ALBERT

Description: We use three-dimensional seismic reflection data and new map-based structural restoration methods to define the displacement history and characteristics of a series of tear faults in the deep-water Niger Delta. Deformation in the deep-water Niger Delta is focused mostly within two fold-and-thrust belts that accommodate downdip shortening produced by updip extension on the continental shelf. This shortening is accommodated by a series of thrust sheets that are locally cut by strike-slip faults. Through seismic mapping and interpretation, we resolve these strike-slip faults to be tear faults that share a common detachment level with the thrust faults. Acting in conjunction, these structures have accommodated a north–south gradient in westward-directed shortening. We apply a map-based restoration technique implemented in Gocad to restore an upper stratigraphic horizon of the late Oligocene and use this analysis to calculate slip profiles along the strike-slip faults. The slip magnitudes and directions change abruptly along the lengths of the tear faults as they interact with numerous thrust sheets. The discontinuous nature of these slip profiles reflects the manner in which they have accommodated differential movement between the footwall and hanging-wall blocks of the thrust sheets. In cases for which the relationship between a strike-slip fault and multiple thrust faults is unclear, the recognition of this type of slip profile may distinguish thin-skinned tear faults from more conventional deep-seated, throughgoing strike-slip faults.

Description: Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated. The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density. These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

Description: Interpretation of seismic data from the Sørvestsnaget Basin, southwest Barents Sea, demonstrates gradual middle Eocene basin infilling (from the north) generated by southward-prograding shelf-margin clinoforms. The basin experienced continued accommodation development during the middle Eocene because of differential subsidence caused by the onset of early Eocene sea-floor spreading in the Norwegian-Greenland Sea, faulting, salt movement, and different tectonic activity between the Sørvestsnaget Basin and Veslemøy high. During this time, the margin shows transformation from an initially high-relief margin to a progradation in the final stage. The early stage of progradation is characterized by the establishment of generally oblique clinoform shifts creating a flat shelf-edge trajectory that implies a gentle falling or stable relative sea level and low accommodation-to-sediment supply ratio (〈1) in the topsets. During the early stage of basin development, the high-relief margin, narrow shelf, stable or falling relative sea level, seismicity, and presumably high sedimentation rate caused accumulation of thick and areally extensive deep-water fans. Seismic-scale sandstone injections deform the fans. A fully prograding margin developed when the shelf-to-basin profile lowered, apparently because of increased subsidence of the northern part. This stage of the basin development is generally characterized by the presence of sigmoid clinoform shifts creating an ascending shelf-edge trajectory that is implying steady or rising relative sea level with an accommodation-to-sediment supply ratio of greater than 1, implying sand accumulation on the shelf. This study suggests that some volume of sand was transported into the deep water during relative sea level rise considering the narrow shelf and inferred high rates of sediment supply.

Description: The petroleum trap for the Athabasca oil sands has remained elusive because it was destroyed by flexural loading of the Western Canada Sedimentary Basin during the Late Cretaceous and Paleocene. The original trap extent is preserved because the oil was biodegraded to immobile bitumen as the trap was being charged during the Late Cretaceous. Using well and outcrop data, it is possible to reconstruct the Cretaceous overburden horizons beyond the limit of present-day erosion. Sequential restoration of the reconstructed horizons reveals a megatrap at the top of the Wabiskaw-McMurray reservoir in the Athabasca area at 84 Ma (late Santonian). The megatrap is a four-way anticline with dimensions 285 x 125 km (177 x 78 mi) and maximum amplitude of 60 m (197 ft). The southeastern margin of the anticline shows good conformance to the bitumen edge for 140 km (87 mi). To the northeast of the anticline, bitumen is present in a shallower trap domain in what is interpreted to be an onlap trap onto the Canadian Shield; leakage along the onlap edge is indicated by tarry bitumen outliers preserved in basement rocks farther to the northeast. Peripheral trap domains that lie below the paleospillpoint, in northern, southern, and southwestern Athabasca, and Wabasca, are interpreted to represent a late charge of oil that was trapped by bitumen already emplaced in the anticline and the northeastern onlap trap. This is consistent with kimberlite intrusions containing live bitumen, which indicate that the northern trap domain was charged not before 78 Ma. The trap restoration has been tested using bitumen-water contact well picks. The restored picks fall into groups that are consistent both with the trap domains determined from the top reservoir restoration and the conceptual charge model in which the four-way anticline was filled first, followed by the northeastern onlap trap, and then the peripheral trap domains.

Description: The presence of hydrocarbon-bearing sandstones within the Eocene of the Forties area was first documented in 1985, when a Forties field (Paleocene) development well discovered the Brimmond field. Further hydrocarbons in the Eocene were discovered in the adjacent Maule field in 2009. Reservoir geometry derived from three-dimensional seismic data has provided evidence for both a depositional and a sand injectite origin for the Eocene sandstones. The Brimmond field is located in a deep-water channel complex that extends to the southeast, whereas the Maule field sandstones have the geometry of an injection sheet on the updip margin of the Brimmond channel system with a cone-shape feature emanating from the top of the Forties Sandstone Member (Paleocene). The geometry of the Eocene sandstones in the Maule field indicates that they are intrusive and originated by the fluidization and injection of sand during burial. From seismic and borehole data, it is unclear whether the sand that was injected to form the Maule reservoir was derived from depositional Eocene sandstones or from the underlying Forties Sandstone Member. These two alternatives are tested by comparing the heavy mineral and garnet geochemical characteristics of the injectite sandstones in the Maule field with the depositional sandstones of the Brimmond field and the Forties sandstones of the Forties field. The study revealed significant differences between the sandstones in the Forties field and those of the Maule and Brimmond fields), both in terms of heavy mineral and garnet geochemical data. The Brimmond-Maule and Forties sandstones therefore have different provenances and are genetically unrelated, indicating that the sandstones in the Maule field did not originate by the fluidization of Forties sandstones. By contrast, the provenance characteristics of the depositional Brimmond sandstones are closely comparable with sandstone intrusions in the Maule field. We conclude that the injectites in the Maule field formed by the fluidization of depositional Brimmond sandstones but do not exclude the important function of water from the huge underlying Forties Sandstone Member aquifer as the agent for developing the fluid supply and elevating pore pressure to fluidize and inject the Eocene sand. The study has demonstrated that heavy mineral provenance studies are an effective method of tracing the origin of injected sandstones, which are increasingly being recognized as an important hydrocarbon play.

Description: Organic-carbon–rich shales of the lower Marcellus Formation were deposited at the toe and basinward of a prograding clinothem associated with a Mahantango Formation delta complex centered near Harrisburg, Pennsylvania. Distribution of these organic-carbon–rich shales was influenced by shifts in the delta complex driven by changes in rates of accommodation creation and by a topographically high carbonate bank that formed along the Findlay-Algonquin arch during deposition of the Onondaga Formation. Specifically, we interpret the Union Springs member (Shamokin Member of the Marcellus Formation) and the Onondaga Formation as comprising a single third-order depositional sequence. The Onondaga Formation was deposited in the lowstand to transgressive systems tract, and the Union Springs member was deposited in the transgressive, highstand, and falling-stage systems tract. The regional extent of parasequences, systems tracts, and the interpreted depositional sequence suggest that base-level fluctuations were primarily caused by allogenic forcing—eustasy, climate, or regional thermal uplift or subsidence—instead of basement fault reactivation as argued by previous workers. Paleowater depths in the region of Marcellus Formation black mudrock accumulation were at least 330 ft (100 m) as estimated by differences in strata thickness between the northwestern carbonate bank and basinal facies to the southeast. Geochemical analysis indicates anoxic to euxinic bottom-water conditions. These conditions were supported by a deep, stratified basin with a lack of circulation.

Description: Offshore sequences of volcaniclastic rocks (such as hyaloclastite deposits) are poorly understood in terms of their rock properties and their response to compaction and burial. As petroleum exploration targets offshore volcanic rifted margins worldwide, understanding of volcanic rock properties becomes important both in terms of drilling and how the rocks may behave as seals, reservoirs, or permeability pathways. The Hawaiian Scientific Drilling Project phase II in 2001 obtained a 3 km-(2-mi)-long core of volcanic and volcaniclastic rocks that records the emergence of the largest of the Hawaiian islands. Core recovery of 2945 m (9662 ft) resulted in an unparalleled data set of volcanic and volcaniclastic rocks. Detailed logging, optical petrology, and major element analysis of two sections at depths 1831–1870 and 2530–2597 m (6007–6135 and 8300–8520 ft) are compared to recovered petrophysical logs (gamma ray, resistivity, and P-wave velocity). This study concludes deviation in petrophysical properties does not seem to correlate to changes in grain size or clast sorting, but instead correlates with alteration type (zeolite component) and bulk mineralogy (total olivine phenocryst percentage component). These data sets are important in helping to calibrate well-log responses through hyaloclastite intervals in areas of active petroleum exploration such as the North Atlantic (e.g., Faroe-Shetland Basin, United Kingdom, and Faroe Islands, the Norwegian margin and South Atlantic margins bordering Brazil and Angola).

Description: Predicting the presence and connectivity of reservoir-quality facies in otherwise mud-prone fluvial overbank successions is important because such sand bodies can potentially provide connectivity between larger neighboring sand bodies. This article addresses minor channelized fluvial elements (crevasse-splay and distributary channels) and attempts to predict the connectivity between such sand bodies in two interseam packages of the Upper Permian Rangal Coal Measures of northeastern Australia. Channel-body percent as measured in well logs was 2% in the upper (Aries-Castor) interseam and 17% in the lower (Castor-Pollux) interseam. Well spacing were too great to allow accurate correlation of channel bodies. The Ob River, Siberia, was used as a modern analog to supply planform geometric measurements of splay and distributary channels so that stochastic modeling of channel bodies was possible. The resulting models demonstrated that (1) channel-body connectivity is more uniform between minor distributary channels than between crevasse-splay channels; (2) relatively good connectivity is seen in proximal positions in splays but decreases distally from the source as channel elements diverge; and (3) connectivity tends to be greater down the axis of splays, with more isolated channel bodies occurring at the margins.

