ALBERT

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: 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.

Description: Carbonate rocks are known for their heterogeneity and petrophysical complexity. This commonly leads to large uncertainties in reservoir models that are intended to predict fluid storage and fluid flow. In this article, focus is given to the characterization of pore systems at core-plug scale to provide improved models for permeability and saturation prediction. These methods fall under a wider rock-typing workflow. We examine the use of mercury-air capillary pressure data for rock-type definition and for predicting saturation and permeability. We present new methods for modeling saturation in rocks with multimodal pore-throat size distributions. The methods bear similarity to those previously published but with some key differences, mainly by relating the capillary pressure data to the pore systems representative for a rock type. We also present a new method for relating permeability to pore-throat sizes that is more versatile, in that it can be employed for all types of pore-throat size distributions—unimodal or multimodal. We demonstrate that a normalized pore-throat radius parameter forms a straight line relationship with permeability over six orders of magnitude. It appears to be a fundamental property for all pore systems so far examined. The wider implication of the workflows presented is that they offer better integration between the methods used for saturation prediction and the methods used for permeability prediction, something that is desirable for all subsurface studies.

Description: Today, an increased emphasis on the distribution, potential volume, and cost to develop CO 2 geologic sequestration resources exists. In the presence of climate change, the need to make accurate and clearly understandable assessments of carbon sequestration potential, which can be used by the government and industry to plan for technology deployment, has never been greater. We compare three CO 2 storage assessment methodologies: the approach applied by the U.S. Department of Energy in its Carbon Atlas III, the modified U.S. Geological Survey methodology, and the CO 2 Geological Storage Solutions methodology. All three methodologies address storage resources in porous geologic media in sedimentary basins, namely oil and gas reservoirs and saline formations. Based on our analyses, these methodologies are similar in terms of computational formulation. We find that each of the proposed methodologies is science and engineering based. As such, they are important in identifying the geographical distribution of CO 2 storage resource and regional carbon sequestration potential at the national and basin-scale levels for use in energy-related government policy and business decisions. Policy makers need these high-level estimates to evaluate the prospective function that carbon capture and sequestration technologies can play in reducing CO 2 emissions over the long term. The value of these high-level assessments of CO 2 storage resource is to help inform decision makers in governments and industry as to whether carbon capture and sequestration is a climate mitigation option worth pursuing in particular regions.

Description: Concerns about potential climate change related to greenhouse gas emissions have spurred researchers across the world to assess the viability of geologic storage of CO 2 . In the Illinois Basin in the United States, the Cambrian Mount Simon Sandstone has been targeted as a reservoir for carbon capture and storage (CCS). In this CCS system, the Eau Claire Formation is expected to serve as the primary seal to prevent upward migration of the CO 2 plume; however, little work has been done to specifically determine how well it will function as a seal. Although the lateral extent and thickness of the Eau Claire Formation, along with its generally low permeability, certainly make it a prime candidate to serve in this capacity, the primary depositional fabric and mineralogy, which are the fundamental controls on the petrophysical charter of this unit, remain poorly constrained. Therefore, the purpose of this study is to investigate the lithologic, mineralogical, and petrophysical properties of the Eau Claire Formation in an effort to characterize its potential as a functional seal in a CCS system. Sixty-six core-derived Eau Claire Formation samples from seven wells within the Illinois Basin are described using a combination of petrography, reflectance spectroscopy, x-ray diffraction, geochemical, and petrophysical analyses. These analyses show that the Eau Claire Formation contains five different lithofacies (sandstone, clean siltstone, muddy siltstone, silty mudstone, and shale) with fine-scale heterogeneities in fabric and mineralogy that greatly influence the petrophysical properties. Porosity, permeability, and entry-pressure data suggest that some, but not all, lithofacies within the Eau Claire Formation have the capability to serve as a suitable CCS seal. Abundant authigenic minerals and dissolution textures indicate that multiple generations of past fluid-rock interactions have occurred within the Eau Claire Formation, demonstrating that much of the formation has behaved as a fluid conduit instead of as a seal. Minerals that would be potentially reactive in a CCS system (including carbonate, glauconite, and chlorite) are common in the Eau Claire Formation. Dissolution of these and other phases in the presence of carbonic acid could potentially jeopardize the sealing integrity of the unit. Although complexities in the sealing properties exist, the dynamics of the CCS system and the potential for precipitation of new minerals should allow the Eau Claire Formation to serve as an adequate seal.

Description: The main objective of this article is to obtain reservoir properties, such as porosity, both at the well locations and in the interwell regions from seismic data and well logs. The seismic and well-log data sets are from an oil field in eastern Saudi Arabia, and the main target is a Jurassic carbonate reservoir. The geology of carbonate reservoirs in Saudi Arabia is well understood. Reservoir porosity estimation is essential and needs to be determined for flow simulation and reservoir management.A major component of this study is establishing the relation between the P-impedance and porosity using well-log data. An amplitude-versus-angle seismic inversion algorithm was used to invert the three-dimensional impedance volumes (i.e., P-impedance and S-impedance) given partial angle stacks of seismic traces representing reflection amplitude variations with angle of incidence. These impedance volumes were used to estimate porosity between the well locations. The seismic and log data provided a-priori information (i.e., the initial starting model and source wavelet estimate) necessary for obtaining geologically consistent results.

Description: The megacrack pattern of the ephemeral north Panamint dry lake, California, United States, is characterized by variably sized polygons with diameters ranging from hundreds of meters to meters. The evolution and subsurface extent of this polygonal pattern and a probable tectonic link are examined by ground resistivity measurements and surface mapping. Crack development is initiated by the shrinking of clays caused by changes in water content near the surface. For crack evolution, the following processes are proposed: Cavities develop at approximately 1-m (∼3-ft) depth during a subsurface phase, followed by the collapse of the overburden into the existing cavities to form the surface cracks. Cracks are filled by wind-blown sand and dried-out lake sediments from collapsing crack walls. Following burial, differences in competence between crack-fill and surrounding playa-lake sediments provide zones of structural weakness that might channelize stress release and faulting. Ground resistivity measurements confirmed the extent of the cracks to a depth of more than 3 m (〉9 ft). The megacrack pattern is compared to a Rotliegende (Upper Permian) tight gas field, located in the southern Permian Basin of northwestern Germany, situated in a comparable geologic setting. There, a multidirectional polygonal pattern is recorded on horizon slices of three-dimensional seismic data and compares well to our observations from the Panamint Valley. The Rotliegende pattern is associated with low-offset faults, which are proposed to be responsible for subtle reservoir compartmentalization.

Description: Geochemical analysis and field relations of linear dolomite bodies occurring in outcrop in the Mohawk Valley of New York suggest that the area has undergone a significant fault-related hydrothermal alteration. The dolomite occurs in the Lower Ordovician Tribes Hill Formation, which is regionally a Lower Ordovician shaley limestone with patchy dolomitization. The outcrop has an en echelon fault, fracture, and fold pattern. A three-dimensional (3-D) ground-penetrating radar (GPR) survey of the quarry floor has helped to map out faults, fractures, anticlines, synclines, and the extent of dolomitization. Most of the dolomitization occurs in fault-bounded synclines or sags flanked by anticlines. The dolomite structures are highly localized, occurring around faults, and are absent away from the faults and fractures. Trenches cut across the outcrop help relate offset along faults to the overall geometry of the dolomitized bodies. Geochemical analysis, although helpful in characterizing the conditions of dolomitization, does not define its origin absolutely. This study uses fluid inclusions, stable isotopes, 3-D GPR, core analysis, and surficial observations, which all show a link between faulting, dolomitization, and other hydrothermal alteration. Although the outcrop is much too small and shallow to act as a producing gas field, it serves as a scaled analog for the Trenton–Black River hydrothermal dolomite reservoirs of eastern United States. It may therefore be studied to help petroleum geologists characterize existing gas plays and prospect future areas of exploration.

Description: The geologic controls on reservoir properties and potential hydrocarbon (volatile, low-molecular-weight liquid and gas) resources of the Cretaceous Shaftesbury Formation in northeastern British Columbia have been investigated. Maturity varies from the oil to dry gas window (Tmax = 429–486°C), with increasing maturity and depth of burial toward the south. The Tmax, in degrees Celsius, is the oven temperature at the peak generation of S2 during pyrolysis. Total organic carbon (TOC) content ranges between 0.64 and 8.0 wt. %, with an average of 2.2 wt. %. The TOC content distribution mirrors the trends in maturity, with lower TOC content in areas of high maturity. Kerogen is characterized as either type II-III or type III. The quartz content ranges between 33 and 66%, with higher quartz content in areas with lower TOC content and greater maturities. Porosity ranges between 4.5 and 14.6%, with higher porosities observed within shallower wells, low quartz content, or maturities, or a combination of all three. The porosity is reduced in high-maturity samples by mechanical compaction and silica cementation. Total gas capacities range between 4.5 and 24.8 cm3/g, and gas-in-place (GIP) estimates are between 0.98 and 3.39 bcf/(section × meter). The calculated hydrocarbon generation is less than 3.6 bcf/(section × meter), with light liquid generation between 3.7 and 516.2 MMBO.Present-day depths and organic maturity have strong influences on the hydrocarbon capacity more so than TOC content. Deeper, higher maturity samples in the south have the largest total gas capacity and GIP estimates (0.98–3.39 bcf/[section × meter]). Maturity is within the dry gas window in the southern one-third of the study area. Highest volumes of light liquid hydrocarbons are found within the less mature northern part of the study area.

