ALBERT

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Węglówka oil field is located in the outer Carpathians. The outer Carpathians are a region where hydrocarbons were discovered and exploited at the end of the nineteenth century in several dozen oil fields, which are relatively small. The Węglówka oil field is one of the largest in this region. In the 150 yr or so of hydrocarbon exploration in the area, more than 1 million t (〉1,237,000 tons [〉8,841,000 bbl]) of oil have been produced. Hydrocarbons are concentrated in Lower Cretaceous sandstones (Grodziszcze and Lgota sandstones) that form an anticline sealed by Upper Cretaceous marls called the Węglówka marls. These cap rocks are up to 600 m (2000 ft) thick. Because of the thrust-related exhumation, they were exposed at the surface and represent the youngest deposits in the region. The present work is focused on a detailed petrographic characterization of the Węglówka marls. This study allows petroleum geologists to better understand the evolution of porosity in these cap rocks and can serve as a foundation for the prediction of their sealing properties. The marls appear as a succession of interbedded red and green varieties, which occur in up to 2-m (6-ft)-thick beds. These beds are nonarenaceous, soft, and bioturbated. Grain size corresponds to approximately 80% clay and less than 20% silt fractions. X-ray diffraction (XRD) reveals that the marls contain, on average, 54% clay, 28% calcite, 16% quartz, up to 3% feldspars and, in red marls, 3% hematite. The XRD patterns of clay are typical of mixed-layer illite–smectite ([I–S]; 40% illite in I–S). The clay structures are dioctahedral with similar octahedral Mg and relatively high Fe〈sup〉3〈/sup〉〈sup〉+〈/sup〉 contents both in the red and green intervals. As revealed by standard petrography combined with high-resolution petrography performed through the use of a field emission scanning electron microscope, the marls have mudstone textures according to Dunham’s (1962) classification and are mostly composed of coccoliths and clay with rare nanoquartz. This rock may be considered an impure chalk. Sealing properties of the Węglówka marls are indicated by the specific surface area, porosity, pore size, and permeability, calculated using N〈sub〉2〈/sub〉 gas adsorption, helium, and mercury porosimetry. The sealing potential is postulated to result from a combination of the following: (1) origin of components (i.e., deposition of minute calcareous bioclasts and volcanic material as a source for clay); (2) oxygenated sedimentary environment (as a result of the presence of oxygen in the sediments, burrowing caused the rocks to be homogenized); and (3) tectonic-induced clogging of pore space because of reorganization of clay flakes (the rocks were strongly tectonically deformed, which resulted in reduction of porosity in clay aggregates).〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Calcite cementation has been identified as an active process in the Upper Triassic Yanchang Formation throughout its burial history and as a major diagenetic factor causing strong reservoir heterogeneities. The origins of calcite cements and their relevance to reservoir heterogeneities were investigated using a suite of petrographic and geochemical methods, including optical microscopy with fluorescence and cathodoluminescence, scanning and backscattered electron microscopy with energy-dispersive spectrometry, x-ray diffraction, x-ray fluorescence, electron probe microanalysis, quantitative evaluation of minerals by scanning electron microscopy, fluid inclusion analysis, and carbon and oxygen stable isotope analyses. The sandstones are compositionally immature with relatively high amounts of volcanic rock fragments. The two generations of calcite cements are Ca-I and Ca-II. The Ca-I calcites are distributed along the interface of sandstone and mudstone units and were formed during the Late Triassic to Early Jurassic at formation temperatures of approximately 90°C. The Ca-II calcite mainly developed in the lower part of the fining-upward sandstone units and was formed in the Late Jurassic at higher temperatures of approximately 110°C. The origins of calcite cements were constrained by geochemical and isotope measurements, fluid inclusion homogenization temperature, and in situ element analysis. The Ca-I calcite cement originated from dissolution of the lacustrine depositional carbonates in the interbedded mudstones and reprecipitation in the adjacent sandstones. The Ca-II calcite was mainly related to organic matter decarboxylation, with Ca〈sup〉2+〈/sup〉 having been provided internally by volcanic fragment alteration and plagioclase dissolution. Calcite cementation had caused strong reservoir heterogeneities in the Yanchang Formation tight sandstones. The Ca-I calcite cementation destroyed reservoir properties along the interface of sandstones and mudstones. The lower parts of the fining-upward sandstone units were tightly cemented by Ca-II calcite, although they originally had high porosity and permeability. The middle–upper parts of the fining-upward sandstone units contain less calcite cements and thus have better preserved reservoir pores because of oil emplacement inhibiting the calcite cementation processes.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling shale gas field is located in a mountainous area, with well-developed underground rivers and karst caves. It also has a highly concentrated population, so the shale gas development in this field is faced with environmental protection problems. Combined with the characteristics of surface natural environment in the Fuling shale gas field and the features of shale gas development engineering, the main environmental issues encountered in the development of the Fuling shale gas field were analyzed. Studies on intensive land use, water conservation and protection, harmless use and disposal of oil-based drill cuttings, recycling of wastewater from drilling and fracturing, and green environment management mode for shale gas development were conducted, and the green development technology system suitable for the Fuling shale gas field was established. Field applications showed that, after applying the green development technology, the land occupation was reduced by 62.l%, the recycling rate of drilling and fracturing wastewater was up to 100%, the oil content of treated oil-based drill cuttings was less than 0.3%, and carbon dioxide emission was reduced by 64.47 × 10〈sup〉4〈/sup〉 t (1.41 × 10〈sup〉9〈/sup〉 lb). Thus, the goal of zero contamination was realized during shale gas field development. Research showed that the green and environmental protection development technology for the Fuling shale gas field has served as a valuable demonstration in the environmental protection in large-scale development of shale gas fields in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study, we determine the lateral and vertical extent of groundwater with less than 10,000 mg/L total dissolved solids near the Lost Hills–Belridge oil fields in northwestern Kern County, California, and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium, the primary protected aquifers in the area.The depth at which groundwater salinity surpasses 10,000 mg/L ranges from 150 m (500 ft) in the northwestern part of the study area to 490–550 m (1600–1800 ft) in the south and east, respectively, as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher-resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity because of infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells commonly exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base because of stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1800 ft) from the main group of disposal wells located along the east flank of South Belridge.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km〈sup〉2〈/sup〉 (10,000 mi〈sup〉2〈/sup〉). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In this paper, high-resolution three-dimensional seismic data are used to interpret a transpressional salt tectonic structure in the Yingxiongling area, Qaidam Basin, China. The geometries of the salt structure and the Shizigou fault system that intersects it are precisely depicted. The Shizigou fault system is composed of suprasalt and subsalt components. The suprasalt component is a Y-shaped reverse fault, and the subsalt component is a complex flower structure. In previous studies, suprasalt and subsalt components were interpreted as two independent fault systems. This paper proposes instead that the suprasalt and subsalt faults are kinematically related and decoupled across the salt layer.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉For oil-rich shales, current solvent extraction– and thermal extraction–based methods inaccurately measure hydrocarbon-filled porosity (〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉). Moreover, the hydrocarbon composition is not characterized by either method. Here, we show how open-system programmed thermal extraction and pyrolysis, LECO total organic carbon, Archimedes bulk density, and helium pycnometry measurements are integrated to calculate oil and gas pore volumes, characterize their composition, and estimate mobility. Use of a modified multiramp, slow-heating thermal extract, and pyrolysis temperature program further subdivides the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. Saturate–aromatic–resin–asphaltene (SARA) separation and gas chromatography of solvent-extracted organic matter and thermally extracted oils are used to compositionally classify the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. The segregated bulk compositions of gas- and oil-filled porosity measured via this method are shown to overlap and are broken into the following categories: gas-filled porosity (∼C〈sub〉1〈/sub〉–C〈sub〉14〈/sub〉), light oil–filled porosity (∼C〈sub〉6〈/sub〉–C〈sub〉36〈/sub〉), and heavy oil–filled porosity (∼C〈sub〉32〈/sub〉–C〈sub〉36〈/sub〉+). Furthermore, slow-heating multiramp thermal extraction can subdivide the light oil–filled porosity into four components capturing the C〈sub〉11〈/sub〉–C〈sub〉13〈/sub〉, C〈sub〉12〈/sub〉–C〈sub〉16〈/sub〉, C〈sub〉14〈/sub〉–C〈sub〉20〈/sub〉, and C〈sub〉17〈/sub〉–C〈sub〉36〈/sub〉 ranges of the extractable organic matter. Analysis of solvent-extracted oils by SARA identifies abundant saturates and aromatics in the light oil–filled porosity and abundant resins and asphaltenes in the heavy oil–filled porosity. Low-maturity shales can be dominated by heavy (C〈sub〉32〈/sub〉+) oils rich in asphaltene and resin fractions not observed in the produced fluid. The ratios of SARA components in the C〈sub〉15〈/sub〉+ fraction of produced fluid and core extract can be used to better estimate the potentially mobile 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 10〈sup〉10〈/sup〉 m〈sup〉3〈/sup〉 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10〈sup〉−13〈/sup〉 m〈sup〉2〈/sup〉/s (1.1 × 10〈sup〉−12〈/sup〉 ft〈sup〉2〈/sup〉/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of 〉10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.〈/span〉

Description: A reliable rock classification in a carbonate reservoir should take into account petrophysical, compositional, and elastic properties of the formation. However, depth-by-depth assessment of these properties is challenging because of the complex pore geometries and significant heterogeneity caused by diagenesis. Common rock-classification methods in carbonate formations do not incorporate the impact of both depositional and diagenetic modifications on rock properties. Furthermore, elastic properties, which control fracture propagation and the conductivity of fracture under closure stress, commonly are not accounted for in conventional rock-classification techniques. We apply an integrated rock-classification technique, based on both depositional and diagenetic effects that can ultimately enhance (1) assessment of petrophysical properties, (2) selection of candidates for fracture treatment, and (3) production in carbonate reservoirs. We apply the conductive and the elastic self-consistent approximation theories to estimate depth-by-depth volumetric concentration of interparticle (e.g., interconnected pore space) and intraparticle (e.g., vugs) pores, as well as elastic bulk and shear moduli, in the formation. This process takes into account the impact of shape and volumetric concentrations of rock components on electrical conductivity and elastic properties. We document a successful application of the introduced technique in two wells in the upper Leonardian carbonate interval of Veterans field in west Texas. The identified rock types were verified using thin-section images and core samples. We estimate elastic moduli as well as interparticle porosity with average relative errors of approximately 8% and 10% compared to the core measurements, respectively. Furthermore, the well-log-based estimates of permeability and water saturation are improved by approximately 50% and 20%, respectively, after considering rock classification. Finally, we explain that the fracture propagation failure in the second well (i.e., well B) could be the result of relatively lower Young’s modulus in the rock class corresponding to fracture locations.

Description: The mineralogical complexity of mudstone reservoirs has led to the increased usage of multimineral optimizing petrophysical models for estimating porosity, water, and hydrocarbon volumes. A key uncertainty in these models is the log response parameter assigned for each log equation related to each volumetric variable. Default parameter values are commonly used and often need to be modified by considering subjective local knowledge or intuition to achieve a result that is considered acceptable. This paper describes the methods developed at Chevron for calibration of mineral log response parameters using core data. Mineral log response parameters are controlled by the major and trace element chemistry of the individual minerals in the formation rock matrix. BestRock™ uses a nonlinear approach to optimize whole-rock chemistry with mineralogy to calculate individual mineral structural formulas and trace element associations from which certain log response parameters can then be calculated. Accurate quantitative phase analysis (QPA) to determine mineral content is a critical step in the process, which is achieved here by rigorous sample preparation methods and QPA by x-ray diffraction (QXRD). The QXRD in combination with whole-rock elemental analyses are processed using Chevron’s BestRock optimization software to provide refined quantities of the mineral species present in the formation, their structural formulas, and their predicted wireline log responses. Calibrated petrophysical models are built from the information obtained from the QXRD and BestRock results. The method described herein provides an independent and robust method for determining petrophysical parameters that is independent of the interpreter, quick to implement, and supported by quantitative measurements.

Description: Clay- and lithic-rich sandstones are difficult to characterize through uncored well sections in terms of their grain size, porosity, and mineralogy, all of which are required for assessing reservoir quality and production performance. This paper presents results from a study through one such interval and shows how a combination of different techniques can be used to better understand rock properties of complex reservoirs, thereby helping to reduce reservoir uncertainty. In this study, mean data from laser grain-size analysis are comparable to point-counted grain size, and both are considered as viable analytical methods. Automated quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN ® ) provides a further useful and consistent grain-size measurement that can be applied to both core and cuttings samples. The QEMSCAN has also proved to be a valuable technique in the mineralogical analysis of sandstones that are lithic, clay- and feldspar-rich, eliminating the subjective nature that is inherent with optical analysis. Results from the studied interval show that porosity measured by conventional core analysis (CA) and mercury injection capillary pressure (MICP) analysis are generally comparable with log-derived total porosity. Porosity measured from point-counting and QEMSCAN techniques is significantly lower than total porosity, with the QEMSCAN porosity locally equivalent to log-derived effective porosity. Both point-count and QEMSCAN porosities show better correlations with permeability ( $${r}^{2}=0.90$$ and 0.94, respectively) than total porosity values ( $${r}^{2}=0.81$$ and 0.60 CA and MICP, respectively), suggesting that they might provide a measure of effective porosity in high-quality reservoir rocks.

Description: As the largest active strike-slip fault zone of east Asia, the Tan-Lu fault zone is the most significant tectonic feature controlling the hydrocarbon accumulation in Bohai Bay. The Penglai 19-3 and Penglai 25-6 fields are the most typical examples among the fields found in the Tan-Lu fault zone. The structures related to the two fields are fault restraining bends produced by dextral strike-slip movement on faults within the Tan-Lu fault zone. The structures initiated at the late depositional stage of the third member of the Eocene Shahejie Formation (ca. 40 Ma) after the deposition of the main source rocks of the basin. They then experienced a main development stage during deposition of the second and first members of the Eocene Shahejie Formation and the Oligocene Dongying Formation (40–25 Ma). During the Neogene, the structures continued to be enhanced slightly because of continued strike-slip until the early to middle Pleistocene. These structures were characterized by the absence of the preponderance of the reverse separations on faults and might represent the restraining bends in a divergent wrench deformation zone. This study shows that restraining bend structures along intrabasinal strike-slip systems formed after the deposition of the source rocks are very favorable for hydrocarbon accumulation.

Description: The distribution of porosity was examined on seven drill cores from west–central Alberta encompassing the Belle Fourche and Second White Specks Formations. These Cenomanian–Turonian mudrocks from the Western Canada Sedimentary Basin exhibit good organic richness (〉2 wt. % total organic carbon) and marine kerogen type II with limited kerogen type III. With the increasing thermal maturity from approximately 0.43% vitrinite reflectance ( R o ) to approximately 0.90% R o , the total porosity decreases from approximately 9 to approximately 1 vol. %. This change translates to a reduction in total pore volume from approximately 0.05 to approximately 0.005 cm 3 /g and is accompanied by changes in relative proportions of micropore, mesopore, and macropore volumes. Variations in total porosity for the seven cores with different thermal maturities across Alberta are mainly related to mesoporosity and macroporosity, although the in-core variations in total porosity are mainly related to microporosity. In general, organic matter micropores contribute to the overall microporosity in the seven cores across the study area. The increase in the total pore volumes is in accordance with an increasing concentration of quartz, although increasing concentrations of chlorite and kaolinite may contribute to greater abundance of micropores in the seven cores. The in-core variations suggest that greater contents of kaolinite and illite may contribute to increasing mesopore volumes. Variations in pore volumes and pore size distribution with depth within individual cores (representing specific thermal maturity level) differ from what is observed laterally, when cores of various thermal maturity levels across Alberta are compared, indicating complex controls on porosity systems.

