pressure to the system resulting from the effect of volume expansion; this pressure is released through the expansion of pore space and formation of microcracks. Using linear elasticity and linear elastic fracture mechanics, our model calculates microcrack sizes (surface areas, lengths, apertures, and volumes) and the amount of overpressure throughout the maturation process. We validated this model with experimental data from 〈a href="https://pubs.geoscienceworld.org/aapgbull#b20"〉Kobchenko et al. (2011)〈/a〉, and performed sensitivity analysis for both laboratory and geological settings. Much larger microcracks are generated in laboratory settings compared to the subsurface because of the lack of overburden, resulting in secondary porosity over 100 times larger than the original organic porosity and crack lengths obtaining millimeter scale. In contrast, microcracks are much smaller in geological settings because of the presence of significant overburden and stiffer rock frames: the crack apertures are in the submicron regime with a crack length ranging from 100 to 300 μm. The formation of microcracks connects isolated microscale HC pockets, providing pathways for primary migration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Studies of lacustrine carbonate rocks in continental rifts have received huge interest in recent years because of their great economic value in the South Atlantic. However, most existing facies and tectonosedimentary models for carbonate platforms are based on marine carbonate systems, whereas models for nonmarine systems are scarce. The main aim of this paper is to establish such models and to further our understanding of the hydrocarbon-bearing late synrift Lower Cretaceous carbonate successions of the Campos Basin, Brazil. This paper is based on a proximal to distal industrial data set of three-dimensional (3-D) seismic, cores, and well logs from the Coqueiros Formation (Coquina), southern Campos Basin. The dominant carbonate facies in the Coqueiros Formation are mollusk-rich grainstones, rudstones, and floatstones, which form the main reservoir facies. The 3-D seismic interpretations show an oblique extensional rift system, characterized by a series of grabens, half grabens, accommodation zones, and horsts oriented northeast–southwest to north–northeast-south–southwest. Three tectonic domains are recognized based on structural style, stretching factors, and subsidence rates as well as facies and different types of lacustrine carbonate platforms. Proximal rift margin areas are characterized by a series of half grabens with footwall and hanging-wall dip slopes of shallow lacustrine carbonates and fluviodeltaic mixed carbonate and siliciclastic deposits in marginal, hanging-wall basins. Central areas are carbonate rich with platforms established over horst blocks surrounded by deeper-water carbonate facies. Distal areas have the highest amount of stretching and subsidence and accumulate the thickest carbonate successions over a template of buried horsts and grabens. The entire carbonate succession underlies a thick layer of Aptian salt, which forms the seal to this prolific hydrocarbon system.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The uppermost Middle Triassic Leikoupo Formation in the western Sichuan Basin of China has recently been shown to host as much as 5.3 tcf (1.5 × 10〈sup〉12〈/sup〉 m〈sup〉3〈/sup〉) of natural gas resources. The reservoir rocks, composed mainly of microbially derived dolomudstone (e.g., thrombolites and stromatolites), are characterized by low porosity (〈8%) and permeability (〈0.001 to 10 md). The limestone is commonly tight and not of reservoir quality because of abundant meteoric calcite cementation, whereas the dolostone has various types of pores dominated by solution-enlarged pores and vugs, microbial framework pores, and micropores. Breccias are well developed in places, probably because of dissolution of underlying evaporites (e.g., anhydrite) by an influx of low-salinity fluids (e.g., freshwater and seawater) during an early burial stage. Early dolomitization created micropores in the dolomudstone, and subsequent diagenetic events were dominated by calcite, dolomite, quartz cementation, pyrite replacement, compaction, fracturing, and development of stylolites. Localized hydrothermal activity has been evidenced by high homogenization temperatures (∼160°C–200°C) obtained from fluid inclusions in fracture-filling cements. Bacterial sulfate reduction probably resulted in H〈sub〉2〈/sub〉S generation, pyrite precipitation, and solution-enlarged pore and vug formation, whereas part of the current H〈sub〉2〈/sub〉S in these reservoirs may have been sourced from thermochemical sulfate reduction or an underlying formation (e.g., the Feixiangguan Formation). Development of microfractures and associated micropores was probably the final diagenetic event, which improved pore interconnectivity. This study confirms the effect of diagenesis on the development of a microbial dolomudstone reservoir, which may be applicable to other similar microbial carbonate reservoirs elsewhere, for example, Middle Triassic sections of the Tethys region and offshore Brazil.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Clinoforms, the basic large-scale architectural form within which sediments are stored and eventually fed down depositional dip in clastic wedges, exist in many shapes and sizes. Understanding how they form, evolve, and degrade is critical to understanding how transport mechanisms affect the shelf margin and sediment partitioning and distribution, and their implications on the presence of a working petroleum system. The Neogene stratigraphic succession of the Taranaki Basin in New Zealand contains clinoform packages that display a variety of architectures well imaged on seismic data. Quantitative characterization of this interval was performed to unravel the processes by which clinoforms evolve under the influence of tectonic- and isostatic-driven subsidence, sea-level change, and sediment supply fluctuations. Nine different clinoform packages were identified on the basis of changes in their seismic stratigraphic characteristics. Two-dimensional stratigraphic forward modeling was used to conduct a sensitivity analysis and determine the relative importance of different geologic controls on their genesis. Our results show that during the early to late Pliocene, clinoform architectures were influenced by the opening of a back-arc rifting structure in the Taranaki Basin (northern graben), which controlled sediment redistribution and partitioning. At the same time, a drop in global sea level allowed sediment bypass to distal parts of the basin. During the late Pliocene, changes in the Australian–Pacific subduction zone forced rapid uplifting of the Southern Alps, generating a significant increase in sediment supply. Model simulations suggest that clinoform architectures during the late Pliocene were controlled by this increase in sediment supply and associated loading.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A detailed, rock-based investigation of three Upper Cretaceous Eagle Ford Group cores situated behind, at, and downdip of the Lower Cretaceous Stuart City paleoreef-shelf margin in south Texas was conducted to understand stratigraphic, sedimentological, and geochemical relationships across this buried shelf margin. An understanding of how the Eagle Ford Group lithofacies vary across the paleoreef-shelf margin is currently lacking. We therefore examined a dip section of three cores across the antecedent shelf margin and delineated seven Eagle Ford lithofacies: (1) massive argillaceous mudstone, (2) massive to laminated foraminiferal lime wackestone, (3) radiolarian and foraminiferal dolomitic to lime packstone, (4) massive to bioturbated skeletal lime wackestone, (5) laminated foraminiferal lime packstone, (6) laminated inoceramid and foraminiferal lime grainstone, and (7) massive to bioturbated claystone. A basinward decrease in calcite from 60% to 48% is accompanied by an increase in clay minerals from 12% to 20%. The low-relief raised rim of the older, buried Stuart City paleoshelf margin may have acted as a barrier, dividing the Eagle Ford Group into two sedimentological systems: (1) a restricted drowned shelf to the north, and (2) an open-marine basinal setting to the south. The lower to upper Cenomanian Eagle Ford strata on the drowned shelf are cyclic and enriched in molybdenum, suggesting anoxic to euxinic water masses. The anoxic, open-marine, basinward strata are less cyclical and have a lower molybdenum (compared with the drowned shelf) content. Ash beds and gravity-flow deposits are rare south of the margin. A depositional model was constructed of the lower and upper Eagle Ford formations.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting the lateral distribution of petroleum play elements (reservoirs, source rocks, and seals) requires basic understanding of regional basin evolution and depositional history. In remote areas where little data are available or where the basins have undergone episodes of tectonic deformation, this understanding relies on integrated analysis of the plate tectonic framework and the resulting paleogeography. The Arctic has experienced several episodes of tectonic deformation, which fundamentally changed the basin configuration and patterns of sediment routing. Here, we present a set of paleogeographic maps highlighting these changes during the Triassic–Paleogene. In the Triassic, the Arctic was characterized by a central restricted basin, which predominantly received clastic input from the Polar Urals and Arctic Canada. The Alaskan and Siberian passive margins received clastics from continent-scale drainage systems extending into the North American craton and the central Asian fold belt, respectively. In the Jurassic, the region was dominated by rifting as the central Arctic landmass rifted away from Laurentia. In the Early Cretaceous, the northern margin of the Barents Sea underwent regional uplift resulting in new provenance areas shedding sediments southward. Compression along the Pacific margin formed continuous topography and high sediment input to the Canada Basin during the Late Cretaceous. Regression in the Canada Basin continued in the Paleogene when major rift–tip deltas formed. This overview of Arctic paleogeography demonstrates the complexity of this overall data-poor area and shows the need for integrated, regional models to understand sediment routing and stratigraphic development in such areas.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this study is to deconstruct the relationship between the Leaf River anticline and the preglacial bedrock paleotopography at the eastern terminus of the Plum River Fault Zone in Ogle County, Illinois, using a geostatistical approach. The contour maps derived from the elevation models provided detailed depictions of the ancient bedrock landscape and subsurface structure in the study area. The Leaf River anticline is interpreted to be a component of hanging-wall anticline at the terminus of the Plum River Fault Zone. The topographic high created by the anticline controlled local drainage and led to the development of the Leaf River paleovalley prior to the Pleistocene. The catastrophic failure of an ice damn during the Illinois glacial episode carved a glacial spillway into the north flank of the Leaf River anticline that interfaced with a tributary of the Leaf River paleovalley. This rerouted the preglacial drainage network and permanently diverted the ancient Rock River to its modern-day position. Ultimately, the subsurface geometry of the Leaf River anticline and its relationship to the local bedrock paleotopography were revealed by the elevation models. The position and development of the Leaf River paleovalley and glacial spillway interpreted in this study aligned with the regional interpretations for the evolution of the ancient bedrock landscape established in prior works. However, this study revealed that the Leaf River anticline and, by association, the terminus of the Plum River Fault Zone extend farther east into the region than indicated by prior works.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last decade, production of shale gas has tremendously increased, and the need for local pre-exploitation baseline data on dissolved natural gas in aquifers has been stressed. This study investigated the origin of hydrocarbons naturally present in shallow aquifers of the Saint-Édouard area (Québec, eastern Canada), where the underlying Utica Shale is known to contain important gas resources that have not yet been exploited. Groundwater and shallow bedrock gas samples were collected and analyzed for isotopic composition of alkanes (δ〈sup〉13〈/sup〉C and δ〈sup〉2〈/sup〉H〈sub〉C1–C3〈/sub〉), dissolved inorganic carbon (δ〈sup〉13〈/sup〉C〈sub〉DIC〈/sub〉), and radiocarbon in methane and DIC (〈sup〉14〈/sup〉C〈sub〉DIC〈/sub〉, 〈sup〉14〈/sup〉C〈sub〉CH4〈/sub〉). This multi-isotope approach proved enlightening, and results revealed that (1) most of the methane in the region is of microbial origin; (2) partial contribution of thermogenic gas occurs in 15% of the wells; (3) processes such as late-stage methanogenesis and methane oxidation are responsible for ambiguous methane isotopic compositions; and (4) both microbial and thermogenic gas originate from the shallow bedrock aquifer, with the exception of one sample likely coming from deeper units. The thick succession of shales overlying the Utica Shale thus appears to act as an effective migration barrier for the shallow aquifers. However, evidence of upward migration of old brines near major fault zones indicates that these may serve as a preferential migration pathway over a certain depth but most likely no more than approximately 200–500 m (∼650–1640 ft). The geochemical framework presented here will hopefully be useful in other research projects, especially when conventional indicators of natural gas origin provide ambiguous results.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Urbanization modifies the natural water cycle. In this study, a weighted-rating multicriteria analysis was adopted to quantify the runoff index and to assess the impact of urbanization on the water cycle. The considered parameters are (1) slope, (2) permeability of soil, and (3) rainfall. Using the land use map, a runoff risk map was established. The approach was applied to Manouba catchment. The main results revealed that between 2004 and 2014, the area with a high runoff index increased from 32% to 39%. The runoff risk increased; in 2004, the high class covered 18% of the watershed area. This value became 30% in 2014. Results demonstrate that urbanization affects hydrological processes. This method is appropriate in other similar watersheds to estimate the runoff index.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉To better understand controls on the origin and evolution of brackish groundwater, the hydrogeochemistry of brackish groundwaters was studied within the Triassic Dockum Group across the Midland Basin in Texas. The suitability of Dockum Aquifer water for use in hydraulic fracturing fluid was examined because the area overlies the largest and most productive tight oil province in the United States. Groundwater generally flows southward and eastward across the basin. Transmissivities indicate that water yield from the Dockum Aquifer is mixed. Higher salinity (up to ∼100 g/L), group I water is found mainly in the center and western parts of the basin; chemistry of these meteoric waters is controlled by water–rock interaction with salinity increasing along its flow path via dissolution of halite and anhydrite, followed by salinity-enhanced carbonate dissolution and/or cation release from clays. Along the down-gradient basin margins, lower salinity (〈7.5 g/L), group II waters of various ion compositions are more commonly found. Group II waters are also meteoric but from local recharge including downward flow from the Edwards–Trinity or other aquifers. Despite having lower salinity, the water in the down-gradient southern and eastern margins of the basin can exceed acceptable SO〈sub〉4〈/sub〉 limits for cross-linked gel fluids. Generally, the majority of the water in the basin is suitable for use with slick-water hydraulic fracturing. Findings from this research provide important information on the complex controls on the chemistry of brackish groundwater and their potential beneficial uses in the oil and gas industry.〈/span〉