Description: Thirty-seven mudstone samples were collected from the uppermost Lower Mudstone Member of the Potrerillos Formation in El Gordo minibasin within La Popa Basin, Mexico. The unit is exposed in a circular pattern at the earth's surface and is intersected by El Gordo diapir in the northeast part of the minibasin. Vitrinite reflectance (R o ) results show that samples along the eastern side of the minibasin (i.e., south of the diapir) are mostly thermally immature to low maturity (R o ranges from 0.53% to 0.64%). Vitrinite values along the southern, western, and northwestern part of the minibasin range between 0.67% and 0.85%. Values of R o immediately northwest of the diapir are the highest, reaching a maximum of 1.44%. The results are consistent with two different possibilities: (1) that the diapir plunges to the northwest, or (2) that a focused high-temperature heat flow existed along just the northwest margin of the diapir. If the plunging diapir interpretation is correct, then the thermally immature area south of the diapir was in a subsalt position, and the high-maturity area northwest of the diapir was in a suprasalt position prior to Tertiary uplift and erosion. If a presumed salt source at depth to the northwest of El Gordo also fed El Papalote diapir, which is located just to the north of El Gordo diapir, then the tabular halokinetic sequences that are found only along the east side of El Papalote may be subsalt features. However, if the diapir is subvertical and the high-maturity values northwest of the diapir are caused by prolonged, high-temperature fluid flow along just the northwestern margin of the diapir, then both of these scenarios are in disagreement with previously published numerical models. This disagreement arises because the models predict that thermal anomalies will extend outward from a diapir a distance roughly 1.5 times the radius of the diapir, but the results reported here show that the anomalous values on one side of the diapir are about two times the radius, whereas they are as much as five times the radius on the other side of the diapir. The results indicate that strata adjacent to salt margins may experience significantly different heat histories adjacent to different margins of diapirs that result in strikingly different diagenetic histories, even at the same depth.

Description: The Molasse Basin represents the northern foreland basin of the Alps. After decades of exploration, it is considered to be mature in terms of hydrocarbon exploration. However, geological evolution and hydrocarbon potential of its imbricated southernmost part (Molasse fold and thrust belt) are still poorly understood. In this study, structural and petroleum systems models are integrated to explore the hydrocarbon potential of the Perwang imbricates in the western part of the Austrian Molasse Basin. The structural model shows that total tectonic shortening in the modeled north–south section is at least 32.3 km (20.1 mi) and provides a realistic input for the petroleum systems model. Formation temperatures show present-day heat flows decreasing toward the south from 60 to 41 mW/m 2 . Maturity data indicate very low paleoheat flows decreasing southward from 43 to 28 mW/m 2 . The higher present-day heat flow probably indicates an increase in heat flow during the Pliocene and Pleistocene. Apart from oil generated below the imbricated zone and captured in autochthonous Molasse rocks in the foreland area, oil stains in the Perwang imbricates and oil-source rock correlations argue for a second migration system based on hydrocarbon generation inside the imbricates. This assumption is supported by the models presented in this study. However, the model-derived low transformation ratios (〈20%) indicate a charge risk. In addition, the success for future exploration strongly depends on the existence of migration conduits along the thrust planes during charge and on potential traps retaining their integrity during recent basin uplift.

Description: This article describes a 250-m (820-ft)-thick upper Eocene deep-water clastic succession. This succession is divided into two reservoir zones: the lower sandstone zone (LSZ) and the upper sandstone zone, separated by a package of pelitic rocks with variable thickness on the order of tens of meters. The application of sequence-stratigraphic methodology allowed the subdivision of this stratigraphic section into third-order systems tracts. The LSZ is characterized by blocky and fining-upward beds on well logs, and includes interbedded shale layers of as much as 10 m (33 ft) thick. This zone reaches a maximum thickness of 150 m (492 ft) and fills a trough at least 4 km (2 mi) wide, underlain by an erosional surface. The lower part of this zone consists of coarse- to medium-grained sandstones with good vertical pressure communication. We interpret this unit as vertically and laterally amalgamated channel-fill deposits of high-density turbidity flows accumulated during late forced regression. The sandstones in the upper part of this trough are dominantly medium to fine grained and display an overall fining-upward trend. We interpret them as laterally amalgamated channel-fill deposits of lower density turbidity flows, relative to the ones in the lower part of the LSZ, accumulated during lowstand to early transgression. The pelitic rocks that separate the two sandstone zones display variable thickness, from 35 to more than 100 m (115–〉328 ft), indistinct seismic facies, and no internal markers on well logs, and consist of muddy diamictites with contorted shale rip-up clasts. This section is interpreted as cohesive debris flows and/or mass-transported slumps accumulated during late transgression. The upper sandstone zone displays a weakly defined blocky well-log signature, where the proportion of sand is higher than 80%, and a jagged well-log signature, where the sand proportion is lower than 60%. The high proportions of sand are associated with a channelized geometry that is well delineated on seismic amplitude maps. Several depositional elements are identified within this zone, including leveed channels, crevasse channels, and splays associated with turbidity flows. This package is interpreted as the product of increased terrigenous sediment supply during highstand normal regression.

Description: Sandstone pressures follow the hydrostatic gradient in Miocene strata of the Mad Dog field, deep-water Gulf of Mexico, whereas pore pressures in the adjacent mudstones track a trend from well to well that can be approximated by the total vertical stress gradient. The sandstone pressures within these strata are everywhere less than the bounding mudstone pore pressures, and the difference between them is proportional to the total vertical stress. The mudstone pressure is predicted from its porosity with an exponential porosity-versus-vertical effective stress relationship, where porosity is interpreted from wireline velocity. Sonic velocities in mudstones bounding the regional sandstones fall within a narrow range throughout the field from which we interpret their vertical effective stresses can be approximated as constant. We show how to predict sandstone and mudstone pore pressure in any offset well at Mad Dog given knowledge of the local total vertical stress. At Mad Dog, the approach is complicated by the extraordinary lateral changes in total vertical stress that are caused by changing bathymetry and the presence or absence of salt. A similar approach can be used in other subsalt fields. We suggest that pore pressures within mudstones can be systematically different from those of the nearby sandstones, and that this difference can be predicted. Well programs must ensure that the borehole pressure is not too low, which results in borehole closure in the mudstone intervals, and not too high, which can result in lost circulation to the reservoir intervals.

Description: The influence of moisture, temperature, coal rank, and differential enthalpy on the methane (CH 4 ) and carbon dioxide (CO 2 ) sorption capacity of coals of different rank has been investigated by using high-pressure sorption isotherms at 303, 318, and 333 K (CH 4 ) and 318, 333, and 348 K (CO 2 ), respectively. The variation of sorption capacity was studied as a function of burial depth of coal seams using the corresponding Langmuir parameters in combination with a geothermal gradient of 0.03 K/m and a normal hydrostatic pressure gradient. Taking the gas content corresponding to 100% gas saturation at maximum burial depth as a reference value, the theoretical CH 4 saturation after the uplift of the coal seam was computed as a function of depth. According to these calculations, the change in sorption capacity caused by changing pressure, temperature conditions during uplift will lead consistently to high saturation values. Therefore, the commonly observed undersaturation of coal seams is most likely related to dismigration (losses into adjacent formations and atmosphere). Finally, we attempt to identify sweet spots for CO 2 -enhanced coalbed methane (CO 2 -ECBM) production. The CO 2 -ECBM is expected to become less effective with increasing depth because the CO 2 -to-CH 4 sorption capacity ratio decreases with increasing temperature and pressure. Furthermore, CO 2 -ECBM efficiency will decrease with increasing maturity because of the highest sorption capacity ratio and affinity difference between CO 2 and CH 4 for low mature coals.

Description: The origin of thermogenic natural gas in the shallow stratigraphy of northeastern Pennsylvania is associated, in part, with interbedded coal identified in numerous outcrops of the Upper Devonian Catskill and Lock Haven Formations. Historically documented and newly identified locations of Upper Devonian coal stringers are shown to be widespread, both laterally across the region and vertically throughout the stratigraphic section of the Catskill and Lock Haven Formations. Coal samples exhibited considerable gas source potential with total organic carbon as high as 44.40% by weight, with a mean of 13.66% for 23 sample locations analyzed. Upper Devonian coal is thermogenically mature; calculated vitrinite reflectances range from 1.25% to 2.89%, with most samples falling within the dry-gas window. Source potential is further supported by gas shows observed while drilling through shallow, identifiable coal horizons, which are at times located within fresh groundwater aquifers. Thermogenic gas detected in area water wells during predrill baseline sampling is determined not only to be naturally occurring, but also common in the region.