Description: The stratigraphic organization of early synrift clastic successions is controlled by the rates of tectonic subsidence and the growth of the master faults, which, coupled with eustatic base level change, control the generation of accommodation. The 100- to 300-m (328- to 984.2-ft)-thick, highly heterolithic Lower Jurassic upper Åre and Tilje succession (Halten terrace, offshore Norway) represents an example of ancient synrift deposits that accumulated within a north–northeast-south–southwest-oriented structurally controlled embayment where sedimentation was strongly influenced by tidal currents but with significant river influence and minor wave action, except in exposed distal locations. The shallowing-upward, deltaic Tilje succession was deposited near the lowstand shoreline. The Tilje Formation consists of two tabular second-order sequences, each of which overlies structurally influenced sequence boundaries (SB2 and SB3 in local terminology) associated with rift-related tectonic pulses. The first pulse led to formation of SB2 (shallow incision into the Åre Formation) and caused a regional geomorphological change of the basin from an open, wave-dominated setting (upper Åre Formation) to a funnel-shaped, tide-dominated setting (Tilje Formation), in which the lower sequence 2 accumulated. Sequence 3 rests erosively on sequence 2 and is characterized by proximal tidal deposits showing at least two main oblique to axial fluvial input points (north–northwest and northeast), with an increase in wave influence and deepening toward the south. Local rapid subsidence of elongated, narrow hanging wall basins exerted a subtle control on the succession thickness and distribution of tidal–fluvial distributary channels. The overall tabular geometry and internal architecture of the Tilje Formation is less complex than that of other tidal successions worldwide, showing lateral and vertical compartmentalization of the best tidal–fluvial sandstone reservoirs.

Description: Carbonate reservoir rocks exhibit a great variability in texture that directly impacts petrophysical parameters. Many exhibit bi- and multimodal pore networks, with pores ranging from less than 1 μm to several millimeters in diameter. Furthermore, many pore systems are too large to be captured by routine core analysis, and well logs average total porosity over different volumes. Consequently, prediction of carbonate properties from seismic data and log interpretation is still a challenge. In particular, amplitude versus offset classification systems developed for clastic rocks, which are dominated by connected, intergranular, unimodal pore networks, are not applicable to carbonate rocks. Pore geometrical parameters derived from digital image analysis (DIA) of thin sections were recently used to improve the coefficient of determination of velocity and permeability versus porosity. Although this substantially improved the coefficient of determination, no spatial information of the pore space was considered, because DIA parameters were obtained from two-dimensional analyses. Here, we propose a methodology to link local and global pore-space parameters, obtained from three-dimensional (3-D) images, to experimental physical properties of carbonate rocks to improve P-wave velocity and permeability predictions. Results show that applying a combination of porosity, microporosity, and 3-D geometrical parameters to P-wave velocity significantly improves the adjusted coefficient of determination from 0.490 to 0.962. A substantial improvement is also observed in permeability prediction (from 0.668 to 0.948). Both results can be interpreted to reflect a pore geometrical control and pore size control on P-wave velocity and permeability.

Description: With the booming exploration and development of unconventional hydrocarbon resources in source rocks, the estimation of total organic carbon (TOC) content from well logs has become increasingly important because of the significance of TOC in the formation evaluation of those resources. In this paper, a new log overlay method is developed to estimate the TOC content of source rocks with excess radioactivity, but containing little or no potassium feldspar. Specifically, on the basis of previous results of log responses of source rocks, it is believed that the natural gamma ray (GR) log responses of source rocks in the applicable conditions are predominantly contributed by clay minerals and organic matter. A practical clay indicator is established to reflect the clay content using density and neutron logs. The indicator is effective not only in nonsource rocks that contain oil or water but also in source rocks. Furthermore, a new method was developed by overlaying the properly scaled clay indicator curve on the GR curve. In nonsource rocks, including clay-rich rocks and reservoirs saturated with oil or water, the two curves overlie each other, whereas a separation between the curves occurs in organic-rich source rocks. The separation between the curves was defined and expressed and can be used to calculate the TOC consecutively after careful calibration with core data. This method has been successfully applied to two shale gas plays with high-maturity kerogen in the Sichuan Basin, China. In addition, a source rock with low-maturity kerogen was used to verify the new method for its effectiveness, reliability, and widespread adaptability.

Description: Geochemical fingerprinting of produced water from hydraulic fracturing projects is an essential tool to trace their provenance during the postfracturing period, to quantify recovery rates and volumes of fracturing fluids, and to visualize the geodynamic structure of natural or induced fracture networks. A total of 41 produced water samples from an exploration well in the Northern Arabia Exploration Area in Saudi Arabia were collected daily from the fracture-stimulated Qusaiba hot shale and analyzed for major ions and trace elements and partially for environmental isotopes. The postfracturing period shows an initial return of supply water and potassium chloride brine, subsequently replaced by the inflow of sodium chloride–type formation water with a stable plateau salinity of 50,000 mg/L. Less than 10% of the total injected fracturing fluids were recovered during postfracturing, whereas 78.8 vol. % of the total recovered fluid is composed of formation water (20,843 out of 26,446 bbls) during the study period. Coinciding values between logged reservoir temperature and calculated geothermometers confirm the provenance of pore water from the Qusaiba hot shale or from nearby units. The recharge of the Silurian sequence with meteoric surface water occurred during the early Holocene (6–6.7 ka), as evidenced by geochronological dating with the 14 C method and 18 O/ 2 H values close to the global meteoric water line. The inflow of formation water into the stimulated shale layer in the postfracturing stage could be originated by the natural occurrence of pore water within a naturally fractured, black shale layer or, more likely, by the rise of groundwater from the underlying Sarah sandstones via migration pathways of natural or newly formed, vertically induced hydraulic fractures. For this particular well site and the specific hydraulic fracturing project, chemical and isotopic fingerprinting confirms the absence of ascending migration pathways from the Silurian Qusaiba hot shale toward a shallower groundwater system, which are isolated through a lithological set of more than 900 m (3000 ft) of impermeable mudstone from the Qusaiba Member.

Description: Oxygen isotope ( 18 O) zonation in carbonate mineral cements is often employed as a proxy record (typically with millimeter-scale resolution) of changing temperature regimes during different stages of sediment diagenesis. Recent advances in secondary ion mass spectrometry allow for highly precise and accurate determinations of cement 18 O values to be made in situ on a micrometer scale, thus significantly increasing the spatial resolution available to studies of diagenesis in sandstone–shale and carbonate systems. Chemo-isotopically zoned dolomite–ankerite cements within shaly sandstone beds of the predominantly silty–shaly Eau Claire Formation (Cambrian, Illinois Basin) were investigated, revealing the following: with increasing depth of burial (from 〈0.5 to ~2 km [〈1500 to 6500 ft]), cement 18 O values decrease from a high of approximately 24 down to approximately 14 (on the Vienna standard mean ocean water [VSMOW] scale, equivalent to –6.5 to –16.5 on the Vienna Peedee belemnite [VPDB] scale). The observed cross-basin trend is largely consistent with cements having formed in response to progressive sediment burial and heating. Within the context of independent burial and thermal history models for the Illinois Basin, cementation began soon after deposition and continued intermittently into the mid-Permian. However, temperatures in excess of burial model predictions are inferred at the time of latest ankerite cement precipitation, which we propose overlapped in time with conductive heating of the Eau Claire Formation (a closed system) from under- and overlying sandstone aquifers that channeled the flow of hot, Mississippi Valley–type mineralizing brines during the mid-Permian (ca. 270 Ma).

Description: The Bohai Sea area, offshore of the Bohai Bay Basin, is one of the most petroliferous regions in China, with proven original oil in place of approximately 2.4 x 10 9 m 3 (150.94 x 10 8 bbl) and proven original gas in place of over 5 x 10 12 m 3 (1.76 x 10 13 ft 3 ). Cumulative oil production is over 50 million tons (3.5 x 10 8 bbl). In this study, using the limited data on source rock thickness, core samples, and Rock-Eval pyrolysis along with sedimentary facies analysis, source rock characteristics of different depositional settings were identified, and the thickness, richness, organic matter type, and thermal evolution of four sets of source rocks in the Bohai Sea area— the second member of Dongying Formation (E 3 d 2 ), the third member of Dongying Formation (E 3 d 3 ), the first and second members of Shahejie Formation (E 2 s 1-2 ), and the third member of Shahejie Formation (E 2 s 3 )—were predicted and evaluated. Subsequently, the intensity and history of hydrocarbon expulsion for different sags was systematically compared and analyzed. The greatest thickness of the four sets of source rocks in the Bohai Sea area is 400–800 m (1300–2600 ft). The average richness of the organic matter of these source rocks is 1.74%–2.87%. The E 2 s 3 set has the highest organic matter abundance; E 2 s 1-2 has the lowest. The organic matter of these source rocks is mainly type I and type II, but their evolutions differ. The vitrinite reflectance of E 3 d 2 is 0.5%–1.0%, that of E 3 d 3 is 0.7%–1.25%, that of E 2 s 1-2 is 0.75%–1.75%, and that of E 2 s 3 is 0.75%–2.0%. The cumulative hydrocarbon expulsion of the four sets of rocks is 4.14 x 10 10 t (2.90 x 10 11 bbl). The E 2 s 1-2 set has the greatest expulsion amount: 1.75 x 10 10 t (1.22 x 10 11 bbl). The peak stages of hydrocarbon expulsion of the four sets of source rocks were during Neogene Minghuazhen Formation (12.2–2.0 Ma) and Neogene Guantao Formation (16.6–12.0 Ma). The Bozhong sag expelled the most hydrocarbons, followed by the Liaozhong, Qikou, and Huanghekou sags.

Description: Schlumberger’s modular dynamics tester (MDT) tool was used to test 10 Miocene sands in the Tubular Bells deep water oil field, offshore Gulf of Mexico, United States. Nine sands from true vertical depths of 19,999–26,464 ft (6096–8066 m) were sampled from a single well and another deeper sand (29,075 ft [8,862 m]) from a second well. Using ion and strontium, oxygen, and hydrogen isotopic analysis, the nine MDT water samples were demonstrated to be mostly formation water. The sample in the second well from 29,075 ft (8862 m) is filtrate, based on its oxygen and hydrogen isotopic composition (–4.10 and –26.3, standard mean ocean water [SMOW]). Insufficient water was recovered for ionic analysis, which made the isotopic analysis even more important to help document the origin of the water in what appears to be a hydrocarbon-charged interval. Using a combination of chemical and isotopic analyses, it is concluded that only two of the sands are possibly in fluid communication or separated by baffles. The other sands are each in separate fluid compartments. The salinity (total dissolved solids) of the formation waters decreases with depth and distance from the salt and ranges from approximately 39,000 to more than 288,000 mg/L. The formation waters have oxygen and hydrogen isotopic compositions ranging from +3.19 to +4.52 and –16.1 to –19.4, respectively (SMOW). Bromide–chloride systematics indicate that the formation waters are mixtures of normal seawater and seawater that was evaporated to and probably beyond halite saturation. The evaporite water is sourced from the deeper Jurassic section (Louann Salt) and likely came up along the salt–sediment interface along faults and fractures associated with emplacement of the salt stock and canopy. The formation waters were subsequently enriched in chloride and sodium to varying degrees by dissolution of the diapiric salt. Strontium isotopes are compatible with mixing of highly concentrated (evaporative) Jurassic seawater with relatively low 87 Sr/ 86 Sr ratios and much less concentrated (almost seawater salinity) pore water with more radiogenic strontium, the latter derived from silicate reactions during burial diagenesis. Short-chain organic acids are present in high concentrations (〉1000 mg/L) along with the organophilic ions boron and iodide. The concentrations of boron, iodide, and organic acids do not correlate with salinity. Boron and iodide show a strong positive relationship with each other and a less strong, but positive, relationship with organic acid concentrations. Boron and iodide are nearly twice as concentrated in waters of oil-bearing sands than in water-bearing sands and appear to be indicators of hydrocarbon proximity. One water-bearing sand has concentrations of boron and iodide as high as those seen in oil-bearing sands, possibly suggesting an updip oil accumulation.

Description: Huge, high gas–oil ratio, hydrogen sulfide (H 2 S)-bearing gas condensate accumulations were recently discovered in the Ordovician carbonate reservoirs of the Tazhong uplift in the Tarim Basin, northwest China. Distinct differences exist between the eastern and western condensates in terms of chemical and isotopic compositions. Condensates from the western part of the uplift were characterized by high dibenzothiophenes (generally 〉500 μg/g), a high H 2 S concentration (~7%, vol./vol.), and relatively depleted 13 C methane ( 13 C 1 = –55.5 to –36). The H 2 S concentration in the Tazhong gas condensates shows a positive correlation to Mg 2+ concentration in the formation water. Formation water in Lower Ordovician–Cambrian strata in the Tazhong uplift is rich in Mg 2+ , which facilitates the thermochemical sulfate reduction (TSR) of sulfate contact ion pairs (CIPs) to produce H 2 S and dibenzothiophenes. A detailed comparison of the chemical compositions of the formation waters in different strata indicates that a high H 2 S concentration in the Tazhong gas condensates originates from the TSR of sulfate CIPs in the Lower Ordovician–Cambrian strata, where a primary oil accumulation may have existed. The concentrations of 3- and 4-methyldiamantanes in the western condensates (80 to 150 μg/g) are relatively lower than those from the eastern part of the uplift. Also, the 13 C 1 in the western H 2 S-bearing gas condensates was more negative, and the 13 C 2 – 13 C 1 value was larger than that from typical TSR-altered gases. These features indicate that the western Tazhong samples had just entered the initial stage of TSR. According to the pressure, volume, temperature (PVT) phase diagram, the lower Paleozoic section was quickly buried after the Tortonian. High-H 2 S hydrocarbon inclusions formed during the last 10 m.y. when paleotemperatures reached 140°C (284°F). Because the reaction rate of the sulfate CIPs oxidation was relatively slower than that of H 2 S autocatalysis during the entire TSR process, advanced TSR has not been accomplished yet. It is also inferred that the Tortonian was the key period for accumulation of secondary H 2 S-bearing gas condensates, resulting from abundant gas washing along deep fractures and charging in the early reservoirs. An increased aromaticity parameter (toluene/n-heptane) and an increased fractionation index from east to west indicate an intensified degree of gas washing. Different gas-washing intensities in the eastern and western gas condensates led to diverse PVT states as well. Deep strata in the Tazhong uplift were characterized by multiple charges and mixing, coupled with periodic TSR, leading to the occurrence of variable H 2 S-bearing gas condensates.

Description: Anomalous carbonate horizons with intercrystalline hydrocarbon residue, cone-in-cone structures, and calcite "beef" veins in adjacent sandstone beds record potential evidence for hydrocarbon generation and seepage in the middle to upper Turonian Frontier Formation from the Uinta Basin, Utah and Colorado. Eight carbonate occurrences, all encountered within distal delta-front facies (thin-bedded sandstones and siltstones), were sampled at outcrop locations from the southern and eastern margins of Dinosaur National Monument. Seven petrographic facies (PF1–PF7) were identified using standard petrographic and cathodoluminescence microscopy: PF1, large and small botryoids and fans; PF2, yellow-brown spherules; PF3, microcrystalline spar cement; PF4, blocky spar; PF5, prismatic spar; PF6, drusy mosaic spar; and PF7, dolomite. Facies PF1–PF3 are synsedimentary phases comprising a large percentage of carbonate horizon volume, whereas PF4–PF7 are late-stage fabrics. The 13 C values of PF1–PF3 (–9.9 to –20.0) are consistent with contributions from biogenic methane seepage during deposition and early diagenesis. Brecciated PF1 fabrics and blowout depressions within sandstone horizons further indicate significant methane generation during deposition and early burial. Late-stage fabrics contain 13 C (–8.0 to –17.3) and 18 O (–6.5 to –13.5) values consistent with progressive burial, during which intercrystalline hydrocarbon residue, cone-in-cone structures, and calcite beef veins were formed by the thermal maturation of organic matter from enclosing distal delta-front facies. Together, these features reveal the potential for the thin-bedded facies of the Frontier Formation distal delta front to serve as a potentially viable petroleum subsystem previously unrecognized in the Uinta–Piceance petroleum province.

Description: Reliable modeling of meandering fluvial reservoirs is challenging because of the heterogeneity in magnitude and pattern of porosity and permeability related to depositional and diagenetic features. Early mechanical and chemical alterations proceed along different pathways directly related to depositionally governed differences in textural and compositional parameters. In a well-constrained sedimentological framework and with relatively homogeneous conditions of detrital composition, this study aims to determine the effect of depositional fabric on early diagenetic processes and their collective effect on petrophysical properties (pore size distribution, open porosity, and permeability). A high-resolution qualitative and quantitative petrographic analysis is conducted on 22 fine- to very fine–grained sandstones from the main meandering fluvial facies of the channel (center and margin), point bar (lower, middle, and upper), scroll bar, and chute channel of a Triassic outcrop analog. The occurrence of small-scale internal heterogeneity associated with detrital matrix and suspension-settling laminae favors the compaction process and hinders early pore-filling cement precipitation that helps the preservation of primary porosity. Multivariate statistical treatment of data demonstrates that large (〉1 µm) and well-connected primary intergranular pores are the main contributors to permeability in the more heterogeneous samples. The distribution of the finer-grained sediment fraction is strongly facies related as a result of hydraulic sorting. Better understanding of linkages between depositionally predictable features and diagenetically induced heterogeneity may lead to realistic reservoir models and enhanced effectiveness of exploitation and bypassed-oil recovery strategies.