Description: An extensive seismic database covering an area of 100,000 km 2 (38,610 mi 2 ) and 16 wells are integrated to define a sequence-stratigraphic framework for the Lower Cretaceous succession in the southwestern Barents Sea. Seven sequences (S0–S6) are defined, and the geometry, trajectory, and lateral variability of decompacted seismic clinoforms are described to elucidate the depositional history of the basin and to better understand coarse-grained sediment transport from the shelf to basin. Three different clinoform scales are recognized: (1) clinoform sets with 35–60 m (115–197 ft) height, interpreted as deltaic or shoreline clinoforms; (2) clinoform sets with 60–110 m (197–361 ft) height, interpreted as sediments prograding on a continental shelf; and (3) clinoforms with greater than 150 m (〉492 ft) height, which represent shelf-margin clinoforms. Furthermore, clinoforms are grouped into two main progradation directions: (1) clinoforms prograded to the southeast in sequences 2–3, in the Fingerdjupet Subbasin and the western Bjarmeland platform, indicating a source of sediments located in the west-northwestern Barents Sea, and (2) clinoforms prograded to the southwest in sequences 1–6, in the eastern part of the Bjarmeland platform, Nordkapp Basin, and Finnmark platform, indicating a second source of sediments located in the east-northeast. Additionally, in the Hammerfest Basin, clinoforms prograded to the southeast off the Loppa high in sequences 5–6. Low-relief (35–60 m [115–197 ft]), high-gradient, and oblique clinoforms are observed within sequence 2 in the western Bjarmeland platform. The high-gradient foresets are interpreted as potential coarse-grained deposits or as a result of clinoforms prograding to progressive deeper waters, resulting in steeper foresets. Clinoforms located in the eastern part of the study area are interpreted as sourced by a mud-rich system, reflecting a long transportation distance. However, thin, heterolithic patterns in the gamma-ray log possibly reflect thin, sheetlike sands. The height of the clinoforms seems to be a factor controlling the sediment bypass to deep water in the study area. When the height is more than 200 m (656 ft), bottomset deposits are common. This study contributes to a better understanding of the paleogeography and the evolution of the frontier southwestern Barents Sea during the Early Cretaceous and to comprehending the variables increasing the bypass of coarse-grained sediments to deep-water settings.

Description: Variations in environmental and biological origins contributing to the heterogeneity of lacustrine source rocks can be illustrated in their diverse genetic facies. The Zhu 1 depression, eastern Pearl River Mouth Basin, South China Sea, is characterized by two thick, Paleogene, organic-rich synrift units, the Wenchang and Enping Formations. The integration of bulk geochemical and biomarker data with tectonic and sedimentary information provides the basis for a comprehensive assessment of the environmental and ecological changes through geologic time and their impact on the heterogeneity of these lacustrine source rocks. Both the Wenchang and Enping Formations display wide variations in total organic carbon content and hydrogen index values as well as biomarker composition, suggesting lateral and chronological changes in organic facies. Using gas chromatography–mass spectrometry and hierarchical cluster analysis, five genetic facies were identified within these two source horizons. These facies represent different organic-matter inputs and sedimentary and early diagenetic environments based on their distinctly different assemblages of 11 source-dependent biomarker ratios. Four facies were distinguished in the Wenchang Formation, and two facies were distinguished in the Enping Formation, with one being common to both formations. During the middle Eocene, the Wenchang Formation was deposited in a series of small, deep lakes of laterally variable salinity, acidity, and biofacies. During the deposition of the Enping Formation in the late Eocene and early Oligocene, the previous lakes merged into fewer lakes with shallower depth and larger areal coverage, with the biota becoming more uniform across the whole depression. The coevolution of these lacustrine settings and their biota is closely associated with the development of the Zhu 1 depression, within which multiple separate sags produced by rapid mid-Eocene subsidence finally merged into a single depositional unit during slow subsidence in the late Eocene and early Oligocene. Accordingly, an integrated model was established to provide an overview of the contrasting origins of lacustrine source rocks during the two Paleogene epochs. This model may have important implications for source-rock prediction in the undrilled parts of the basins or for reference to source-rock heterogeneity in other rift basins.

Description: Three-dimensional (3-D) printing provides an opportunity to build lab-testable models of reservoir rocks from tomographic data. This study combines tomography and 3-D printing to reproduce a sample of the Fontainebleau sandstone at different magnifications to test how this workflow can help characterization of transport properties at multiple scales. For this sandstone, literature analysis has given a porosity of 11%, permeability of 455 md, mean pore throat radius of 15 μm, and a mean grain size of 250 μm. Digital rock analysis of tomographic data from the same sample yielded a porosity of 13%, a permeability of 251 md, and a mean pore throat radius of 15.2 μm. The 3-D printer available for this study was not able to reproduce the sample’s pore system at its original scale. Instead, models were 3-D printed at 5-fold, 10-fold, and 15-fold magnifications. Mercury porosimetry performed on these 3-D models revealed differences in porosity (28%–37%) compared to the literature (11%) and to digital calculations (12.7%). Mercury may have intruded the smallest matrix pores of the printing powder and led to a greater than 50% increase in measured porosity. However, the 3-D printed models’ pore throat size distribution (15 μm) and permeability (350–443 md) match both literature data and digital rock analysis. The powder-based 3-D printing method was only able to replicate parts of the pore system (permeability and pore throats) but not the pore bodies. Other 3-D printing methods, such as resin-based stereolithography and photopolymerization, may have the potential to reproduce reservoir rock porosity more accurately.

Description: 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 x 10 10 m 3 ) 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.

Description: Event-based risk management (EBRM) is an improved way of describing subsurface uncertainties and their possible business impacts in a manner that facilitates specific actions to improve business performance. In EBRM, uncertainties are viewed as potential causes of risk events that could in turn lead to consequences that affect the attainment of objectives. This "causes–event–consequences" syntax aids the design of prevention measures to inhibit the causes turning into the event and mitigation measures to reduce the potential consequences should the risk event occur, and it also facilitates construction of a risk taxonomy scheme based on risk consequences, events, and causes. Using a data set of 1456 subsurface risks, each risk was described in this manner and placed in the taxonomy, and the proportion of risks in each taxonomic group was analyzed. This revealed clear trends in the relative frequency of risk groups with type of field: for example, risks related to hydrocarbon-in-place volumes are more frequently identified in deep-water oil fields and gas fields feeding liquefied natural gas plants, situations in which resource volumes are critical to support the large project capital costs. Trends were also evident with field maturity: for example, risks related to hydrocarbon-in-place volumes are more frequently identified before the field sanction decision than afterward. Several benefits have yielded from EBRM: the risk description syntax encourages the creation of meaningful risk-management actions, the taxonomy and associated risk identification frequencies assist the identification of relevant risks so that key risk areas are not overlooked and also help to anticipate future risks, and the focus on risks (rather than uncertainties) helps to focus resources (data acquisition, technical studies) onto those aspects of the subsurface that are likely to impact business outcomes.

Description: A comprehensive study of seep carbonates at the top of the organic-rich Maastrichtian to Danian Moreno Formation in the Panoche Hills (California) reveals the mechanisms of generation, expulsion, and migration of biogenic methane that fed the seeps. Two selected outcrops show that seep carbonates developed at the tip of sand dykes intrude up into the Moreno Formation from deeper sandbodies. Precipitation of methane-derived cements occurred in a succession of up to 10 repeated elementary sequences, each starting with a corrosion surface followed by dendritic carbonates, botryoidal aragonite, aragonite fans, and finally laminated micrite. Each element of the sequence reflects three stages. First, a sudden methane pulse extended up into the oxic zone of the sediments, leading to aerobic oxidation of methane and carbonate dissolution. Second, after consumption of the oxygen, anaerobic oxidation of methane coupled with sulfate reduction triggered carbonate precipitation. Third, progressive diminishment of the methane seepage led to the deepening of the reaction front in the sediment and the lowering of precipitation rates. Carbonate isotopes, with 13 C as low as –51 Peedee belemnite, indicate a biogenic origin for the methane, whereas a one-dimensional basin model suggests that the Moreno Formation was in optimal thermal conditions for bacterial methane generation at the time of seep carbonate precipitation. Methane pulses are interpreted to reflect drainage by successive episodes of sand injection into the gas-generating shale of the Moreno Formation. The seep carbonates of the Panoche Hills can thus be viewed as a record of methane production from a biogenic source rock by multiphase hydraulic fracturing.