Description: The estimated ultimate recovery (EUR) is one of the most significant properties of tight-gas sandstone reservoirs, but it remains difficult to predict. Estimated ultimate recovery is dependent on the success of stimulation by hydraulic fracturing, the existence and connectivity of natural fractures, and as illustrated in this article, the pore structure of the matrix. Here, we analyze the lab measurements that are indicative of the pore structure, and then we predict the effect of pore structure on producibility. We develop a relationship between the EUR of tight-gas sandstones and their petrophysical properties measured by drainage and imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. We use the ratio of residual mercury saturation after mercury withdrawal ( S gr ) to initial mercury saturation ( S gi ), which is the saturation at the start of withdrawal, as a measure of gas likely to be trapped in the matrix during production and, hence, a proxy for EUR. A multitype pore space model is required to explain mercury intrusion capillary pressures in these rocks. Implications of this model are supported by other available laboratory measurements. The model comprises a conventional network model and a treelike pore structure (an acyclic network) that mimic the intergranular and intragranular void spaces, respectively. The notion of the treelike pore structure is introduced here for the first time in the context of tight-gas sandstones. Applying the multitype model to porous plate data, we classify the pore spaces of rocks into intergranular dominant, intermediate, and intragranular dominant. This pore space classification is topological and is not based on scale or size. These classes have progressively less drainage and imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from intragranular porosity than intergranular porosity. Available field data (production logs) corroborate the higher producibility of intervals with intragranular porosity, although the data are not sufficient to eliminate the possible contribution of other factors such as size and shape of the volume contacted by hydraulic fractures or the presence and attributes of natural fractures. The superior recovery of hydrocarbon from intragranular-dominant pore structures is despite its inferior initial production rate.

Description: The Ardath Shale and Scripps Formation exposed along Black’s Beach north of La Jolla, California, record a deep-water channelized slope system of an Eocene forearc basin. The outcrop exposure, which is approximately 100 m (330 ft) high by 1.7 km (~1 mi) long, offers insight into reservoir distribution and connectivity within coarse-grained, confined, deep-water channel systems. To use this outcrop as a quantitative subsurface analog, a detailed two-dimensional lithologic model was constructed from measured sections and interpreted photopanels. Elastic rock properties, including compressional-wave velocity, shear-wave velocity, and density typical of shallow offshore west African reservoirs were used to construct an impedance model. This model was convolved with 15-, 25-, and 50-Hz quadrature-phase Ricker wavelets to generate near- and far-angle stack one-dimensional and two-dimensional synthetic seismic reflection models. Because deep-water lithofacies have distinct amplitude-variation-with-offset behaviors and the interpretation of surfaces is intimately coupled with predicting lithofacies, simple bed interface models of conglomerate, sandstone, interbedded sandstone and mudstone, and muddy sandy debrite were used to build a template for successful interpretation. Interpretation of these forward seismic models demonstrates (1) the limits of and uncertainty associated with the interpretation of seismic data at different frequencies commonly encountered in the exploration, development, and production of deep-water reservoirs; and (2) how the combination of near- and far-angle seismic data can be used to interpret channel-fill lithofacies and improve seismic interpretation. Large-scale channel complex set surfaces with significant impedance contrast (e.g., conglomerate overlying interbedded sandstone and mudstone) are readily interpretable at all frequencies with an increasing vertical error of 5 to 30 m (16 to 98 ft) from 50 to 15 Hz, respectively. Channel and channel complex surfaces can only be accurately mapped on the 50-Hz data, albeit with significant uncertainty. Near- to far-angle stack changes enable the identification of upward-fining, amalgamated, and fine-grained channel-fill lithofacies. Far-angle seismic reflections can provide a more detailed image of boundaries defining channel architecture and reservoir facies distribution.

Description: Numerous oil and gas accumulations exist in the Brooks Range foothills of the National Petroleum Reserve in Alaska (NPRA). We use cores and well logs from 12 abandoned legacy wells at Umiat field, near the southeastern boundary of the NPRA, to characterize the sedimentology and stratigraphy of unconventional shallow frozen reservoirs in sandstones of the Cretaceous (Albian–Cenomanian) Nanushuk Formation. The Nanushuk Formation at Umiat has five facies associations: offshore and prodelta, lower shoreface, upper shoreface, delta front, and delta plain. Three stratigraphically distinct, regionally extensive Nanushuk Formation depositional systems at Umiat contain several potential petroleum reservoirs. The lower Nanushuk Formation, including a reservoir interval known informally as the lower Grandstand, primarily consists of marine mudstone and shoreface sandstones. The middle Nanushuk Formation is dominantly deltaic and contains a second major reservoir interval in the informal upper Grandstand sandstone. Both the upper Grandstand and lower Grandstand are regressive. The transgressive upper Nanushuk Formation contains an additional potential reservoir interval in shoreface sandstones of the informal Ninuluk interval. The primary reservoir intervals at Umiat field are upper shoreface and delta-front sandstones in the upper Grandstand and lower Grandstand, where increased sorting and decreased bioturbation in high-energy depositional environments affect overall permeability and permeability anisotropy.

Description: Multiple techniques are available to construct three-dimensional reservoir models. This study uses comparative analysis to test the impact of applying four commonly used stochastic modeling techniques to capture geologic heterogeneity and fluid-flow behavior in fluvial-dominated deltaic reservoirs of complex facies architecture: (1) sequential indicator simulation; (2) object-based modeling; (3) multiple-point statistics (MPS); and (4) spectral component geologic modeling. A reference for comparison is provided by a high-resolution model of an outcrop analog that captures facies architecture at the scale of parasequences, delta lobes, and facies-association belts. A sparse, pseudosubsurface data set extracted from the reference model is used to condition models constructed using each stochastic reservoir modeling technique. Models constructed using all four algorithms fail to match the facies-association proportions of the reference model because they are conditioned to well data that sample a small, unrepresentative volume of the reservoir. Simulated sweep efficiency is determined by the degree to which the modeling algorithms reproduce two aspects of facies architecture that control sand-body connectivity: (1) the abundance, continuity, and orientation of channelized fluvial sand bodies; and (2) the lateral continuity of barriers to vertical flow associated with flooding surfaces. The MPS algorithm performs best in this regard. However, the static and dynamic performance of the models (as measured against facies-association proportions, facies architecture, and recovery factor of the reference model) is more dependent on the quality and quantity of conditioning data and on the interpreted geologic scenario(s) implicit in the models than on the choice of modeling technique.

Description: The Boat Harbour Formation constitutes the upper part of the Lower Ordovician St. George Group on the Northern Peninsula, western Newfoundland. It ranges in thickness from 140 m (459 ft) at Main Brook to 96 m (315 ft) at Daniel's Harbour. Dolomitization of the carbonate sequence is more pervasive in the lower 30 to 40 m (98 to 131 ft) at Main Brook, whereas at Daniel's Harbour, the section is entirely dolomitized. Petrography suggests that the Boat Harbour Formation has been affected by three phases of dolomitization. The earliest (near surface or synsedimentary) phase is D1 dolomicrite (4–55 μm), which exhibits dull to no luminescence. It commonly occurs as laminae-capping cycles and as breccias in the younger dolomite phases. It has low Sr (228 ± 30 ppm) and an average 18 O value of –6.0 ± 0.8 (Vienna Peedee belemnite [VPDB]) in the Main Brook section but more depleted signatures for 18 O of –8.8 ± 1 (VPDB) and lower Sr contents (45 ± 8 ppm) in the Daniel's Harbour section. The geochemical composition suggests that D1 was developed from fluids of a mixture of meteoric and marine waters. The midburial phase D2 dolomite consists of coarse planar subeuhedral crystals (30–400 μm) that show concentric cathodoluminescence zoning and are also crosscut by microstylolites. Its 18 O values range between –6.6 ± 1.3 (VPDB) at Main Brook and –9.0 ± 0.5 (VPDB) at Daniel's Harbour. This dolomite likely precipitated from fluids that circulated through crustal rocks with progressive burial ( T h value of 114°C ± 11°C and salinity value of 23 ± 1.8 eq. wt. % NaCl). The late-stage D3 dolomite has large and coarse nonplanar crystals (125 μm–7 mm) that exhibit sweeping extinction under crossed polars, which is characteristic of saddle dolomite and also sometimes shows thin brightly luminescent rims. It was likely precipitated during deeper burial in pulses and from hot fluids ( T h values of 148°C ± 19°C and 115°C ± 19.6°C and mean salinities of 23 ± 2 and 22 ± 2 eq. wt. % NaCl at Main Brook and Daniel's Harbour, respectively). This is also supported by their relatively more depleted 18 O (–11.1 ± 1.2 and –12.3 ± 1.4 VPDB, respectively) and low Sr contents (88 ± 36 and 38 ± 5.9 ppm, respectively). Porosity in the Boat Harbour Formation is mainly associated with the midburial D2 dolomite. Intercrystalline porosity is the dominant type, and it ranges in the formation from less than 1% to 8% at Main Brook and from 7% to 12% at Daniel's Harbour. Vugs are less common but are associated with D3 dolomite. The porous zone in the formation at Main Brook starts approximately 10 to 15 m (33 to 49 ft) below the lower Boat Harbour disconformity and extends down to the lower formational boundary, whereas porous zones in the formation at Daniel's Harbour are indiscriminately distributed throughout the section.

Description: The style of faulting in offshore Louisiana, Gulf of Mexico, is characterized by short, arcuate regional and counterregional growth faults, which commonly form complex transfer zones above shallow, Miocene level salt bodies. South Timbalier Block 54 (ST54) constitutes one such area where a basinward-dipping regional and a landward-dipping counterregional growth fault form a convergent transfer zone. Structural interpretation using three-dimensional (3-D) seismic and well data reveals that the eastern and western flanks of the structure contain salt in the footwalls of the main regional and counterregional faults. The salt rises to a much shallower stratigraphic level in the central part of the transfer zone, forming a symmetric salt diapir. Secondary antithetic and synthetic faults adjacent to the two main faults and extending into the transfer zone accommodate slip between the main faults. Kinematic restoration of a series of north–south-trending cross sections across the structure show that upslope evacuation of salt is the result of sediment loading and growth fault movement, and the location of the transfer zone is possibly controlled by the allochthonous salt. The entire area is characterized by down-to-basin movement, with the major regional and counterregional faults displaying footwall and hanging-wall fixed deformation, respectively. The presence of the crestal graben above the salt high and the timing of maximum salt evacuation from the flanks suggest that active or reactive diapirism occurred during part of the deformation history. A 3-D structural model using depth-converted horizons, balanced cross sections, and well tops accurately portrays the subsurface structure. Understanding the evolution of the structure in ST54 provides insight on similar structures in other areas in offshore Louisiana and the relationship between salt evacuation and transfer zone development.