Description: Fractures are the main fluid-flow pathways in tight-oil sandstones, and they have a significant influence on tight-oil distribution, exploration, and development. Cores and image logs are commonly unavailable because of their high costs, so employing conventional logs for fracture detection is imperative for tight-oil sandstones. We compared the fracture-response characteristics of conventional logs based on two data sets, one from 8 cored wells with fracture intensities greater than 1 m –1 (3.3 ft –1 ) and the other from 11 cored wells with fracture intensities less than 0.5 m –1 (1.6 ft –1 ), with a case study of the Upper Triassic Yanchang Formation in southwest Ordos Basin, China. The results indicate that when tight-oil sandstones are more intensely fractured, the caliper log, acoustic log, compensated neutron log, density log, dual induction logs, and laterolog 8 present fracture responses to some extent. However, it is difficult to make a distinction between fractured and nonfractured zones using conventional logs in sandstones with smaller fracture intensities. The fracture-response intensities of conventional logs are weak, and they are influenced by fracture abundance, fracture occurrence, fracture scale, and mineral-filling degree. Moreover, lithology, fluids, and rock physical properties can cause fracturelike responses. Hence, some ambiguity exists when using conventional logs to directly identify fractures. Accompanying fracture-sensitive conventional logs with some methods to enhance fracture-response intensity and eliminate nonfracture influence could enable fracture identification in tight-oil sandstones.

Description: Accurate definition of structural style in subsurface interpretation is critically important for understanding the deformation history of fold-and-thrust belts, as well as assessing the petroleum prospectivity of structural traps. Using two- and three-dimensional seismic reflection surveys, well data, field mapping, forward models, and balanced cross sections, we describe the structural styles across the actively deforming southern Junggar fold-and-thrust belt in northwestern China, a basin undergoing petroleum exploration and development operations. Subsurface interpretations indicate several folds in the basin overlie Jurassic normal faults that were tectonically inverted in the Late Jurassic to Early Cretaceous. Following inversion, multiple detachment levels propagated northward from the Tian Shan and formed a series of imbricated fault-related folds. The most prominent fold trend in southern Junggar consists of the Tugulu, Manas, and Huoerguosi anticlines, which trap hydrocarbons in clastic Eocene reservoirs. These structures exhibit complex internal geometries, with coeval forethrusts and backthrusts forming imbricated structural wedges. In the latest stages of deformation, and continuing at present, the uppermost thrust sheet, the Southern Junggar Thrust (SJT), truncated the backlimbs of these structural traps, implying the SJT is a tectonically active, out-of-sequence thrust. From these interpretations, we present a model for how the southern Junggar fold-and-thrust belt developed from Jurassic to present. Moreover, we detail how fold growth, fault activity, and structural style affected charge histories, trap formation, and reservoir compartmentalization. Our results have direct implications for assessment of the southern Junggar petroleum system as well as other complex fold-and-thrust belts.

Description: Distinguishing axial and lateral sedimentary systems in rift basins is crucial for predicting reservoir distribution and quality, particularly where synrift strata are interrupted by mass transport complexes (MTCs). Upper Jurassic deep-marine synrift successions in the central North Sea have been studied to assess the temporal and spatial relationships of sediments and controls on reservoir quality. In the Late Jurassic, the central graben experienced erosion at rift margins, whereas adjacent grabens were starved and underfilled with marine sediments, supplied by axial and transverse systems. This study focused on sediments adjacent to a major intrabasinal high, the Josephine ridge. Data included seismic, wireline logs from 16 wells, and biostratigraphic and sedimentological analysis of 144 m (472 ft) of core. Synrift strata are dominated by mudstones but include MTCs interbedded with coarse sandstones at the rift margin and fine-grained turbidite sandstones in basinal depocenters. Petrographic and heavy mineral data indicate different provenance between MTCs and basinal turbidites. Turbidites correlate with periods of lowered relative sea level, during the initial rift phase, and record axial sediment supply. The composition of the MTCs corresponds to in situ strata on the adjacent Jade and Judy horsts. The distribution of MTCs implies formation by crestal collapse horsts during the rift climax and represents a transverse system, with no genetic relationship to axial turbidites. In starved deep-marine basins, fine-grained, well-sorted axial systems may provide the most extensive reservoirs. Transverse systems derived from isolated horsts are typically coarse-grained, poorly sorted, and spatially restricted, being unlikely to provide significant reservoir material.

Description: We evaluated the geochemical transformations that would likely occur after injecting CO2 into a sandstone formation using The Geochemist's Workbench(R), with the intent of simulating CO2 solution and mineral storage mechanisms. We used a hypothetical reservoir intended to closely resemble the Lamotte Sandstone in southwest Missouri, a reservoir rock found at about 600-m (1970-ft) depth, well above the recommended depth for CO2 sequestration of 800 m (2625 ft). In the absence of specific water chemistry and lithology data for this formation at the proposed injection site, the model considered two best estimates of each input parameter. Carbon dioxide (CO2) sequestered in the dissolved phase was found to range between 76.74 and 76.80 g/kg free water, and the pH dropped from 7.7 to 4.8 after a 10-yr injection period. During a 50-yr postinjection interval with no additional CO2(g) added, the model predicted the pH to rise from 4.8 to 5.3 and various minerals to precipitate, among them magnesite, nontronite-Mg, and gibbsite, as well as smaller amounts of siderite and dolomite. Magnesite, siderite, and dolomite contribute to removal of carbon. In general, the model is very flexible, allowing the user to incorporate variations in temperature, pressure, water chemistry, solid-phase mineralogy, and kinetics. Modeling steps are described here as well as the results, which are all based in 1 kg of free water. To determine the total sequestration potential, transport modeling is needed, in addition to the geochemical modeling presented here.

Description: Engineered landfill liner systems are expensive to install and represent a challenge to several developing countries. Alternatively, native soils, preferentially clays, can be used as cost-effective bottom liners. The purpose of this work is to justify the reliance on the ability of the clays at the Kharga-Dakhla land stretch, Western Desert, Egypt, to act as a containment and barrier for pollutants that might be generated in a landfill leachate. This is particularly valid in hyperarid regions where many environmental requirements for landfill liner design are relaxed, as precipitation is rare and percolation to buried wastes is practically absent. The availability of native clays and clay-bearing sediments in the study area, both on surface and subsurface, makes it a potential landfill site. Collaborating techniques have been used to determine the mineralogical, geochemical, and geotechnical characteristics of the sediments constituting the Quseir Formation (Upper Cretaceous). These techniques include x-ray diffraction analysis, differential thermal analysis, cation exchange capacity (CEC), swelling properties, Atterberg limits, porosity, and hydraulic conductivity. The obtained results indicate that the investigated clayey sediments are dense and compact. They have low hydraulic conductivity that ranges from 1 x 10 -10 to 4.96 x 10 -11 cm/s, with moisture content that does not exceed 7%. The swelling values of samples containing smectite range between 250 and 500%. The plasticity limit of the red clay (floor of the Dakhla Oasis) ranges between 11 and 18%, which indicates its suitability as a landfill lining material. Values for CEC are generally high and increase with increasing smectite content. It reaches as much as 69 meq/100-g sample, indicating enhanced ability for natural attenuation and can act within the containment system for metal pollutants. The obtained mineralogical, geochemical, and geotechnical data suggest that the studied clays can be used, effectively, as a viable alternative liner system for solid waste and/or secured landfills, replacing the costly state of the art liner systems. Satisfying siting criteria, the availability of the clays, and the easy way and their low cost of extraction provide a cost-effective solution to the problem of landfill lining in developing countries.

Description: The Cambrian Mount Simon Sandstone is the major target reservoir for ongoing geologic carbon dioxide (CO 2) sequestration demonstrations throughout the midwest United States. The potential CO 2 reservoir capacity, reactivity, and ultimate fate of injected CO 2 depend on textural and compositional properties determined by depositional and diagenetic histories that vary vertically and laterally across the formation. Effective and efficient prediction and use of the available pore space requires detailed knowledge of the depositional and diagenetic textures and mineralogy, how these variables control the petrophysical character of the reservoir, and how they vary spatially. Here, we summarize the reservoir characteristics of the Mount Simon Sandstone based on examination of geophysical logs, cores, cuttings, and analysis of more than 150 thin sections. These samples represent different parts of the formation and depth ranges of more than 9000 ft (〉2743 m) across the Illinois Basin and surrounding areas. This work demonstrates that overall reservoir quality and, specifically, porosity do not exhibit a simple relationship with depth, but vary both laterally and with depth because of changes in the primary depositional facies, framework composition (i.e., feldspar concentration), and diverse diagenetic modifications. Diagenetic processes that have been significant in modifying the reservoir include formation of iron oxide grain coatings, chemical compaction, feldspar precipitation and dissolution, multiple generations of quartz overgrowth cementation, clay mineral precipitation, and iron oxide cementation. These variables provide important inputs for calculating CO 2 capacity potential, modeling reactivity, and are also an important baseline for comparisons after CO 2 injection.

Description: Subsurface geologic storage of carbon dioxide calls for sophisticated monitoring tools with respect to long-term safety and environmental impact issues. Despite extensive research, many factors governing the fate of injected carbon dioxide (CO2) remain unclear. To identify possible risks through leakage of the CO2 storage reservoir, a program for monitoring of the CO2 flux at the surface was started at the Ketzin test site, which allows to distinguish between natural temporal and spatial flux variations and a potential leakage. To gain adequate long-term baseline data on the local background CO2 flux variations, CO2 soil gas flux, soil moisture, and temperature measurements were conducted once a month during a 6-yr period. Furthermore, soil samples were analyzed for their organic carbon and total nitrogen contents. The mean flux of all sampling sites before the CO2 injection (2005-2007) was 2.8 {micro}mol m-2 s-1 (ranging from 2.4 to 3.5), with a Q10 factor of 2.4, and in the years after commencing injection (2009-2010), 2.4 {micro}mol m-2 s-1 (ranging from 2.2 to 2.5), with the same Q10 factor. The CO2 flux rate is mainly controlled by the soil temperature. A significant influence of diurnal temperature variation and soil moisture was not detected. The spatial variability of the CO2 flux among the 20 sampling locations ranges from 1.0 to 4.5 {micro}mol m-2 s-1, depending on the organic carbon and total nitrogen content of the soil. Through comparison with the long-term measurements, unusual high CO2 fluxes can theoretically be distinguished from natural variations.

Description: Shale oil and gas have been discovered in the lacustrine organic-rich Zhangjiatan Shale of the Upper Triassic Yanchang Formation, Ordos Basin, China. Core observations indicate abundant silty laminae in the producing shales. This study documents the stratigraphic distribution of silty laminae and their relationship with interlaminated clay laminae. The type, structure, and characteristics of pores and mineral composition of silty laminae were observed and analyzed through thin section and scanning electron microscopy, X-ray diffraction, low-pressure $${\mathrm{CO}}_{2}$$ and $${\mathrm{N}}_{2}$$ adsorption, mercury porosimetry, and helium pycnometry. Results from silty laminae are compared with those of clayey laminae. The frequency and thickness of silty laminae vary over a wide range. The thickness ranges from 0.2 to 4 mm and is 1.5 mm on average; the frequency ranges from 4 to 32 laminae/m and is 23 laminae/m on average. The thickness percentage of silty laminae in the measured segments ranges from 6% to 17%. Silty laminae consist of quartz, feldspar, mixed-layer montmorillonite, and chlorite. In comparison to clayey laminae, non-clay detrital grains are larger, quartz and feldspar are more common, and clay minerals are less abundant. Pores in silty laminae are primary interparticle, dissolutional, intercrystalline, and microfracture types. Mesopores (2–50 nm in diameter) and macropores (50 nm–1 μm) are common, whereas, micropores $$( 〈 2\hbox{ \hspace{0.17em}\hspace{0.17em} }\mathrm{nm})$$ are rare; the distribution of pore diameters is multimodal. However, microscopic pores with a diameter commonly smaller than 100 nm are common in clayey laminae. Thus, pore volume and surface area of micropores in silty laminae are less than those in the adjacent clayey laminae, and vice versa for meso- and macropores. The porosity of shales increases with the proportion of silty laminae in the shales. The silty laminae provide the storage space and flow conduit for oil and gas, and they play a significant role in the migration, accumulation, occurrence, and amount of gas in the shales.

Description: The Pleistocene Saturnia travertine (central Italy) represents a possible analog of the pre-salt continental carbonate reservoirs discovered in the Santos and other basins in the South Atlantic margin of Brazil. Two subhorizontal travertine tabular bodies, several tens of meters thick and extending over an area of $$15\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{km}}^{2}$$ ( $$5.8\hbox{ \hspace{0.17em}\hspace{0.17em} }{\mathrm{mi}}^{2}$$ ), have been studied in two quarries. Facies variations and associated petrophysical properties were reconstructed applying a multidisciplinary approach. The Saturnia travertine, formed from a warm water spring, is composed of various stacked carbonate banks, separated by subaerial erosive phases and paleosols. The lacustrine tabular bodies, terraces, and sills are made of crystalline crust, shrub, pisoid, paper-thin raft, coated bubble, reed, and lithoclast-breccia facies. The $$\delta ^{13}\mathrm{C}$$ (from +4 to +8) supports an interpreted $${\mathrm{CO}}_{2}$$ volcanic mantle source, whereas, the $$\delta ^{18}\mathrm{O}$$ (from –9 to –5) is in agreement with warm meteoric waters. The $$^{87}\mathrm{Sr}/^{86}\mathrm{Sr}$$ ratio isotopic signature indicates a carbonate from dissolution of deep-seated carbonates. The facies reservoir properties were studied via porosity and permeability analysis of plugs, three-dimensional x-ray computer tomography, as well as image analysis on microscale under thin section and macroscale on large rock slabs to define various porosity indices. A strong heterogeneity of the petrophysical properties and variable connectivity were observed (porosity from 4% to 30% and permeability up to hundreds of md), but no compartmentalization of the carbonate bodies is present.

Description: The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at $${\mathrm{C}}_{16}\mbox{--}{\mathrm{C}}_{18}$$ , indicating marine algal organic matter. Rock-Eval $${T}_{\mathrm{max}}$$ and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Description: Significant amounts ( $$ 〉 150\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}/\mathrm{day}/\mathrm{well}$$ ) of water are currently being extracted from coalbed methane (CBM) wells in Permian–Carboniferous coal in the Liulin area of the eastern Ordos basin, China. Waters coproduced with CBM have common chemical characteristics that can be an important exploration tool because they relate to the coal depositional environment and hydrodynamic maturation of groundwater and can be used to guide CBM development strategies. The CBM production targets of the No. 3 and 4 coal seams from sandstone in the Shanxi Formation and No. 8, 9, and 10 coal seams in the karst of the Taiyuan Formation were deposited in fluvial-deltaic and epicontinental-sea environments, respectively. This paper combines CBM geology, hydrogeology, CBM recovery, and laboratory data to define mechanisms of CBM preservation including the important influence of groundwater. Relevant indices include fluid inclusions as an indicator of the hydraulic connection between the coal seam reservoir and the overlaying strata and the ensemble characteristics of total dissolved solids (TDS) contents of water, water production rates, and reservoir temperatures as an indication of the current hydraulic connection. The TDS contents of waters from the No. 3 and 4 and No. 9 and 10 coal seams are double those from the subjacent karst No. 8 coal seam, indicating the important control of fast flow in karst. Low-salinity fluid inclusions from the roof of the subjacent-karst No. 8 coal seam also indicate an enduring hydraulic connection with overlaying strata during its burial history. Relatively low current temperatures in the No. 8 (subjacent-karst) coal seam also infer a strong hydraulic connection and active flow regime. Deuterium concentrations are elevated in the mudstone-bounded No. 9 and 10 coal seams, further confirming low rates of fluid transmission. The gas contents of coal seams from the Taiyuan Formation are higher than those from the sandstone-bounded coal seams in Shanxi Formation, also correlating with low rates of water transmission and low permeability. Conceptual models for these fluvial-deltaic and epicontinental-sea environments that are consistent with geology, gas content, and gas and water production rate histories are of gas-pressure sealing for the Shanxi Formation and hydrostatic-pressure sealing for the Taiyuan Formation. These results confirm the important controls of hydrogeological conditions on the preservation of CBM and the utility of hydrogeological indicators in prospecting for CBM.