Description: The origin of the immense oil sand deposits in Lower Cretaceous reservoirs of the Western Canada sedimentary basin is still a matter of debate, specifically with respect to the original in-place volumes and contributing source rocks. In this study, the contributions from the main source rocks were addressed using a three-dimensional petroleum system model calibrated to well data. A sensitivity analysis of source rock definition was performed in the case of the two main contributors, which are the Lower Jurassic Gordondale Member of the Fernie Group and the Upper Devonian–Lower Mississippian Exshaw Formation. This sensitivity analysis included variations of assigned total organic carbon and hydrogen index for both source intervals, and in the case of the Exshaw Formation, variations of thickness in areas beneath the Rocky Mountains were also considered. All of the modeled source rocks reached the early or main oil generation stages by 60 Ma, before the onset of the Laramide orogeny. Reconstructed oil accumulations were initially modest because of limited trapping efficiency. This was improved by defining lateral stratigraphic seals within the carrier system. An additional sealing effect by biodegraded oil may have hindered the migration of petroleum in the northern areas, but not to the east of Athabasca. In the latter case, the main trapping controls are dominantly stratigraphic and structural. Our model, based on available data, identifies the Gordondale source rock as the contributor of more than 54% of the oil in the Athabasca and Peace River accumulations, followed by minor amounts from Exshaw (15%) and other Devonian to Lower Jurassic source rocks. The proposed strong contribution of petroleum from the Exshaw Formation source rock to the Athabasca oil sands is only reproduced by assuming 25 m (82 ft) of mature Exshaw in the kitchen areas, with original total organic carbon of 9% or more.

Description: Producers adjacent to a natural-gas storage field claimed that the natural gas they were producing was native gas from the area and not storage gas being pulled from the nearby gas storage field. The objective of this work is to apply a combination of area-specific and generic geochemical fingerprinting techniques to determine the source(s) of the natural gas being produced by third-party producers outside the gas storage field and to determine the extent of storage gas migration beyond geologic faults that lie between the production area and the gas storage field. An extensive set of natural-gas samples from the storage field, observation wells around the field, and third-party wells was analyzed for gas hydrocarbon and nonhydrocarbon compositions, as well as stable carbon isotopic compositions of methane and ethane. Gas chemical compositional data, including concentrations of the natural native gas tracer, helium, and ethane carbon isotope, were used to establish the unique fingerprints of native gas and storage gases (end-member sources) and to compare those end-member-source fingerprints to those of natural gas in the third-party wells. The analysis determined that gas in both the observation wells and third-party wells was, in fact, storage gas.

Description: This study has evaluated the hydrogeochemistry of some parts of the aquifer underlying and near Abakaliki City, Nigeria, to better understand the local groundwater quality conditions. Twelve representative groundwater samples from water boreholes (wells) in the study area were analyzed for their hydrogeochemical properties: pH, electrical conductivity (EC), turbidity, total dissolved solids (TDS), total hardness, chemical oxygen demand, Ca2+, Mg2+, Na+, K+, , , Cl−, , and . The aquifer is situated in the fractured shales of Abakaliki Formation. The dominant ions in most samples are Ca2+, Mg2+, , and Cl−. Furthermore, strong positive correlations exist between EC-TDS, Na+-TDS, , and . Piper trilinear diagrams were used to classify the hydrogeochemical facies, which included Ca-Mg-Cl and Ca-Mg-Na-Cl-SO4 water types. Ratios of Na-Cl ranged from 0.12 to 0.73, with a mean of 0.55, which is consistent with those of fresh water. The results of this study indicate that the groundwater local to the Abakaliki City poses no threat to human consumption, health, or the environment because the concentrations of physicochemical parameters that can be used to evaluate drinking water quality are within the World Health Organization standard specification.

Description: Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles.In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.

Description: Shengli oil field, the second largest oil and gas field in China, is located in the Tertiary Dongying graben system in the southern Bohai Basin. Three petroleum systems, one for each mapped source rock, and as many as seven reservoir rocks are documented in the Dongying graben system, representing a complex migration and accumulation pattern. In addition, both the source and the reservoir facies are distributed unevenly throughout the system, requiring a complex distribution of possible migration pathways. Stratigraphic conduits, that is, sandy and conglomeratic facies, are mostly present in the northern graben flank area, where coarse sediments provide possible migration pathways. Over most of the basin, however, faults—active at different times throughout basin evolution—add important additional conduits for petroleum migration, as well as acting locally as seals, depending on their surrounding lithology and their respective sealing or leaking properties through time. This article aims to show that the Shengli oil field provides an excellent example of how three-dimensional petroleum systems modeling allows the assessment of fault behavior and timing to predict the distribution of hydrocarbons in a system.

Description: Upper Jurassic–Lower Cretaceous sandstones of the Scotian Basin, offshore eastern Canada, are important gas reservoirs. Previous studies of fluid inclusions in Jurassic limestones and apatite thermochronology of Cretaceous sandstones have suggested a late Mesozoic thermal event. Fluid inclusions in different authigenic cements were analyzed to determine the temperature and composition of basinal fluid at the time of precipitation and the timing of hydrocarbon migration and entrapment. Fifty-one sandstone samples were analyzed for stable isotope composition (δ18O and δ13C) of carbonate cements.Trapping temperatures for primary aqueous inclusions hosted in quartz overgrowths (89–175°C) and in late carbonate cements (138–173°C) are higher than predicted by two-dimensional modeling from burial alone based on postrift geothermal gradients. These inclusions contain high-salinity fluids (mostly 19–22 wt. % NaCl equivalent). Second, predominantly aqueous inclusions have much lower salinities (5.2–6.7 wt. % NaCl equivalent), and some contain liquid hydrocarbons. Late Fe-calcite cement in Hauterivian sandstone shows negative values of δ13 CVPDB (−13.17 to −9.2‰), whereas cements in deeper and shallower sandstones have higher δ13C values.These data indicate that high-temperature, high-salinity fluids preceded hydrocarbon migration. The oldest and youngest rocks studied show less effect of high temperatures than do rocks that were buried to depths of at least 2 km (1.2 mi) after 135 Ma and before 100 Ma. Both fluid inclusions and δ13C of carbonate cement suggest that highest temperatures were achieved during burial at 115 to 105 Ma. This Early Cretaceous thermal event had a geothermal gradient of at least 55°C/km. It is earlier than the previously reported event based on apatite fission tracks but is consistent with the fission track data. The event is synchronous with regional evidence of volcanism, and its peak coincides with rapid salt-tectonic deformation in the deep basin. Hydrocarbon charge to the outer-shelf wells occurred after this thermal event and thus not before the Late Cretaceous.

Description: The Tarim Basin is one of the richest basins in oil and gas resources in China. The Cambrian and Middle–Upper Ordovician strata are the most important source rocks. Previous early Paleozoic thermal histories have led to varied hypotheses on the evolution of the lower Paleozoic source rocks, causing a significant impact on petroleum exploration in the basin. A new Paleozoic thermal history of the Tarim Basin was reconstructed in this article using the integrated thermal indicators of apatite and zircon (uranium-thorium)/helium ages, apatite fission tracks, and equivalent vitrinite reflectance data. The modeled results indicate that different parts of the basin experienced widely differing early Paleozoic thermal gradient evolution. The eastern and central regions of the basin experienced a decreasing thermal gradient evolution from 37 to 39°C/km during the Cambrian and Ordovician to 35 to 36°C/km in the Silurian, whereas the northwestern region of the basin had an increasing early Paleozoic thermal gradient evolution from 28 to 32°C/km in the Cambrian to 30 to 34°C/km in the Ordovician and Silurian. The Lower Cambrian thermal gradient resulted from the higher thermal conductivity of the 800- to 1000-m (2625- to 3280-ft) thickness of gypsum and salt in the Cambrian strata. The basin experienced an intracratonic phase during the late Paleozoic and a foreland basin phase during the Mesozoic and Cenozoic, with the thermal gradient decreasing to the present-day value of 20 to 25°C/km. The sensitivity of thermal modeling by the best-fit method is less than ±5% in our study, and the differences of the early Paleozoic thermal gradient evolution in different regions of the basin may result in differential maturation of lower Paleozoic source rocks. The maturity histories of the source rocks, modeled based on the new thermal histories, indicate that the lower Paleozoic source rocks in most areas of the basin matured rapidly and reached the late mature to dry-gas stage during the Paleozoic but experienced slower maturation during the Mesozoic and Cenozoic. These new data on the Paleozoic thermal history and lower Paleozoic source rock maturity histories of the Tarim Basin provide new insights to guide oil and gas exploration of the basin.

Description: A three-dimensional physical experiment was conducted to study secondary oil migration under an impermeable inclined cap. Light-colored oil was released continuously at a slow rate of about 0.1 mL/min from a point at the base of an initially water-saturated porous model. With buoyancy as a primary driving force, a vertical cylindrical shape of an oil migration pathway was observed first, and then a layer-shaped lateral migration pathway was observed beneath the top inclined sealing plate once the oil cluster had reached the top cap. Magnetic resonance imaging was used to observe the migration processes—for example, morphology of the migration pathway, intermittency of oil bubbles, and variation of oil saturation within the migration paths. Results show that the snap-off phenomenon (related to fast local imbibition processes) occurred more commonly during vertical migration than it did during lateral migration. The lateral migration pathway that parallels to the top inclined cap has a typical vertical thickness of 2 to 4 cm (0.8–1.6 in.) (i.e., roughly 40–80 pores). This thickness is consistent with the prediction derived from scaling laws related to pore size and Bond number. Along the lateral migration direction, the sectional area and the horizontal width of the migration pathway fluctuate significantly, although the average oil saturation along the pathway remains almost the same. After stopping the initial oil injection, the sectional area of the migration pathway shrinks significantly. Therefore, we believe that this significant shrinking of the migration pathway is the main reason why only a relatively small volume of oil and gas has been lost during secondary migration.