Description: Production decline prediction is important to understand the performance and life span of oil and gas wells. The most common prediction method is decline curve fitting based on available production rate data. Such data are fit with different equations that extrapolate to future time. However, the parameters are commonly poorly constrained, especially when the production rate data are limited. In this study, we establish a novel gas isotope interpretation tool to better predict the resource quantity and life span of producing gas wells. This tool is based on the evolution of methane carbon isotope ratios ( 13 C1) caused by different gas-releasing processes during production. It requires (1) real-time methane carbon isotope ratio data, (2) continuous gas production rate data for a certain period of time, and (3) basic geological and engineering conditions. We successfully applied the production decline prediction tool to a producing shale gas well in the Barnett Shale. We obtained real-time 13 C1 data for approximately 1 yr using our proprietary, field-deployable gas chromatography–infrared isotope ratio analyzer. The prediction in this well from the isotope method showed a total reserve of up to 7.34–7.75 BCF (2.07–2.19 x 10 8 m 3 ), which was used to constrain the production decline trend of the study well. The measured production rate data were first fit using the Arps equation, which then joined to an exponential decline curve smoothly at approximately 10 yr, such that the cumulative production calculation from integration of the product rate curve equaled to the total reserve predicted by the isotope method. The novel production decline prediction method thus provided important constraint on the future well production and expected ultimate recoverable reserves.

Description: Opening-mode veins in cores drilled from the mudrocks overlying and underlying the major Silurian salt décollement in the Appalachian plateau (Tioga and Lawrence Counties, Pennsylvania) have mineralogic and isotopic compositions generally matching those of their host mudrocks, suggesting opening and filling amid little cross-stratal fluid motion. Calcite and most trace minerals probably entered the veins via dissolution–reprecipitation from nearby host rock. Consistent with this interpretation are the observations that (1) trace minerals within the veins, including quartz, pyrite, and dolomite, are invariably also present within the layers hosting the veins, with vein cement minerals generally reflecting the abundance and solubility of minerals in the host rock, and (2) carbon and oxygen isotopic compositions of vein-filling calcite are similar to those of calcite within the host rock, with vein-filling 18 O slightly depleted and 13 C slightly enriched. Modeling the fluid isotopic evolution, assuming vein opening and filling amid immobile connate formation water, accounts for these minor but systematic differences, which are attributable to increasing temperature and hydrocarbon maturation. An exception to the above trend is barite, which, despite its low solubility, is systematically enriched in veins with respect to the host rock. It is unclear whether barite precipitation resulted from the influx of external fluids—perhaps deriving from Silurian salt—or from barium mobilized at depth from local clays or organic material.

Description: Water salinity in the San Joaquin Valley is a function of depth, location, and stratigraphy. This paper presents a reconnaissance study of water salinity within Kern County, California, using chemical analyses from oil field produced water and water wells as well as geophysical logs. Log analysis indicates that the base of underground sources of drinking water (USDWs) (〈10,000 mg/L) slopes from northwest to southeast. Lab analyses show that USDWs extend to depths as great as 1900 m (6233.5 ft) southeast of Bakersfield. This area receives the greatest amount of fresh water recharge from streams flowing westward from the Sierras. The marine Olcese Sand is more saline than the overlying and underlying aquifers and separates the aquifers into an upper and lower USDW. Log analysis also indicates a zone of higher salinity separating zones of lower salinity in this area. Salinities in the west are higher, and depths to base USDW are variable. Although waters in many sands in the western valley are more saline than 3000 ppm total dissolved solids (TDS), numerous wells contain waters between 3000 and 10,000 ppm at depths of less than 600 m (1968.5 ft), particularly in the nonmarine Tulare Formation. At North Belridge field, a salinity reversal is apparent below 2100 m (6890 ft). Waters above this depth are approximately 40,000 mg/L TDS, whereas water salinities below 2200 m (7218 ft) range from 10,000 to 32,000 mg/L. Extremely high salinities are found in several wells less than 30 m (98 ft) deep, primarily in the northwestern area. These may be perched aquifers or lie adjacent to unmapped agricultural drainage sumps and do not reflect salinities in the regional aquifer.

Description: To assess prospective modeling trends for oolitic tidal sand shoals and explore potential patterns of reservoir heterogeneity, this study examines, quantifies, and models the cycle-scale architecture of the Holocene mobile oolitic tidal sand shoal complex at Schooner Cays, Bahamas. Process-based stratigraphic trends are captured in quantitative, geocellular models of the shoal from analyses of satellite imagery; two-dimensional, high-frequency seismic (chirp) data; and sediment cores. Data show that longitudinal tidal sand ridges extend up to 8 km (5 mi) along depositional dip, gradually transforming bankward into channel-bound, compound barforms consisting of linear, parabolic, and shoulder bars. These bars terminate into a laterally extensive (10 km [6 mi]), strike-elongate sand sheet. Each bar type includes distinct internal architecture, grain size, and sorting related to feedbacks among hydrodynamics, geomorphology, and sedimentology. Building on these data and concepts from the Holocene accumulations, this study demonstrates a methodology for quantifying and validating probabilistic stratigraphic trends prior to their inclusion in stochastic-based facies modeling algorithms. Inclusion of statistically robust facies probability volumes during truncated Gaussian simulation generated ordered and geologically accurate facies distributions relative to bar-crest centerlines, water depth, and geomorphic position. Petrophysical models that incorporate facies-specific porosity, permeability, and water saturation functions display pronounced cycle-scale heterogeneity that could provide insights into variable production rates and poor sweep efficiency commonly encountered during development of analogous oolitic reservoirs.

Description: Organic-rich and carbonate-rich Eagle Ford Shale is a self-sourced oil and gas reservoir with little alteration of gas chemistry as might be affected by petroleum expulsion and migration. As such it provides an ideal natural laboratory to quantify the compositional variation of gases generated from oil-prone type II kerogen during thermal maturation. The chemical composition of the gas released from rock crushing was conducted and integrated with Rock-Eval pyrolysis to define the empirical relationship between gas compositional parameters and thermal maturity in this study. From 10 wells in the Eagle Ford Shale in south Texas, we collected 74 core samples having a range of thermal maturity (the measured maximum temperature [ T max ] values of hydrocarbons generated in Rock-Eval pyrolysis range from 427°C to 494°C [800°F to 921°F], and the calculated equivalent vitrinite reflectance ( R oe ) values range from 0.51% to 1.73% based on T max values). Total organic carbon content ranges from 0.3% to 8.53%, with an average of 3.12% (standard deviation of 1.77%). Burial depth is from 2989.6 to 13,827.3 ft (911.2 to 4214.6 m). Our results showed that gas composition in the Eagle Ford Shale is mainly controlled by thermal maturity, and three stages of gas generation are identified based on the C 1 and C 2 concentrations of the gases released by rock crushing from Eagle Ford Shale core samples. The three stages of gas generation correspond to the following processes of organic matter conversion: (1) kerogen and bitumen thermal cracking to crude oil, (2) bitumen and heavy crude oil thermal cracking to light oil, and (3) light oil cracking to gas. Methane-rich gas and an abundance of branched butane and pentane are generated in light oil cracking to gas, resulting in high C 1 /C 2 , C 1 /(C 2 + C 3 ), i-C 4 /n-C 4 , and i-C 5 /n-C 5 ratios. Increased cracking of normal alkanes such as n-butane and n-pentane occurs in the light oil cracking to gas. Empirical equations between gas compositional parameters and thermal maturity ( T max or R oe ) are obtained for oil-prone type II. The C 1 , C 2 , C 1 /C 2 , C 1 /C 2 + C 3 , and i - C 4 /n - C 4 ratios are the five best parameters for determining thermal maturity with an exponentially derived R 2 value of 0.74. The composition of gas produced from the Eagle Ford Shale following hydraulic fracturing is used to validate the empirical equations. Calculated thermal regime for the oil production based on the produced gas is located at the peak of oil generation and the beginning of light oil cracking to gas, corresponding to T max from 454°C to 464°C (849°F to 867°F) or at an R oe ranging from 1.01% to 1.19%. Empirical equations provide a basis for interpretation of mud gas logging data and produced gas composition.

Description: In this paper, a new approach to calculating and restoring the effects of physical compaction in subsalt units is presented. The loading of subsalt units and associated physical compaction is controlled by a combination of suprasalt sedimentation and salt movements. Here it is proposed that the change in load affecting the subsalt units is equivalent to the thickness between paleosurfaces of the basin (regional levels) reconstructed for successive stratigraphic horizons. This is in contrast to suprasalt units, where the changes in load are equivalent to the thickness of the stratigraphic unit. The new approach is integrated into a complete workflow for sequential restoration in a salt basin, which involves (1) removing the effects of physical compaction in suprasalt units, (2) reconstructing the paleosurfaces of the basin (regional level), (3) restoring faults, (4) unfolding to the reconstructed regional level to restore the effects of salt movement in the suprasalt units, (5) reconstructing the change in load affecting subsalt units and restoring the associated physical compaction, and (6) restoring any isostasy and postrift thermal subsidence. Results obtained using this workflow are compared with other methodologies to assess the differences in subsalt sediment thickness and structural configurations. These results suggest that the workflow proposed in this paper will improve the accuracy of sequential restoration of subsalt hydrocarbon plays, allowing their structural configurations through time to be more accurately quantified, and will ultimately reduce the risks in developing subsalt resources.

Description: The Upper Jurassic Norphlet Formation is an eolian sandstone and important hydrocarbon reservoir that overlies the Louann Salt in the Gulf of Mexico (GOM). Because the sand was concentrated into dunes formed by Late Jurassic winds, determining the source areas and paleotransport direction of the sand can improve predictions of the distribution of the dune facies around the GOM. Paleo–wind-blown sediment transport into the proto-GOM was controlled by wind direction and magnitude and the extant topography of the basin and adjacent uplands. Analysis of the Norphlet Formation in the eastern GOM shows that wadis and alluvial fans controlled by the location of highs were the primary route for introducing sediment of varied provenance into the eolian erg. Eolian transport directions interpreted from dip-log analyses are south directed in southern Alabama and west to northwest directed in western Florida. Interpretations of regional, two-dimensional, prestack-depth-migrated seismic data show that erosional incision of the Middle Ground arch occurred prior to and during the time of Norphlet deposition; this as well as preexisting lows in the basement topography may have facilitated basinward sand transport of sediment that fed the Norphlet Formation erg preserved in the deep-water subsurface eastern GOM.