Description: Whereas the vast majority of discovered hydrocarbon reserves in Iraq reside in Cretaceous and Cenozoic reservoirs, numerous oil and gas fields have been discovered recently in deeper Jurassic and Triassic reservoirs in the Kurdistan region of Iraq. This study presents a Middle–Upper Jurassic thermal maturity map for the Kurdistan region of Iraq and demonstrates that regional first-order trends in Jurassic source rock maturity show a close correlation to the spatial distribution of oil gravities within the overlying Jurassic (and Cretaceous) reservoirs. This distribution is consistent with compartmentalization of the active source rock kitchens due to Zagros folding, resulting in relatively short-distance migration and charge of the anticlinal structures from the adjacent synclinal lows. The thermal maturity map confirms relatively low maturity over the Mosul high, where the Cretaceous and Cenozoic section overlying the source rock interval is relatively thin, and increasing maturity to the southeast as the thickness of the Cenozoic foredeep sediments increases toward the depocenter located in the southeastern Iraqi Zagros and the adjacent Iranian Zagros. The correlative trend in oil gravities is exemplified by the recent Jurassic discoveries: low to medium gravity oils (14–27° API) in Shaikan and Atrush to the northwest, light oil (39–47° API) in Mirawa and Bina Bawi, and gas condensate (55° API) in Miran West to the southeast. Understanding thermal maturity patterns and hydrocarbon fluid-type distributions will help to guide risk assessment for remaining prospectivity and future exploration drilling within the Kurdistan region of Iraq.

Description: The northern Flinders Ranges and eastern Willouran Ranges, South Australia, expose Neoproterozoic salt diapirs, salt sheets, and associated growth strata that provide a natural laboratory for testing and refining models of allochthonous salt initiation and emplacement. The diapiric Callanna Group (~850–800 Ma) comprises a lithologically diverse assemblage of brecciated rocks that were originally interbedded with evaporites that are now absent. Using stereonet analysis to derive three-dimensional information from two-dimensional outcrops of stratal geometries flanking salt diapirs and beneath salt sheets, we evaluate 10 examples of the transition from steep diapirs to salt sheets, 3 of ramp-to-flat geometries, and 2 of flat-to-ramp transitions. Stratal geometries adjacent to feeder diapirs range from a minibasin-scale megaflap to halokinetic drape folds to high-angle truncations and appear to have no relationship to subsequent allochthonous salt development. In all cases, the transition from steep diapirs to salt sheets is abrupt and involved piston-like breakthrough of thin roof strata, which permitted salt to flow laterally. We suggest two models to explain the transition from steep diapirs to subhorizontal salt: (1) salt-top breakout, where salt rise occurs inboard of the salt flank, thereby preserving part of the roof strata beneath the sheet; and (2) salt-edge breakout, where rise occurs at the edge of the diapir with no roof preservation. Lateral emplacement of salt sheets is dependent on the interplay between the rate of salt supply to the front of the sheet and the sediment-accumulation rate. When the ratio of salt-supply rate to sediment-accumulation rate is high to moderate, thrust advance produces base-salt flats and truncation ramps, respectively. Halokinetic folds are absent because the thrust emerges at the base of the sea-floor scarp and mass-transport complexes are rare as a result of relatively low scarp relief. If the ratio is low, pinned inflation leads to drape folding of the top salt and cover into a fold ramp, with occasional slumping of the sheet and its roof and further breakout on thrust or reverse faults. In the shallow-water depositional environments of South Australia, lateral emplacement of salt sheets occurred through some combination of thrust advance, extrusive advance, and open-toed advance, with no evidence for subsalt thrust imbricates, shear zones, or continuous rubble zones. In deep-water environments, such as the northern Gulf of Mexico, thrust imbricates and rubble zones, which represent slumped carapace, are more common. The presence of slumped carapace is caused primarily by higher topographic relief related to thicker hemipelagic roofs, a lack of dissolution, and gravity-driven transport of overburden strata to the toes of large canopies.

Description: This paper examines the discovery process in terms of changing exploration paradigms and describes a field discovered because of this change in mindset. Prior to the Umiak discovery all wells in the Mackenzie Delta had been drilled on structural highs. Reevaluation of two 30-yr-old dry holes along with existing two-dimensional (2-D) seismic data resulted in discovery of the Umiak gas field. This reappraisal led to recognition that a stratigraphic trap might exist between these two wells drilled in the early 1970s. The Kilagmiotak M-16 well contained 290 m (951 ft) of porous sandstone in the Eocene Taglu Formation, whereas the Umiak J-37 well, up dip and 11 km (6.8 mi) to the west, had no sandstone in the same interval. Examination of 2-D seismic lines found evidence of an updip sandstone pinchout beneath an angular unconformity on a tilted fault block. Strata in the tilted fault block below the unconformity contain strong amplitudes and flat spots. Interpretation of a subsequent three-dimensional (3-D) survey supported the play. A partnership of Alberta Energy Company (operator, now Encana), Anadarko, and Gulf Canada (now ConocoPhillips Canada) drilled the Umiak N-16 discovery well during 2004. Gas and some oil was found in gently dipping Eocene Taglu shoreface and delta front sandstones, and within gently folded foreset beds of the Eocene Richards Formation above a mid-Eocene unconformity. The Umiak N-05 appraisal well drilled a year later confirmed the discovery. Together these two wells delineate the fourth largest onshore gas accumulation on the Mackenzie Delta.

Description: The Upper Cretaceous Tuscaloosa marine shale (TMS) is an oil play across central Louisiana and southwest Mississippi. The lower TMS is characterized by relatively high log resistivity (〉5 ohm-m) compared to the upper part, and this elevated resistivity zone (ERZ) has become the primary target zone. This study is to investigate the cause of variation in log resistivity based on the data of petrography, mineralogy, and organic matter property and porosity. The results suggest that log resistivity is not controlled by mineralogy or porosity; rather, it is associated with oil generation during organic matter maturation. Total organic carbon (TOC) content, Rock-Eval free hydrocarbon yield (S1), and hydrogen index (HI) in the studied core increase with depth. Porosity within organic matter (OM), measured by field-emission scanning electron microscopy (FE-SEM), is also higher within the ERZ. The correlated variations among TOC content, S1 values, OM porosity, and log resistivity suggest that the higher log resistivity resulted from in situ oil generation and that the OM pores were generated during oil generation. Thermal maturity varies little in the core; whereas the downward-increasing HI indicates an increasing abundance of oil-prone type II kerogen. Higher OM porosity appears to be related to the greater proportion of type II kerogen in the ERZ. The data set demonstrates that higher contents of TOC and oil-prone kerogen are the combined factors for higher oil generation, therefore, higher log resistivity in the ERZ. The study provides a quantitative relationship between OM porosity and oil generation.

Description: The number of Marcellus Shale gas wells drilled in the Appalachian basin has increased rapidly over the past decade, leading to increased interest in the highly saline water produced with the natural gas which must be recycled, treated, or injected into deep disposal wells. New geochemical and isotopic analyses of produced water for 3 time-series and 13 grab samples from Marcellus Shale gas wells in southwest and north central Pennsylvania (PA) are used to address the origin of the water and solutes produced over the long term (〉12 months). The question of whether the produced water originated within the Marcellus Shale, or whether it may have been drawn from adjacent reservoirs via fractures is addressed using measurements of $$^{228}\mathrm{Ra}/^{226}\mathrm{Ra}$$ and $$^{226}\mathrm{Ra}$$ activity. These parameters indicate that the water originated in the Marcellus Shale, and can be more broadly used to trace water of Marcellus Shale origin. During the first 1–2 weeks of production, rapid increases in salinity and positive shifts in $${\delta }^{18}\mathrm{O}$$ values were observed in the produced water, followed by more gradual changes until a compositional plateau was reached within approximately 1 yr. The $${\delta }^{18}\mathrm{O}$$ values and relationships between Na, Cl, and Br provide evidence that the water produced after compositional stabilization is natural formation water, the salinity for which originated primarily from evaporatively concentrated paleoseawater. The rapid transition from injected water to chemically and isotopically distinct water while $$ 〈 50\%$$ of the injected water volume had been recovered, supports the hypothesis that significant volumes of injected water were removed from circulation by imbibition.

Description: One of the challenges confronting carbon dioxide capture and sequestration (CCS) in geologic media over extended periods of time is determining the caprock sealing capacity. If the pressure of supercritical carbon dioxide $$({\mathrm{scCO}}_{2})$$ injected in the repository overcomes the caprock sealing capacity, leaking of $${\mathrm{scCO}}_{2}$$ may enter other porous formations, compromising the storage formation, or even may go back to the atmosphere, and thus the process of sequestration becomes futile. Carbon dioxide sealing capacity is controlled by two groups of parameters: (1)  texture (e.g., the pore-throat size, distribution, geometry, and sorting; median grain size, porosity, degree of bioturbation, specific surface area, preferred orientation of matrix clay minerals, orientation, and aspect of ratio of organic particles) and (2)  composition (mineralogical content, proportion of soft, deformable mineral grains to rigid grains, organic matter content, carbonate content, silt content, cementation, ductility, compaction, and ash content). The primary goal of this study was to investigate several parameters listed above and to estimate their respective contributions to sealing capacity to better understand its role in shale and carbonates. To assess the effect of textural and compositional properties on $${\mathrm{scCO}}_{2}$$ maximum retention column height, we collected 30 representative core samples from caprock formations in three counties (Cimarron, Texas, and Beaver) in the Oklahoma Panhandle. The study area was chosen because it hosts three depleted gas fields with a storage capacity of more than 35 million bbl and is situated at a crossroad leading to some significant $${\mathrm{CO}}_{2}$$ stationary sources from North Texas, South Kansas, and northern Oklahoma. We used mercury injection porosimetry, scanning electron microscopy (SEM), Sedigraph energy dispersive spectra (EDS), x-ray diffraction (XRD), Brunauer–Emmett–Teller-specific surface area, and total organic carbon (TOC) measurements to assess textural and compositional properties of collected samples. The range of $${\mathrm{scCO}}_{2}$$ column height for the samples used in this study is between 0.2 and 1358 m (0.66 and 4455 ft). The average $${\mathrm{scCO}}_{2}$$ column height is 351 m (1152 ft). The depth interval approximately 1400 m (4593 ft) could reach relatively high values of $${\mathrm{scCO}}_{2}$$ column height, up to 1200 m (3937 ft). The above-mentioned interval is composed of mainly Cherokee and Morrowan Formations (shale seals). Principal component analysis (PCA) was carried out to infer the possible relationships between textural and compositional parameters. Generally, composition of our samples (shales vs. carbonates and sandstones) indicates a relatively stronger control on caprock sealing capacity, although individual mineral makeup of shale samples seems not correlated with $${\mathrm{scCO}}_{2}$$ retention column heights. In the same time, many textural parameters play a significant role in determining the sealing capacity of carbonate caprocks.

Description: Using a seismic database from the Qiongdongnan Basin in the South China Sea, this study demonstrates that shelf-edge trajectories and stratal stacking patterns are reliable, but understated, predictors of deep-water sedimentation styles and volumes of deep-water sand deposits, assisting greatly in locating sand-rich environments and in developing a more predictive and dynamic stratigraphy. Three main types of shelf-edge trajectories and their associated stratal stacking patterns were recognized: (1) flat to slightly falling trajectories with negative trajectory angles ( $${T}_{\mathrm{se}}$$ ) (–2° to 0°) and negative shelf-edge aggradation to progradation ratios ( $$\mathrm{d}y/\mathrm{d}x$$ ) (–0.04 to 0) and associated progradational and downstepping stacking patterns with low clinoform relief ( $${R}_{\mathrm{c}}$$ ) (150–550 m [492–1804 ft]) and negative differential sedimentation on the shelf and basin ( $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ ) (–0.6 to 0); (2) slightly rising trajectories with moderate $${T}_{\mathrm{se}}$$ (0°–2°) and medium $$\mathrm{d}y/\mathrm{d}x$$ (0–0.04), and associated progradational and aggradational stacking patterns with intermediate $${R}_{\mathrm{c}}$$ (250–400 m [820–1312 ft]) and intermediate $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (0–0.6); and (3) steeply rising trajectories with high $${T}_{\mathrm{se}}$$ (2°–6°) and high $$\mathrm{d}y/\mathrm{d}x$$ (0.04–0.10) and associated dominantly aggradational stacking patterns with high $${R}_{\mathrm{c}}$$ (350–650 m [1148–2132 ft]) and high $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ (1–2). Each trajectory regime represents a specific stratal stacking patterns, providing new tools to define a model-independent methodology for sequence stratigraphy. Flat to slightly falling shelf-edge trajectories and progradational and downstepping stacking patterns are empirically related to large-scale, sand-rich gravity flows and associated bigger and thicker sand-rich submarine fan systems. Slightly rising shelf-edge trajectories and progradational and aggradational stacking patterns are associated with mixed sand/mud gravity flows and moderate-scale slope-sand deposits. Steeply rising shelf-edge trajectories and dominantly aggradational stacking patterns are fronted by large-scale mass-wasting processes and associated areally extensive mass-transport systems. Therefore, given a constant sediment supply, then $${T}_{\mathrm{se}}$$ , $$\mathrm{d}y/\mathrm{d}x$$ , $${R}_{\mathrm{c}}$$ , and $${A}_{\mathrm{s}}/{A}_{\mathrm{b}}$$ are all proportional to intensity of mass-wasting processes and to amounts of mass-transport deposits, and are inversely proportional to the intensity of sand-rich gravity flows and to amounts of deep-water sandstone. These relationships can be employed to relate quantitative characteristics of shelf-edge trajectories and stratal stacking patterns to deep-water sedimentation styles.

Description: Cementation of sandstone by minor late barite and sphalerite is widespread in the Scotian Basin at burial depths 〉2 km (〉1 mi), providing information on fluid flow in the basin. The texture and geochemistry of these minerals were analyzed by scanning electron microscopy and electron microprobe on samples from conventional core. Barite and sphalerite postdate silica and carbonate cementation, occurring in veins or occupying secondary porosity. They occur with diagenetic chlorite, kaolinite, pyrite, titania minerals, kutnohorite, and Mn-siderite. This study relates barite and sphalerite to the salt-tectonic evolution of the basin, based on seismic interpretation, and the thermal history of the basin, based on fluid inclusion studies. Barite is readily transported in basinal fluids 〉100°C (212°F), yet is consistently a very late diagenetic mineral. This implies that the source of Ba is because of the late diagenetic breakdown of K-feldspars at 2–3 km (1–2 mi) depth, which is confirmed by covariation of Ba and Rb in sandstones. Sulfur isotope data suggest that the $${\mathrm{SO}}_{4}^{2+}$$ was derived from Argo Formation evaporites that include 1%–7% anhydrite. Sphalerite is mobile only in saline formation water 〉140°C (〉284°F) and requires long-distance transport through sandstones with Zn-rich Fe-Ti oxides. Active detachment faults on salt welds provide potential pathways and a source of salt for migrating formation water. The particularities of source and transport of both barite and sphalerite allow the pathways of basinal fluids and their relationship to active salt tectonics to be inferred, providing indirect dating of the later stages of diagenetic paragenesis corresponding to times of hydrocarbon charge.

Description: Net fluid production and pressure data were gathered to estimate the amount of $${\mathrm{CO}}_{2}$$ storage space available and the potential for additional oil recovery using $${\mathrm{CO}}_{2}$$ -enhanced oil recovery (EOR) in the Phacoides sandstone, McKittrick oilfield, San Joaquin Valley, California. The Phacoides reservoir has produced 61.5 million reservoir barrels of fluid, a volume equivalent to the subsurface capacity of 9.8 million metric tons of $${\mathrm{CO}}_{2}$$ . Reservoir pressure changes with fluid production suggest that injecting 1 million metric tons of $${\mathrm{CO}}_{2}$$ may raise reservoir pressures by 2 MPa (255 psi). We assume that the sealing capacity of the reservoir for $${\mathrm{CO}}_{2}$$ injection is equivalent to the conditions controlling the original hydrocarbon accumulation. If injection pressures exceed this limit, the $${\mathrm{CO}}_{2}$$ could leak through the caprock, from aging wellbores or along faults in the reservoir. Faulting has compartmentalized the reservoir into six major blocks with varying degrees of hydraulic communication. Injection wells will be required within each sealed fault block, resulting in additional costs for implementing a carbon capture and sequestration (CCS) project. Through $${\mathrm{CO}}_{2}$$ -EOR, an additional 17 million bbl of oil may be recoverable, thereby offsetting the cost of carbon storage. This is equivalent to 1.4 million metric tons of additional storage space. However, assuming that none of the carbon is captured, combustion of this additional oil will add approximately 7 million metric tons of $${\mathrm{CO}}_{2}$$ to the atmosphere, negating the available storage space in the reservoir and resulting in a net carbon gain to the atmosphere of 700,000 metric tons.