Description: Three-dimensional (3-D) seismic volumes from southeast Brazil, southeast Japan, and borehole data from the Ocean Drilling and Integrated Ocean Drilling Programs are used to demonstrate a new method to distinguish mass-transport deposits (MTDs) from confining hemipelagites, quantify MTDs internal architecture, and assess their reservoir potential or seal competence—the contrast, directionality, energy (CDE) method. The CDE values extracted from 3-D seismic data can be tied to any ground-truthed property of strata regardless of their depositional history, age, and lithology. The application of the CDE method is, however, dependent on seismic-data acquisition parameters and selected processing sequences and should be independently applied to different seismic volumes. Borehole data indicate contrast (C) to reflect MTDs lithological heterogeneity and degree of disaggregation, which increase proportionally to the absolute value of C. More uniform values of P-wave velocity ( V p ) and peak shear strength are recorded in strata with lower contrast. Directionality (D) relates to the existence of syn- or postdepositional fabric such as compressional ridges, imbricated strata or faults. Energy (E) relates to the acoustic impedance of strata, with high-amplitude reflections correlating with strata with higher shear strength, i.e., high V p and shear-wave velocity ( V s ) values, or with abrupt contrasts in density (bright spots). This work shows that distinct values of C, D, and E reflect variable degrees of vertical and horizontal connectivity in strata and, consequently, their seal and reservoir potential. The CDE values are thus subdivided in nine classes, which are represented in ternary plots to cover the full spectrum of MTDs and any confining strata. As a result, the data in this article confirm that lower seal competence, and higher reservoir potential, is recorded in strata with large D or moderate CDE values.

Description: In the central Appalachians, fluid inclusion microthermometry and oxygen and carbon stable isotope analysis vein minerals from the Middle Devonian shale section show that fluid conditions (pressure, temperature, and composition) are constantly changing during deformation and vary spatially across the fold-thrust belt. The earliest fractures in the region formed prior to folding, early during the Alleghenian orogeny as the rocks were buried into the oil generation window. They contain minerals that contain degraded hydrocarbon inclusions and basinal brine inclusions. During multiple vein reopening events, later mineral stages contain increasingly more mature hydrocarbon fluids. Late quartz mineralization is pervasive and typically contains the high-temperature brine inclusions. The vein opening history is related to changes in fluid connectivity associated with (1) burial by over-thrusting and/or syntectonic depositional loading and/or (2) folding during uplift and erosion. Initial fracture formation and fluid-trapping depths range from 3.5 km (2.2 mi) in the Plateau province and along the Appalachian structural front to 4.5 to 5.0 km (2.8 to 3.1 mi) in the Valley and Ridge province. Late-stage fracturing and fracture reopening is related to the maximum syntectonic burial, which varies from about 4 km (2.5 mi) in the Plateau to over 11 km (6.8 mi) in the Valley and Ridge. Fractures in the Valley and Ridge and western Pennsylvania Plateau provinces cannot be categorized into the simple $${\mathrm{J}}_{1}$$ and $${\mathrm{J}}_{2}$$ classification model. Burial history modeling indicates that fractures forming within and near the end of the oil window were NNW- and NW-striking, not ENE-striking, $${\mathrm{J}}_{1}$$ fractures.

Description: Two of the major joint-driving mechanisms are joint-normal stretching and poroelastic shrinkage, and these lead to joint sets commonly associated with structural bending and natural hydraulic fracturing, respectively. Regardless of joint-driving mechanism, joint infilling is a nonhomogeneous Poisson process in the presence of stress shadows. Through probability modeling, we show that in all cases joint spacing is best fit with gamma distributions. The shape parameter of the best-fit gamma distribution to joint-spacing data is a quantitative means to assess the extent of saturation, which is represented in a new parameter, the joint-saturation ratio (JSR). To test the utility of JSR, we call upon published structural bending joint data (Elk Basin, Lilstock, and Rives plate-bending experiment). The shape parameters for these well-developed structural bending joints are equal to around three, corresponding to a JSR of approximately 30%. Using the same analysis on the spacing of natural hydraulic fractures collected from outcrops in the gas-prone Devonian sections of the Appalachian Basin, we find that natural hydraulic fractures differ in two aspects from structural bending joints. First, the joint spacing is proportional to bed thickness in bedded rocks but not in gas shale sections. Second, the joint saturation of natural hydraulic fractures is generally lower than in well-developed structural bending joints. Thus, the JSR is a means to distinguish the joint-driving mechanism and to represent joint-saturation level independent of bed thickness effects. It can be used to distinguish natural fractures from drilling-induced fractures and to improve the fracture-network modeling.

Description: We report on subsurface deformation features measured from recently acquired core and image logs from the Marcellus Formation in north-central Pennsylvania, supplemented with data collected from Valley and Ridge outcrop. The subsurface data are from an area that bridges a gap in existing published data between outcrop in the Valley and Ridge province of Pennsylvania and the relatively undeformed outcrop exposed on the Appalachian Plateau of New York. We find one distinct set of vertical veins that strike orthogonal to Appalachian Plateau fold axes and an associated set of low-angle reverse faults and stylolites that strike parallel to fold axes. As the trend of the fold axes changes around the Pennsylvania salient, the trend of associated mesostructures changes to maintain kinematic compatibility with the shortening direction change along the salient. These structures are interpreted to support a single, although possibly protracted, strain event during Alleghanian deformation, as opposed to multiple events previously interpreted to occur in different regions and stratigraphic levels within the fold belt. The veins are associated with clusters of bedding-plane slip surfaces, which are found at distinct mechanical stratigraphic positions where the competence contrast between shale and stiff limestone units is greatest. We interpret this association to indicate that bed parallel-shear within detachment zones provides the sufficient driving force required to nucleate vertical veins, and the decoupling of beds accommodates extension orthogonal to the shortening direction. Although these veins are oriented orthogonal to the present-day maximum principal horizontal stress, they remain propped open by crystalline cements. Homogenization temperatures of fluid inclusions trapped in the veins, combined with one-dimensional burial and thermal history models, suggest that the pervasive vein set formed during the Late Pennsylvanian–Permian during the Alleghanian orogeny.

Description: Natural fractures have long been suspected as a factor in production from shale reservoirs because gas and oil production commonly exceeds the rates expected from low-porosity and low-permeability shale host rock. Many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with hydraulic-fracture stimulation have been ascribed to natural fracture reactivation. Here we review previous work, and present new core and outcrop data from 18 shale plays that reveal common types of shale fractures and their mineralization, orientation, and size patterns. A wide range of shales have a common suite of types and configurations of fractures: those at high angle to bedding, faults, bed-parallel fractures, early compacted fractures, and fractures associated with concretions. These fractures differ markedly in their prevalence and arrangement within each shale play, however, constituting different fracture stratigraphies—differences that depend on interface and mechanical properties governed by depositional, diagenetic, and structural setting. Several mechanisms may act independently or in combination to cause fracture growth, including differential compaction, local and regional stress changes associated with tectonic events, strain accommodation around large structures, catagenesis, and uplift. Fracture systems in shales are heterogeneous; they can enhance or detract from producibility, augment or reduce rock strength and the propensity to interact with hydraulic-fracture stimulation. Burial history and fracture diagenesis influence fracture attributes and may provide more information for fracture prediction than is commonly appreciated. The role of microfractures in production from shale is currently poorly understood yet potentially critical; we identify a need for further work in this field and on the role of natural fractures generally.

Description: The sedimentologic and tectonic histories of clastic cap rocks and their inherent mechanical properties control the nature of permeable fractures within them. The migration of fluid through mm- to cm-scale fracture networks can result in focused fluid flow allowing hydrocarbon production from unconventional reservoirs or compromising the seal integrity of fluid traps. To understand the nature and distribution of subsurface fluid-flow pathways through fracture networks in cap-rock seals we examine four exhumed Paleozoic and Mesozoic seal analogs in Utah. We combine these outcrop analyses with subsidence analysis, paleoloading histories, and rock-strength testing data in modified Mohr–Coulomb–Griffith analyses to evaluate the effects of differential stress and rock type on fracture mode. Relative to the underlying sandstone reservoirs, all four seal types are low-permeability, heterolithic sequences that show mineralized hydraulic-extension fractures, extensional-shear fractures, and shear fractures. Burial-history models suggest that the cap-rock seal analogs reached a maximum burial depth 〉4 km (2.5 mi) and experienced a lithostatic load of up to 110 MPa (15,954 psi). Median tensile strength from indirect mechanical tests ranges from 2.3 MPa (334 psi) in siltstone to 11.5 MPa (1668 psi) in calcareous shale. Analysis of the pore-fluid factor ( $${\lambda }_{\mathrm{v}}={P}_{\mathrm{f}}/{\sigma }_{\mathrm{v}}$$ ) through time shows changes in the expected failure mode (extensional shear or hydraulic extension), and that failure mode depends on a combination of mechanical rock properties and differential stress. As expected with increasing lithostatic load, the amount of overpressure that is required to induce failure increases but is also lithology dependent.