Description: A total of 225 rock samples and 37 oil samples from the Beibuwan Basin, South China Sea, were analyzed with geochemical and organic petrological techniques to evaluate the Eocene lacustrine source rocks and investigate controls on their properties and the distribution of different oil families in the basin. Two types of organic facies are recognized in the Liushagang Formation (LS). The first organic facies is algal-dominated and mainly occurs in the organic-rich, laminated mudstones of the middle member of the LS (LS-2) that were deposited in an anoxic, stratified, medium–deep lake environment. It is geochemically identified by its high abundance of C 30 4-methylsteranes and heavy 13 C values in the range of –22.4 to –27.5. The organic matter in this organic facies comprises type I and II 1 kerogens, with its macerals dominated by fluorescent amorphous organic matter (AOM) and exinites, indicating a highly oil-prone character. The second organic facies is of terrestrial algal origin and is mainly identified in the nonlaminated mudstones of the upper (LS-1) and lower (LS-3) members of the LS that were deposited in shallow, dysoxic, weakly stratified, freshwater environments. Source rocks of the second organic facies mainly contain type II 1 –II 2 kerogens with mixed macerals of AOM, internites, and vitrinites. It is geochemically differentiated from the algal-dominated organic facies by its relatively low abundance of C 30 4-methylsteranes and lighter 13 C values in the range of –27.20 to –28.67. Three oil groups are identified by their biomarkers and stable carbon isotopes. The first two groups (A and B) are probably end-members of two major oil families (A and B) that correspond to the algal-dominated organic facies and algal–terrestrial organic facies, respectively. Most of the discovered oils belong to group A oils that are characterized by a high abundance of C 30 4-methylsteranes and heavy 13 C values and show a good correlation with the algal-dominated organic facies in LS-2. Group B oils are found only within the LS-1 and LS-3 reservoirs, and they are recognized by their relatively low content of C 30 4-methylsteranes and lighter 13 C values, showing a close relation to the algal–terrestrial source facies within the LS-1 and LS-3 members, respectively. Group C oils display intermediate biomarker features and stable carbon isotope values and are interpreted to be a mixture of group A and B oils. The oil–source correlation reveals a strong control of organic facies on the geographic distribution of oil groups or oil fields in the basin.

Description: Two-dimensional seismic refraction tomography was used to map the bedrock topography beneath Hallsands beach in southwest Devon, United Kingdom. Seismic refraction data were acquired from 11 spreads, 4 parallel to the beach and 7 normal to the beach, with either 12 or 24 geophones at 5-m (16-ft) spacing. Eight sediment cores were used to calibrate the velocity model. The bedrock consists of metasedimentary rocks that have a seismic velocity of 2100–2500 m/s (6900–8200 ft/s) and is overlain by variable amounts of gravel, peat, and muddy peat. Wood peat and peaty mud are differentiated within the peat as 700-m/s (2300-ft/s) velocity for wood peat and 1200-m/s (4000-ft/s) velocity for peaty mud. These refraction data were collected and processed in two dimensions, then imported into Petrel, a three-dimensional (3-D) geological modeling software package. The 3-D geologic model was built using the velocity attribute of the seismic refraction data. These selected data points were used to create 3-D horizons, surfaces, and contacts constraining the target bedrock surface from the overlying unconsolidated deposits. The bedrock surface beneath Hallsands beach is marked by two paleochannels. One paleochannel occurs in the north end of the beach beneath the axis of the modern valley. A second paleochannel occurs in the southern section of Hallsands beach centered along the axis of a tributary valley. Bedrock occurs at a depth of approximately –10 m (–33 ft) in the southern and northern sections of the main valley. Bedrock occurs at a depth of approximately –2 m (–6 ft) along the valley wall at the southern end of the beach east of the parking lot. Shore-perpendicular refraction lines differentiate layers within the peat, whereas shore-parallel lines delineate wood-peat, peaty-mud, and bedrock topography.

Description: Drilling for oil/gas and trawling on a continental shelf can cause damage to hard-bottom communities. Moving these activities offshore poses a threat to offshore communities. Habitat complexity is correlated with species diversity. The relationship of bottom relief to benthic species richness is not well understood in deeper communities. Relief may act as a proxy for species richness and disturbance risk. Geographic patterns in relief and richness are also not well understood. We gathered information on bottom relief and species richness of the sessile epibenthic community using a remotely operated vehicle. We surveyed hard bottom on the flanks of 13 banks in the north–central Gulf of Mexico, greater than 27-m (89-ft) depth, on the shelf and at the shelf edge. We found a positive asymptotic relationship between mean relief and species richness at the transect level. Secondary analyses at the drop site level revealed a similar relationship; variance was higher. The relationship was positively linear at the bank level. Analyses using standard deviation of relief yielded even stronger positive results. There was no significant relationship between species richness and latitude or longitude over the study area (215 km [133 mi]). When species richness was plotted in three dimensions, however, peaks in richness emerged in the southeastern study area and the western region, with a trough between them, coinciding with bottom relief. Species richness is positively correlated with bottom relief on banks in the northern Gulf of Mexico. Relief and species richness may be predicted at many spatial scales, up to hundreds of kilometers.

Description: Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at T max (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

Description: The deep high-temperature, high-pressure Lower Cretaceous Bashijiqike sandstone (buried to depths as great as 6.5–7.1 km [21,325–23,293 ft]) is an important natural gas reservoir in Keshen gas field, Kuqa depression of the Tarim basin. Reservoir quality is a critical risk factor in the development of these ultradeep reservoirs. Integrated approaches incorporating routine core analyses and mineralogical, petrographic, and geochemical analyses have been used to investigate the diagenetic history of these rocks and their effect on reservoir quality with the aim to unravel the mechanisms for maintaining anomalously high porosities in sandstones that are buried to such a great depth. These sandstones are dominantly fine- to medium-grained, moderately to well-sorted lithic arkoses and feldspathic litharenite. Most primary pores have been lost by mechanical compaction or carbonate cementation, and the reduction of porosity by mechanical compaction was more significant than that by cementation. Dissolution of framework grains contributed to the enhancement of reservoir quality. Eogenetic diagenetic alterations mainly include mechanical compaction, precipitation of calcite cements, and grain-coating clays, and mesogenetic diagenesis is characterized by dissolution of framework grain by organic acids and subsequent precipitation of clay minerals and quartz. Infiltration of meteoric water related to teleodiagenesis would result in dissolution of the framework grains. The meteoric leaching events during teleodiagenesis are of great importance for the Bashijiqike sandstones. Grain-coating clay minerals (mixed-layer illite/smectite clays) help to preserve porosity at depth by retarding quartz cementation and pressure solution. The unique burial regime as early-stage shallow burial with late-stage rapid deep burial contributes to porosity preservation in eodiagenesis. Fluid overpressure caused by intense structural compression in the middle Himalayan movement retarded compaction and helped preserve porosity in the late rapid deep burial stage. Anomalously high porosities are mainly found in medium-grained, well-sorted sandstones with grain-coating clays but with low clay and carbonate cement content, of which the porosity is preserved primarily and enhanced secondarily. The lowest porosities are associated with sandstones that are tightly compacted or cemented with carbonates or rich in detrital matrix. Porosity–depth trends may vary significantly with lithofacies because of their differences in textural and compositional attributes. Five lithofacies are defined in terms of detrital composition and texture and type and degree of diagenesis. The reservoir quality prediction models of various litho-facies are constructed, and the results of this study provide insights into mechanisms for maintaining anomalously high porosity and permeability in high-temperature, high-pressure sandstone reservoirs and may help explain hydrocarbon distribution.

Description: 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.

Description: We use finite element modeling to show that upbuilding can be a significant component of salt diapir growth in tectonically stable systems when basin sediments are elastoplastic mudrocks. The ability of such sediments to deform plastically and the dependence of their strength on confining pressure enable structural thinning, which allows salt to pierce through a relatively thick roof. Once pierced, the originally continuous roof uplifts to form a megaflap. We show that the evolution to an upturned megaflap adjacent to a salt stock causes shortening of the bedding layers in the radial and vertical directions and extension in the hoop (circumferential) direction. These deformations lead to significant shear strains within the sediments; as a result, in some areas within the upturned megaflap, mudrocks have reached their maximum level of shear resistance and are failing. Thinning and shear failure of sediments are also significant near salt walls, despite the absence of out-of-plane deformation. We illustrate that cross-sectional area and bedding line lengths are not necessarily preserved. Based on our results, we re-evaluate traditional assumptions of kinematic restoration and show that established workflows may not properly restore salt systems that interact with shallow plastic sediments. Finally, we show that when wall rocks are deformable, salt diapir shapes are not necessarily a simple function of sedimentation and salt flux rates ( q fx / Å ) and that the diapir hourglass shape might result from lateral deformation of the megaflap.

Description: Provenance of Pleistocene–Holocene deepwater sediments in the Gulf of Papua (National Science Foundation Source to Sink Focus Area) has been studied to understand sediment sources and glacioeustatic influences on sedimentary routing and to better understand processes controlling sediment sources and delivery. We show how diverse processes operate in a complex deep-sea environment over time to control sediment routing and accumulation. Quantitative detrital analyses were conducted on 53 turbidite sand and 3 terrestrial samples with scanning electron microscopy and mineral liberation analysis, which yielded a broader and more insightful classification than manual point counts. We determined that (1) multiple terrestrial sediment sources along an approximately 500-km (300-mi) basin margin converged to form one continuous deep-sea system in two major basins (〉30 cal [calibrated] ka); (2) subsequent sea level fall near the last glacial maximum (LGM) (18–22 cal ka) drove repartitioning of sediment sources to create multiple distinct depocenters, presumably caused by migration and incision of individual rivers across the newly exposed coastal plain; and (3) multiple separate deep-sea channels then regained compositional similarity near the end of the LGM. In the subsequent Holocene, deepwater sand transport shut down, except for one locality where delivery continues because of a combination of narrow shelf–slope setting, oceanographic processes, and additional volcanic supply. These findings highlight the diverse processes that must be considered for the development of deepwater petroleum systems, in terms of sediment delivery, deposition, and provenance that may affect the reservoir geometry and quality.