Description: We integrated well logs and three-dimensional seismic data to describe a wedge of deformed shallow Frio rocks lying above a major bed-parallel decollement within the upper Oligocene Frio Formation located between the Houston and Norias deltas on the south Texas Gulf Coast. Our analyses show that the identified deformed shallow Frio rocks can be divided into proximal clay-rich and low-permeability sandstones characterized by discontinuous, mounded, and chaotic seismic events; near-proximal, clay-poor, and high-permeability sandstones characterized by parallel to subparallel bedded seismic events; and distal sand-, silt-, and mudstones composed of a mix of proximal and near-proximal rocks. All of the deformed rocks are composed of acoustic-impedance materials that are lower than those of the undeformed shallow Frio and are underlain by low-velocity, overpressured, shale-rich rocks. The mechanism that triggered the collapse of the shallow Frio and subsequent development of mass-transport deposits is attributed to an uprising, overpressured, shale-rich high and the development of a shelf-edge listric fault. Proprietary biostratigraphic data show that the collapse of the shallow Frio in areas between the Houston and Norias deltas occurred between 27.5 and 25.3 Ma—approximately the same time as the Hackberry collapse in the Mississippi delta. In the proximal area, interpreted paleowater depths from biostratigraphic data based on benthic foraminifers range from 60 to 120 ft (20–40 m) in a shallow neritic environment. In contrast, the distal area lies in paleowater depths interpreted to be between 120 and 300 ft (40–90 m) in a middle neritic environment.

Description: Sedimentary basins can be classified according to their structural genesis and evolutionary history and comprise tectonic and sedimentary cycles and stages, to which common elements of petroleum systems and plays may be linked. We describe a new method that allows easier and more efficient comparisons between petroliferous sedimentary basins with similar geologic characteristics. Using this method, we can make predictions of potential petroleum systems and plays occurring in underexplored basins or regions. In this article, the methodology is applied to the well-explored Gabon coastal basin (west African margin) and the conjugate Almada-Camamu Basin (Brazilian margin), which is a frontier basin. The two basins experienced a similar tectonostratigraphic evolution and share many similarities. We propose that petroleum systems and plays identified in the Gabon coastal basin might potentially also be present in the Almada-Camamu Basin. These could include a second lacustrine synrift petroleum system, as well as a fluviomarine transitional petroleum system. Potential, but not yet proven, reservoirs in the Almada-Camamu Basin include coarse sandstones surrounding basement highs within the synrift, synrift lacustrine carbonates, fluviomarine sandstones at the base of the transitional cycle, and early postrift ramp carbonates. The methodology and newly developed figures are particularly useful to obtain a first impression of the tectonostratigraphy, likely petroleum system and play development, and exploration history of potentially analogous basins. Furthermore, the approach allows for the recognition of important differences, raising questions that can be answered by more direct techniques.

Description: Salt canopies, formed by the coalescence of salt sheets, are an integral part of the slope and deep-water areas of many passive margin salt basins. A suture separates the two coalesced salt sheets (allosuture) or two lobes from a single salt sheet (autosuture), including any trapped sediments.Autosutures can form in two ways. An overriding autosuture is produced when part of a salt sheet overrides its neighbor in the direction of salt movement. The overridden roof subsides into the salt sheet, and these trapped sediments appear as intrasalt reflections on seismic data. An encircling autosuture forms when two lobes of a salt sheet separate to bypass an obstacle and then rejoin on the downstream side of the obstacle. Encircling autosutures tend to be short and parallel to the dominant salt-flow direction.Allosutures separate sheets sourced from two different feeders. If neither salt sheet overrides the other, the resulting suture is symmetric, forming an upright zone of roof sediments trapped between the two sheets. More typically, one salt sheet is more vigorous (generally the larger sheet or the one whose feeder is farther updip) and overrides the other. Sediments trapped in an asymmetric allosuture are mostly from the roof of the overridden sheet. The overriding sheet shears and extends the roof of the overridden sheet, detaching it from the base of the canopy and obscuring its origin.We present diagnostic criteria to distinguish between suture types and provide physical-model examples of each. This distinction between suture types is important because autosutures and allosutures have very different implications for canopy dynamics and evolution.

Description: The Upper Devonian–Lower Carboniferous Bakken Formation is a widespread siliciclastic unit in the subsurface of the Williston Basin that is subdivided into three members: lower and upper organic-rich shale members and a dolomitic, silty, and sandy middle member. Although the unit has become one of the most active oil plays in North America and numerous sedimentologic studies have been made, no consensus about the depositional environments of the middle member has been achieved. Previous studies suggested several depositional and sequence-stratigraphic scenarios, including lowstand offshore-shoreface, normal-regressive offshore-shoreface, incised estuary, and falling-stage shoreface complexes for the middle member. We propose a new depositional and sequence-stratigraphic model and compare it with some previous interpretations. This new model includes a basal transgressive systems tract (TST) embracing shelf deposits, a highstand systems tract comprising shelf to lower shoreface environments, and an upper TST encompassing a brackish-water embayment complex and offshore to shelf settings. Petrophysical characterization of the sedimentary facies reveals that bay-mouth cross-stratified fine-grained sandstone, flaser-bedded very fine grained sandstone formed in wave-dominated tidal flats, offshore-transition highly bioturbated interbedded very fine grained sandstone and siltstone, and tidal-flat very fine grained sandstone with common mud drapes possess the best reservoir qualities. Recognition of a restricted embayment within the Bakken middle member has major implications for both exploration and production. Embayment facies with good reservoir quality constitute good oil prospects in localized areas, whereas fully marine facies may represent good oil prospects of more regional extent.

Description: A geochemical study of 34 oil samples was conducted to understand the types and distributions of effective source rocks and evaluate the geographic extent of the petroleum systems in the Barents Sea and northern Timan-Pechora Basin. Taxon-specific, age-related, and source-related biological markers (biomarkers) and isotope data provided information on the depositional environment of the source rock, source input, and source age of the oil samples. A relationship between biomarker and diamondoid concentration was used to identify mixed oils having both oil window and highly cracked components. Compound-specific isotope analyses of diamondoids and n-alkanes were used to deconvolute cosourced oils and identify deep source rocks in the basin. Results suggest five major source rocks in the Barents Sea and the northern Timan-Pechora Basin: Upper Jurassic shale, Lower–Middle Jurassic shale, Triassic carbonate and shale, Devonian marl, and Devonian carbonate. The Upper and Lower–Middle Jurassic source rocks are dominant in the Barents Sea. Triassic source rock consists of carbonate in the onshore part of northern Timan-Pechora Basin and marine shale in the Barents Sea. The Devonian Domanik Formation carbonate source rock extends offshore into the southern Barents Sea. The high-maturity Domanik Formation could also be a secondary source rock for most of the mixed oils in the northern Timan-Pechora Basin. This detailed geochemical study provides a new and detailed understanding of petroleum systems in the Barents Sea and northern Timan-Pechora Basin.

Description: The nanometer-scaled pore systems of gas shale reservoirs were investigated from the Barnett, Marcellus, Woodford, and Haynesville gas shales in the United States and the Doig Formation of northeastern British Columbia, Canada. The purpose of this article is to provide awareness of the nature and variability in pore structures within gas shales and not to provide a representative evaluation on the previously mentioned North American reservoirs. To understand the pore system of these rocks, the total porosity, pore-size distribution, surface area, organic geochemistry, mineralogy, and image analyses by electron microscopy were performed. Total porosity from helium pycnometry ranges between 2.5 and 6.6%. Total organic carbon content ranges between 0.7 and 6.8 wt. %, and vitrinite reflectance measured between 1.45 and 2.37%. The gas shales in the United States are clay and quartz rich, with the Doig Formation samples being quartz and carbonate rich and clay poor. Higher porosity samples have higher values because of a greater abundance of mesopores compared with lower porosity samples. With decreasing total porosity, micropore volumes relatively increase whereas the sum of mesopores and macropore volumes decrease. Focused ion beam milling, field emission scanning electron microscopy, and transmission electron microscopy provide high-resolution (∼5 nm) images of pore distribution and geometries. Image analysis provides a visual appreciation of pore systems in gas shale reservoirs but is not a statistically valid method to evaluate gas shale reservoirs. Macropores and mesopores are observed as either intergranular porosity or are confined to kerogen-rich aggregates and show no preferred orientation or align parallel with the laminae of the shale. Networks of mesopores are observed to connect with the larger macropores within the kerogen-rich aggregates.

Description: Mature and aging clastic-dominated hydrocarbon fields commonly become increasingly difficult to produce, causing lower economic return than initially forecast. A major cause of this reduced economic viability is compartmentalization, defined as limitation on the ability to produce hydrocarbons resulting from permeability barriers within a field. Three primary causes of compartmentalization are structural variations in permeability, stratigraphic variations in permeability, and permeability reduction resulting from compaction adjacent to producing wellbores. Recognition and delineation of compartmentalization permit formulation of development and depletion plans to maximize recovery and economic value. Here, we examine one of 52 reservoir-scale faults that compartmentalize the eastern shallow oil zone (ESOZ), Elk Hills field, California. Using well-log, stratigraphic, structural, and pressure data, we apply standard fault seal analyses to the selected fault. Results are compared with known pressure conditions across the fault and show the fault capable of supporting pressure differentials two to three times those expected from standard static fault seal measures. Although this observation could be used as a basis for local calibration of standard fault seal measures for a dynamic seal, such an approach assumes that these fault seal mechanisms are in fact the cause of sealing behavior. Alternatively, one of the most significant changes in ESOZ reservoir conditions over the production lifetime of the field is the reduction of fluid pressure from approximately 1500 to approximately 200 psi (from ∼10.27 to ∼1.37 MPa). Decreasing fluid pressure would have driven stress states acting on faults in the reservoir from critical (near or at slip) to stable (nonslipping) conditions. Critically stressed faults and fractures are more transmissive than those that are noncritically stressed. We propose that decreasing fluid pressure can cause faults to become less leaky, causing production-induced reservoir compartmentalization.