Description: Ore grade is one of the primary variables controlling the economic recovery of bitumen from oil sands reservoirs, hence there is a need for fast and reliable quantification of total bitumen content (TBC). This is typically achieved through laboratory-based Dean-Stark analyses of drill core samples. However, this method is time and labor intensive and destructive to the core sample. Hyperspectral imaging is a remote sensing technique that can be defined as reflectance spectroscopy with a spatial context, where high-resolution digital imagery (~1 mm/pixel [0.04 in./pixel]) is acquired and reflectance measurements are collected in each pixel of the image. This study compares two hyperspectral models for the determination of TBC from imagery of both fresh and dry core samples. For three out of four suites of fresh core, TBC was predicted within ±1.5 wt. % of the Dean-Stark data with both spectral models achieving correlations of $${R}^{2} 〉 0.97$$ . For a fourth fresh core and the dry core, larger margins of error were found because of some instances of overestimation. Surface roughness because of uneven oil distribution and small-scale fracturing is a potential source of error in some of the spectral TBC results, particularly for the dry core. Producing results within minutes with the additional benefit of being nondestructive to the core sample, hyperspectral imaging shows great potential to become a viable alternative method for bitumen content determination in oil sands.

Description: Many $${\mathrm{CO}}_{2}$$ -rich (up to 97% by volume) natural gas pools have been found in the continental margin basins of the northern South China Sea. By combining the geochemical data from 53 samples with their geologic backgrounds, this study investigated the origins and accumulation mechanism of $${\mathrm{CO}}_{2}$$ , and discussed the role of $${\mathrm{CO}}_{2}$$ in driving oil as it charged the reservoirs. The results reveal that the $${\mathrm{CO}}_{2}$$ gases in the Yinggehai basin originate mainly from the thermal decomposition of both Miocene calcareous shales and Paleozoic carbonates, and that $${\mathrm{CO}}_{2}$$ from mantle degassing is only a minor contributor. The $${\mathrm{CO}}_{2}$$ accumulations in the Yinggehai basin are mainly controlled by diapiric faults and episodic thermal fluid movements. The $${\mathrm{CO}}_{2}$$ gases in the eastern Qiongdongnan and western Pearl River Mouth basins are mainly related to magmatic or mantle degassing, and the volatiles from magmatic degassing during the igneous intrusion stage are the most likely major source of $${\mathrm{CO}}_{2}$$ in these reservoirs, with basement faults providing pathways for upward migration of $${\mathrm{CO}}_{2}$$ -rich mantle fluids. Natural displacements of oil by $${\mathrm{CO}}_{2}$$ appear to be common in the eastern Qiongdongnan and western Pearl River Mouth basins. The $${\mathrm{CO}}_{2}$$ -flooded oil or gas reservoirs have two common features that the present $${\mathrm{CO}}_{2}$$ gas pools or oil-bearing structures have residual oils representing prior charge, and are close to the basement faults that provide pathways along which the mantle-derived $${\mathrm{CO}}_{2}$$ -rich gas was migrated. The oils from prior hydrocarbon reservoirs have been naturally driven out by $${\mathrm{CO}}_{2}$$ to form secondary oil reservoirs in the eastern Qiongdongnan and western Pearl River Mouth basins. Therefore, a full understanding of the origin and distribution of $${\mathrm{CO}}_{2}$$ cannot just be used to trace hydrocarbon migration pathways, but also provide useful information for risk assessment prior to drilling.

Description: We reviewed the tectonostratigraphic evolution of the Jurassic–Cenozoic collision between the North American and the Caribbean plate using more than 30,000 km (18,641 mi) of regional two-dimensional (2-D) academic seismic lines and Deep Sea Drilling Project wells of Leg 77. The main objective is to perform one-dimensional subsidence analysis and 2-D flexural modeling to better understand how the Caribbean collision may have controlled the stratigraphic evolution of the offshore Cuba region. Five main tectonic phases previously proposed were recognized: (1) Late Triassic–Jurassic rifting between South and North America that led to the formation of the proto-Caribbean plate; this event is interpreted as half grabens controlled by fault family 1 as the east-northeast–south-southwest–striking faults; (2) Middle–Late Jurassic anticlockwise rotation of the Yucatan block and formation of the Gulf of Mexico; this event resulted in north-northwest–south-southeast–striking faults of fault family 2 controlling half-graben structures; (3) Early Cretaceous passive margin development characterized by carbonate sedimentation; sedimentation was controlled by normal subsidence and eustatic changes, and because of high eustatic seas during the Late Cretaceous, the carbonate platform drowned; (4) Late Cretaceous–Paleogene collision between the Caribbean plate, resulting in the Cuban fold and thrust belt province, the foreland basin province, and the platform margin province; the platform margin province represents the submerged paleoforebulge, which was formed as a flexural response to the tectonic load of the Great Arc of the Caribbean during initial Late Cretaceous–Paleocene collision and foreland basin development that was subsequently submerged during the Eocene to the present water depths as the arc tectonic load reached the maximum collision; and (5) Late Cenozoic large deep-sea erosional features and constructional sediment drifts related to the formation of the Oligocene–Holocene Loop Current–Gulf Stream that flows from the northern Caribbean into the Straits of Florida and to the north Atlantic.

Description: Although conventional reservoirs dominate the Bohai Basin, China, a new type of sandstone reservoir also exists in the Dongpu depression that has a low matrix porosity (tight) in which natural fractures govern both permeability and porosity. These fractured sandstones are located on a structurally modified buried hill underlying Paleogene mudstones, and are truncated along an angular unconformity. The fractured sandstone oils of the Triassic Liujiagou, Heshanggou, and Ermaying Formations are derived from the Paleogene Shahejie Formation, which reached peak oil generation and expulsion during the Oligocene to early Miocene (32.8–15.6 Ma). Gas was generated primarily during the Paleogene from Carboniferous and Permian coals. Petrographic evidence suggests that oil and gas emplacement followed the compaction and cementation of the Triassic sandstone reservoirs. Fluid inclusion evidence and burial history analysis suggest that fractures developed before oil emplacement but may have coincided with peak gas generation, which suggests that oil and gas mainly migrated and accumulated in fractures.

Description: Characterization of oil shale kerogen and organic residues remaining in postpyrolysis spent shale is critical to the understanding of the oil generation process and approaches to dealing with issues related to spent shale. The chemical structure of organic matter in raw oil shale and spent shale samples was examined in this study using advanced solid-state 13 C nuclear magnetic resonance (NMR) spectroscopy. Oil shale was collected from Mahogany zone outcrops in the Piceance Basin. Five samples were analyzed: (1) raw oil shale, (2) isolated kerogen, (3) oil shale extracted with chloroform, (4) oil shale retorted in an open system at 500°C to mimic surface retorting, and (5) oil shale retorted in a closed system at 360°C to simulate in-situ retorting. The NMR methods applied included quantitative direct polarization with magic-angle spinning at 13 kHz, cross polarization with total sideband suppression, dipolar dephasing, CH n selection, 13 C chemical shift anisotropy filtering, and 1 H- 13 C long-range recoupled dipolar dephasing. The NMR results showed that, relative to the raw oil shale, (1) bitumen extraction and kerogen isolation by demineralization removed some oxygen-containing and alkyl moieties; (2) unpyrolyzed samples had low aromatic condensation; (3) oil shale pyrolysis removed aliphatic moieties, leaving behind residues enriched in aromatic carbon; and (4) oil shale retorted in an open system at 500°C contained larger aromatic clusters and more protonated aromatic moieties than oil shale retorted in a closed system at 360°C, which contained more total aromatic carbon with a wide range of cluster sizes.

Description: The central Black Sea Basin of Turkey is filled by more than 9 km (6 mi) of Upper Triassic to Holocene sedimentary and volcanic rocks. The basin has a complex history, having evolved from a rift basin to an arc basin and finally having become a retroarc foreland basin. The Upper Triassic–Lower Jurassic Akgöl and Lower Cretaceous Çaglayan Formations have a poor to good hydrocarbon source rock potential, and the middle Eocene Kusuri Formation has a limited hydrocarbon source rock potential. The basin has oil and gas seeps. Many large structures associated with extensional and compressional tectonics, which could be traps for hydrocarbon accumulations, exist. Fifteen onshore and three offshore exploration wells were drilled in the central Black Sea Basin, but none of them had commercial quantities of hydrocarbons. The assessment of these drilling results suggests that many wells were drilled near the Ekinveren, Erikli, and Ballifaki thrusts, where structures are complex and oil and gas seeps are common. Many wells were not drilled deep enough to test the potential carbonate and clastic reservoirs of the Inalti and Çaglayan Formations because these intervals are locally buried by as much as 5 km (3 mi) of sedimentary and volcanic rocks. No wells have tested prospective structures in the north and east where the prospective Inalti and Çaglayan Formations are not as deeply buried. Untested hydrocarbons may exist in this area.

Description: The concept of common stratigraphic framework was previously introduced to construct and cross-validate multilayer static and dynamic petrophysical models by invoking the interactive numerical simulation of well logs both before and after invasion. This article documents the successful implementation of the common stratigraphic framework concept to examine and quantify the effects of mud-filtrate invasion on apparent resistivity, nuclear, and magnetic resonance logs acquired in the San Martin, Cashiriari, and Pagoreni gas fields in Camisea, Peru. Conventional petrophysical interpretation methods yield abnormally high estimates of water saturation in some of the reservoir units that produce gas with null water influx. Such an anomalous behavior is caused by relatively low values of deep apparent electrical resistivity and has otherwise been attributed to the presence of clay-coating grains and/or electrically conductive grain minerals coupled with fresh connate water. Concomitantly, electrical resistivity logs exhibit substantial invasion effects as evidenced by the variable separation of apparent resistivity curves (both logging-while-drilling and wireline) with multiple radial lengths of investigation. In extreme cases, apparent resistivity logs stack because of very deep invasion. We diagnose and quantify invasion effects on resistivity and nuclear logs with interactive numerical modeling before and after invasion. The assimilation of such effects in the interpretation consistently decreases previous estimates of water saturation to those of irreducible water saturation inferred from core data. We show that capillary pressure effects are responsible for the difference in separation of apparent resistivity curves in some of the reservoir units. This unique field study confirms that well logs should be corrected for mud-filtrate invasion effects before implementing arbitrary shaly sand models and parameters thereof in the calculation of connate-water saturation.

Description: This article addresses the controls exerted by sedimentologic and diagenetic factors on the preservation and modification of pore-network characteristics (porosity, pore types, sizes, shapes, and distribution) of carbonates belonging to the Bolognano Formation. This formation, exposed at the Majella Mountain, Italy, is composed of Oligocene–Miocene carbonates deposited in middle- to outer-ramp settings. The carbonates consist of (1) grainstones predominantly composed of either larger benthic foraminifera, especially Lepidocyclina , or bryozoans; (2) grainstones to packstones with abundant echinoid plates and spines; and (3) marly wackestones to mudstones with planktonic foraminifera. The results of this field- and laboratory-based study are consistent with skeletal grain assemblages, grain sizes, sorting, and shapes, all representing the sedimentologic factors responsible for high values of connected primary macroporosity in grainstones deposited on the high-energy, middle to proximal outer ramp. Cementation, responsible for porosity reduction and overall macropore shape and distribution in grainstones to packstones deposited on the intermediate outer ramp, was mainly dependent on the following factors: (1) amount of echinoid plates and spines, (2) grain size, (3) grain sorting and shapes, and (4) clay amount. Differently, in the wackestones to mudstones, laid down on the low-energy, distal outer ramp, matrix is the key sedimentologic factor responsible for low values of scattered macroporosity and dominance of microporosity. The aforementioned results may be useful to improve the prediction of reservoir quality by means of mapping, simulating, and assessing individual carbonate facies with peculiar pore-network characteristics.

Description: Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C 1 ,C 2+ ) ( 13 C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature ( 13 C[ C1 – C2 ][ 13 C 1 – 13 C 2 ]: 〈–9), isotopically light methane, with low ( 4 He) (average, 1 x 10 –3 cc/cc) elevated 4 He/ 40 Ar* and 21 Ne*/ 40 Ar* (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane ( 13 C [C1 – C2] [ 13 C 1 – 13 C 2 ]: 〉3), with high ( 4 He) (average, 1.85 x 10 –3 cc/cc) 4 He/ 40 Ar* and 21 Ne*/ 40 Ar* near crustal production levels and elevated crustal noble gas content (enriched 4 He, 21 Ne*, 40 Ar*). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

Description: The recognition of paleokarst in subsurface carbonate reservoirs is not straightforward because conventional seismic interpretation alone is generally not sufficient to discriminate karstified areas from their surroundings. In the Loppa High (Norwegian Barents Sea), a protracted episode of subaerial exposure occurring between the late Paleozoic and mid-Triassic—Late Permian to Anisian—resulted in a significant overprinting of the previously deposited carbonate units. Here, we map the extension of the karstified areas using an integrated approach consisting of (1) a core study of critical paleokarst intervals, (2) a three-dimensional (3-D) seismic stratigraphic analysis, and (3) a 3-D multiattribute seismic facies (SF) classification. A core retrieved in the flat-topped Loppa High revealed breccia deposits at least 50 m (164 ft) thick, which probably resulted from cave collapses following the burial of the karst terrain. The SF classification was tested on a 3-D cube to (1) discriminate the respective SF related to the breccia deposits compared with other SF and (2) to estimate their spatial extent. Seismic-facies analysis suggests that breccias occupied the topmost area of the structural high, extending up to 12 km (7 mi) in width, 46 km (29 mi) in length, and tens of meters in thickness. The inference of such a large amount of breccia suggests that a significant part of this terrain was derived from the amalgamation of successive cave-development events—including periods of subaerial exposure and subsequent burial and collapse—resulting in a coalesced collapsed paleocave system. Previous observations from the Loppa High revealed the presence of karst plains associated with sinkholes, caves, and other dissolution phenomena associated with the breccia facies, further suggesting that a large volume of carbonate rocks in this area was affected by subaerial exposure and karstification. Our integrated approach and proposed karstification model could be applied to similar sedimentary basins that accommodate deeply buried carbonate successions affected by protracted episodes of subaerial exposure, where only few wells as well as 3-D seismic data are available.

Description: Unconventional gas (tight gas, coalbed methane, and shale gas) has become an increasingly significant source of energy. Economic production from such low-permeability reservoirs relies upon identifying regions of the reservoir that will yield the highest gas production rates. Currently available gas recovery technologies are highly dependent on the fracturability of the reservoir. Zones of enhanced brittleness and permeability within shale-gas reservoir horizons are a prerequisite for successful shale-gas recovery. Such brittle zones are directly linked with increased quartz and/or carbonate content within the mudstone. In mudstones with high clay-mineral content, quartz may be concentrated and redistributed as a result of burrowing activities of infaunal organisms. High-quality porosity and permeability zones in shale-petroleum reservoirs may be present in the form of silty and sandy tortuous strips of selectively concentrated grains of quartz that constitute burrow halos. Grain-selective burrows therefore can improve reservoir capacity, permeability, and fracturability and thus control the storativity of the shale-petroleum reservoir. This study presents three-dimensional reconstructions of three different types of Phycosiphon -like burrows and investigates the possible fluid-flow paths caused by the ichnofabric. The volumetric approach to the bioturbation generated by phycosiphoniform burrow makers used herein shows that the volume of sediment that becomes more porous and more permeable media within such bioturbated interval can range from 13 to 26% of the total volume. The quartzose strips of sediment caused by bioturbation are highly tortuous and interconnected vertically and horizontally, thereby increasing both horizontal and vertical permeability. Additionally, the quartz frameworks created by the burrows may locally increase fracturability within otherwise nonbrittle mudstones.