Description: Secondary processes within reservoir sandstones during and after hydrocarbon production are poorly understood. This study looks at the effect of secondary water fill on a sandstone reservoir within a time span of 8 yr. The reservoir rocks consist of medium-grained litharenites with large clasts of shales and carbonates. They originate from a depleted gas reservoir that has been converted into an underground storage field for natural gas. Gas production resulted in a rise of the gas–water contact of approximately 30 m (98 ft). Based on their initial and final gas and water saturations, four zones can be identified. Observed diagenetic changes in all four zones include carbonate cementation, K-feldspar overgrowths, authigenic quartz overgrowths, pyrite formation, and poorly crystallized authigenic clay minerals. However, the authigenic clay mineral fraction differs significantly within the zones. Total clay mineral content and crystallinities of smectite, chlorite, kaolinite, and illite increase from the gas-bearing to the initial water zone. Additionally, expandable clay minerals and kaolinite were not identified in the gas-bearing zone. This is different in the secondary watered zones, where smectites and kaolinites are developing. The study shows that within a maximum of 8 yr from the start of water influx into the gas zone, new clay minerals are forming. The porosity and permeability reduction caused by this artificially induced process might continue and could also be of relevance within producing reservoirs, where water saturation increases during production.

Description: The northern deep-water Gulf of Mexico is one of the most active deep-water petroleum provinces in the world. This paper introduces the regional geologic setting for the northern deep-water Gulf of Mexico and briefly discusses the importance of technology in developing the area’s resources. Exploration has focused on four major geologic provinces: Basins, Subsalt, Fold Belt, and Abyssal Plain. These provinces formed from the complex interactions between Mesozoic–Cenozoic sedimentation and tectonics. Improved understanding of the geology of these provinces has largely been accomplished by improvements in seismic acquisition and processing. In addition, advances in drilling technology have permitted drilling and field development in increasingly greater water depths. The 226 oil and gas fields and discoveries in the northern deep-water Gulf of Mexico are summarized in terms of their exploration and development history, producing facility, ages of reservoirs (Upper Jurassic, upper Paleocene–lower Eocene, Oligocene, lower Miocene–upper Pleistocene), and trap type (structural, combined structural-stratigraphic, and stratigraphic). In addition, the interpreted regional distribution of Upper Jurassic and possible Lower Cretaceous source, source rocks is shown, in part based on the 26 wells that have penetrated these source rocks. The eight papers in this special issue review the geology of the Mississippi Canyon and northern Atwater Valley protraction areas. The first five papers review the subregional structural setting and the evolution of its tectonics and petroleum systems. The final three papers summarize the geologic evolution of two economically important intraslope basins—Thunder Horse and Mensa—in terms of their stratigraphy, structural evolution, and petroleum systems. These two basins contain two of the larger oil and gas fields, respectively, in the northern deep-water Gulf of Mexico.

Description: Thunder Horse and Mensa are two of the largest fields of oil or gas, respectively, in the northern deep-water Gulf of Mexico. The fields are present in adjacent intraslope minibasins, located approximately 12 mi (19 km) apart in Mississippi Canyon. Both fields illustrate important complexities of deep-water sedimentation. Analysis is based on the integration of wire-line logs, biostratigraphy, and a 378-mi 2 (979-km 2 ), three-dimensional seismic data set. Thunder Horse and Mensa reservoirs were deposited during the middle to late Miocene. Changes in paleobathymetry controlled the reservoir deposition, initially as salt withdrawal and later as turtle structures. From 125 to 24 Ma, the lithologies in both intraslope basins are interpreted as dominantly deep-water marls with interbedded shales. From 24 to 14.35 Ma, major input of deep-water siliciclastic sediments began. Sands were deposited in amalgamated sheets and amalgamated channel-fill units within the two major paleobathymetric lows; by contrast, shales were deposited across paleobathymetric highs. Between 14.35 and 13.05 Ma, the Thunder Horse turtle formed, creating a paleobathymetric high. Channelized sands were diverted around and deposited on the flanks of the structure. Meanwhile, to the north at Mensa, thick channel-fill sediments continued to be deposited. From 12.2 to 8.2 Ma, the lithologies throughout the entire area are dominantly overbank shales with thin channel-fill sands, suggesting that large volumes of sand bypassed the study area farther downslope to the south. Finally, at 9.0 Ma, Mensa's sheet-sand reservoir represents a different setting; sands were deposited near the crest of the Mensa turtle, which had subtle bathymetric expression.

Description: The Mensa and Thunder Horse intraslope minibasins in south-central Mississippi Canyon, northern deep-water Gulf of Mexico, had a linked structural evolution from the Early Cretaceous through the late Miocene. Analysis of the two minibasins illustrates the complexities of deep-water sedimentation and salt tectonics in intraslope minibasins. This study is based on the integration of a 378-mi 2 (979-km 2 ) three-dimensional seismic data set, wire-line logs, and biostratigraphic data. These two minibasins comprise several structural features that affected their geologic evolution: basement faults, autochthonous salt, three allochthonous salt systems (top Barremian, top Cretaceous, and Neogene), a growth fault and raft system, three major turtle structures with associated extensive crestal faults, and strike-slip faults. Remnant allochthonous salt pillows are present above the 125 Ma horizon (approximate top Barremian system) and on the 66 Ma horizon (top Cretaceous system) throughout the Mensa minibasin, whereas the top Cretaceous allochthonous salt system is identified regionally by a salt weld in the Thunder Horse area. These allochthonous salt systems formed weld surfaces beneath the Mensa and Thunder Horse turtle structures. Structural features and associated minibasins evolved during several discrete intervals. From the Early Cretaceous through the latest Oligocene (125 to 24 Ma), an extensive allochthonous salt canopy was present within the Mensa and Thunder Horse minibasins. During this interval, sediments loaded the salt, forming thin wedge- and sheet-form deposits in the Mensa area and a thick, northwest-trending trough in the Thunder Horse area. A secondary allochthonous salt system extruded at the Top Cretaceous level, as seen by remnant salt bodies. Salt withdrawal from these allochthonous salt systems provided accommodation for bowl- and trough-shaped external stratigraphic forms to develop during the Miocene. High sedimentation rates produced salt evacuation from these allochthonous salt systems and initiated diapirism that formed the Neogene allochthonous salt level. The prominent turtle structures in the two minibasins, critical to the formation of traps to the two major fields, developed at slightly different times: Thunder Horse at 14.35 and Mensa at 11.4 Ma.

Description: The 86 fields and discoveries in the central Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and Lloyd Ridge protraction areas are summarized with production characteristics and representative seismic profiles and wire-line logs. Three trap styles are recognized: four-way closure, three-way closure, and stratigraphic. The reservoirs in nearly all of the fields are Neogene deep-water sandstones; four are in Upper Jurassic eolian sandstones. Development facilities include a variety of floating platforms and production units and subsea tiebacks.

Description: The petroleum systems of two adjacent Miocene intraslope minibasins in the northern deep-water Gulf of Mexico are modeled to investigate why one of them produces primarily gas but the other produces oil. Specifically, the Mensa field produces gas from a faulted four-way closure that overlies a turtle structure, whereas the adjacent Thunder Horse field produces from a turtle structure with four-way structural closure. To resolve this issue, a three-dimensional petroleum-system model was constructed, whose results indicate that the Lower Cretaceous source interval, comprising type II kerogen, matured significantly earlier in the Mensa basin; the oil window was reached between 11.4 and 9.0 Ma, and the thermogenic gas window was reached between 6.2 and 0.0 Ma. By contrast, within the Thunder Horse basin, the source interval reached the oil window by 10.75 to 9.4 Ma and largely remains in the oil window. The Thunder Horse trap had formed by 13.05 Ma, which was before the end of the oil window. The Mensa trap (9.0–8.2 Ma) was not in place when the source rock passed though the oil window. The primary control on the timing of maturation and charge is related to the original thickness of allochthonous salt that created the accommodation for the thick Miocene deep-water sediments. Originally, the Mensa minibasin contained thicker Cretaceous allochthonous salt than the Thunder Horse minibasin. Consequently, as the salt was loaded with sediment and completely evacuated, the turtle structure (trap) formed earlier in Thunder Horse field than in Mensa. By contrast, the source rocks matured earlier in Mensa, prior to the deposition of reservoir sands and the formation of the trap. The results indicate that turtle structures with similar appearances can have subtle differences in the timing of their petroleum systems, which ultimately control whether the feature is charged and with what fluid. These features must be modeled carefully in evaluating their exploration potential.

Description: The structural framework and evolution from the Middle Jurassic to the present of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas consist of a complex history influenced by basement fabric, multiple stages of salt movement, and gravitational gliding. A detailed tectono-stratigraphic interpretation of the study area indicates that three main stages of salt movement controlled sediment dispersal patterns and the formation and evolution of intraslope minibasins. These three stages of salt movement occurred during the Cretaceous, the Paleogene, and the Neogene. Basement structures were the primary control on initial salt kinematics, affecting gravity-driven slope deformation and resulting in a wide variety of structural styles. Basement (acoustic basement) structures (horsts, grabens, and half grabens) formed prior to the deposition of the Middle Jurassic autochthonous Louann Salt. These features are interpreted to have controlled the original thickness of the autochthonous salt layer and subsequent salt-withdrawal patterns. Mesozoic structures, such as extensional-compressional gliding systems and expulsion rollovers, formed above the autochthonous salt. Three levels of allochthonous salt systems are identified: (1) approximate top Barremian, (2) top Cretaceous, and (3) intra-Neogene (between 10 and 4 Ma). Early emplacement of two allochthonous salt layers is present in the northeastern part of the study area, whereas the Neogene allochthonous salt system extends throughout the Mississippi Canyon, western DeSoto Canyon, and northern Atwater Valley protraction areas. Salt from the autochthonous and two deep allochthonous salt layers was expelled vertically and basinward during the Neogene, feeding the younger allochthonous salt systems. The autochthonous and deep allochthonous salt layers were detachments for many of the large Neogene extensional (growth faults and turtles) and contractional (anticlines and thrust faults) structures, whereas the Neogene allochthonous salt system accommodated suprasalt minibasins associated with counterregional and roho salt systems. These three allochthonous salt layers were successively loaded by gravity-flow sediments, resulting in deep (above autochthonous or deep allochthonous salt layers) and shallow (supra-Neogene allochthonous salt) minibasin formations and local development of extensive salt welds. Northwest–southeast-oriented strike-slip structures, active during the Neogene, are present in the salt province within the study area. They are related to basinwide heterogeneities in the salt distribution and are controlled by differential basinward movement of adjacent suprasalt minibasins.

Description: Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO 4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.

Description: This study evaluates the proportion, length, and effective properties of thin (0.003–0.7 m [0.01–2.3 ft]) shale beds and drapes in tidally influenced channels within a compound valley fill with a focus on estimating geologically based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial–tidal systems with primary reservoirs being deposited as tidally influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging–derived digital outcrop models have been used to characterize shale length, width, thickness, and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in valley 1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in valley 2 (V2) were abundant, short, common, and equidimensional, suggesting deposition by more tidally influenced meandering rivers. Short, frequent, and equidimensional shales in valley 3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone–shale model was used to estimate the effects of shales on vertical to horizontal permeability ratio ( \[{k}_{v}/{k}_{h} \] ). The unique character of each depositional unit was reflected in resultant \[{k}_{v}/{k}_{h} \] distributions. The valley fill deposits, V1, V2, and V3, had average \[{k}_{v}/{k}_{h} \] ratios of 0.11, 0.09, and 0.17, respectively. More tidally influenced reservoirs such as the studied V2 had short but frequent shales, which resulted in low \[{k}_{v}/{k}_{h} \] estimates. Estimates of \[{k}_{v}/{k}_{h} \] for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.