Description: Faults and fractures within the well-exposed Lower Jurassic Cleveland Ironstone and Whitby Mudstone Formations may provide insights into the tectonic history of gas-prospective, Mississippian shale in northern England. Subvertical opening mode fractures occur throughout the Cleveland Basin. Bed-parallel fractures, some of which contain blocky calcite fills, occur preferentially within well-bedded, clay-rich mudstones of the Cleveland Ironstone and Whitby Mudstone Formations at Jet Wyke and Port Mulgrave. Subvertical fractures display abutting or curving-parallel relationships with under- and overlying bed-parallel fractures. Together, these observations suggest that bed-parallel fractures, at times, acted as free surfaces. Some bed-parallel fractures curve toward and branch from calcite-filled fault slip surfaces, indicating that bed-parallel fracturing and normal faulting were synchronous, occurring within a regional stress field with vertical maximum principal stress. This apparent paradox can be explained by normal compaction, followed by cementation and coupling between pore pressure and minimum horizontal stress driven by poroelastic deformation or incipient slip along critically stressed normal faults, causing elevation of horizontal stress in excess of the vertical stress within clay-rich units. Propagation of bed-parallel fractures was enhanced by dilatational strains adjacent to normal fault planes. Bed-parallel fractures have not been observed within more $${\mathrm{SiO}}_{2}$$ -rich units at the top of the Whitby Mudstone Formation at Whitby East Cliff, or within well-bedded, clay-rich shale at Saltwick Nab. This observation is consistent with the lack of normal faulting at Saltwick Nab, and the Whitby Mudstone Formation having been drained by structural and/or stratigraphical juxtaposition against permeable Middle Jurassic sandstones at both these localities.

Description: Outcrops of the middle Eagle Ford Formation in south-central Texas reveal well-developed joint networks in subhorizontal competent carbonate (chalk) beds and less well developed networks in interlayered incompetent calcareous mudrock beds. Northeast-striking bed-perpendicular joints in competent beds have the longest trace lengths and are abutted by northwest-striking joints. All observed joints terminate vertically in incompetent beds. Normal faults are common but less abundant than joints; dominantly dip north, northwest, or southeast; and are abutted by the joint sets and, thus, predated jointing. The faults cut multiple competent and incompetent beds, providing vertical connectivity across mechanical layering. Products of hybrid and shear failure, the dip of these faults is steep through competent beds and moderate through incompetent beds, resulting in refracted fault profiles with dilation and calcite precipitation along steep segments. Fluid inclusions in fault zone calcite commonly contain liquid hydrocarbons. Rare two-phase fluid inclusions homogenized between about (1) 40 and 58°C, and (2) 90 and 100°C, suggesting trapping of aqueous fluids at elevated temperatures and depths on the order of 2 km (6562 ft). Fluid inclusion and stable isotope geochemistry analyses suggest that faults transmitted externally derived fluids. These faults likely formed at depths equivalent to portions of the present-day oil and gas production from the Eagle Ford play in south Texas. Faults connect across layering and provide pathways for vertical fluid movement within the Eagle Ford Formation, in contrast to vertically restricted joints that produce bed-parallel fracture permeability. These observations elucidate natural fractures and induced hydraulic fracturing within the Eagle Ford Formation.

Description: Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Description: We investigate the hydraulic fracturing process by analysis of the associated microseismicity. In part 1, we recognized double-couple and hybrid microseismic events and their fault plane orientations. Critical stress (instability) and stress inversion techniques were used to assess fracture activation conditions. In part 2, we apply results from the tensile source model to investigate how activated faults relate to the stress state and geologic setting. We assess potential mechanisms for induced microseismicity including leakoff and diffuse pressurized fracture network flow, stress shadowing adjacent to large parent hydraulic fractures, and crack tip stress perturbations. Data are from the Mississippian Barnett Shale, Texas, and include microseismic events from sequential pumping stages in two adjacent horizontal wells that were recorded in two downhole monitor wells, as well as operations, wellbore-derived stress, and natural fracture data. Results point to activation of inclined faults whose orientation is dominantly northeast–southwest and vertical north–south faults. The activation stress states for a range of modeling scenarios show stress rotation, decreased mean stress, and increased deviatoric stress. This stress state cannot be explained by sidewall leakoff in the stress shadow region adjacent to hydrofractures, but is consistent with hybrid and shear activation obliquely ahead of pressurized fractures. Information about hydrofracture evolution and operationally related dynamic stress change is obscured by geomechanical heterogeneity that is likely geologic in nature. The most compelling observation is that the most highly misoriented microseismic faults occur in the same vicinity as a carbonate-dominated submarine fan feature that was previously expected to act as a minor fracture barrier.

Description: Shale is one of the most common rock types, with a rich and complex variety of failure structures in the Earth’s continental crust. In this paper, a synopsis of these structures including joints, pressure-solution seams and cleavages, faults, and shear bands is presented. First, two main categories, sharp and diffuse structures, each of which has subclasses based on its displacement discontinuity type including shear, compaction, and dilation are defined. Then, natural field examples are provided for each class as well as complex structural assemblages that include more than one type of failure-mode structures. Finally, the significances of these assemblages in terms of how older structures may influence later natural and man-made fractures and how they may interact in terms of fluid and gas flow are briefly discussed.

Description: As the importance of self-sourcing reservoirs continues to increase, it is more important than ever to evaluate rock properties that contribute to productive wells. It has become increasingly evident that in order to maximize potential returns, an integrated approach to shale play characterization is necessary to identify productive areas. Numerous criteria exist to characterize ultra-low permeability shale reservoirs and their associated resource potential; these include measures of organic richness, thermal maturity, lithologic heterogeneity, and formation brittleness. The latter, a descriptor of the geomechanical rock properties, can play a significant role in overall well performance and is commonly a key productivity driver. Thus, an understanding of the mechanical properties of the target section is fundamental for high-grading prospective areas, well placement design, and hydraulic stimulation effectiveness. Observation of geomechanical attributes extracted from seismic data in the Eagle Ford Shale captures changing mechanical properties indicative of strike-oriented lithologic facies changes. Using acoustic logs, core, and three-dimensional seismic data, we assess the mechanical contrast between Eagle Ford facies units and their effect on well performance. We use three-dimensional seismic data to map the structure and facies distribution in an area where identification of reservoir facies is a major challenge to development drilling. In this study, we demonstrate how Young’s modulus and density, inverted from three-dimensional seismic data, prove as effective discriminators for the purpose of identifying and mapping facies changes and establishing the hydraulically fracturable limits in areas where effective stimulation and proppant embedment in the formation during pressure drawdown is a concern. The result is an interpretation that identifies and uses the mechanical changes from three-dimensional seismic data attributes associated with the brittle carbonate-rich Eagle Ford facies to predict both the reservoirs hydraulically fracturable limits as well as the variability in well performance associated with proppant embedment. The changes in mechanical properties of the Eagle Ford facies are important in high-grading productive intervals in these ultra-low permeability rocks. We believe we can apply this method to other shale reservoirs where rock mechanics may play an important role.

Description: The increasing exploration and production in unconventional resource plays in the past decade has been accompanied by a greater need for understanding the effectiveness of multistage hydraulic fracturing programs, particularly in long (〉1500 m or 5000 ft) subhorizontal boreholes (laterals). Traditional (analytical) analysis techniques for estimating the size and orientation of fractures induced by fluid injection typically result in predictions of relatively long and planar extension (mode I) bi-wing fractures, which may not be representative of natural systems. Although these traditional approaches offer the advantage of rapid analysis, neglect of key features of the natural system (e.g., realistic mechanical stratigraphy, pre-existing natural faults and fractures, and heterogeneity of in situ stresses) may render results unrealistic for planning, executing, and interpreting multimillion-dollar hydraulic stimulation programs. Numerical geomechanical modeling provides a means of including key aspects of natural complexity in simulations of hydraulic fracturing. In this study, we present the results of two-dimensional finite element modeling of fluid-injection-induced rock deformation that combines a coupled stress–pore pressure analysis with a continuum damage-mechanics-based constitutive relationship. The models include both the natural mechanical stratigraphic variability as well as the in situ stress-state anisotropy, and permit tracking of the temporal and spatial development of shear and tensile permanent strains that develop in response to fluid injection. Our results show that simple, long planar fractures are unlikely to be induced in most mechanically layered natural systems under typical in situ stress conditions. Analyses that assume this type of fracture geometry may significantly overestimate the reach of hydraulically induced fractures and/or effectively stimulated rock volume.

Description: We investigate the geomechanical behavior of hydraulic-fracturing-induced microseismicity. Microseismic events are commonly used to discern stimulation patterns and hydraulic fracture evolution; however, techniques beyond fracture mapping are required to explain the mechanisms of microseismicity. In this series we present an approach to combine seismological and geomechanical techniques to investigate how microseismicity relates to propagating hydrofractures as well as existing natural fractures and faults. Part 1 describes the first analysis step, which is to characterize the microseismic events by their source parameters, focal mechanisms, and fault-plane orientations. These parameters are used to determine the mechanical conditions responsible for activation of discrete populations or subpopulations of microseismic events that then can be interpreted in their geological and operational context. First, we compare microseismic fault-plane populations from a Mississippian Barnett Shale, Texas data set that are determined using a traditional double-couple model (shear only) with a tensile source model (hybrid events), which may be more suitable for hydraulic fracturing conditions. Second, we employ a new method to distinguish fault planes from auxiliary planes using iterative stress inversion and critical stress (instability) selection criteria. The result is an enhanced microseismic characterization that includes geomechanical parameters such as slip tendency and local activation stress state during the operation. Using this approach on the Barnett Shale data, two microseismic fault sets are resolved: an inclined northeast–southwest set with dominant shear, and a vertical north–south set with more hybrid behavior. The results are used in part 2 to further investigate the heterogeneity of the stimulations and to compare models for microseismic activation.

