ALBERT

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thick marine shales occur in the Wufeng Formation and Longmaxi Formation of Sanquan Town of the Nanchuan District, Chongqing Municipality, which is located on the southeast margin of the Sichuan Basin. However, few details of the characteristics of the Wufeng–Longmaxi shales in this area have been reported. In this study, a well approximately 100 m (∼328 ft) deep was drilled. A high-quality shale (total organic carbon [TOC] 〉2.0 wt. %, clay 〈40%) interval that was approximately 24 m (∼79 ft) thick with an average TOC value of 3.0 wt. % mainly occurs in the Ordovician Wufeng Formation (Katian and Hirnantian) and base of the Silurian Longmaxi Formation (Rhuddanian). Shales with higher TOC values commonly have a higher porosity and specific surface area. Tectonic movements may also have been very important factors that influenced the petrophysical properties of the shales. For example, a detachment layer that resulted from complex tectonic movements is extensive in the Wufeng Formation. The cracks and microcracks in the detachment layer can result in good pore connectivity. Consequently, the detachment layer can be an effective migration pathway. The Longmaxi–Wufeng shales of Sanquan Town are also compared with those of the famous Jiaoye 1 well in the Jiaoshiba shale gas field in the eastern Sichuan Basin. Although the shales in Sanquan Town have considerable shale gas generation potential, the shale gas resource potential in Sanquan Town is probably poor because the escape of shale gas may be accelerated by the detachment layer in destroyed anticlines and synclines.〈/span〉

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

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

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

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

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

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

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

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

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

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

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

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

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

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