Description: Deep gas potential in the Polish Basin may factor significantly in European geopolitics, and thermal effects can influence that outcome there and elsewhere. Deep (〉3 km [9843 ft]) well data from the Kujawy area of the central Polish Basin reveal average geothermal gradient (36°C/km), thermal conductivity of Mesozoic strata ( k = 2.29 W/m K), and present-day heat flow ( Q = 82.4 mW/m 2 ) that is 3% less than that obtained using the entire borehole. The extrapolated surface temperature (–6.2°C) is in good agreement with temperatures during the Weichselian glaciation. The thermal conductivity of the Upper Permian Zechstein (4.89 W/m K) is in good agreement with values from the North Sea and northern Germany. Steady-state heat-flow theory (one-dimensional [1-D]) predicts present-day temperature (199°C) at the base of Zechstein cap rock at 6-km (19,685-ft) depth in Kujawy. This is reduced just more than 10°C by low Zechstein thermal gradients (16.8°C/km). Because of thermal refraction, two-dimensional and three-dimensional models of Zechstein salt pillows can significantly negate this cooling effect; however, such effects appear absent in the Kujawy wells studied. A widespread Early to Middle Jurassic (~195–175 Ma) hydrothermal event appears to have reached maximum in the Kujawy area. A 455°C paleotemperature at 7-km (22,966-ft) depth (Carboniferous) is predicted by 1-D conductive heat transfer; however, geologic evidence does not support this result. The discrepancy is reconciled by convective heat transfer with upward fluid flow (3.3 x 10 –10 m/s [10.8 x 10 –10 ft/s]), resulting in a maximum paleotemperature of 273°C at 7-km (22,966-ft) depth, despite a paleoheat flow of 142 mW/m 2 . The trend of intensity of the hydrothermal event correlates with the present-day heat-flow trend. Hydrothermal event sites are subparallel to the major northwest-southeast structural and regional heat-flow trend, whereas other sites as close as 14 km (45,932 ft) and without hydrothermal event are not. The decay of the hydrothermal event is consistent with localized cylindrical plumes (10-km [32,808-ft] radius) that cool by conduction. Results suggest a long-term (~185 m.y.) structural control on heat flow. Linear regression to vitrinite paleotemperatures yields a 185-Ma Jurassic surface temperature of approximately 21.3°C that is approximately 13°C higher than the present-day temperature for Warsaw, Poland. The duration of maximum reservoir and source rock paleotemperature (〈50 m.y.) is contrary to the kinetics of nitrogen and CO 2 -producing wells. Equilibrium thermodynamics predicts approximately 60% methane for present-day Kujawy reservoirs, with considerable uncertainty that should be removed by anticipated new deep drilling.

Description: The Marcellus Formation of Pennsylvania represents an outstanding example of an organic matter (OM)–hosted pore system; most pores detectable by field-emission scanning electron microscopy (FE-SEM) are associated with OM instead of mineral matrix. In the two wells studied here, total organic carbon (TOC) content is a stronger control on OM-hosted porosity than is thermal maturity. The two study wells span a maturity from late wet gas (vitrinite reflectance [R o ], ~1.0%) to dry gas (R o , ~2.1%). Samples with a TOC less than 5.5 wt. % display a positive correlation between TOC and porosity, but samples with a TOC greater than 5.5 wt. % display little or no increase in porosity with a further increasing TOC. In a subset of samples (14) across a range of TOC (2.3–13.6 wt. %), the pore volume detectable by FE-SEM is a small fraction of total porosity, ranging from 2 to 32% of the helium porosity. Importantly, the FE-SEM–visible porosity in OM decreases significantly with increasing TOC, diminishing from 30% of OM volume to less than 1% of OM volume across the range of TOC. The morphology and size of OM-hosted pores also vary systematically with TOC. The interpretation of this anticorrelation between OM content and SEM-visible pores remains uncertain. Samples with the lowest OM porosity (higher TOC) may represent gas expulsion (pore collapse) that was more complete as a consequence of greater OM connectivity and framework compaction, whereas samples with higher OM porosity (lower TOC) correspond to rigid mineral frameworks that inhibited compactional expulsion of methane-filled bubbles. Alternatively, higher TOC samples may contain OM (low initial hydrogen index, relatively unreactive) that is less prone to development of FE-SEM–detectable pores. In this interpretation, OM type, controlled by sequence-stratigraphic position, is a factor in determining pore-size distribution.

Description: In this study, seismic models and a Starfak and Tiger Shoal fields data set in the Gulf of Mexico Basin are used to investigate uncertainties caused by the frequency dependence of seismic data and solutions for avoiding pitfalls in seismic-stratigraphic and facies interpretation. Seismic amplitude and instantaneous attributes, along with stratigraphic interpretation of these attributes, are controlled by seismic interference, or tuning, between thin geologic units. Seismic-tuning effects include thickness tuning and frequency tuning, which cause nonlinear variations of reflection amplitude and instantaneous seismic attributes with thickness and/or data frequency. Seismic modeling shows that, whereas thickness tuning determines seismic-interference patterns and, therefore, occurrence of seismic events and seismic facies in layered rock, frequency tuning may further influence the nature of the correlation of seismic data and geologic time and modify seismic facies. Frequency dependence offers a new dimension of seismic data, which has not been fully used in seismic interpretation of geology. Field-data examples demonstrate that a stratigraphic formation is typically composed of lithofacies of varying thicknesses, and a broadband, stacked seismic data set is not necessarily optimal for stratigraphic and facies interpretation. Although it is difficult to predict correct frequency components for interpretation of not-yet-known geologic targets, local geologic models and well data can be used to optimize the frequency components of seismic data to a certain degree and intentionally modify seismic-interference patterns and seismic facies for better seismic interpretation of geologic surfaces, sediment-dispersal patterns, geomorphology, and sequence stratigraphy.

Description: This article concentrates on the question, Which parameters govern recovery factor (RF) behavior in channelized turbidite reservoirs? The objective is to provide guidelines for the static and dynamic modeling of coarse reservoir-scale models by providing a ranking of the investigated geologic and reservoir engineering parameters based on their relative impact on RF. Once high-importance (H) parameters are understood, then one can incorporate them into static and dynamic models by placing them explicitly into the geologic model. Alternatively, one can choose to represent their effects using effective properties (e.g., pseudorelative permeabilities). More than 1700 flow simulations were performed on geologically realistic three-dimensional sector models at outcrop-scale resolution. Waterflooding, gas injection, and depletion scenarios were simulated for each geologic realization. Geologic and reservoir engineering parameters are grouped based on their impact on RF into H, intermediate-importance (M), and low-importance (L) categories. The results show that, in turbidite channel reservoirs, dynamic performance is governed by architectural parameters such as channel width, net-to-gross, and degree of amalgamation, and parameters that describe the distribution of shale drapes, particularly along the base of channel elements. The conclusions of our study are restricted to light oils and relatively high-permeability channelized turbidite reservoirs. The knowledge developed in our extensive simulation study enables the development of a geologically consistent and efficient dynamic modeling approach. We briefly describe a methodology for generating effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into fast simulation models.

Description: This study documents that Danian-aged sand remobilization of deep-water slope-channel complexes and intrusion of fluidized sand into hydraulically fractured slope mudstones of the Great Valley sequence, California, generated 400-m (1312 ft)–thick reservoir units: unit 1, parent unit channel complexes for shallower sandstone intrusions; unit 2, a moderate net-to-gross interval (0.19 sand) of sills with staggered, stepped, and multilayer geometries with well-developed lateral sandstone-body connectivity; unit 3, a low net-to-gross interval (0.08 sand) of exclusively high-angle dikes with good vertical connectivity; and unit 4, an interval of extrusive sandstone. Unit 2 was formed during a phase of fluidization that emplaced on an average 0.19 km 3 (0.046 mi 3 ) of sand per cubic kilometer of host sediment. Probe permeametry data reveal a positive relationship between sill thickness and permeability. Reservoir quality is reduced by the presence of fragments of host strata, such as the incorporation of large rafts of mudstone, which are formed by in-situ hydraulic fracturing during sand injection. Mudstone clasts and clay- and silt-size particles generated by intrusion-induced abrasion of the host strata reduce sandstone permeability in multilayer sills (70 md) when compared to that in staggered and stepped sills (586 and 1225 md, respectively). Post-injection cementation greatly reduces permeability in high-angle dikes (81 md). This architecturally based reservoir zonation and trends in reservoir characteristics in dikes and sills form a basis for quantitative reservoir modeling and can be used to support conceptual interpretations that infer injectite architecture in situations where sands in low net-to-gross intervals are anticipated to have well-developed lateral and vertical connectivity.

Description: A series of short and steep unidirectionally migrating deep-water channels, which are typically without levees and migrate progressively northeastward, are identified in the Baiyun depression, Pearl River Mouth Basin. Using three-dimensional seismic and well data, the current study documents their morphology, internal architecture, and depositional history, and discusses the distribution and depositional controls on the bottom current–reworked sands within these channels. Unidirectionally migrating deep-water channels consist of different channel-complex sets (CCSs) that are, overall, short and steep, and their northeastern walls are, overall, steeper than their southwestern counterparts. Within each CCS, bottom current–reworked sands in the lower part grade upward into muddy slumps and debris-flow deposits and, finally, into shale drapes. Three stages of CCSs development are recognized: (1) the early lowstand incision stage, during which intense gravity and/or turbidity flows versus relatively weak along-slope bottom currents of the North Pacific intermediate water (NPIW-BCs) resulted in basal erosional bounding surfaces and limited bottom current–reworked sands; (2) the late lowstand lateral-migration and active-fill stage, with gradual CCS widening and progressively northeastward migration, characterized by reworking of gravity- and/or turbidity-flow deposits by vigorous NPIW-BCs and the CCSs being mainly filled by bottom current–reworked sands and limited slumps and debris-flow deposits; and (3) the transgression abandonment stage, characterized by the termination of the gravity and/or turbidity flows and the CCSs being widely draped by marine shales. These three stages repeated through time, leading to the generation of unidirectionally migrating deep-water channels. The distribution of the bottom current–reworked sands varies both spatially and temporally. Spatially, these sands mainly accumulate along the axis of the unidirectionally migrating deep-water channels and are preferentially deposited to the side toward which the channels migrated. Temporally, these sands mainly accumulated during the late lowstand lateral-migration and active-fill stage. The bottom current–reworked sands developed under the combined action of gravity and/or turbidity flows and along-slope bottom currents of NPIW-BCs. Other factors, including relative sea level fluctuations, sediment supply, and slope configurations, also affected the formation and distribution of these sands. The proposed distribution pattern of the bottom current–reworked sands has practical implications for predicting reservoir occurrence and distribution in bottom current–related channels.

Description: The Sierra Diablo Mountains of west Texas contain world-class exposures of Lower Permian (Leonardian) platform carbonates. As such, these outcrops offer key insights into the products of carbonate deposition in the transitional icehouse to greenhouse setting of the early to middle Permian that are available in few other places. They also afford an excellent basis for examining how styles of facies and sequence development vary between inner and outer platform settings. We collected detailed data on the facies composition and architecture of lower Leonardian high-frequency cycles and sequences from outcrops that provide more than 2 mi (3 km) of continuous exposure. We used these data to define facies stacking patterns along depositional dip across the platform in both low- and high-accommodation settings and to document how these patterns vary systematically among and within sequences. Like icehouse and waning icehouse successions elsewhere, Leonardian platform deposits are highly cyclic; cycles dominantly comprise aggradational upward-shallowing facies successions that vary according to accommodation setting. Cycles stack into longer duration high-frequency sequences (HFSs) that exhibit systematic variations in facies and cycle architectures. Unlike cycles, HFSs can comprise symmetrical upward-shallowing or upward-deepening facies stacks. High-frequency sequences are not readily definable from one-dimensional stratigraphic sections but require dip-parallel two-dimensional sections and, in most cases, HFS boundaries are best defined in middle platform settings where facies contrast and offset are greatest. These studies demonstrate that HFSs are the dominant architectural element in many platform systems. As such, the lessons learned from these remarkable outcrops provide a sound basis for understanding and modeling carbonate facies architecture in other carbonate-platform successions, especially those of the middle to upper Permian.

Description: It has been suggested by some that methane contamination of water wells is the main negative consequence of the development of natural gas resources. Concurrently, speculation in academic white papers and in the press that methane may be toxic has resulted in public concern. In northern Pennsylvania, methane being released from groundwater and entering homes (so-called stray gas) has become a focus of this concern. This phenomenon was widespread decades before shale gas development was initiated. This paper reviews the available literature on the safety and health hazards associated with natural gas. It concludes that the risks to homeowners are highest from flash fires occurring in methane oxygen gas clouds at relatively low methane concentrations collecting in poorly ventilated, confined areas of houses such as basements. Such risks can be mitigated effectively and in most cases at minimal cost. Methane can result in death from hypoxia (lack of oxygen) but only at methane levels in the air of more than 60%, which are unlikely to develop except under exceptional circumstances. There is no evidence that low to moderate levels of exposure to methane in air have any toxic effect on humans, and evidence for such effects at very high levels (already fatal because of hypoxia) is equivocal. It seems likely that methane at concentrations at least as high as 2.5% may well have positive health benefits for some diseases.

Description: Micropores can constitute up to 100% of the total porosity within carbonate-hosted hydrocarbon reservoirs, usually existing within micritic fabrics. Here, three-dimensional computational representations of end-point micritic fabrics are produced using a flexible, object-based algorithm to further our understanding of the contribution that micropores make to flow. By methodically altering model parameters, we explore the state space of microporous carbonates, quantifying single and multiphase flow using lattice-Boltzmann and network models. In purely micritic fabrics, average pore radius (ranging from 0.26 to 0.44 μm) was found to have a positive correlation with single-phase permeability (1.7 to 2.7 md, respectively). Similarly, increasing average pore size resulted in decreasing residual oil saturation under both water-wet and 50% fractionally oil-wet states. Permeability was found to increase by an order of magnitude (from 0.6 to 7.5 md) within fabrics of varying total matrix porosity (from 18% to 35%) because of increasing pore size (0.37 to 0.56 μm, respectively), but minimal effect on multiphase flow was observed. Increased pore size due to micrite rounding notably increases permeability in comparison with original rhombic fabrics with the same porosity, but multiphase flow properties are unaffected. Finally, when moldic mesopores are added to a micritic matrix, they impact flow when directly connected. Otherwise, micropores control single-phase permeability magnitude. Importantly, recovery is dependent on both wetting scenario and pore-network homogeneity: under water-wet imbibition, increasing proportions of microporosity yield lower residual oil saturations. Together, these results quantify the importance of micropores in contributing to, or controlling, overall flow and sweep characteristics in such fabrics.

Description: Coal rank reflects the temperature of coalification, with higher rank coal forming at higher temperatures. If the temperature of coalification depended only on the Earth’s geothermal gradient, then the maximum rank of coal in a sedimentary basin should be directly proportional to the thickness of strata above the coal. This association does not occur in the Illinois Basin, a continental-interior basin in the midwestern United States, where the overall coal rank observed is higher than can be explained by past burial depth alone. Recognition of this anomaly has led many authors to suggest that hot groundwater flowing from south to north, during a Paleozoic basin-scale groundwater-migration event, increased coal rank. We analyzed vitrinite reflectance $$({R}_{\mathrm{o}})$$ , a measure of rank, as a function of depth in wells across the basin to determine how paleogeotherms, representing variation in temperature with depth, change with location. Our results show that the basin can be divided into three zones: (1) in the southern zone, the paleogeotherm varies irregularly with depth in strata above the sub-Absaroka unconformity (the contact separating Pennsylvanian and Mississippian strata); (2) in the central zone, the paleogeotherm displays a distinct inflection at the unconformity, for the rate of increase in $${R}_{\mathrm{o}}$$ with depth is greater above the unconformity than below the unconformity; and (3) the observed inflection in the paleogeotherm dies out northward, until, in the northern zone, the paleogeotherm has the same slope both above and below the unconformity. We propose that the inflection in the paleogeotherm of the central zone indicates that the hot groundwater responsible for causing an increase in coal rank flowed through a high-permeability zone just below the sub-Absaroka unconformity. This flow, which advected heat into Pennsylvanian strata above, cooled as it moved northward, so it did not influence the paleogeotherm in the northern zone. Preliminary studies of vein paragenesis, stable-isotope composition, and fluid-inclusions, as well as computer modeling of flow-related heat advection, support this proposal.