Description: The long and narrow island Hopen exposes mainly the Late Triassic De Geerdalen Formation, which is time-equivalent to the upper part of the Snadd Formation: a proven hydrocarbon reservoir in the Barents Sea. The De Geerdalen Formation on Hopen has previously been superficially described in a regional context and has been suggested to represent tidally dominated, paralic coastal plain deposits. Recent sedimentological investigations explain subtle but important variability in sedimentary architecture pointing to different depositional processes. Tidal and fluvial channel deposits show equal size and geometry, but are distinguishable by virtue of characteristic internal heterogeneities and structures. Lateral correlation along the island suggests that the channel-sandstone deposits are positioned at different stratigraphic levels and that they were deposited in a dynamic, paralic depositional environment. Based on the interpreted gross depositional environments, sequence-stratigraphic intervals are defined; these can be used as a basis for correlation. The scales of depositional architectures at Hopen are found to be directly relatable to subsurface seismic data from the upper part of the Snadd Formation in the Barents Sea, and, through regionally correlatable maximum flooding surfaces, these depositional elements can be put in a stratigraphic context. Additionally, some of the channel features demonstrated at Hopen are of comparable size and geometry to plan-view channel bodies extracted from seismic attribute mapping in the Snadd Formation. Detailed sedimentological studies undertaken on Hopen explain these depositional elements in more detail than can be resolved in subsurface data, with implications for future exploration efforts in the Barents Sea.

Description: A probabilistic method has been devised to assess the geologic realism of subsurface well-to-well correlations that entail the lateral tracing of geologic bodies across well arrays with constant spacing. Models of geo-body correlability (based on the ratio between correlatable and penetrated geo-bodies) are obtained from total probabilities of penetration and correlation, which are themselves dependent on the distribution of lateral extent of the geo-body type. Employing outcrop-analog data to constrain the width distribution of the geo-bodies, it is possible to generate a model that describes realistic well-to-well correlation patterns for given types of depositional systems. This type of correlability model can be applied for checking the quality of correlation-based subsurface interpretations by assessing their geologic realism as compared with one or more suitable outcrop analogs. The approach is illustrated by generating total-probability curves that refer to fluvial channel complexes and that are categorized on the basis of outcrop-analog classifications (e.g., braided system, system with 20% net-to-gross), employing information from a large fluvial geo-body database, Fluvial Architecture Knowledge Transfer System (FAKTS), which stores information relating to fluvial architecture. From these total-probability functions, values can be drawn to adapt the correlability models to any well-array spacing. The method has been specifically applied to rank three published alternative interpretations of a stratigraphic interval of the Travis Peak Formation (Texas), previously interpreted as a braided fluvial depositional system, in terms of realism of correlation patterns as compared to (1) all analogs recorded in FAKTS and considered suitable for large-scale architectural characterization, and (2) a subset of them including only systems interpreted as braided.

Description: A normal-fault network from Milne Point, Alaska, is investigated focusing on characterizing geometry, displacement, strain, and different fault interactions. The network, constrained from three-dimensional seismic reflection data, comprises two generations of faults: Cenozoic north-northeast–trending faults and Jurassic west-northwest–trending faults, which highly compartmentalize Upper Triassic to Lower Cretaceous reservoirs. The west-northwest–trending faults are influenced by a similarly oriented underlying structural grain. This influence is characterized by increases in throw on several faults, strain localization, reorientation of faults and an increase in linkage maturity. Reconstructing fault plane geometries and mapping spatial variations in throw identified key characteristic features in their interactions and reactivation of pre-existing structures. Faults are divided into isolated, abutting, and splaying faults. Isolated faults exhibit a range of displacement profiles depending on the degree of restriction at fault tips. Fault splays accommodate step-like decreases in throw along larger main faults with a throw maximum at the intersection with the main fault. Throw profiles of abutting faults are divided into two groups: early stage abutting faults with throw minima at both the isolated and abutting tips, and developed abutting faults with throw maxima near the abutting tip. Developed abutting faults accumulate throw after initial abutment, locally reactivating and transferring throw onto the pre-existing fault. Two abutting faults can link kinematically by reactivating a segment of the pre-existing fault forming a trailing fault. The motion sense of the trailing fault can be synthetic or antithetic to the reactivated pre-existing fault, producing increases or decreases in the throw of the pre-existing fault, respectively.

Description: Our work on the dark pelitic sediments of the Polish Carpathians and eastern Alps shows that these Jurassic through Lower Cretaceous sediments owe their organic content to a combination of global processes, such as climatic changes and changes to the carbonate compensation depth (CCD), and local controls, such as basin morphology, input of terrestrial organic material, and local volcanic activity. These sediments developed in basins both floored by oceanic crust as well as within the continental crust (North European platform). Our data show that these anoxic or poorly oxygenated deposits (average total organic carbon [TOC] value is around 2.5 wt. %) were laid down in the individual basins at different times, from the Late Jurassic to the Barremian and almost continuously up to the early Cenomanian, a period of 30 to 50 m.y., and their thickness reached hundreds of meters. This long time span made it impossible to distinguish precisely the known Aptian and Albian oceanic anoxic events (OAE). Our data show that sedimentation of dark organic-rich deposits was not only controlled by global events such as climatic and CCD changes, but also by local ones as a result of differences in their basin morphology and development, input of land-plant detritus, and local volcanic activity. As an example of the anoxic succession, a detailed description of the black sediments of the proto-Silesian basin is presented. Some of these anoxic shales were buried to a depth of a few thousand meters during the folding and overthrusting movements. We propose that these shales could represent a unique shale-oil and shale-gas resource in an intensely structured basin.

Description: We analyze fracture-density variations in subsurface fault-damage zones in two distinct geologic environments, adjacent to faults in the granitic SSC reservoir and adjacent to faults in arkosic sandstones near the San Andreas fault in central California. These damage zones are similar in terms of width, peak fracture or fault (FF) density, and the rate of FF density decay with distance from the main fault. Seismic images from the SSC reservoir exhibit a large basement master fault associated with 27 seismically resolvable second-order faults. A maximum of 5 to 6 FF/m (1.5 to 1.8 FF/ft) are observed in the 50 to 80 m (164 to 262 ft) wide damage zones associated with second-order faults that are identified in image logs from four wells. Damage zones associated with second-order faults immediately southwest of the San Andreas Fault are also interpreted using image logs from the San Andreas Fault Observatory at Depth (SAFOD) borehole. These damage zones are also 50–80 m wide (164 to 262 ft) with peak FF density of 2.5 to 6 FF/m (0.8 to 1.8 FF/ft). The FF density in damage zones observed in both the study areas is found to decay with distance according to a power law $$F={F}_{0}{r}^{-n}$$ . The fault constant $${F}_{0}$$ is the FF density at unit distance from the fault, which is about 10–30 FF/m (3.1–9.1 FF/ft) in the SSC reservoir and 6–17 FF/m (1.8–5.2 FF/ft) in the arkose. The decay rate $$n$$ ranges from 0.68 to 1.06 in the SSC reservoir, and from 0.4 to 0.75 in the arkosic section. This quantification of damage-zone attributes can facilitate the incorporation of the geometry and properties of damage zones in reservoir flow simulation models.

Description: Tracing petroleum migration pathways is essential for predicting petroleum occurrence and reducing exploration risks associated with hydrocarbon charge, but a difficult task because of rapid lateral and vertical facies changes in lacustrine basins. An integration of geological, geophysical, and geochemical analysis is employed to investigate the origin of crude oil, the carrier-bed architecture, and migration pathways from source to trap in the JX1-1 oil field, Liaodong Bay subbasin, Bohai Bay Basin. Detailed geochemical studies suggest that three potential source-rock intervals ( $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ , $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ , and $${\mathrm{E}}_{3}{\mathrm{d}}_{3}$$ ) exist in the Liaodong Bay subbasin, and crude oil in the JX1-1 field was derived from the $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ and $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ source rocks. The carrier beds from $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ and $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ source rocks to the trap were characterized using geophysical data. The fan-delta sandstone in the $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ Member has an immediate contact with $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ source rock and served as dominant conduit for the expulsion and migration of oil generated from $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ source rock. The $${\mathrm{E}}_{3}{\mathrm{d}}_{3}$$ braided-delta sandstones overlying the $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ source rock served as dominant conduit for $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ -sourced oil. The focusing of petroleum migration pathways and the merge of migration pathways in $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ and $${\mathrm{E}}_{3}{\mathrm{d}}_{3}$$ sandstones account for the accumulation of the JX1-1 field and the mixing of $${\mathrm{E}}_{2}{\mathrm{s}}_{3}$$ - and $${\mathrm{E}}_{2}{\mathrm{s}}_{1}$$ -sourced oil in the field. This study suggests that the distribution of permeable sandstones and their stratigraphic contact with the source rocks are key for petroleum migration and occurrence, and integration of geophysical, geological, and geochemical studies provide an effective way to trace petroleum migration pathways.

Description: We present a new method to determine the total dissolved solids (TDS) concentration and the stable isotope composition of drill-core-derived Porewater in oil sands reservoirs of northeastern Alberta, Canada. The technique described here uses two end-member mixing relationships between the stable isotope compositions of drilling fluids and formation waters from mechanically extracted porewater samples to calculate the formation water TDS, $${\delta }^{2}\mathrm{H}$$ , and $${\delta }^{18}\mathrm{O}$$ values. Analysis of water samples extracted directly from McMurray Formation drill core provides an inexpensive and robust advance in the ability to characterize the properties of reservoir pore waters that can be widely deployed because of the ubiquity of drill-core sampling. Porewater data from three oil sands wells from different locations within the Athabasca region are presented in this study. Water derived from these wells had TDS values of 860 to 45,000 mg/L, $${\delta }^{2}\mathrm{H}$$ values of –172 to –149, and $${\delta }^{18}\mathrm{O}$$ values of –22.4 to –19.3. These values are consistent with regional trends in formation water salinity and stable isotope compositions, and illustrate the wide range of TDS values that can be found in McMurray Formation waters. The ability to characterize aqueous fluids within bitumen-saturated reservoirs is a new development that enables measurement of aqueous fluid properties that is not easily obtained by other sampling means. This methodology provides a tool to understand the origin and movement of reservoir water related to natural groundwater flow, or to anthropogenic influence by steam injection. Novel in situ extraction technologies that use electromagnetic heating systems may also benefit from detailed characterization of aqueous reservoir fluids to accurately determine the properties of the reservoir porewater.