Description: The Mount Simon Sandstone (Cambrian) has significant potential for use as a reservoir for geologic carbon sequestration in the Midwest region, but lithologic variations within the unit remain poorly understood. Petrophysical heterogeneities controlled by the changes in lithologic and diagenetic character challenge the process of estimating the storage capacity of this reservoir. Geophysical logs from wells across the Midwest region were interpreted to define three lithostratigraphic subunits within the Mount Simon Sandstone: an upper unit that has relatively high gamma-ray (GR) values caused by the admixture of argillaceous material; a middle unit defined by relatively lower GR values that result from a cleaner quartzose sandstone and potentially constitutes the main reservoir and flow unit within the formation (the GR values of this unit also display the lowest amount of vertical variability through the section); and a lowermost unit defined by GR values that, in general, progressively increase with depth toward the base of the formation. This downward increase is caused by the increased nonquartz fraction in the formation as the top of the Precambrian basement is approached. In all three units, but especially in the lowermost one, the admixture of feldspars and the presence of dissolution porosity complicate storage capacity calculation. In addition to quartz overgrowths and compaction phenomena that reduce pore volume, the presence of other diagenetic products further complicates the distribution of porosity and permeability within the unit. Storage capacity was calculated only for the middle unit within the Mount Simon Sandstone using values derived from GR and porosity geophysical logs (sonic, neutron, and density). The range of storage capacity found in this study is primarily controlled by reservoir thickness because the variation in porosity within this middle unit is less than that in the other units. However, an assessment of the vertical distribution of porosity and permeability at each site will be required to determine the best intervals with the best flow and storage properties.

Description: Identifying the source of stray gas in drinking water supplies principally relies on comparing the gas composition in affected water supplies with gas samples collected in shows while drilling, produced gases, casing head gases, pipeline gases, and other potential point sources. However, transport dynamics of free and dissolved gas migration in groundwater aquifers can modify both the concentration and the composition of point source stray gases flowing to aquifers and occurring in the groundwater environment. Accordingly, baseline and forensic investigations related to stray gas sources need to address the effects of mixing, dilution, and oxidation reactions in the context of regional and local hydrology. Understanding and interpreting such effects are best addressed by collecting and analyzing multiple samples from baseline groundwater investigations, potential point sources, and impacted water resources.Several case studies presented here illustrate examples of the natural variability in gas composition and concentration data evident when multiple samples are collected from produced gases, casing head gases, and baseline groundwater investigations. Results show that analyses of single samples from either potential contaminant point sources or groundwater and surface water resources may not always be sufficient to document site-specific baseline conditions. Results also demonstrate the need to consistently sample and analyze a variety of baseline groundwater and gas composition screening parameters. A multidisciplinary approach is the best practice for differentiating among the effects of fluid and gas mixing, dilution, and natural attenuation.

Description: Most surface water and shallow groundwater occurring in northeastern Nebraska are of the calcium bicarbonate type, with minor concentrations (e.g., 10–200 mg/L) of sulfate (SO4). Examination of historical water quality data (major cations and anions) for Ponca Creek, a predominantly ephemeral stream in northeastern Nebraska, revealed that SO4 concentrations ranged from about 110 to almost 1000 mg/L and contribute to a calcium sulfate hydrochemical facies. Consequently, most SO4 concentrations were above the U.S. Environmental Protection Agency secondary maximum contaminant level in drinking water of 250 mg/L. Sulfate concentrations for the same period for a nearby stream, Verdigre Creek, range from about 20 to 120 mg/L. Research into probable sources of the elevated SO4 in Ponca Creek revealed that a Late Cretaceous shale, the Pierre Shale, occurs at or near the land surface throughout most of the creek's drainage area, whereas alluvium, other Quaternary deposits, or the Tertiary Ogallala Formation comprises the streambed in Verdigre Creek. The Pierre Shale, encompassing soils formed on this Cretaceous shale, is rich in sulfate-bearing minerals (e.g., gypsum, pyrite, jarosite) that comprise the principal source of the high sulfate in drainage basin soils, alluvium, creek discharge, and shallow groundwater of the Ponca Creek watershed. A public domain geochemical speciation software (Visual MINTEQ) was used to investigate aqueous SO4 geochemistry of Ponca Creek flow. Calculated saturation indices for Ponca Creek waters suggest that they are slightly undersaturated with respect to gypsum and anhydrite despite significant sulfate dissolution and are slightly supersaturated with respect to calcite in numerous samples.

Description: Depositional sequences capped by peritidal carbonates and breccias on the Aptian Adriatic carbonate platform, Croatia, were studied to evaluate evidence for glacioeustasy within an age framework constrained by carbon-isotope chemostratigraphy. Sequence Ad1 (17–60-m [56–197-ft] thick; uppermost Barremian–lower Aptian) is dominated by shallow subtidal parasequences. Sequence Ad2 (7–13-m [23–43-ft] thick; lower Aptian–lowermost upper Aptian) contains oceanic anoxic event (OAE) 1a, associated with lagoonal laminated carbonates. Sequence Ad3 (3–8-m [10–26-ft] thick) probably is lower upper Aptian and likely is separated by a major hiatus from sequence Ad4 (8–20-m [26–66-ft] thick; uppermost Aptian), which spans OAE1b. Both Ad2 and Ad3 are dominated by peritidal parasequences updip in the lower transgressive systems tract and upper highstand systems tract and by subtidal parasequences elsewhere, whereas sequence Ad4 is dominated by shallow subtidal parasequences. Low accommodation rates (4.0–6.0 cm [1.6–2.4 in.] in the earliest Aptian, decreasing to approximately 1.0 cm/k.y. [0.3 in./k.y.] later) promoted widespread breccia development during relative sea level falls, aided by tectonic warping. The sequence-capping breccias, eccentricity-dominated cyclicity, restriction of peritidal facies to late highstands, and coeval off-shelf oxygen-isotope records all suggest that sea level falls occurred during times of cooling and had a significant glacioeustatic component. These intermittent cooler periods and continental ice buildup punctuated the Aptian greenhouse climate.

Description: Descriptions of mineralogy and textural relationships in sandstones and limestones have been used to establish a sequence of diagenetic events (epigenesis), involving mineral dissolution and precipitation, which have been interpreted to have occurred during the burial history. Published epigenetic sequences commonly imply a geochemically open system with very significant changes in the bulk chemical composition of the sediments during burial. Near-surface diagenetic reactions may be open, involving significant changes in the sediment composition and formation of secondary porosity caused by high pore-water flow rates of meteoric water or reactions with sea water near the sea floor. Calculations show that the bulk chemical composition of the sediments below the reach of high pore-water flow rates of meteoric water or hydrothermal convection should remain nearly constant during progressive burial because of limited pore-water flow. Mass transport between shales and sandstones is also limited because the pore water is, in most cases, buffered by the same minerals so that the concentration gradients are low. Recent studies show that silica released from clay-mineral reactions in mudstones has been precipitated locally as small quartz crystals and not exported to adjacent sandstones. If the geochemical constraints for mass transfer during burial diagenetic reactions are accepted, the chemical reactions involved in diagenesis can be written as balanced equations. This offers the possibility to make predictions about reservoir quality based on assumptions about primary sediment composition related to facies and provenance. Large-scale changes in the bulk composition of sandstones and mudstones during burial diagenesis have been suggested, but because such changes cannot be explained chemically and physically, no predictions can be made. Burial diagenetic processes are, in most cases, not episodic but occur as slow adjustments to increased stress and temperature, driving the sediments toward increased mechanical and thermodynamic stability. As a result, the porosity of a single lithology must decrease during progressive burial, but each lithology has a different porosity curve. This article discusses quantitative calculations and estimates that show clearly that burial diagenesis must represent geochemically nearly closed systems where mineral dissolution and precipitation must be balanced. This provides a theoretical basis for the modeling and prediction of reservoir quality.

Description: Episodic deformation, triangle zone development, and related back thrusting in the central Brooks Range foothills are major factors in the distribution of fractures and the thermal history of rocks involved in the deformation. Structural reconstructions suggest that the rocks forming the Endicott Mountains allochthon, the youngest and northernmost part of the orogen during its first phase, were emplaced during the Early Cretaceous (Valanginian) at temperatures approximately 150°C. Fractures associated with that deformation are filled with synkinematic calcite cement, indicating that they formed in the presence of fluids. After a period of quiescence during the Late Cretaceous, renewed deformation involved the shortening of the existing orogenic wedge and the development of a triangle zone and overlying back thrust in adjacent mid- to Late Cretaceous rocks of the foreland basin. This later deformational event and subsequent uplift resulted in two sets of uncemented barren fractures that formed in all parts of the fold and thrust belt. Restriction of cement-filled fractures to the older and structurally deeper parts of the orogen implies that the youngest and most obvious fractures visible at the surface developed at shallow depths and temperatures and thus may not have been an important factor in petroleum migration.