Description: The Permian Khuff-C reservoir in Saudi Arabia is known for its lateral and vertical heterogeneity caused mainly by dolomitization. Detailed petrographic analysis of 600 thin sections, from six cored wells, revealed three main replacive dolomite fabrics: (1) fabric-preserving mimetic (FPM), (2) fabric-preserving nonmimetic (FPNM), and (3) fabric-destructive (FD) dolomites. Crystal sizes are mostly less than or equal to 20 μm for FPM dolomite, less than or equal to 50 μm for FPNM dolomite, and less than or equal to 100 μm for FD dolomite. The FPM dolomite decreases in abundance, and FPNM dolomite increases in abundance, with increasing grain content of the facies. The 18 O values of dolostones (although considered an obsolete term, dolostone is used here to mean rock containing ≥80% dolomite) indicate early dolomitization at low temperatures in Permian seawater or evaporated seawater, with landward facies (mudstone and wackestone) generally dolomitized by more evaporated waters and seaward grainy facies generally dolomitized by less evaporated, more normal marine seawaters. Stratigraphic variations in the dolostones’ 18 O values track with facies variations through fourth-order depositional sequences and indicate that different stratigraphic bodies of dolomite formed from seawaters with different degrees of evaporation. The 13 C values of the dolostones exhibit temporal trends inherited from the precursor limestones. Variations in the lateral and vertical abundance of dolomite and dolomite fabrics, in the propensity for each facies to be dolomitized, and in the dolomites’ oxygen isotopic values all suggest that multiple dolomitization events occurred in the Khuff-C reservoir as depositional cycles accumulated, with some dolostones overprinted by younger events. Average porosities of grain-rich dolostones are greater than those of mud-rich dolostones, indicating that depositional facies preordained porosity distribution within the dolostones. However, the more evaporated the dolomitizing fluid, the more likely dolomitization resulted in lower porosity regardless of facies.

Description: Outcrop studies of fracture development, used as analogs for subsurface fracture patterns, are critical because of the importance of fractures as fluid flow pathways and the fact that most fracture networks exist at a smaller resolution than current seismic data can resolve. Fracture networks in carbonate units are typically controlled by the mechanical properties of the unit, indicating that the mechanical stratigraphy, as well as the fracture stratigraphy, should be considered. This study presents the results of a fracture analysis in the Mississippian carbonates of the Ozark Plateau, considering both mechanical and fracture network characteristics. Mechanical characteristics of the succession were defined using a combination of rebound values and thin section petrography. Fracture characteristics included orientation and intensity, together with abutting relationships. Results indicate that fracture orientations show a distinct evolution throughout the measured succession, including the appearance of early systematic sets, followed by pervasive systematic fracture sets related to existing basement features. Fracture orientation changes do not correspond to changes in mechanical stratigraphy. Fracture intensity, however, is related to the thickness of the mechanical unit instead of the bed thickness and is greatest in less competent units. Mechanical control influences the fracture network on a smaller scale than that of regional tectonic stresses. Thus, evaluations of carbonate reservoirs must account for both the large-scale and the small-scale investigations into fracture characteristic controls. Outcrop evaluations are of critical importance to properly assess characteristics that are challenging to recover from conventional subsurface data sets such as core and seismic reflection volumes.

Description: The results of petroleum system models (PSM) critically depend on the computed evolution of the temperature field. Because PSM typically only resolve the sedimentary basin and not the entire lithosphere, it is necessary to apply a basement–heat-flow boundary condition inferred from well data, surface–heat-flow measurements, and an assumed tectonic scenario. The purpose of this paper is to assess the use of surface–heat-flow measurements to calibrate basin models. We show that a simple relationship between surface and basement heat flow only exists in thermal steady state and that transient processes such as rifting and sediment deposition will lead to a decoupling. We study this relationship in extensional sedimentary basins with a one-dimensional, lithosphere-scale finite element model. The numerical model was built to capture the large-scale dynamic evolution of the lithosphere and simultaneously solve for transient thermal processes in basin evolution, such as sedimentation, compaction-driven fluid flow, and seafloor temperature variations. Our analysis shows that several corrections need to be applied when using surface–heat-flow information for the calibration of basement heat flow in PSM. Not doing so can lead to significant errors of up to 30°C–50°C (86°F–122°F) at typical petroleum-reservoir and source-rock depths. We further show that resolving sediment-blanketing effects in basin modeling is crucial, with the thermal impact of sediment deposition being at least as important as rifting-induced basement–heat-flow variations.

Description: The Lower Mississippian upper shale member of the Bakken Formation in the Williston Basin, North Dakota, consists of organic-rich, black, siliciclastic mudstones deposited offshore on a low-gradient shelf; 12 fine-grained facies are recognized and grouped into 5 facies associations (FAs). Very fine-grained, massive to faintly laminated mudstone (FA1) records deposition in the deepest, calmest parts of the basin, whereas well-laminated mudstones (FA2a); well-laminated, clay-clast–bearing mudstones (FA2b); burrow-mottled mudstone with shells (FA3); and interlaminated siltstone and mudstone (FA4) suggest deposition in the shallower, less calm, and more proximal offshore environment. These proximal-offshore mudstones (FA2a, FA2b, FA3, and FA4) reflect (1) variation in bottom-water oxygen levels and (2) lateral changes in the input of silt and clay clasts. Ubiquitous Phycosiphon fecal strings, patches of shells, burrows, and rare agglutinated foraminifera indicate dysoxic to suboxic basinal deposition and not a persistently anoxic environment. In all FAs, storm-event laminae are sparse to ubiquitous. Repeated stacking of FAs defines up to 10 coarsening-upward parasequences mostly 0.15–0.60 m (0.49–1.97 ft) thick. Individual parasequences can be correlated for 300 km (180 mi) through the basin. The lower half of the succession (interval 1) represents a transgressive systems tract and shows high radiolarian productivity with minor silt input. The upper half of the succession (interval 2) represents the base of a highstand systems tract. In contrast to interval 1, interval 2 mudstones are characterized by high clay content, low radiolarian productivity, and intermittent colonization of the sea floor during higher-order sea-level lowstands.

Description: The Fort Worth basin in northcentral Texas is a major shale-gas producer, yet its subsidence history and relationship to the Ouachita fold-thrust belt have not been well understood. We studied the depositional patterns of the basin during the late Paleozoic by correlating well logs and constructing structure and isopach maps. We then modeled the one-dimensional (1-D) and two-dimensional subsidence history of the basin and constrained its relationship to the Ouachita orogen. Because the super-Middle Pennsylvanian strata were largely eroded in the region, adding uncertainty to the subsidence reconstruction, we used PetroMod 1-D to conduct thermal-maturation modeling to constrain the post-Middle Pennsylvanian burial and exhumation history by matching the modeled vitrinite reflectance with measured vitrinite reflectance along five depth profiles. Our results of depositional patterns show that the tectonic uplift of the Muenster uplift to the northeast of the basin influenced subsidence as early as the Middle Mississippian, and the Ouachita orogen became the primary tectonic load by the late Middle Pennsylvanian when the depocenter shifted to the east. Our results show that the basin experienced 3.7–5.2 km (12,100–17,100 ft) of burial during the Pennsylvanian, and the burial depth deepens toward the east. We attributed the causes of deep Pennsylvanian burial and its spatial variation to flexural subsidence that continued into the Late Pennsylvanian in response to the growth of the Ouachita orogen and southeastward suturing of Laurentia and Gondwana. The modeling results also suggest that the Mississippian Barnett Shale reached the gas maturation window during the Middle–Late Pennsylvanian.

Description: Compaction disequilibrium is a widely accepted cause of overpressure, especially in clay-rich, rapidly deposited sediments. Clay diagenesis has been associated with the occurrence of overpressure greater than the compaction disequilibrium overpressure. These observations have led to the expectation that overpressure will be greater than the compaction disequilibrium contribution when clay diagenesis occurs within an overpressured mudstone. Clay diagenesis have been reported in a Pliocene section of a well from the Gulf of Mexico, offshore Louisiana. Pressure and log data from that well indicate that despite clay diagenesis, the overpressure can be attributed solely to compaction disequilibrium. This paper examines the whole mudstone and clay mineralogy composition and petrophysical characteristics of the offshore Louisiana well with clay diagenesis, but without a diagenesis contribution to overpressure and contrasts that data with results from other clay diagenesis and petrophysical studies. The comparison suggests that the offshore Louisiana well was relatively smectite poor compared with wells from regions associated with a clay diagenesis contribution to overpressure. The lower smectite content resulted in a lower percentage of reacted volume that was insufficient to allow the load transfer often associated with clay diagenesis. Petrophysical features of the offshore Louisiana well and nearby wells differ from the features associated with clay diagenesis in other Gulf of Mexico wells and a limited number of international wells. Comparison of location, age, depositional package, clay mineralogy, and petrophysical features suggests that provenance may control the occurrence of Gulf of Mexico mudstones that do not experience increased overpressure as a result of clay diagenesis.

Description: Fresh cores from tight-rock samples of subsurface hydrocarbon reservoirs retain mobile fluids. These fluids have complex chemical compositions and a large spectrum of molecules with different diameters and polarities. When investigated using high-resolution field-emission scanning electron microscopy (SEM), the imposed vacuum over hours of time causes pore fluids trapped in the rock sample to flow and interact with the mineral matrix. This paper reports the capillary fluid dynamics effect observed on freshly milled cross sections of tight chalk at high resolution. Multiphase fluid dynamic simulations confirm the aggregation of heavier fluid molecules on the geometrical irregularities of the pore space. As a consequence of this pitfall, the differentiation of solid organic matter versus variably viscous hydrocarbons from SEM data is subject to a fundamental revision.