Description: Understanding the factors controlling the development of accommodation above collapsing salt diapirs and their influence on reservoir distribution is critical in reducing exploration risk in salt-influenced sedimentary basins. In this study, we use an integrated subsurface data set (three-dimensional and two-dimensional seismic reflection, wire-line-log, core, and biostratigraphic data) from the Upper Jurassic of the Cod terrace, Norwegian North Sea, to understand the influence of rifting on accommodation creation and shallow-marine deposition during the initial-stage collapse of salt diapirs. We demonstrate that rifting resulted in the rise and fall of salt diapirs, and the formation of supra-diapir minibasin-style depocenters that became sites for deposition and preservation of up to 500 m (1640 ft) thick net-transgressive shallow-marine sandstone reservoirs. Maximum thickness is recorded in the axis of minibasins with a reduction in thickness of up to 65% noted on their flanks. The stratigraphic architecture of individual minibasins is variable. Proximal-to-distal facies variations from shoreface to offshore shelf and commensurate changes in reservoir quality occur over scales larger than individual minibasins. These deposits contain large sand volumes, and are not confined to areas of localized sandstone subcrop. In combination, these features suggest that the minibasins formed a linked network supplied by regional sediment-routing systems. The results of this study provide a new tectono-stratigraphic model for prediction of reservoir presence, thickness, and continuity in diapir-collapse minibasins along salt walls in the Central North Sea, and in other less mature, data-poor basins where reservoirs have been identified in depocenters above salt walls.

Description: By using recently acquired three-dimensional seismic data, a seismic-based sediment provenance analysis was conducted in the late Paleogene sequence of the western slope of the Bozhong sag, Bohai Bay Basin, where the main depositional center was between the Shaleitian uplift and the Shijiutuo uplift. Three styles of sediment-transport pathways were identified in the study area, including sediment transport via (1) faulted troughs, (2) incised valleys, and (3) structural transfer zones. The Paleogene deposits in the study area were primarily controlled by the faulted-trough pathways, which are northeast–southwest oriented in between different northeast–southwest-trending faults with sediments derived primarily from the Shaleitian uplift. The sediments to the east of the Shaleitian uplift were interpreted to have sourced via relatively long-distance transportation and deposited along the northeast–southwest-trending faulted troughs, forming a deltaic sediment belt. In contrast, sediments derived from the Shijiutuo uplift, which were transported by the incised-valley pathways and deposited in the southern margin of the uplift, formed proximal fan-deltas. The depositional systems in the study area are characterized by the coupling of source–faulted-trough pathway–deltaic–lacustrine deposits in the eastern margin of the Shaleitian uplift and that of source–incised-valley-pathway–fan-deltaic–lacustrine deposits near the southern margin of the Shijiutuo uplift. The proposed spatial distribution of the sand bodies extends the distribution range for potential reservoir sand bodies beyond the currently exploration area. This work may serve as a useful reference for sedimentary provenance analysis in other types of sedimentary basins.

Description: A new stable isotope approach was used to determine the total dissolved solids concentration and stable isotope composition for oil sands drill core extracted porewater at the Suncor–Firebag oil sands field in northeastern Alberta, Canada. A stable isotope mixing approach was used to correct for contamination by drilling fluids in the porewater samples. The mean isotopic compositions of oxygen ( $${\delta }^{18}\mathrm{O}$$ ) and hydrogen ( $${\delta }^{2}\mathrm{H}$$ ) in water for fluid samples from 12 wells at Firebag were –20.5 ± 1.4 and –157 ± 11, respectively. The mean total dissolved solids (TDS) concentration of the reservoir formation water in 12 sampled wells was 1100 ± 400 mg/L (1). These results suggest that the McMurray Formation water at Firebag is primarily derived from Holocene groundwater recharge, and that the water within the bitumen reservoir is similar to groundwater well samples obtained within the McMurray Formation at Firebag. The results obtained in this study are consistent with regional trends and previously proposed local hydrogeological flow conditions.

Description: The Eau Claire Formation of the midwestern United States was evaluated for its potential use as a confining unit (seal) overlying a sandstone reservoir to securely store injected $${\mathrm{CO}}_{2}$$ . This evaluation included: (1) lithofacies composition and distribution, (2) capillary entry pressure analysis, and (3) fluid- and fracture-pressure analysis. The regional distribution of lithofacies in the Eau Claire was evaluated by examination of core and log data from selected wells across the study area. Log data were used to define electro-lithofacies, which are spatially variable and represent a mixture of shale, siltstone, sandstone, limestone, and dolomite. Because of the significant variation in lithofacies and the complex spatial distribution, the entire interval should be considered in evaluating the seal capacity of the unit at a given locality. Mercury-injection capillary pressure (MICP) data were obtained on 17 samples of Eau Claire lithofacies ranging from muddy shale to sand/silt to evaluate the potential for capillary entry of fluids into the pore system of the lithofacies of the unit. Interpretation of these data indicated capillary failure of the muddy shale lithofacies is unlikely. However, many of the MICP samples contain millimeter-scale silt/sand interbeds, which would probably allow $${\mathrm{CO}}_{2}$$ entry but, because these beds commonly have very limited lateral continuity, they are very unlikely to provide pathways for large-scale $${\mathrm{CO}}_{2}$$ leakage through the interval. Evaluation of structural settings, lithostatic and existing formation aquifer pressures in the Eau Claire, in conjunction with the height of $${\mathrm{CO}}_{2}$$ columns stored in the underlying Mount Simon Sandstone (Cambrian), suggest that fluid pressures induced by a static buoyant $${\mathrm{CO}}_{2}$$ plume are unlikely to induce fractures in the formation. However, elevation of the aquifer pressure during injection may be capable of creating fractures within the unit.

Description: Hydraulic fracture stimulation (HFS) of unconventional oil and gas reservoirs is of public concern with respect to fugitive gas emissions, fracture height growth, induced seismicity, and groundwater quality changes. We evaluate the potential pathways of fugitive gas seepage during stimulation, in production, and after abandonment; we conclude that the quality of the casing installations is the major concern with respect to future gas migration. The pathway outside the casing is of particular concern as it likely leads to many wells leaking natural gas from thin intermediate-depth gas zones rather than from the deeper target reservoirs. These paths must be understood, likely cases identified, and the probability of leakage mitigated by methods such as casing perforation and squeeze, expanding packers of long life, and induced leakoff into saline aquifers. HFS itself appears not to be a significant risk, with two exceptions. These occur during the high-pressure stage of HFS when (1) legacy well casings are intersected by fracturing fluids and when (2) these fluids pressurize nearby offset wells that have not been shut in, particularly offset wells in the same formation that are surrounded by a region of pressure depletion in which the horizontal stresses are also diminished. This paper focuses on the issue of gas migration from deeper than the surface casing that occurs outside the casing caused by geomechanical processes associated with cement shrinkage, and we review the origin of the gas pulses recorded in noise logs, landowner wells, and surface-casing vents.

Description: Assessing the production potential of shale gas can be assisted by constructing a simple, physics-based model for the productivity of individual wells. We adopt the simplest plausible physical model: one-dimensional pressure diffusion from a cuboid region with the effective area of hydrofractures as base and the length of horizontal well as height. We formulate a nonlinear initial boundary value problem for transient flow of real gas that may sorb on the rock and solve it numerically. In principle, solutions of this problem depend on several parameters, but in practice within a given gas field, all but two can be fixed at typical values, providing a nearly universal curve for which only the appropriate scales of time in production and cumulative production need to be determined for each well. The scaling curve has the property that production rate declines as one over the square root of time until the well starts to be pressure depleted, and later it declines exponentially. We show that this simple model provides a surprisingly accurate description of gas extraction from 8305 horizontal wells in the United States’ oldest shale play, the Barnett Shale. Good agreement exists with the scaling theory for 2133 horizontal wells in which production started to decline exponentially in less than 10 yr. We provide upper and lower bounds on the time in production and original gas in place. NOMENCLATURE Symbols and dimensions of key quantities Symbol SI dimensions Field dimensions $$c$$ –compressibility $${\mathrm{Pa}}^{-1}$$ μ cip $$d$$ –half-distance between hydrofractures m ft $$D$$ –production decline coefficient $$k$$ –permeability $${\mathrm{m}}^{2}$$ darcy $$K$$ –partitioning coefficient $$m$$ –gas pseudopressure $$\mathrm{Pa}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ $${\mathrm{psi}}^{2}/\mathrm{cp}$$ $$\mathfrak{m}$$ –cumulative produced mass kg ton $$\mathcal{M}$$ –Original gas in place kg ton $$M$$ –molecular weight kmol lbmol $$H$$ –formation thickness m ft $$p$$ –pressure Pa psi $$q$$ –volumetric flow rate $${\mathrm{m}}^{3}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ bbl/d $$Q$$ –volumetric cumulative production $${\mathrm{m}}^{3}$$ bbl $$R$$ —universal gas constant J/kmol-K psi- $${\mathrm{ft}}^{3}/\mathrm{lb}$$ -mol $$\mathrm{RF}$$ –recovery factor $$S$$ –saturation $$t$$ –time in production s month, y $$T$$ –temperature K °F, °C $$\widehat{v}$$ –specific volume $${\mathrm{m}}^{3}/\mathrm{kg}$$ $${\mathrm{ft}}^{3}/\mathrm{lbm}$$ $$\mathbf{\boldsymbol{y}}$$ –molar composition $$Z$$ –compressibility factor $$\alpha $$ –hydraulic diffusivity $${\mathrm{m}}^{2}\hbox{ \hspace{0.17em} }{\mathrm{s}}^{-1}$$ $${\mathrm{ft}}^{2}/\mathrm{y}$$ $$\kappa $$ –dimensionless constant for gas production in square root phase $$\mathcal{K}$$ –dimensional constant for gas production in square root phase $$\mathrm{kg}/\sqrt{\mathrm{s}}$$ $$\mathrm{ton}/\sqrt{\hbox{ month }}$$ $$\mu $$ –gas viscosity Pa s cp $$\rho $$ –density $$\mathrm{kg}\hbox{ \hspace{0.17em} }{\mathrm{m}}^{-3}$$ $$\mathrm{lbm}/{\mathrm{ft}}^{3}$$ $$\tau $$ –time to interference s y $$\phi $$ –porosity Subscripts and Superscripts Symbol Meaning $$a$$ adsorbed $$f$$ (hydro)fracture $$g$$ gas $$i$$ initial $$L$$ Langmuir $$ST$$ stock tank conditions $$w$$ water $$wc$$ connate water ~ dimensionless specific 0 reference or standard conditions