Description: The Yufutsu oil and gas field, located in Hokkaido, northern Japan, produces hydrocarbon from a typical fracture-type reservoir composed of very tight Cretaceous granitic basement and overlying conglomerate of the Eocene. Here, delineations of faults accompanying large open fractures are essential for optimal developments. To capture fault distribution objectively, various seismic-attribute estimates ascribed to fault distributions are derived from three-dimensional seismic data by computational procedures. However, to use the estimates properly, calibrating them with independent observations other than seismic data is important. We present a calibration scheme by coupling seismic data with microseismic data and in-situ stress data to delineate active faults under a strike-slip faulting stress regime in the Yufutsu field. Active faults are interpreted to be fluid pathways formed by shear dilation. In the calibration, two kinds of parameter sets are tuned. One controls linkages of fault responses fragmented by artificial noises caused by seismic acquisition and processing to adjust spatial continuities of fault surfaces properly. Another limits extracted fault strikes with respect to Mohr-Coulomb failure criterion to highlight active faults. The calibrated seismic-attribute estimates show a qualitative consistency with the microseismic hypocenter distribution observed during a massive hydraulic stimulation. In addition, a large difference in gas productivity observed at four wells, from very high productivity to no gas flowing, is clearly related to an existence of distinct lineation with strong magnitudes of the calibrated seismic attributes. It suggests that the calibrated estimate becomes a criterion to judge an economic viability of a well.

Description: The Upper Cretaceous Mesaverde Group in the Piceance Basin, Colorado, is considered a continuous basin-centered gas accumulation in which gas charge of the low-permeability sandstone occurs under high pore-fluid pressure in response to gas generation. High gas pressure favors formation of pervasive systems of opening-mode fractures. This view contrasts with that of other models of low-permeability gas reservoirs in which gas migrates by buoyant drive and accumulates in conventional traps, with fractures an incidental attribute of these reservoirs. We tested the aspects of the basin-centered gas accumulation model as it applies to the Piceance Basin by determining the timing of fracture growth and associated temperature, pressure, and fluid-composition conditions using microthermometry and Raman microspectrometry of fluid inclusions trapped in fracture cement that formed during fracture growth. Trapping temperatures of methane-saturated aqueous fluid inclusions record systematic temperature trends that increase from approximately 140 to 185°C and then decrease to approximately 158°C over time, which indicates fracture growth during maximum burial conditions. Calculated pore-fluid pressures for methane-rich aqueous inclusions of 55 to 110 MPa (7977–15,954 psi) indicate fracture growth under near-lithostatic pressure conditions consistent with fracture growth during active gas maturation and charge. Lack of systematic pore-fluid–pressure trends over time suggests dynamic pressure conditions requiring an active process of pressure generation during maximum burial conditions. Such a process is consistent with gas generation within the Mesaverde Group or by gas charge from deeper source rocks along fracture and fault systems but is inconsistent with significant high-pressure generation by compaction disequilibrium during earlier stages of burial. On the basis of a comparison of trapping temperatures with burial and thermal maturity models, we infer that active gas charge and natural fracture growth lasted for 35 m.y. and ended at approximately 6 Ma. Our results demonstrate that protracted growth of a pervasive fracture system is the consequence of gas maturation and reservoir charge and is intrinsic to basin-centered gas reservoirs.

Description: Channel avulsion is fundamental in defining submarine fan morphology yet, as a process, is poorly understood. The postavulsion evolution of five channel-levee systems, documented from both the shallow subsurface and the sea floor, is marked in the early stages by relatively wide axial channel belts containing sinuous channel elements. The axial channel belt in each system narrowed through time in association with levee aggradation, which resulted in increased channel confinement. Of the five systems studied, four avulsed from a radial avulsion node at the mouth of the basin feeder-channel complex, which is the entry point to the basin. Only one avulsion occurred at an avulsion node downflow of the mouth of the feeder-channel complex. The degree of channel instability in three of the four systems before an avulsion event was increased by channel-floor aggradation caused by the backfilling of channel-confined turbidity current deposits. Channel-floor aggradation reduced the confinement relief of the systems, thereby increasing the probability of avulsion during an outsized flow event. The backfilled deposits in the channel belts display relatively high seismic-reflection amplitudes inferred to be coarser grained (more sand rich) than their surroundings, that is, out-of-channel deposits. Overbank cyclic steps are exceptionally well preserved on subsurface levees, and their potential function in promoting an avulsion event is discussed. The actual process of avulsion is caused by the flow itself instead of a reduction in confinement relief, and although outsized flows are the likely trigger, depending on the degree of this relief in the channel, multiple small flows could also be responsible for levee breaching, resulting in avulsion.The process of channel-system evolution resulting in avulsion can be applied to other subsurface data where compensating high-amplitude channel belts are recognized. In the context of hydrocarbon exploration, investigating up depositional dip to identify avulsion nodes increases the chance of locating sand-rich deposits, especially where multiple channels converge on one point.

Description: Lower Triassic platforms in the Nanpanjiang Basin contain extensive oolites. Interior oolites are stacked in meter-scale cycles arranged into larger coarsening-upward sequences. Oolites thicken toward margins to include grainstones up to 50 m (164 ft) thick and contain giant ooids (up to 1 cm [0.4 in.]) and composite coated grains. Cross-bedding, ripples, and abraded ooids indicate deposition in high-energy shoals. Apparent layer-cake correlation across interiors indicates amalgamation of shoals. Thinner interior lenses represent spillover lobes. Ooids are interpreted to have originally been bimineralic with cortices of radial or micritic fabrics (high-magnesium calcite), alternating with coarse pseudospar or brickwork (originally aragonite). Distorted ooids formed by brittle compaction of micritic cortices around voids are interpreted to have been dissolved aragonite. Abundant potential nuclei indicate that limited supply was not a factor contributing to the large ooid size. High-energy and abnormally high–seawater CaCO 3 saturation are interpreted to be causes of the giant ooids. Most previous reports of giant ooids come from the Neoproterozoic, a period of increasing surface-water oxygenation and high CaCO 3 saturation caused by a minimal skeletal carbonate precipitation. We interpret similar seawater chemistry in the aftermath of the end-Permian extinction to explain the genesis of the giant ooids in the Early Triassic. The genesis of bimineralic ooids during an Early Triassic period of rapidly increasing pCO 2 and low $${\hbox{ SO }}_{4}^{2-}$$ indicates that an increasing Ca/Mg ratio was the primary mechanism driving the change from aragonite to calcite seas. The architecture, textures, and diagenesis of the Lower Triassic oolites of the Nanpanjiang Basin provide useful analogs for coeval reservoirs in Sichuan and the Middle East.

Description: This study compares the results of the petroleum resources of China evaluated in the U.S. Geological Survey World Petroleum Assessment 2000 ( USGS WPA 2000 ) with those evaluated in the China National Petroleum Assessment 2007 ( CNPA 2007 ). The USGS WPA 2000 reported the mean undiscovered petroleum resources of China to be 12.12 BBO and 85.79 TCFG, which is a much lower estimate than the 107.38 BBO and 692.13 TCFG assessment reported in the CNPA 2007 . Six major factors, including petroleum resource classification systems, data sources, assessment scopes, unit divisions, assessment methods, and assessment parameters, contributed to the differences in these two assessments. Reserve growth and undiscovered resources are two independent parts of total petroleum resources according to the definition in the USGS WPA 2000 , whereas undiscovered resources of the CNPA 2007 included estimates of reserve growth. The USGS WPA 2000 showed a much higher minimum field size than the CNPA 2007 did, and only six Chinese basins were covered in the former, whereas 115 Chinese basins were evaluated in the latter. For the same basins, unit divisions of the USGS WPA 2000 also differed from those of the CNPA 2007 because of their different data sources and exploration and exploitation experiences. Different methods used by these two agencies also affected their assessment results to some degree.

Description: The Embla field, located in the greater Ekofisk area of the Norwegian part of the southern North Sea, has been producing oil and gas since the early 1990s. The wells on the crest are the best and most continuous producers, whereas the wells on the flanks are only good producers over limited periods after pressure buildup. The reason for the poorer production from the flanks is reduced permeability caused by the presence of bitumen, a nonmovable biodegraded oil that fills the pore space. This oil is shown to be of Paleozoic age and is suggested to have charged the Embla field at the end of the Triassic. The structure was uplifted and eroded during the Jurassic, and the Paleozoic oil accumulation became biodegraded on the oil-water contact. The crest of the structure is believed to have been protected from biodegradation until the seal was eroded, which resulted in the escape of the oil and the biodegradation of the residual oil. Subsidence during the Cretaceous, the formation of a new seal, and the Upper Jurassic source rock intervals reaching oil window maturity resulted in the structure being recharged. Partly contradicting maturity estimates based on various biomarker ratios suggest that the analyzed oils represent different mixing ratios between the two oil generations. The change in light oil composition observed between the drill-stem tests sampled approximately 20 yr ago and the presently produced oil suggests that the Embla field currently is receiving Jurassic-sourced oil.

Description: As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term "shale" does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, R o = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output ( T max ) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.

Description: The lower Pennsylvanian Jackfork Group in Arkansas has been the subject of studies, field trips, and publications for many years because of excellent outcrop exposures of different deep-water architectural elements. This latest study is focused on the Baumgartner Quarry located near Kirby, Arkansas, which exposes a series of vertical walls in three dimensions. This quarry has not been as well documented as other popular exposures, although three-dimensional (3-D) quarry faces exist, and the quarry strata comprise part of a complete 600-m (1970-ft)-thick near-continuous Jackfork stratigraphic sequence not unlike younger deep-water stratigraphic exploration targets in the Gulf of Mexico and elsewhere. Subsurface problems including reservoir uncertainties and reservoir performance of lobe versus channel-fill deposits are addressed based on our work in the quarry. A 3-D sequence-stratigraphic model was developed using a correlation of seven measured stratigraphic sections in the quarry. The 180-m (590-ft)-thick quarry strata consist of a lower lowstand systems tract (LST) (lower sandstones) dominated by channel-fill sandstones, overlain by a shaly transgressive systems tract (condensed section), and then by an upper LST (upper sandstones) dominated by sheet or lobe sandstones. This model was translated into an updip against salt field, which is analogous to some deep-water Gulf of Mexico reservoirs. Performance simulation was conducted on the model using a one-injector water well and two vertical producing wells, one of which was connected to the injector via a channel sandstone and the other of which was offset from the channel sandstone. Results yielded 60% more production from the connected injector-producer pair than from the nonconnected pair. Comparison between the lower (channel-prone) sandstones and the upper (sheet-prone) sandstones revealed that the sheet-prone sandstone is more sustainable, whereas the channel-prone sandstone exhibits a larger drop in production rate during a 10-yr production period. These results illustrate the value of 3-D outcrop models for reservoir performance simulation for development planning of deep-water fields with limited data control, such as in the deep-water Gulf of Mexico.