Description: This study analyzed crude oils from the lower part of the third member of the Eocene Shahejie Formation (Es 3 L ) and three prospective source rocks from the Shulu sag, Bohai Bay basin, eastern China, using a variety of organic geochemical methods. Biomarker characteristics were used to interpret source rock organic matter input and depositional environment, and oil–source rock correlation. The biomarker data indicate that the crude oils originated from the Es 3 L source rock, which contains a mixture of plankton and land plant organic matters deposited in brackish–fresh water under reducing conditions. The oil in the Es 3 L is self-sourced instead of migrated from the overlying source rocks. The petroleum generation potential of the Es 3 L source rock was evaluated using organic geochemistry. Total organic carbon (TOC) values for approximately 100 samples are between 1.02 and 4.92 wt. %, and hydrogen indices range from 285 to 810 mg hydrocarbons/g TOC. The Es 3 L source rock contains mainly type II and III kerogen, and most of the samples are thermally mature. The data show that the Es 3 L source rock has good potential for liquid hydrocarbon generation. The Es 3 L rock also acts as the oil reservoir, having very low bulk porosity and permeability. Various types of storage space in the marlstone and carbonate rudstone in the Es 3 L of the Shulu sag include (1) fractures, (2) intergranular pores, (3) dissolution pores, (4) organic matter pores, (5) intragranular pores, and (6) seams around gravels. Pore size ranges from nanometers to millimeters. Because the oil was generated and stored in Es 3 L strata, which lack any obvious trap and seal and have low permeability, the unit represents a continuous petroleum accumulation.

Description: This paper shows how nonuniform source–receiver spacing in a three-dimensional (3-D) land acquisition creates footprints that could easily be mistaken for geology. In a 3-D time-migrated seismic volume from the midcontinent United States, amplitude extraction along the top of the Mississippian limestone formation shows a sinkhole-like feature, which is justified from a depositional perspective. However, an inspection of the acquisition layout shows that the sinkhole is a replica of the fold distribution. In land surveys where source and receivers seldom have a regular distribution and for unconventional plays that are not developed through patterned drilling, a thorough review of processing and acquisition parameters is necessary before interpreting amplitude maps.

Description: We use experimental (analog) models to examine the three-dimensional (3-D) fault geometries and interactions that develop during two phases of noncoaxial extension. In the models, a homogeneous layer of wet clay undergoes two phases of extension whose directions differ by 45°. The resulting fault pattern varies significantly with depth. At shallow levels, second-phase normal faults accommodate most second-phase extension. At depth, both second-phase normal faults and reactivated, first-phase faults with oblique slip accommodate most second-phase extension. A variety of interactions occurs between first-phase and second-phase faults. One interaction involves the upward propagation of second-phase faults from tips of reactivated, blind, first-phase faults. These hybrid faults have deep segments that strike subperpendicular to the first-phase extension direction and shallow segments whose strike varies with depth, becoming increasingly subperpendicular to the second-phase extension direction at shallow levels. A second interaction involves the nucleation of second-phase normal faults on the surfaces of reactivated, first-phase faults. These splay faults propagate upward and laterally from their nucleation sites into the hanging walls of the first-phase faults. As they propagate, they commonly encounter and link with different first-phase faults. The resulting composite faults have zigzag geometries in both map and cross-sectional views. A third interaction involves either the termination of second-phase antithetic normal faults against or near first-phase faults or the offset of first-phase faults by second-phase antithetic normal faults. The 3-D fault patterns and interactions within our models closely resemble those within the Taranaki basin of offshore New Zealand and Milne Point on Alaska’s North Slope.

Description: The geochemistry and reservoir characteristics of the lacustrine shale in the Eocene Dongying depression are described in detail based on thin-section and field-emission–scanning electron microscope observations of well cores combined with x-ray diffraction, physical property testing, and geochemical indicators. The Eocene Shahejie (Es) Formation Es4s–Es3x shale member is predominantly carbonate, clay minerals, and quartz. Six lithofacies were identified: (1) laminated limestone (organic-rich laminated limestone and organic-poor laminated limestone), (2) laminated marl, (3) laminated calcareous mudstone, (4) laminated dolomite mudstone, (5) laminated gypsum mudstone, and (6) massive mudstone. The Es4s–Es3x shale samples from three cored wells had total organic carbon (TOC) contents in the range of 0.58 to 11.4 wt. %, with an average of 3.17 wt. %. The hydrocarbon generation potential (free hydrocarbons [S1] + the hydrocarbons cracked from kerogen [S2]) values range from 2.53 to 87.68 mg/g, with an average of 24.19 mg/g. The Es4s–Es3x shale of the Dongying depression has a high organic-matter content with very good or excellent hydrocarbon generation potential. The organic maceral composition is predominantly sapropelinite (up to 95%). The hydrogen index (being S2/TOC) versus the maximum yield temperature of pyrolysate ( T max ) indicates that the organic matter is predominantly type I kerogen, which contains a high proportion of convertible organic carbon. The Es4s–Es3x shale is thermally mature and within the oil window, with the vitrinite reflectance values ranging from 0.46% to 0.74% and the T max value ranging from 413°C to 450°C, with the average being 442°C. The shale contains interparticle pores, organic-matter pores, dissolution pores, intracrystalline pores, interlaminar fractures, tectonic fractures, and abnormal-pressure fractures. The primary matrix pore storage is secondary recrystallized intercrystal pores and dissolution pores that formed during thermal maturation of organic matter. The TOC content and effective thickness of the organic-rich shales are the primary factors for hydrocarbon generation. The reservoir capacity is related to the scale, abundance, and connectivity of pore spaces, which are controlled by the characteristics of the lithofacies, mineral composition, TOC content, and microfractures.

Description: A succession of four deep-water lobe complexes deposited within a salt-controlled minibasin have been imaged in unprecedented detail on high-resolution, high-frequency, three-dimensional seismic-reflection data. The ponded interval was deposited over approximately 2.7 m.y. and consists of four discrete sequences, each of which contains one lobe complex. A systematic change exists in the shape and orientation of the lobe complexes through time: the two older lobe complexes are oriented broadly north–south and are up to 10 km (6 mi) long by 5 km (3 mi) wide, whereas the youngest lobe complexes are oriented southeast–northwest and have a rounder shape (9 km [6 mi] long by 8 km [5 mi] wide). The north–to-south migration of the feeder-channel entry point and the change in lobe-complex orientation are attributed to growth of the basin-bounding salt structures. Each lobe complex is composed of a feeder channel, multiple individual lobes formed of a trunk channel, and a diverging network of smaller distributary channels, commonly fringed by a high-amplitude band. The lobes are on average 1.6 km (1 mi) long by 1.3 km (0.8 mi) wide and are fed by trunk channels that range from 60 to 200 m (197 ft to 656 ft) wide, with thicknesses up to 15 m (49 ft). Variations in lobe shape and spatial location are driven by the response of the lobes to topographic growth along the edge of the basin and inherited seabed relief generated by previous lobe growth. In areas where lobe development is constrained by structural growth along the edge of the basin, the lobes become elongated and divert away from the growing topography. Lobe complexes of similar scales have been described in detail in outcrops and in unconfined settings on the sea floor, but this is the first study to describe these systems in such detail in the subsurface, resolving the individual lobes and lobe elements within a ponded intraslope basin. The high-resolution plan-view images help bridge the gap between the fine-scale sedimentological studies that have been carried out on lobe complexes and sheet sands in outcrop for the past 20 yr and more recent research on less well-resolved seismically imaged systems. The sheet sands described in outcrop studies can be correlated with features seen in the plan-view amplitude extraction maps. We record densely channelized lobes passing laterally into more branched, thinner channels and lobe elements then terminating in a high-amplitude fringe. We relate these seismic characteristics to outcrop facies of channelized, amalgamated, and layered sheets.

Description: Confidently defining the trajectory of faults that control structural traps is a recurring challenge for seismic interpreters. In regions with fault-related folds, seismic and well data often constrain the upper fold geometry, but the location and displacement of the controlling fault are unknown. We present a generalized area–depth strain (ADS) analysis method that uses the observed depth variation in deformed horizon areas to directly estimate underlying fault depth, dip, displacement, and layer-parallel strain from a structural interpretation. Previously established ADS methods are only applicable to structures controlled by faults that sole into layer-parallel detachments. The new technique, referred to as the fault-trajectory method, generalizes ADS analysis to contractional and extensional structures controlled by fault ramps that cut across layers and displace the regional. For structures where area is conserved during deformation and shear is minimal, laterally shifting the analysis limits across the structure defines changes in fault orientation. We validate the method by applying it to numerical forward models, analog clay models, and seismically imaged structures from the San Joaquin basin in California, the Sierras Pampeanas in Argentina, and the North Sea. The fault-trajectory method is shown to be robust, because it exactly reproduces the prescribed fault trajectories and displacements used to construct the numerical and analog models. In the natural examples, the ADS-estimated fault trajectories are consistent with independent fault-location constraints such as earthquake focal mechanisms, seismic imaging, and forward modeling.

Description: Well logs such as spontaneous potential and gamma ray historically have been the only tools available for facies evaluation of noncored wells in the McMurray Formation. The addition of microresistivity image logs has greatly improved facies identifications and interpretations, particularly when integrated with core data sets. In the case of McMurray channel complexes, core descriptions provide detail about bedding contacts, sedimentary texture, stratification, bioturbation intensity, and trace fossil diversity. Image logs provide texture, fabric, bedding contact style, dip directions and angles, and bedding architecture information, yielding paleoflow and lateral accretion directions. This study characterizes facies by integrating interpretations from 414 image logs with core-based descriptions from 138 of these wells. The reservoir targets, and most prolific depositional facies in this study, are associated with channel systems and their associated point-bar deposits. Facies identifications are based on several image log criteria. Mud clast breccias display variable dip angles and dip directions. Cross-stratified sands comprise vertical successions of stacked, internally consistent bedsets with high dip angles (〉15°) that indicate paleoflow direction. Lateral accretion beds show consistent dip directions with a progressive change from shallow-to-steep-to-shallow dip angles (e.g., 〈4 to 15° to 〈4°) from the base to the top of the succession, as well as beds that dip toward the thalweg of the paleochannel. Flat-lying (〈4°) mud records vertical accretion associated with point-bar tops or channel abandonment. Although this facies classification is specific to the McMurray Formation in the study area, the principles provided here are applicable to other subsurface studies and demonstrate the enhanced reliability of integrated core–image log data sets.

Description: The northeastern Brooks Range of northern Alaska is an active, north-directed fold-and-thrust belt that is advancing on the Barrow arch and the north-facing passive margin of the Arctic Basin. Density logs, leak-off tests, and mud-weight profiles from 57 wells from the northeastern North Slope were used to determine the magnitude of the present-day in situ stresses and document significant regional lateral and vertical variations in relative stress magnitude. Preliminary analysis of the in situ stress magnitudes indicates two distinct stress regimes across this region of Alaska. Areas adjacent to the eastern Barrow arch exhibit both strike-slip and normal stress regimes. This in situ stress regime is consistent with fault patterns in the subsurface and with north–south extension along the Barrow arch and the northern Alaska margin. To the south in and near the northeastern Brooks Range thrust front, in situ stress magnitudes indicate that an active thrust-fault regime is present at depths up to 6000 ft (1829 m). This is consistent with the fold-and-thrust structures in surface exposures and in the subsurface. However, at depths greater than 6000 ft (1829 m), the relative in situ stress magnitudes indicate a change to a strike-slip regime. This observation is consistent with the few earthquake focal mechanisms in the area and suggests deep north-northeast–oriented strike-slip faults may underlie the western margin of the northeastern Brooks Range.