Description: This multidisciplinary study evaluates the structural and hydrogeologic evolution of Cretaceous-age reservoirs in the Putumayo basin, Colombia. We focused on the Eastern Cordillera fold-thrust belt along the southern Garzón Massif. Many important hydrocarbon accumulations occurred regionally along the proximal foreland basin and frontal fold-thrust belt defining the eastern margin of the northern Andes. To understand why recent Putumayo basin and adjacent thrust belt exploration has resulted in a wide range of oil quality and limited economic discoveries, we reconstructed the structural evolution, timing of oil migration, and timing of groundwater infiltration by (1) assessing regional trends in formation water, oil, and reservoir properties; (2) quantifying the timing of hydrocarbon generation and migration relative to trap formation using (a) two-dimensional (2-D) and three-dimensional seismic data to define and constrain a restorable balanced cross section from the Upper Magdalena Valley to the Putumayo foreland and (b) coupled one-dimensional thermal basin modeling; (3) evaluating the potential roles of Mesozoic extensional faulting and Paleogene shortening in the generation and preservation of structural traps; and (4) assessing groundwater influx from the modern foothills into the reservoir using a 2-D numerical groundwater flow model. We suggest that four-way closure is limited in the study area, where most foreland-verging structures create three-way fault closures that do not effectively trap light hydrocarbons. In addition, east-dipping structures and a relatively large reservoir outcrop area provide water infiltration pathways. Groundwater modeling suggests reservoirs were water washed by 2–200 million pore volumes since Andean uplift. Finally, average reservoir temperatures are 〈80°C (〈176°F), which further facilitated biodegradation.

Description: Potentiometric surfaces for Paleozoic strata, based on water well levels and selected drill-stem tests, reveal the control on hydraulic head exerted by outcrops in eastern Kansas and Oklahoma. From outcrop in the east, the westward climb of hydraulic head is much less than that of the land surface, with heads falling so far below land surface that the pressure:depth ratio in eastern Colorado is less than 5.7 kPa/m (0.25 psi/ft). Permian evaporites separate the Paleozoic hydrogeologic units from a Lower Cretaceous (Dakota Group) aquifer, and a highly saline brine plume pervading Paleozoic units in central Kansas and Oklahoma is attributed to dissolution of Permian halite. Underpressure also exists in the Lower Cretaceous hydrogeologic unit in the Denver Basin, which is hydrologically separate from the Paleozoic units. The data used to construct the seven potentiometric surfaces were also used to construct seven maps of pressure:depth ratio. These latter maps are a function of the differences among hydraulic head, land-surface elevation, and formation elevation. As a consequence, maps of pressure:depth ratio reflect the interplay of three topologies that evolved independently with time. As underpressure developed, gas migrated in response to the changing pressure regime, most notably filling the Hugoton gas field in southwestern Kansas. The timing of underpressure development was determined by the timing of outcrop exposure and tilting of the Great Plains. Explorationists in western Kansas and eastern Colorado should not be surprised if a reservoir is underpressured; rather, they should be surprised if it is not.

Description: In many tight-gas basins of the western United States distinguishing between productive and non-productive low-permeability sandstones, and predicting relative amounts of gas and water production is difficult. Comparison of gas shows, calculated water saturations, and saturation-height profiles between gas-productive and non-productive sandstones of equal reservoir quality all appear similar. Capillary pressure derived height functions are difficult to apply, and classic rock-typing procedures lack the predictive capability that is common to more traditional reservoirs. Basin reconstructions suggest the timing of petroleum charge and migration preceded maximum burial and uplift. This initial charge was likely a primary drainage displacement with reservoir porosity greater by a factor of 2-3 relative to values found today and permeability greater by 1-3 orders of magnitude. These reservoir systems became low-permeability following initial charge reflecting continued diagenesis throughout burial, subsequent uplift and erosion. With burial, decreasing pore volume caused water saturations and gas columns to increase. During uplift and erosion gas columns adjusted to changing structural configuration. In some cases this led to gas accumulations being leaked and spilled. In other cases, structural readjustment resulted in capillary imbibition and, in some cases, secondary (or higher order) drainage and imbibition. Within trapped accumulations, gas expansion upon uplift further increased gas columns. In cases where gas columns were spilled or within migration pathways imbibition led to residual or near-residual water saturations. Conventional formation evaluation is fundamentally rooted in concepts associated with primary drainage displacement. Tight-gas reservoirs that have experienced late uplift following an earlier phase of charge are unlikely to be characterized by primary drainage and are much more likely to be characterized by imbibition or secondary (or higher order) drainage and possibly imbibition. The hysteresis between primary drainage and imbibition or secondary (or higher order) drainage and imbibition in tight-gas reservoirs is significant and unlike many more traditional reservoirs does not tend to converge on a narrow range of values. Estimates of water saturation are scalar values and do not contain information that allows the saturation history and displacement direction to be deciphered. Recognition that reservoirs are unlikely to be in primary drainage equilibrium is a fundamental paradigm shift that impacts petroleum evaluation at all scales ranging from basin potential to completion decisions within a given well. Although this paper is written from the perspective of tight-gas petroleum systems, the principles are equally applicable to low-permeability oil reservoirs.

Description: Lithofacies, architectural-element abundance, and estimates of dune-bedform height and channel sinuosity from borehole images (BHIs) and well-exposed outcrops allow for an expanded interpretation of the fluvial stratigraphic architecture of the Upper Cretaceous Williams Fork Formation. Sedimentologic and stratigraphic data from outcrops and detailed core descriptions of the Williams Fork Formation, Piceance Basin, Colorado, were used to compare attributes of fluvial architectural elements to BHI characteristics and spectral-gamma-ray (SGR) log motifs. Results show a distinct set of criteria based on BHIs that aid in the interpretation of lithofacies and fluvial reservoir architecture. In contrast, a practical correlation does not exist between outcrop- and core-derived SGR log motifs or thorium and potassium abundances and fluvial lithofacies or architectural elements. Four electrofacies based on BHI characteristics (e.g., dip type, dip pattern, and color scheme) represent the most common fluvial lithofacies and are identified through comparison of paired, calibrated BHIs and core. Cross-bed-set thickness values from BHIs are used to calculate dune height as a proxy for flow energy. The lower and middle Williams Fork Formation represent low-energy meandering and higher energy braided systems, respectively, as evident by changes in channel sinuosity and architectural-element type. The upper Williams Fork Formation is divided into two intervals based on lithofacies, architectural elements, channel sinuosity, and net-to-gross ratio. The subdivision for the upper Williams Fork Formation represents a change from a lower energy, meandering fluvial system to a higher energy, lower sinuosity braided system as related to changes in accommodation through time.

Description: Petroleum (oil and gas) forms from the bacterial or thermal breakdown of kerogen during progressive burial in sedimentary basins. During times of petroleum generation, kerogens in organic-rich source rocks expel petroleum to form a fluid phase in the pore system, capable of migrating under hydrodynamic and buoyancy forces to ultimately escape to the surface or accumulate within petroleum traps in the subsurface. The relative timing of petroleum charge and trap formation is a vital component in the accumulation of petroleum deposits. Exhumed basins have been historically viewed as higher-risk targets for conventional petroleum exploration because of, inter alia, the switch-off of petroleum generation in the source rock at the commencement of cooling during exhumation. However, even at the switch-off point, the source rock may retain a significant volume of petroleum sorbed in kerogen and within its pore system. Herein we demonstrate that if the source rock is exhumed to shallower depths after peak burial, pore pressure reduction and the associated volumetric expansion of the petroleum—particularly of the gaseous—phase in the pore system will result in the discharge of additional petroleum into the adjacent carrier bed or reservoir formations. Because most onshore sedimentary basins are characterized by major exhumation events at some point in their history, this represents an additional and underappreciated mechanism for a late-stage petroleum charge in exhumed sedimentary basins. The modeling also indicates that both the initial, pre-exhumation, total gas storage capacity and the exhumation gas charge are likely to be volumetrically more significant for gas-bearing source rocks that have been exposed to higher initial pressures and lower thermal gradients. The concepts presented here also have implications for petroleum resources retained within unconventional shale reservoirs because high-graded shale plays may be associated with systems where the magnitude or rate of relative overpressure dissipation has limited exhumation charge from the unconventional to conventional reservoirs within the basin.

Description: An estimate or measurement of organic matter density is required for converting between the weight percent of total organic carbon (TOC) and the volume percent of organic matter for wireline log calibration; it is therefore important to recognize when significant changes in organic matter density occur. A method is presented for calculating organic matter density from measurements of crushed-rock dry grain density and Soxhlet-extracted TOC. I have investigated the thermal evolution of organic matter by tracking changes in the intrinsic density of organic matter as a function of thermal maturity. Organic matter density shows two step increases that correspond to the generation of liquid hydrocarbons in the oil window (up to ~1.2% vitrinite reflectance [ R o ]) and the conversion of organic matter to graphitelike carbon (more correctly, "turbostratic carbon") at high thermal maturity (〉4% R o ). Profound structural changes of organic matter may, in part, determine the maturity limits of source-rock tight liquids and shale-gas plays, particularly at high thermal maturity, where gas is hosted within the organic matter–hosted pore system.

Description: Apatite fission track (AFT) and vitrinite reflectance data from five exploration wells and three seafloor cores illuminate the thermal history of the underexplored United States Chukchi shelf. On the northeastern shelf, Triassic strata in the Chevron 1 Diamond well record apatite annealing followed by cooling, possibly during the Triassic to Middle Jurassic, which is a thermal history likely related to Canada Basin rifting. Jurassic strata exhumed in the hanging wall of the frontal Herald Arch thrust fault record a history of probable Late Jurassic to Early Cretaceous structural burial in the Chukotka fold and thrust belt, followed by rapid exhumation to near-surface temperatures at 104 ± 30 Ma. This history of contractional tectonism is in good agreement with inherited fission track ages in low-thermal-maturity, Cretaceous–Cenozoic strata in the Chukchi foreland, providing complementary evidence for the timing of exhumation and suggesting a source-to-sink relationship. In the central Chukchi foreland, inverse modeling of reset AFT samples from the Shell 1 Klondike and Shell 1 Crackerjack wells reveals several tens of degrees of cooling from maximum paleo-temperatures, with maximum heating permissible at any time from about 100 to 50 Ma, and cooling persisting to as recent as 30 Ma. Similar histories are compatible with partially reset AFT samples from other Chukchi wells (Shell 1 Popcorn, Shell 1 Burger, and Chevron 1 Diamond) and are probable in light of regional geologic evidence. Given geologic context provided by regional seismic reflection data, we interpret these inverse models to reveal a Late Cretaceous episode of cyclical burial and erosion across the central Chukchi shelf, possibly partially overprinted by Cenozoic cooling related to decreasing surface temperatures. Regionally, we interpret this kinematic history to be reflective of moderate, transpressional deformation of the Chukchi shelf during the final phases of contractional tectonism in the Chukotkan orogen (lasting until ~70 Ma), followed by renewed subsidence of the Chukchi shelf in the latest Cretaceous and Cenozoic. This history maintained modest thermal maturities at the base of the Brookian sequence across the Chukchi shelf, because large sediment volumes bypassed to adjacent depocenters. Therefore, the Chukchi shelf appears to be an area with the potential for widespread preservation of petroleum systems in the oil window.

Description: Advances in virtual outcrop technologies and their introduction to fracture characterization allow extraction of fracture data from very large and inaccessible areas. The recent development of automated or semiautomated methods for fracture extraction aims to reduce or avoid tedious, time-consuming, and biased manual interpretation of fractures from virtual outcrops. We present a benchmarking exercise between a previously proposed automated fracture picking method, manual picking, and fieldwork methods. Comparison between the three methods highlighted their relative advantages and limitations. The automated fracture picking method provided excellent results in terms of fracture orientation, size, spatial distribution, and density. Fieldwork is complementary to fracture extraction from virtual outcrops, and it should focus on quality control of remote sensing data, poorly exposed areas, small-scale observations, diagenesis, timing of fracture development, building conceptual models, and linking fracture stratigraphy to rock properties. We propose a best practice for the use and integration of manual and/or automated fracture extraction from virtual outcrop and fieldwork data for fracture characterization and modeling from outcrop analogs. We consider integration of different methods as the best way to improve the modeling exercise while reducing operational costs and risks.

Description: Because of its significant impact on relative permeability, capillary pressure, stimulation methods, and ultimate recovery, the wettability of reservoir rocks is a critical factor of the petroleum recovery process. However, characterizing the wettability of shale with extremely low matrix permeabilities is a challenging task because of the dominant presence of nanopores in shale and high heterogeneity of shale compositions at multiple scales. From spontaneous imbibition behavior that uses two types of imbibing fluid (water and n-decane), the present study examines the wettability characteristics of gas-window Barnett Shale samples taken from four different depths of Texas United 1 Blakely core in Wise County in Texas. Imbibition experiments were conducted in two directions: parallel and transverse to the lamination of the samples. A scaling method was used to analyze imbibition data, and observed imbibition behaviors were interpreted to infer the different wettability conditions of four samples with different mineralogy, total organic carbon content, and pore-throat size distribution. Our results show that wettability significantly affects fluid imbibition behavior and that four tested samples can be divided into three wettability categories: more water wet, mixed wet, and more oil wet. Overall, the variable wettability of Barnett samples will affect hydrocarbon storage, distribution, and production.

Description: The prolific Los Angeles basin in California may be the most petroliferous province on Earth per volume of sedimentary fill. However, because most exploration in the basin occurred prior to the advent of modern geochemical methods, genetic relationships among the various petroleum accumulations and their source rocks have remained speculative. A training set of 24 source-related biomarker and stable carbon isotope ratios for 111 non- or mildly biodegraded oil samples from the basin was used to construct a chemometric (multivariate statistics) decision tree. The decision tree allows genetic classification of additional oil or source-rock extract samples that might be collected. The decision tree identifies 6 tribes and a total of 12 genetically distinct oil families. The families have different bulk properties, such as API gravity and sulfur content, which were previously explained as resulting from secondary processes, including thermal maturity or biodegradation. However, the chemometric assignments are based on genetic properties that reflect distinct organofacies. The oil families occur in different locations and reservoir intervals in the basin, consistent with their origins from different organofacies of active source rock. The source-rock depositional environment for each oil family can be inferred using biomarker and isotope ratios. The samples show stable carbon isotope ratios for saturate and aromatic hydrocarbons that indicate different organofacies of Miocene marine source rocks. Tribes 1 and 2 straddle the central trough, mainly occur east of the Newport-Inglewood fault zone (NIFZ), and show evidence of proximal, clay-rich source rock deposited under suboxic conditions with elevated angiosperm input. Tribes 3–6 occur west of the NIFZ and show evidence of more distal, clay-poor source rock deposited under anoxic conditions. Geochemistry and stratigraphy of the oil tribes (1–6 below) suggest the following source-rock organofacies:

Description: The origin of the overpressure in the northern Qaidam Basin has not been clearly understood, which has caused some difficulties in hydrocarbon exploration. Using a compaction study, we applied a modified acoustic-velocity and effective-stress diagram to identify the overpressure transfer in the study area. This phenomenon has not been discussed in previous studies. For the present study, we approximately calculated the magnitude of the transfer overpressure and analyzed the cause of the overpressured aquifer at the crest of the anticline in the study area. Our study indicates that the effect of overpressure transfer is very distinct, and the largest contribution to the total overpressure is 57%. The main media of overpressure transfer include vertical faults and lateral conducting layers. The vertical faults can connect deep overpressured strata, and the lateral conducting layers can connect overpressured strata at the top and wing of the anticline. During anticline formation, the crest fractures, and then the overpressured water in the anticline wing flows into the fractured crest and forms the overpressure compartment that prevents the charging of deeper natural gas.

Description: There is a common belief that we can expect to add value to a prospect or prospect portfolio by improving the prospect chance of success (Pg) as a consequence of acquiring information and doing work. Established laws of probability dictate that this is incorrect. We do expect new information to add value to the exploration cycle, but not by an expectation of improving the prospect risk. New information may result in an increase or a decrease of Pg, but the expected result (the average of all possible outcomes) is zero change. Moreover, for a typical exploration prospect (Pg 〈 0.5), we expect that new information will downgrade more prospects Pg than are upgraded. Real-world prospect data are neither suitable nor publically available to study this. Instead, the concept is explored using an analogous process (prenatal prediction of fetus gender) for which good statistics exist, and by creating a synthetic prospect that can be analyzed in a repeatable way. The results support the predictions made above.