Description: Porosity, permeability, and total organic carbon (TOC) in a heterogeneous suite of 21 high-maturity samples (vitrinite reflectance 1.52–2.15%) from the Barnett Shale in the eastern Fort Worth Basin display few correlations with parameters of rock texture, fabric, and composition, these factors being mostly obscured by the effects of a protracted history of diagenesis. Diagenesis in these rocks includes mechanical and chemical modifications that occurred across a wide range of burial conditions. Compaction and cementation have mostly destroyed primary intergranular porosity. The porosity (average 〈5 vol. % by Gas Research Institute helium porosimetry) and pore size (〈8 nm median pore-throat diameter) are reduced to a degree such that pores are difficult to detect even by imaging Ar ion–milled surfaces with a field-emission scanning electron microscope. The existing porosity that can be imaged is mostly secondary and is localized dominantly within organic particulate debris and solid bitumen. The grain assemblage is highly modified by replacement. A weak pattern of correlation survives between bulk rock properties and the ratio of extrabasinal to intrabasinal sources of siliciclastic debris. Higher porosity, permeability, and TOC are observed in samples representing the extreme end members of mixing between extrabasinal siliciclastic sediment and intrabasinal-derived biosiliceous debris. Reservoir quality in these rocks is neither more strongly nor more simply related to variations in primary texture and composition because the interrelationships between texture and composition are complex and, importantly, the diagenetic overprint is too strong.

Description: A 15,000-km 2 (5792-mi 2 ) three-dimensional seismic data survey that covers the shelf-slope transition of the eastern offshore Trinidad continental margin reveals the geometry and depositional history of the last maximum glacial lowstand shelf-margin succession. Despite the lack of well information at these shallow depths, the quality and continuity of the seismic data allow us to pursue a detailed seismic stratigraphic interpretation of the last lowstand margin succession. The basin-fill stratal architecture of the studied stratigraphic interval shows a great deal of lateral and vertical variability along the continental margin during the Pleistocene to Holocene. Three geomorphological elements controlled the character of the accommodation within the basin and were crucial in transporting, delivering, and storing sediment supply from shelf to slope areas: (1) the Columbus sedimentary pathway on the shelf, (2) bypass zones in the shelf-break region, and (3) deep-water depocenters. The location and geometry of these geomorphological elements within the basin are clearly controlled by underlying structures, transpressional to the north and gravity driven to the south. Migration of the paleo-Orinoco delta system across the shelf was also a key factor in defining the stratigraphic geometries that are observed within the shelf break. Development of shelf-edge versus outer-shelf deltaic systems on the continental margin was controlled by the nature of sediment supply at specific times, as well as by the availability of accommodation, although, to a lesser extent, to relative sea level fluctuations. The interpretation also showed that, for time-equivalent units, parts of the shelf-edge region could develop as an erosional margin (sediment bypass zones), whereas other parts of the shelf edge could behave as an accretionary margin (sediment accumulation). The sequence-stratigraphic interpretation that was attempted in this work also demonstrated that the characteristics of systems tracts can abruptly change along strike in the shelf-edge region for time-equivalent units. These changes can be misleading if a genetic interpretation is pursued only on the basis of the definition of system tracts in the shelf-edge region without the consideration of a complete regional framework.

Description: This article describes a method to determine geothermal gradients and formation temperatures using bottom-hole temperatures (BHTs) from wireline-log headers and then tests the method by applying it to analyses from more traditional sources. Bottom-hole temperatures, depths, and times since circulation ended were collected from at least one well in every township that had been drilled for petroleum exploration in the state of Wyoming. Using approximately 3500 BHTs collected from almost 2000 wells, equations were developed for average formation temperatures and geothermal gradients across the state. A method of correcting the average data to true formation temperatures in each individual well was also developed. The geothermal temperatures so derived very closely match temperatures from production BHTs that are the normal industry standard for formation temperatures and suggest that BHT information is much more accurate than commonly thought. The use of BHT measurements to compute temperature gradients was also developed. The effects upon formation temperatures of common data recording errors; of vertical circulation of groundwater, especially above 1700-m (5577-ft) depth; and of lateral groundwater circulation through deep aquifers are documented. The methods developed offer promising avenues for research in the areas of hydrogeology, geothermal exploration, determining formation temperatures, and heat flow.

Description: The sandstone at the base of the Upper Pennsylvanian Taiyuan Formation (Ct2) is a prominent gas reservoir in the Daniudi gas field, northeastern Ordos Basin, China. Logs, cores, thin sections, outcrops, scanning electron microscopy, and three-dimensional seismic data are used to delineate sedimentary facies and to divide the succession into sequence-stratigraphic units.The gas-bearing coarse-grained sandstone is interpreted as a fluvial-dominated incised-valley fill. A sedimentary hiatus documented for the first time in the study area forms the sequence boundary between the Lower Pennsylvanian Taiyuan Formation (Ct1) and Upper Pennsylvanian (Ct2). The hiatus and overlying incised-valley fill can be observed at the Heidaigou outcrop, where the presence of bauxite indicates a period of subaerial weathering. The incised-valley fill and hiatus can also be found through the outcrop correlation of Xipo, Chengjiazhuang, Qiaotou, and Heidaigou at the eastern margin of Ordos Basin. Two types of basinward and two types of landward facies shifts are identified between Ct1 and Ct2 based on core observations and cross-well profiles analysis to demonstrate abrupt facies change and punctuation. Further evidence for a hiatus is provided by an onlap at this surface on the seismic data.

Description: Petrophysical properties and their heterogeneity within sandstone bodies are key parameters in the evaluation of hydrocarbon and geothermal reservoirs. However, common tools applied to constrain the porosity distribution pattern in borehole cores are commonly time consuming and destructive, or suffer from a resolution limited to the meter to decimeter scale. We examine the applicability of nondestructive high-resolution sonic (HRS) logging of well core sections in the ultrasonic frequency range as a method providing porosity proxy data at the centimeter scale in a clastic sedimentary sequence.The middle Solling Sandstone Member, a gas-bearing reservoir offshore from the Netherlands, is used as a test sample. It consists almost entirely of clean, cross-bedded to massive eolian dune and dry sand-flat deposits that are salt plugged to variable degrees. Plots of HRS logging data versus core-plug porosity values show a positive linear relationship that develops the highest coefficient of determination (R2 = 0.86) in structureless eolian dune sands, most probably caused by the lack of bedding-related anisotropies there. Once calibrated for a particular facies type, this correlation enables the calculation of porosity proxy data from sonic transit time values, acquired at centimetric steps. High-resolution sonic logging thus contributes a reliable and time-efficient, highly spatially resolving quantification of reservoir heterogeneities at centimeter scale and turns out to be a suitable tool for the nondestructive in-situ detection of high-porosity zones in otherwise uniform sandstone successions. Moreover, plots of closely spaced HRS logging–derived porosity proxy data significantly improve interpolation between single, wider spaced core-plug porosity data points.

Description: Oil-producing sills are commonly considered atypical reservoirs, although they can hold significant exploration potential. The need for a better understanding of fracture properties and petroleum system characteristics for this and similar igneous rock plays is the main motivation of our study. We explore the evolution of this play type by an analysis of the Los Cavaos oil field, located in the Malargue fold belt of the Neuquén Basin, Argentina, integrating multiscale fracture data from outcrops and subsurface. The field was created by a combination of intrusions and mild Miocene-Pliocene inversion. Production stems from thick cavity zones in naturally fractured andesitic sills emplaced in Upper Jurassic shale source rocks. Orientation patterns, fracture spacing, and length of fracture sets in the sill are consistent over several orders of magnitude. Large multiply connected and weakly cemented fractures are responsible for excellent interconnectedness in the reservoir. Fracture density is correlated with fault proximity, indicating a cogenetic evolution during active deformation. Abundant fractures in core with strike-slip to oblique striations support transpressional overprint during and after fracture formation. Although it is challenging to separate cooling from tectonic fractures, we propose two phases of fracturing, marked by a coexistence of subvertical and oblique fractures together with transpressional striae. Petrographic evidence suggests initial local oil expulsion and migration through microfractures, with opening displacements of 0.01 to 1 mm, followed by subsequent charging of the evolving intrasill cavity system as well as the bulk fracture system during cooling and mild deformation. We suggest that the observed patterns may be extrapolated to sills in similar geotectonic settings.