Description: The geometry and growth of normal faults are fundamental to the evolution and petroleum prospectivity of sedimentary basins, controlling trap development; source, reservoir, and seal rock distribution; and fluid flow. The poorly studied, petroliferous Ceduna Subbasin located offshore southern Australia contains an east–southeast-striking, gravity-driven fault array, which soles out onto a southwest-dipping detachment horizon. These gravity-driven faults displace the White Pointer delta and overlying Hammerhead delta. Within the subbasin, structural closures bound by these gravity-driven faults represent the main exploration targets. Determining when these faults and associated traps formed relative to petroleum generation and migration and, more specifically, if the faults reactivated is thus critical to understanding the prospectivity of the Ceduna Subbasin. In this study, we use a time-migrated two-dimensional (2-D) seismic reflection survey covering the central Ceduna Subbasin to constrain the geometry and kinematics of the fault array. Throw patterns reveal that most faults nucleated in the Cenomanian. Although some faults display evidence for continuous growth by upper tip propagation throughout the Cenomanian to Maastrichtian, it is apparent that other faults were inactive during the Turonian–Santonian, before reactivating and propagating upward or dip-linking with overlying, newly formed faults during the Campanian and/or Maastrichtian. Faults that grew continuously during the Cenomanian to Maastrichtian primarily formed in the center of the study area, whereas reactivated faults developed in landward positions. Faults that formed because of dip linkage developed in seaward positions. We suggest that this spatial variation in fault growth style was controlled by compositional and mechanical heterogeneities in the Tiger and lower Hammerhead supersequences, which mark the boundary between the two delta systems. In addition to providing insights into the petroleum prospectivity of the Ceduna Subbasin, this study shows how 2-D seismic reflection data can be used to probe the kinematics of normal faults.

Description: The vast majority of discovered oils in the Bohai offshore area have undergone biodegradation ranging from 1 to 9 on the PM scale (a scale to rank the level of biodegradation, proposed by Peters and Moldowan, 1993 ). The extent of distribution and biodegradation of all discovered oils in the Bohai offshore area was investigated systematically using geologic and geochemical data to reveal controlling factors of varying levels of biodegraded oils. Based on the analysis of the environment and material significances and the resistance to degradation of biomarkers, the biomarker parameter assemblage that is suitable for the oil-source correlation of severely biodegraded oils (higher than PM 6) in the Bohai offshore area was determined. The spatial distribution and biodegradation extent are mainly controlled by the current burial depth, the duration of biodegradation, the area of the oil–water contact (OWC), and a late strike-slip movement of the Tanlu fault. Almost all biodegraded oils are found in shallow reservoirs above 2000 m (6562 ft). The longer the oils are present in these reservoirs or the larger the area of the OWC the reservoirs show, the greater the extent of biodegradation will be. The late, strong strike-slip movement of the Tanlu fault may have significantly enhanced the biodegradation extent of several oils in fields located in the Tanlu fault zone by introducing oxygenated freshwater from the surface or near surface and creating a more suitable environment for biodegradation. The C 19 tricyclic terpane/C 23 tricyclic terpane, C 24 tetracyclic/C 26 tricyclic terpane, and gammacerane/C 24 Tetracyclic do not seem to be influenced by biodegradation and show obvious differences between the three different source-rock intervals. Such a biomarker parameter assemblage can be used successfully to determine the origin of severely biodegraded oils (higher than PM 6) by correlating with extracts of possible source rocks in the Bohai offshore area.

Description: The successful implementation of geologic carbon sequestration depends on the careful evaluation of the petrophysical characteristics of the storage reservoir. Two petrophysical properties, porosity and permeability, constrain the reservoir in terms of its storage potential and injectivity. These two key parameters may vary significantly in scale within a reservoir. Likewise, the analytical tools that are useful for measuring these properties also vary and only assess pores of a given scale. In this investigation, 52 rock samples that consist of carbonates having a high degree of dolomitization were obtained from the Cambrian–Ordovician Knox Supergroup from different depth intervals; these samples span a significant area of the Midwestern United States. The samples were analyzed for total porosity and pore-size distribution using a variety of techniques, including petrographic image analysis, helium porosimetry, gas adsorption, mercury porosimetry, and ultrasmall-angle/small-angle neutron scattering. Capillary entrapment, or "residual saturation," is that part of the injected CO 2 that remains trapped in micropores after the pressure elevated by the injection process returns to ambient reservoir pressure. Results from low-pressure nitrogen and carbon dioxide adsorption and from mercury injection capillary pressure are important in that they provide insights about small pore size that otherwise cannot be resolved by standard helium porosimetry or by image analysis software. Results from these analyses suggest that micro- and mesoporosity control capillary entrapment, whereas macroporosity controls permeability.

Description: Cambrian–Ordovician strata of the midwestern United States are considered a promising reservoir for geologic storage of carbon dioxide. To assess the potential of the Ordovician St. Peter Sandstone, storage-resource estimates were generated using a hierarchical approach to estimating prospective storage resources. The method employs a series of increasingly sophisticated analyses to better facilitate an understanding of the uncertainty in the estimates. Results demonstrate how uncertainty of storage-resource estimates varies as a function of data availability and quality as well as the underlying assumptions used in the application of specific storage efficiency factors. In the simplest analysis, storage-resource estimates were calculated from updated regional-scale mapping of the gross thickness of the formation and by applying a single best estimate of the mean porosity for the entire formation. This analysis follows the technique prescribed by the US Department of Energy and yields storage-resource estimates ranging from 3.3 to 35.1 billion t CO 2 in the Michigan Basin and 1.0 to 11.0 billion t CO 2 in the Illinois Basin at the 10% and 90% probability levels. The second analysis incorporated generalized models of the diagenetic history of the formation throughout the two basins by implementing depth-dependent functions of porosity that lead to more realistic portrayals of spatially variable results. Similar resource estimates were calculated for the Michigan Basin, but reduced estimates (43%) were found for the Illinois Basin. The third analysis explicitly accounted for the local-scale spatial variability in reservoir quality using net-porosity calculations, resulting in a significant increase in the low-range resource estimate for the Michigan Basin and dramatic increases for Illinois Basin resource estimates (factor of 3 to 11 increases). A fourth analysis was conducted for the Michigan Basin that used advanced reservoir characterization to define reservoir properties for multiple reservoir facies and yielded resource estimates significantly larger than the third analysis and a larger range of uncertainty. This study highlights how different factors impact the expected uncertainty in storage-resource estimates, and analysis suggests that estimates from the first two approaches provide excessively conservative results, whereas the second two approaches tend to overestimate the resource.

Description: Two different approaches have been used to evaluate the potential for CO 2 geologic sequestration and CO 2 -assisted enhanced oil recovery in the major oil fields in Ohio: a volumetrics-based method, which uses field volumetric data to calculate CO 2 storage capacity, and a production-based method, which uses historical oil and gas production data to calculate CO 2 storage capacity. The fields were selected based on their historical importance as oil and gas producers as well as the availability of data in published sources. The storage capacity found using the production data–based methodology—878 million t—is believed to be more representative than that found using the volumetrics-based method because it uses actual production data to calculate void space for CO 2 storage rather than estimated efficiency factors. This estimated capacity is higher than previously reported values based on efficiency factors and is enough to support the storage of 25% of annual emissions from 45 of Ohio’s largest power plants for a period of 36 yr.

Description: The type section of the Oligocene to lower Miocene Maikop Group, considered the main source rock in the eastern Paratethys, has been studied using geochemical proxies to gain insights into depositional setting and hydrocarbon potential. The Maikop Group at the type section is approximately 600 m (2000 ft) thick. Deposition commenced after a major late Eocene sea level drop and a subsequent early Oligocene sea level rise. The Maikop Group is composed mainly of carbonate-free pelitic rocks. Calcareous rocks are limited to the lower Oligocene succession, including the Polbian Bed that forms a basin-wide marker horizon deposited during a time with significantly decreased salinity (Solenovian event). Anoxic conditions prevailed and were only interrupted for longer periods during deposition of the lower part of the lower Oligocene Pshekha Formation, the Polbian Bed, and the lower Miocene Olginskaya Formation. Total organic carbon (TOC) contents range up to 3.5 wt. %. Hydrogen index values are typically less than 300 mg hydrocarbons (HC)/g TOC but reach 420 mg HC/g TOC in black shales overlying the Polbian Bed (lower Morozkina Balka Formation). Organic richness of this level, approximately 10 m (33 ft) thick, is controlled by low salinity and high bioproductivity. The Maikop Group could generate approximately 2.0 t HC/m 2 surface area. A significant part (0.45 t/m 2 ) comes from the lower Morozkina Balka Formation, which generates a high-wax paraffinic–naphthenic–aromatic mixed oil. The Pshekha, upper Morozkina Balka, and Batalpashinsk Formations would generate low-wax oil or condensate. The hydrocarbon generation potential of the overlying formations is minor. Overall, the generation potential of the Maikop Group is surprisingly low.

Description: Micropore-dominated carbonate reservoirs remain challenging for accurate hydrocarbon evaluation and production because conventional reservoir models using depositional textures and petrophysical properties to distribute porosity and permeability cannot be applied. Nevertheless, understanding the distribution of pore systems and predicting the fluid flow behavior of microporous reservoirs is fundamental because micropores constitute a significant percentage of the total porosity and storage capacity. We present the results from an integrated study on the producing micropore-dominated Word field characterized by a facies-independent, diagenetically controlled pore system that approaches 100% microporosity. Four cored wells through the Albian Edwards Formation were described and correlated using stacking patterns and vertical facies trends; pore type characterization was done through thin section petrography, routine core analyses, scanning electron microscopy, and mercury injection capillary pressure data. This study is an example of a permeable reservoir in which intergrain pores are cemented during burial diagenesis and micropores, being more resistant to cementation, remain open to depths greater than 4000 m (13,000 ft). A unique relationship exists between porosity, permeability, median pore throat size, and microcrystalline textures, independent of facies and fabrics. Cumulative gas production data show there is a correlation between the total porosity and the structural position of the wells: wells high on the structure have the highest production. We demonstrate that an equally well–connected micropore network exists in mud-dominated rocks via the matrix and via grain-to-grain contacts in grain-dominated rocks. The here described intragrain micropore network through grain-to-grain contacts in cemented grainstones is a new carbonate flow path that will likely become more important as more unconventional carbonate reservoirs are explored.