Description: The Marathon 1 Mesquite well was drilled in Hamilton County, Texas, targeting the Barnett Shale with late oil window maturity. Combining a large suite of petrologic and high-resolution organic geochemical analyses on 120 core samples, we have been able to document qualitatively and quantitatively the effects of petroleum retention within and expulsion from five intervals within the Barnett Shale. Lithological heterogeneities control the composition and amount of retained fluids; the sorption of oil by solid organic matter is important in all intervals. Applying empirical formulas, we have been able to demonstrate not only that retention is primarily controlled by total organic carbon (TOC), but also that the "live" or "labile" component, rather than "dead" or "inert" carbon, constitutes the most active sorptive sites. Additional retention in the micropores provided by biogenic microcrystalline quartz (sponge spicules) accounts for the sweet spot defined by an "oil crossover" in the 9.14-m (30-ft) thick second interval. The fluorescing oil occurring in the axial chamber of the sponge spicules and that sorbed on organic particles are together enriched in saturated hydrocarbons, whereas the dispersed oil from the adjacent interval 3 is depleted in this compound class. Mass-balance calculations reveal that short-distance migration of petroleum into this "reservoir" interval (second) fractionates the generated oil into a higher quality oil by preferential retention in the order polar compounds 〉 aromatic hydrocarbons 〉 saturated hydrocarbons within the underlying organic matter and clay-rich third interval (source unit). Furthermore, molecular fractionation, i.e., a preferential expulsion of lower molecular weight hydrocarbons (n-alkanes) could be calculated. An additional practical result for source rock assessment is that corrected S2 (petroleum generated by pyrolysis) and TOC values should be calculated by combining Rock-Eval pyrolysis data on whole rocks and rocks following Soxhlet extraction. Using parameters based on unextracted rock only, the expulsion of petroleum is systematically overestimated and the degree of kerogen conversion is, therefore, concomitantly underestimated.

Description: The exploitation of hydrocarbon reserves in naturally fractured reservoirs composed of different types of rocks has drawn considerable attention from the fracture characterization research community because of the importance of fractures to the prediction of fluid flow. One of the most common methods for rapidly analyzing fracture features is the scanline technique, which provides an estimate of fracture density and frequency. Despite the confidence provided by the systematic use of this method, errors and uncertainties caused by sampling biases exist. The problems caused by these uncertainties can detrimentally affect the construction of a computational model due to misleading trends. This study evaluated the uncertainty caused by sampling biases in the scanline data of opening-mode fractures in outcrops of naturally fractured Aptian laminated limestone from the Crato Formation, Araripe Basin, northeastern Brazil. The Monte Carlo method was chosen to introduce random values into the sampled values, which enabled us to verify the importance of errors in the accuracy of the method of representing the fracture network. In this study, errors and uncertainties were grouped into one parameter, termed the coefficient of uncertainty, which was defined as the ratio between the uncertainties, created by the errors and artifacts introduced artificially, and the original scanline data. The propagation of errors and uncertainties in the scanline data to the coefficients of the corresponding power law were determined. This evaluation can be applied in the construction of more reliable geomechanical models using analog geological models for naturally fractured reservoirs.

Description: Characterizing natural fracture systems involves understanding fracture types (faults, joints, and veins), patterns (orientations, sets, and spacing within sets), size distributions (penetration across layering, aperture, and trace length), and timing relationships. Traditionally, observation-based relationships to lithology, mechanical stratigraphy, bed thickness, structural position, failure mode, and stress history have been proposed for predicting fracture spacing along with the relative abundance of opening-mode fracture versus faults in fractured rocks. Developing a conceptual fracture model from these relationships can be a useful process to help predict deformation in a fractured reservoir or other fractured rock systems. A major pitfall when developing these models is using assumptions based on general relationships that are often site specific rather than universal. In this paper, we examine a mixed carbonate-shale sequence that is cut by a seismic-scale normal fault where fracture attributes do not follow commonly reported fracture relationships. Specifically, we find (1) no clear relationship between frequency (or spacing) of opening-mode fractures (joints and veins) and proximity to the main fault trace and (2) no detectable relationship between fracture spacing and bed thickness. However, we did find that (1) the frequency of small-displacement faults is strongly and positively correlated with proximity to the main fault trace, (2) fracture networks change pattern and failure mode (extension versus shear fracture) from pavement to pavement through the mechanically layered stratigraphic section, and (3) faults are more abundant than opening-mode fractures in many areas within the fracture network. We interpret that the major fracturing initiated near maximum burial under relatively high-differential stress conditions where shear failure dominated and that mode-1 extension fracturing occurred later under lower differential stress conditions, filling in between earlier formed shear fractures. We conclude that whenever possible, site-specific observations need to be carefully analyzed prior to developing fracture models and perhaps a different set of fracture network rules apply in rocks where shear failure dominates and mechanical stratigraphy influences deformation.

Description: Thousands of shale gas wells have been drilled and hydraulically fractured across the state of Pennsylvania over the past decade, and more wells are being drilled each year. The drilled lengths of these wells and the amount of water being used to hydraulically fracture (frac) them continue to increase. These increases have led to an increase in the volume of wastewater being produced each year. However, the ratio of energy produced per barrel of wastewater has increased significantly over the past six years. Recent data show the volume of wastewater produced in one year is approximately 20% of the volume of frac water used in that same year. With changes in state policies, drilling companies in Pennsylvania have been recycling most of their wastewaters over the past few years. The development of various treatment technologies and brine-resistant frac mixtures has allowed companies to recycle this wastewater for use in future frac jobs. Use of this recycled water does not appear to be having a significant effect on production of oil or gas from wells. Recycling wastewater can be very cost-competitive when compared to options such as disposal via waste-treatment plants or injection wells.

Description: Shale gas development in the United States has revolutionized energy production and supply, making the nation energy independent for the first time in decades. However, many people remain concerned that the large-scale hydraulic fracturing necessary to recover hydrocarbons from shale may degrade the environment, including groundwater. Improving the understanding of how groundwater may be impacted by shale gas development requires field monitoring at multiple sites on different shale plays under a variety of climates and hydrologic conditions. Such monitoring has been difficult to achieve because of a lack of access to commercial sites and an absence of funding to drill dedicated research wells.

Description: Many different rock intervals are used for brine disposal injection in the Appalachian Basin. The study area was defined as eastern Kentucky, Ohio, Pennsylvania, and West Virginia. Brine injection in the study area has increased from approximately 6–7 million barrels (bbl) per year in the early 2000s to 17.6 million bbl in 2012, mostly due to shale gas activity. A review of geologic properties and subsurface distribution of rock formations used for injection is useful to understand brine disposal operations in the region. Operational data on injection rates and pressures were compiled for 2008–2012 for more than 300 class II brine disposal wells. Several class II brine disposal wells were monitored with continuous wellhead pressure loggers to estimate reservoir properties and understand injection operations. Project results provide a catalog of injection rates for the various formations, which range from hundreds to more than 100,000 bbl per month per well. Hydrologic analysis of depleted hydrocarbon reservoirs and deep saline formations in the study area indicates that there is a large capacity for brine disposal, but the characteristics of the rock formations may limit injection rates. Based on hydrocarbon production and brine injection volumes from 2008 to 2012, approximately 9984 bbl of brine were routed to class II brine disposal wells per billion cubic feet gas production, which suggests ultimate demand of up to 706–2290 million bbl brine disposal related to unconventional Marcellus and Utica plays. Understanding the geology and operational history of the injection zones is critical to support safe, reliable, and environmentally responsible brine disposal in the region.

Description: Disposal of the liquid wastes generated during extraction of unconventional oil and gas resources in North America is increasingly becoming a constraint to development. Currently, the bulk of these wastes is disposed of by injection into deep bedrock formations. In certain development areas, the presence of suitable disposal formations is scarce, or disposal operations are difficult to site given area constraints. To address this challenge, a process of identifying high-value disposal targets (i.e., formations and locations) was developed using a combination of hydrogeological principles, multicriteria analysis, and geospatial mapping. This paper outlines the process developed to identify potential disposal targets to support oil sand development in Alberta and the results obtained.

Description: Regional fracture systems are characterized by subparallel opening-mode fractures formed as a result of brittle deformation in the Earth's crust. Understanding the origin and distribution of these fracture systems is of great practical importance because they can control the flow of underground fluids, such as water, oil and gas, ore-forming fluids, and geothermal fluids. As the world's remaining hydrocarbon reserves continue to be depleted, the rapidly increasing importance of unconventional fractured reservoirs for oil and gas is widely recognized. Here, it is demonstrated that thermal contraction caused by cooling may be an important mechanism for creating tensile fractures in rock during major exhumation events. The extent of this phenomenon is particularly dependent on the magnitude of cooling and on the mechanical properties of the rock. Thermally induced fracture systems are more likely to develop in stiffer rocks, such as well-cemented sandstones and carbonates. The process described herein can be modeled and tested with field data and provides another mechanism to account for and to predict the presence of permeable tensile fractures in the subsurface.

Description: Our hydrogeologic model tests the effectiveness of brine reflux as the mechanism for early dolomitization of the Permian San Andres Formation. Brine circulation is constrained by sequence-stratigraphic parameters and a heterogeneous distribution of petrophysical properties based on outcrop data. The model simulates accumulation of the San Andres platform and calculates fluid flow and solute transport in response to relative sea level fluctuations. It tracks porosity loss caused by compaction and the concomitant permeability feedback. The amount of dolomite potentially formed is calculated by means of a magnesium mass balance between brine and rock. Results show that (1) brine reflux is an effective mechanism to deliver magnesium to dolomitize large carbonate successions; (2) relative sea level–controlled transient boundary conditions result in intricate flow and salinity patterns that can generate irregular dolomite bodies with complex spatial distributions; (3) pervasive dolomitization can result from several short-lived reflux events by the amalgamation of brine plumes sourced in different locations and times; and (4) the model successfully recreates the dolostone and limestone patterns observed in San Andres outcrops.

Description: The function of normal faults in upsequence flow of gas has been examined using two-dimensional and three-dimensional seismic-reflection data from the southern Taranaki Basin, New Zealand. The spatial distributions of late-stage normal faults, gas chimneys, thickness of the Oligocene mudstone-rich seal (Otaraoa Formation), and modeled hydrocarbon expulsion volumes are compared. Gas chimneys are most common above Cretaceous source rocks modeled to have expelled hydrocarbons. Most (~70%) of the observed gas chimneys follow, and/or are rooted in, late-stage normal faults. These faults are the primary seal bypass mechanism for hydrocarbons, where they displace the seal (or intersect faults that displace the seal) and the seal is thick (e.g., more than ~340 m [~1115 ft]). Active vertical gas flow through the seal commenced after the onset of faulting (~3.6 Ma), whereas subseal lateral flow started significantly earlier at approximately 15 Ma and resulted in an early charge of structural highs. Gas flow up along faults in low-permeability mudstones (〈1 md) is channelized with steep chimneys commonly occurring close to fault tips and relay ramps. In these cases, gas flow may be focused by the presence of high densities of open fractures locally elevating upsequence bulk permeabilities to approximately 1 to 400 md.

Description: The aim of part 2 is to understand the development of complex hydraulic fractures (HFs) that are commonly observed in the field and in experiments but are not explained by most models. Our approach uses finite element simulations and a numerical rheology developed in part 1 to model damage fracturing, the fracturing process by damage propagation in a rock with elastic–plastic damage rheology. Using this rheology and a dynamic solution technique, we investigate the effect of far-field stresses and pressure distribution in the fracture on the geometric complexity of the fractures. The model is for the vertical propagation of an HF segment into an overlying bed located far from borehole effects. The layer is 2.3 m (7.5 ft) tall, has elastic–plastic damage rheology, and contains a 0.3-m (1-ft)–tall initial vertical fracture. Vertical and horizontal tectonic loads of 50 MPa (7252 psi) and 10 to 45 MPa (1450–6527 psi) are established, and then an internal fracture pressure of 10 MPa/s (1450 psi/s) is applied until the layer fails. The simulated fracturing is sensitive to the stress state and generated patterns range from single straight fractures to treelike networks. Reducing differential stress increases the injection pressure required to fracture and promotes off-plane damage, which increases fracture complexity. Consecutive periods of nonuniform weakening followed by unstable rupture generate multiple branches and segments. We find that the processes that form HF complexity occur under a range of in-situ reservoir conditions and are likely to contribute to complex far-field fracture geometry and enhanced network connectivity.

Description: Statistical stationarity is a key assumption for the many modeling techniques based on variograms and transiograms used for geostatistical reconstruction of the subsurface. Stationarity expresses the property that the rules of geometry and neighborhood in the model are translation invariant, that is, no directional change in either mean or variance is observed. These criteria are met when the lateral arrangement of lithologic elements into a facies mosaic is isotropic. The balance between isotropy and anisotropy is a defining statistic in the configuration of both real and modeled carbonate landscapes. Even a cursory look at a satellite image of a modern carbonate platform shows that gradients in environment and hydrodynamics cause radical departures from isotropy. Although reef-forming organisms have changed through time, we do not expect that ancient reef systems behaved any differently than today. Hence, significant anisotropy should also be anticipated in the vertical and lateral arrangements of lithologies in the subsurface. To maintain sufficient geologic realism, it is paramount that process-imitating and pattern-replicating models alike be capable of honoring an expected degree of nonstationarity. Despite this need, few studies exist that provide quantitative information to the reach and location of zones of geometric isotropy and anisotropy in carbonate systems, let alone methods with which this property can be assessed. In an effort to close this disjoint, we develop a method for evaluating a modern Pacific depositional system, the Saipan Lagoon, for which we have created a geographic information system stack consisting of mapped facies distributions and a seabed topographic model, both at meter-scale resolution. By developing a lagged spatial metric based on the Markov property of facies transitions, we demonstrate that the degree of anisotropy is influenced by water depth; the shallowest areas (〈5 m [〈16 ft]) of the platform interior tend to be anisotropic whereas areas at greater depth are isotropic. This behavior suggests a possible extension to a genetic rule set that could be imparted to subsurface models based on the environment of deposition. This marks an advance in the understanding and, ultimately, handling of geometric nonstationarity in models of carbonate depositional systems.

Description: In this series of studies, we develop a numerical tool for modeling finite deformation of reservoir rocks. We present an attempt to eliminate the main limitations of idealized methods, for example, elastic or kinematic, that cannot account for the complexity of rock deformation. Our approach is to use rock mechanics experimental data and finite element models (Abaqus). To generate realistic simulations, the present numerical rheology incorporates the dominant documented deformation modes of rocks: (1) rock mechanics experimental observations, including finite strength, inelastic strain hardening, strength dependence on confining pressure, strain-induced dilation, pervasive and localized damage, and local tensile or shear failure without macroscopic disintegration; and (2) field observations, including large deformation, distributed damage, complex fracture networks, and multiple zones of failure. Our analysis starts with an elastic–plastic damage rheology that includes pressure-dependent yield criteria, stiffness degradation, and fracturing via a continuum damage approach, using the Abaqus materials library. We then use experimental results for Berea Sandstone in two configurations, four-point beam and dog-bone triaxial, to refine and calibrate the rheology. We find that damage and fracturing patterns generated in the numerical models match the experimental features well, and based on these observations, we define damage fracturing, the fracturing process by damage propagation in a rock with elastic–plastic damage rheology. In part 2, we apply this rheology to investigate fracture propagation at the tip of a hydrofracture.

Description: Geologic sequestration of anthropogenic carbon dioxide (CO 2 ) is one of the most promising approaches to safely and effectively reduce emissions of CO 2 created through the oxidation of fossil fuels. Methods used by the petroleum industry in the characterization of hydrocarbon accumulations can be used to assess potential subsurface traps for sequestration purposes. In this article, we use these approaches to evaluate the characteristics of a naturally occurring accumulation of CO 2 in western Wyoming. The Moxa arch is a 200-km (124-mi)-long basement-involved anticline. The Mississippian Madison Formation and the Ordovician Bighorn Dolomite contain the most CO 2 within the structure. Relict anhydrite in these and other Paleozoic units was an important factor in evolving hydrocarbons into CO 2 through inorganic thermal sulfate reduction and, more importantly, in creating a seal to hold large columns of buoyant gas. Fluid-inclusion data sets have been particularly useful in understanding the sealing characteristics of the units within the Moxa arch and affirming that the Devonian Jefferson, Mississippian Amsden, and Triassic Dinwoody and Woodside formations have been very effective seals. Existing pressure data reveal that the two gas columns in the Madison and Bighorn formations lie on a similar gradient and share a common gas-water contact, yet are likely not in hydraulic communication. Currently, all available data suggest that both reservoirs share a fault-dependent spill point. By reconciling the spill points of the gas in the Madison and Bighorn reservoirs, their compositions, their initial and current pressures, their seal, and the uncertainties associated with injection of CO 2 can be identified and potentially derisked with additional information. If the Madison and Bighorn are filled to their fault-dependent spill point, it implies that additional storage capacity in the reservoir can only be obtained by production of the original gas column. This uncertainty may be abated if data from future drilling demonstrates that neither the Madison Formation nor the Bighorn Dolomite have a fault-dependent spill point, suggesting that these structures are underfilled with respect to their closure and possess additional storage capacity.