Description: This study defines the depositional systems of mature lower Atoka Group reservoirs, structural influence on their sedimentation, and sand-transport patterns at a higher degree of resolution and over a significantly larger part of the play area than previously conducted. The reservoir systems are characterized by pronounced variations in depositional style, even between stratigraphically adjacent systems. They represent a variety of on-shelf siliciclastic depositional facies, including gravelly braided river, fluvial-dominated delta, and low-sinuosity incised river deposits. Penecontemporaneous, high-angle, basement-rooted reverse faults and genetically associated folds of the Mineral Wells–Newark East fault system exerted direct control on the orientation of complex fluvial-channel and delta-distributary sand-transport pathways and the geometry of deltaic depocenters. Multiple contemporaneous source areas, including the Ouachita fold belt to the southeast, the Muenster arch to the northeast, and the south flank of the Red River arch, also contributed to the complexity of sandstone trends in the lower Atoka play area.Bubble maps of normalized per-well first-year production and total cumulative production allow qualitative conclusions regarding geologic controls on production distribution. Most wells with optimal gas production occur within two northwest-trending production fairways that coincide with primary sandstone trends of one or more reservoir systems. Highest per-well oil production exists where lower Atoka reservoir facies occur above oil-prone Barnett Shale source rocks (vitrinite reflectance

Description: Weakly confined channel systems are common in low-relief minibasins on continental margins and are important hydrocarbon reservoirs. They are characterized by channels that diverge in the proximal part of the basin and converge because of topographic confinement in the distal part of the basin. The Morillo 1 member, in the Ainsa Basin, Spain, is an excellent outcrop analog of a weakly confined submarine channel system. Data from the Morillo 1 member are used to quantitatively document how reservoir characteristics vary laterally and longitudinally in weakly confined submarine channel reservoirs. The key axis-to-margin patterns are the proportions of channel elements, channel complexes, channel-complex sets, reservoir facies, and net sand content; static connectivity decreases laterally from the axis to the margins of the system. The key longitudinal patterns in the updip area are channel elements that have levees, are spatially dispersive, and have a radially divergent map pattern. In the downdip area, channel elements are spatially focused and have uniform orientations, and the proportion of channel elements does not change along the longitudinal profile. However, the size of channel elements, percentage of reservoir facies, and connectivity of channel elements are higher in the downdip area. Patterns identified herein are significant because they cannot be resolved using subsurface or sea-floor data. Results of this study can therefore be used to reduce uncertainty in the interpretation of subsurface data, provide input to constrain rule-based forward stratigraphic models, and provide input to constrain reservoir models.

Description: The Bakken Formation of the Williston Basin is a prime example of an unconventionally produced petroleum system, with a low-permeability reservoir that requires application of advanced technologies for commercial production. A three-dimensional model of the Williston Basin was constructed to integrate and assess the parameters that influence the generation and migration of hydrocarbons in the Bakken Formation. This study tests the applicability of available basin and petroleum system modeling technology on an unusually low-permeability petroleum system. The model is based on nine surfaces constructed from log tops of thousands of wells in the study area and additional depth and isopach maps of the Bakken Formation members. These were integrated with the established basin evolution in line with published research. Temperature and thermal maturity were calibrated during model construction from well temperature and geochemistry data. The resulting heat-flow map supports the existence of a heat-flow anomaly along longitude 103°W, discussed controversially in the literature. Furthermore, the results indicate that the invasion-percolation migration approach best describes the distribution of petroleum accumulation and the saturated areas in the Bakken members. The volume of generated hydrocarbons was calculated, and the extent of the highly saturated accumulation beyond the area of the high-mature source was mapped. Furthermore, it was demonstrated that petroleum accumulations beyond the high-saturation zones have to be related to stratigraphic pinch-outs, lateral variability in permeability of the Bakken members, or smaller structural influences that were lost because of the resolution applied in the model.

Description: The topset compartments of two Maastrichtian basin-scale clinothems are characterized, with focus on the function they played in constructing the Lance–Fox Hills–Lewis shelf-margin sedimentary prism in the Laramide Washakie Basin, south Wyoming. Approximately 1000 well logs were used to map the delta lobes and complexes on the Fox Hills shelf and to detail their depositional character, dimensions, and orientation as they autogenically shifted during transit from an inner-shelf to shelf-edge position. The regressive transits of the deltas initiated up to 40 km (25 mi) landward from the preexisting shelf-edge and preserved river and wave-dominated deltaic deposits that thicken and concentrate sand on the outer shelf. Tidally influenced deltas (now outcropping) also occur in localized areas along the paleoshelf edge, probably where wave influence was reduced along invaginated coastal segments. Net sandstone maps of the individual clinothem topsets show that (1) coeval delta lobes exist within each clinothem, suggesting multiple rivers; (2) delta lobes have a likely autogenic compensational stacking pattern; and (3) deltas thicken and storm-wave influence become dominant closer to the shelf edge. Our results support the ideas of (1) predictable increased wave influence and (2) change to strike-elongate architecture as deltas transit the shelf. In addition, along-strike changes in process dominance cause deltaic reservoirs to be highly variable in their orientation, external shape, and internal character. Some process changes are interpreted to be autogenic responses during overall shoreline progradation. The study also provides new data on delta-lobe and delta-complex thicknesses as well as on deltaic coastline versus shelf-edge progradation rates.

Description: Foreland basement-involved structures commonly occur in front of major fold-thrust belts as irregular chains of uplifts. The variation in the map and three-dimensional (3-D) geometries of individual structures, and their mutual spatial and angular relationships, are strongly suggestive of the influence of preexisting basement discontinuities. Three-dimensional experimental models were constructed to determine the function of preexisting frontal and lateral discontinuities in determining the geometry of the structures. The models consisted of two layers, with stiff clay representing the basement and soft clay representing the sedimentary cover. Laser scanning and 3-D surface modeling were used to determine the map geometry to compare the models with examples of natural structures from the Rocky Mountain foreland in Wyoming. Planar discontinuities result in doubly plunging structures terminating against a frontal fault with a linear trace (Sheep Mountain anticline), whereas intersecting fault sets with sharp or curved intersections result in trapdoor geometries (Grass Creek anticline). Opposite-dipping faults result in uplifted blocks with varying relief and orientations of the structures, depending on the relative orientations of the two fault trends. Significant strike-slip faulting along the frontal fault only occurs when the angle between the two fault trends exceeds 30°. Chains of structures show offsets or relay patterns, commonly accompanied by changes in the orientations of adjacent structures. The Sage Creek–Steamboat Butte chains, the Hamilton Dome–Wagonhound anticline chain, the Maverick Springs–Circle Ridge chain, and the Grass Creek–Walker Dome trend in the Rocky Mountain foreland are examples of these configurations. These patterns suggest the influence of preexisting frontal or lateral discontinuities on the trends and locations of structures. Lateral discontinuities are either preexisting, controlling the lateral extent of structures, or form during deformation to accommodate the formation of structures formed along offset frontal faults. Preexisting lateral faults that penetrate the entire basement commonly result in surface lateral faults bounding the surface structures. However, reverse faults in the basement connected by buried lateral faults result in surface structures with overlaps between them. A relay of reverse faults in the basement not connected by lateral faults may develop parallel or oblique structures with transfer zones between them. The mapped geometries of the experimental models, and the orientations of secondary faults, provide predictive analogs that can be used in the interpretation of surface and subsurface structures.

Description: The Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics. Depositional environments were interpreted based on organic geochemical (Rock-Eval pyrolysis, extract analysis, and biomarker distributions) and organic petrological methods. Organic carbon contents range between 1.0 and 32.5 wt. %. The Khatatba shale and coaly shale samples have hydrogen index values in the range of 63 to 261 mg hydrocarbon (HC)/g total organic carbon, with mixed types 2–3 and 3 kerogens. Mean vitrinite reflectance (R o ) between 0.77 and 1.07% is in reasonably good agreement with pyrolysis T max (temperature at maximum of S 2 peak) data (438–459°C). Organic-rich sediments of the Middle Jurassic Khatatba Formation have very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The main generation products are gas with very limited liquid HCs (oil or condensate). Seven shale and coaly shale samples from Khatatba Formation were characterized using gas chromatography (GC) and GC–mass spectrometry techniques. The Khatatba samples are characterized by the predominance of C 14 -C 24 alkanes, a pristane/phytane ratio of less than 2, abundant C 27 regular steranes, and the presence of tricyclic terpanes. These are consistent with the suboxic marine-environment conditions for the Khatatba source rock. Biomarker parameters for these samples generally indicate a mixture of land- as well as marine-derived organic-matter input. The maturity indicators based on C 32 22S/(22S + 22R) homohopane and C 29 20S/(20S + 20R) and ββ/(ββ + αα) sterane ratios reveal that the Khatatba samples are thermally mature and have reached the peak oil-window maturity supporting the R o data.

Description: The petroleum industry is increasingly using geographic information systems (GISs) for mapping and spatial database needs because they are useful for elucidating and exploiting spatial relationships between geologic and geophysical data. However, the petroleum industry, in general, does not exploit the full potential of GIS as an analysis tool. In particular, GIS offers spatial and analytical support for multicriteria evaluation (MCE) methods, which are used to combine data to show areas best fulfilling specific criteria. Petroleum explorations would benefit from an MCE method that is spatial, is flexible for combining heterogeneous data, considers the interpretive nature of the data, is geologically applicable, and is applicable for frontier areas or where little information exists regarding probabilities of the presence of petroleum. This study proposes a GIS-based MCE method for petroleum exploration based on fuzzy logic, which fulfills the previously stated requirements using 16 subcriteria and one constraint combined in tiers to produce a favorability map of potential exploration areas. A case study applied to northern South America, chosen because of its centrality to petroleum exploration, shows potential new exploration areas in the Cretaceous–Paleogene and Miocene–Holocene. The method was validated by comparing the favorability maps of one non–geologic age–specific and of two geologic age–specific favorability maps to known producing fields. We conclude that the method can be applied in an exploration setting and, as such, is applicable for other regions of the world.

Description: Paleogene saline lacustrine carbonate rocks are important fractured reservoirs in the western Qaidam Basin. Core data show that most fractures are small, steeply dipping faults; bedding-plane slip faults; and subvertical opening-mode fractures. Other fractures are diagenetic in origin. Fracture occurrence and abundance patterns are controlled by lithology, bed thickness, and proximity to larger faults. Fractures are generally filled with calcite, gypsum, or glauberite (Na 2 Ca[SO 4 ] 2 ); the degree of fracture filling determines the effectiveness of fractures as fluid conduits and the distribution of high-quality reservoirs. Open fractures not only provide the main pathways for fluid flow, but also enhance the free fluid index and the free fluid saturation measured by nuclear magnetic resonance and determine the potential production rates of tight carbonate reservoirs. The open fractures are parallel to and occur near faults, and many do not coincide with the present-day direction of the maximum horizontal compressive stress.

Description: Successions that characterize the eastern southern Alps have been compared with coeval units drilled in the Alpine foreland (Po and Veneto plains, northern Adriatic Sea). The eastern southern Alps are composed of a carbonate platform-plateau, drowned in the Early Jurassic (Trento platform and plateau); a basin formed in the Early Jurassic (Belluno Basin) and a carbonate platform that lasted from the Jurassic to the Cretaceous (Friuli platform). Integration of stratigraphic and geophysical data illustrates the extensional architecture of the Alpine foreland subsurface. At the beginning of the Jurassic, peritidal successions were widespread everywhere except for the Belluno Basin. A reorganization of the Early Jurassic paleogeography affected the southern Alps around the Sinemurian–Pliensbachian boundary: the Pliensbachian successions were deposited in the central-western areas of the Trento platform whereas, elsewhere in the same platform and in the northern Friuli platform, Pliensbachian units are missing, replaced by an unconformity surface covered by crinoidal sands that have also been found in the subsurface. The Belluno Basin is recognizable in seismic profiles under the Veneto Plain. Southward (northern Adriatic Sea and Po plain), the basin between the Trento and the Friuli platforms, here called the "northern Adriatic Basin," possesses a stratigraphy different from that of the Belluno Basin. The northern Adriatic Basin drowned later, and seismic profiles indicate that it was wider and bounded by groups of small synsedimentary faults instead of the major faults displacing the Belluno Basin. The northern Adriatic Basin can be interpreted as the northeastern extension of the Umbro-Marchean Basin of central Italy.

Description: Observations and hydrothermal experiments were used to derive new information about how clay grain coats inhibit quartz cement and preserve porosity in deeply buried sandstones. Samples of deeply buried, porous sandstones with different types of clay coats were split in two, coats removed from one of each pair of splits, and grain surfaces inspected with scanning electron microscopy. Quartz grains in a fluvial-deltaic sandstone buried to 115°C had no visible authigenic quartz on grain surfaces cleaned of diagenetic chlorite coats, though well-developed overgrowths occurred on nearby, naturally uncoated grains. However, in similar sandstones buried to ≥164°C, quartz-grain surfaces exposed by chlorite-coat removal were covered with small (~5 μm), mainly anhedral, syntaxial quartz overgrowths. Similar overgrowths were observed under various detrital and diagenetic clay coats in porous eolian sandstones buried to temperatures up to 215°C. We conclude that clay coats may retard quartz nucleation at moderate temperatures, but at high temperatures, many coats permit quartz nucleation and preserve porosity by limiting cement growth. To investigate cement growth-limitation mechanisms, samples with coats removed were subjected to quartz-cementing conditions in a hydrothermal reactor. During experiments, the naturally occurring small overgrowths on clay-cleaned grains coalesced and grew, suggesting that clay particles in coats inhibit cement growth by forming barriers to early-overgrowth coalescence. Although the fraction of grain-surface coverage is the primary control on cement inhibition by coats, cement growth–interference textures vary with coat type, providing a mechanism by which coat composition may be a secondary control on inhibitory effectiveness. In deeply buried sandstones, quartz cement can fill significant microporosity within diagenetic chlorite coats, potentially affecting mechanical and petrophysical rock properties.

Description: Quantitative databases storing analog data describing the geometry of sedimentologic features are commonly used to derive input for geostatistical simulations of reservoir sedimentary architecture; however, geometrical information alone is inadequate for the detailed characterization of sedimentary heterogeneity. A relational database storing fluvial architecture data has been developed and populated with literature- and field-derived data from modern rivers and ancient successions. The database scheme characterizes fluvial architecture at three different scales of observation—recording style of internal organization, geometries, and spatial relationships of genetic units—classifying data sets according to controlling factors (e.g., climate type) and context-descriptive characteristics (e.g., river pattern). The database can therefore be filtered on both architectural features and boundary conditions to yield outputs tailored on the system being modeled to generate input to object- and pixel-based stochastic simulations of reservoir architecture. When modeling heterogeneity with stochastic simulations, the choice of input parameters quantifying spatial variation is problematic because of the paucity of primary data and the partial characterization of supposed analogs. This database-driven approach permits the definition of various constraints referring to either genetic units (e.g., architectural elements) or material units (i.e., contiguous volumes of sediment characterized by the same value of a given categorical or discretized variable; e.g., same lithofacies type, clay and silt content, and others), which permit the realistic description of fluvial architecture heterogeneity. Applications of this database approach include the computation of relative dimensional parameters and the generation of auto- and cross-variograms and transition-probability matrices, which are necessary to effectively model spatial complexity.

Description: Determination of the membrane seal capacity of deformation bands is critical for managing geologic reservoirs in porous sandstones. In this study, we have analyzed a cataclastic shear-band network developed in uncemented porous sandstone in Provence, France. Geometrical analyses of the bands show significant differences between three types of bands (single strand, multistrand, and band cluster), sorted by their number of strands, their amount of shear displacement, and their thicknesses. At the microscopic scale, the image-analysis porosities and the grain-size distributions allow definition of three different types of microstructural deformation: damage zone, protocataclastic, and cataclastic. Whereas damage zone and protocataclastic deformations are observed in each type of band, cataclastic strands are observed in clusters and, sometimes, in multistrands. Cataclastic strands are characterized by a porosity reduction of 10 to 25% and a permeability reduction of three to five orders of magnitude compared to the host rock. Field observations of iron hydroxide precipitations around the bands suggest that cataclastic strands were membrane seals to water flow under vadose condition. This study therefore highlights the importance of the degree of cataclasis in shear bands as membrane seals to subsurface fluid flows in sandstone reservoirs.

Description: Dynamic earth models are used to better understand the impact of mantle dynamics on the vertical motion of continents and regional and global sea level change since the Late Cretaceous. A hybrid approach combines inverse and forward models of mantle convection and accounts for the principal contributors to long-term sea level change: the evolving distribution of ocean floor age, dynamic topography in oceanic and continental regions, and the geoid. We infer the relative importance of dynamic versus other factors of sea level change, determine time-dependent patterns of dynamic subsidence and uplift of continents, and derive a sea level curve. We find that both dynamic factors and the evolving distribution of sea floor age are important in controlling sea level. We track the movement of continents over large-scale dynamic topography by consistently mapping between mantle and plate frames of reference, and we find that this movement results in dynamic subsidence and uplift of continents. The amplitude of dynamic topography in continental regions is larger than global sea level in several regions and periods, so that it has controlled regional sea level in North and South America and Australia since the Late Cretaceous, northern Africa and Arabia since the late Eocene, and Southeast Asia in the Oligocene–Miocene. Eastern and southern Africa have experienced dynamic uplift over the last 20 to 30 m.y., whereas Siberia and Australia have experienced Cenozoic tilting. The dominant factor controlling global sea level is a changing oceanic lithosphere production that has resulted in a large amplitude sea level fall since the Late Cretaceous, with dynamic topography offsetting this fall.

Description: Open faults and fractures act as a major control of fluid flow in the subsurface, especially in fine-grained, low-permeability lithologies. These discontinuities commonly form a part of seal bypass systems, which can lead to the failure of hydrocarbon traps, CO 2 geosequestration sites, and waste and injected fluid repositories. We evaluate mesoscale variability in fracture density, morphology and the variability in elastic moduli in the Jurassic Carmel Formation, a proposed seal to the underlying Navajo Sandstone for CO 2 geosequestration. By combining mechanostratigraphic outcrop observations with elastic moduli derived from wireline-log data, we characterize the variability in fracture pattern and morphology with the observed variability in rock strength within this heterolithic top seal. Outcrop inventories of discontinuities show that fracture densities decrease as bed thickness increases and that fracture propagation morphology across lithologic interfaces vary with changing interface type. Dynamic elastic moduli, calculated from wireline-log data, show that Young's modulus ranges by as much as 40 GPa (5,801,510 psi) across depositional interfaces and by an average of 3 GPa (435,113 psi) across the reservoir-seal interface. We expect that the mesoscale changes in rock strength will affect the distributions of localized stress and thereby influence fracture propagation and fluid flow behavior within the seal. These data provide a means to closely tie outcrop observations to those derived from subsurface data and estimates of subsurface rock strength. The characterization of rock strength variability is especially important for modeling the response of caprocks to changing stress conditions associated with increased fluid pressures and will allow for better site screening and subsurface fluid management.

Description: The occurrence of several water crises in India over the years has resulted in the formulation of strategies that promote sustainable development of groundwater resources. For such planning efforts, the evaluation of groundwater recharge zones is a vital component of the water balance equation. Therefore, this study presents a systematic scientific analysis of various morphometric parameters relating to groundwater flow in hard rock terrain. The numerical classification scheme presented herein constitutes an integrated approach that shows how to leverage basic watershed information to evaluate prospective sites and measures at various scales for the purposes of water resources development and management. We have used our morphometric analysis of the Mamundiyar watershed of southern India to demonstrate the use of this classification scheme as a helpful tool in the watershed development planning process. The results of this relative ranking of Mamundiyar subbasins, using various parameters that are ultimately indicative of surficial rock permeability, show the usefulness of this classification scheme in identifying suitable rainfall infiltration sites. Together with an evaluation of the various hydrogeologic conditions in a given basin, this type of numerical classification scheme can be developed and applied to properly identify recharge sites in the planning stages of sustainable watershed development, as well as in already active watersheds, perhaps where extractive industries are working or certain land use practices exist, to evaluate potential relationships between hydrogeologic regimes and these anthropogenic activities.