Description: This paper explores some basic economics of the climate change issue and how government response may impact the petroleum industry. Possible economic aspects are addressed by examining past and projected fossil fuel production numbers, calculating their resulting emissions, and then projecting how regulations or taxes might affect energy prices and production. Nine medium to major petroleum companies, which do business in the USA, are currently factoring in some kind of carbon emission restrictions into their long-range business plans. A driver for these plans is that the vast majority of countries, including the world’s largest $${\mathrm{CO}}_{2}$$ emitters, have formally agreed to limit their $${\mathrm{CO}}_{2}$$ emissions to avoid a 2°C (3.6°F) rise in global temperatures. Because there is no agreement yet on a set number of allowable emissions, this paper utilizes estimated carbon budgets from one paper, Meinshausen et al. ( 2009 ). Some pertinent results derived herein are the following: 1) oil and natural gas only comprise 33.3% of potential $${\mathrm{CO}}_{2}$$ emissions from fossil fuels; 2) under a $$\sim 50\%$$ probability scenario of exceeding 2°C (3.6°F), all proven reserves of oil and natural gas (as of 2012) could be consumed, whereas only 56% could be utilized with continued coal consumption. To demonstrate how a market approach might limit carbon emissions, a simple model shows how an annually increasing carbon tax affects the relative price of fossil fuels and alternative energy. The objective of this paper is to present arguments that there are economic reasons for American Association of Petroleum Geologists (AAPG) to address the issue of climate change.

Description: Geological sequestration of $${\mathrm{CO}}_{2}$$ for enhanced oil recovery (EOR) has been in use for decades, but it now represents a potentially economical method of mitigating anthropogenic $${\mathrm{CO}}_{2}$$ output. However, current understanding of the interaction between injected $${\mathrm{CO}}_{2}$$ and the reservoir rock is limited and prevents accurate estimation of reservoir $${\mathrm{CO}}_{2}$$ capacity. Delineating the diagenesis of the reservoir is useful in predicting post- $${\mathrm{CO}}_{2}$$ injection changes in reservoir porosity and permeability. The Albian Donovan Sand member of the Rodessa Formation, Citronelle Field, Alabama, is the subject of an ongoing Department of Energy $${\mathrm{CO}}_{2}$$ -EOR suitability study. The arkosic Donovan Sand is highly heterogeneous, containing conglomeratic intervals, low to extensive poikilotopic calcite cement, loose to tight grain packing, and low 〈1% to high (5%) porosity (primary and secondary) observed in thin section. It forms the basal members of laterally discontinuous upward-fining parasequences that define a marine to brackish to fluvial delta system. The diagenesis of the Donovan Sand occurred in five stages: 1) pre-burial and compaction–formation of extensive calcite cement; 2) partial dissolution of calcite cement and framework feldspars; 3) secondary calcite cementation, localized dolomitization, and calcite and anhydrite concretion formation; 4) hydrocarbon charge; and 5) pyrobitumen development. Primary porosity is dominant, but substantial secondary porosity was formed during stage 2. Following injection of $${\mathrm{CO}}_{2}$$ , water injection and oil and gas production rates dropped below modeled values. We propose that the $${\mathrm{CO}}_{2}$$ injection dissolved calcite cement proximal to the injection well and reprecipitated it nearby with the effect of reducing porosity and/or permeability.

Description: Detailed stratigraphic and paleogeographic analyses of data from 72 boreholes for the Middle Jurassic intermontane fluvial-lacustrine coal-bearing sequences were conducted in the Yuqia coalfield of the northern Qaidam Basin, northwestern China. Three third-order sequences lasting in total ca. 10.6 m.y., and an internal lowstand systems tract (LST), transgressive systems tract (TST), highstand systems tract (HST), and falling-stage systems tract (FSST) have been identified. A series of sequence-specific paleogeographic maps have been constructed based on the contours of lithological parameters. The paleogeographic units include alluvial fan-braided (meandering) fluvial plain, upper delta plain, lower delta plain, subaqueous delta, shore-shallow lake, and deep lake. The preferred sites of coal accumulation are interdelta bays, upper delta plains, lower delta plains, and fluvial back swamps. The sequence stratigraphic and sedimentological analysis of the Middle Jurassic coal-bearing measures of the Yuqia coalfield provides a basis for a comprehensive coal accumulation model that involves a six-period evolution from the LST, early TST, late TST, early HST, late HST to FSST. The major coal seams were accumulated in the early and late TST of the sequences S1 and S2. These results are of practical significance for coal resources exploration and enhance geological effects of prospecting engineering in the northern Qaidam Basin.

Description: Forward seismic modeling of outcrop analogs has been used to characterize the seismic expression of clinoforms in different deltaic depositional environments, and thus constrain uncertainty in interpretation of intra-reservoir clinoforms imaged in seismic data from the Troll field, Norwegian North Sea. Three outcrop analogs from the Cretaceous Western Interior seaway, United States, were studied to quantify the geometry, distribution, and lithologic character of clinoforms in fluvial-dominated and mixed-influence deltaic deposits. Outcrop-derived geometric data were calibrated to sedimentological and petrophysical data from the Krossfjord and Fensfjord Formations in the Troll field, and then used to create a suite of forward seismic models for comparison with real seismic reflection data from the Troll field. Clinoforms were imaged in the forward seismic models in which they were (1) spaced wider than the tuning thickness (〉10 m [〉33 ft]); (2) marked by pronounced interfingering of facies associations with different acoustic properties; and/or (3) lined by relatively thick (〉50 cm [〉20 in.]) carbonate-cemented layers. However, where clinothems are thinner than the vertical resolution limit of seismic data, destructive interference occurred creating misleading geometrical relationships. Furthermore, our ability to image clinoforms is dependent on (1) the frequency of the seismic wavelet; (2) the overburden velocity; and/or (3) the acoustic impedance contrast at the boundary between the overburden and the clinoform-bearing target. The established methodology has allowed characterization of deltaic clinoformal architectures in reservoir seismic data from the Troll field, and has facilitated a more robust interpretation by bridging the critical gap in resolution between well and seismic data.

Description: With increasing exploration maturity, reserve growth is becoming an increasingly important component of petroleum resources worldwide. The U.S. Geological Survey has studied reserve-growth models for United States and foreign petroliferous basins for nearly two decades and has developed several reserve-growth forecast methodologies. However, no reserve-growth research has been carried out on Chinese basins, and it is not clear how much reserve growth contributes to the total petroleum resources of China. This paper uses the Bohai Bay basin, the largest petroleum basin in China, as a case study of reserve growth for Chinese basins. Of the 278 oil fields in the basin, 168 fields are chosen to develop the model using the modified Arrington method, and 121 fields are selected to build the model using the group-growth method. The results show that the cumulative growth factors (CGFs) calculated by these two methods are 2.41 and 2.44, respectively, in the 37-yr period after the first significant reserve-reporting year in the Bohai Bay basin. Reserve growth for global basins could be classified into four models, that is, the lowest growth (CGF 〈 1.5), low-growth (CGF 1.5–2.5), medium-growth (CGF 2.5–4.5) and high-growth (CGF 〉 4.5) models in light of their CGFs. The low-growth model fits for the oil fields in the Bohai Bay basin.

Description: Hydrous-pyrolysis experiments at 360°C (680°F) for 72 h were conducted on 53 humic coals representing ranks from lignite through anthracite to determine the upper maturity limit for hydrocarbon-gas generation from their kerogen and associated bitumen (i.e., primary gas generation). These experimental conditions are below those needed for oil cracking to ensure that generated gas was not derived from the decomposition of expelled oil generated from some of the coals (i.e., secondary gas generation). Experimental results showed that generation of hydrocarbon gas ends before a vitrinite reflectance $$({\mathrm{R}}_{\mathrm{o}})$$ of 2.0%. This reflectance is equivalent to Rock-Eval maximum-yield temperature $$({T}_{\mathrm{max}})$$ and hydrogen indices (HIs) of 555°C (1031°F) and 35 mg/g total organic carbon (TOC), respectively. At these maturity levels, essentially no soluble bitumen is present in the coals before or after hydrous pyrolysis. The equivalent kerogen atomic H/C ratio is 0.50 at the primary gas-generation limit and indicates that no alkyl moieties are remaining to source hydrocarbon gases. The convergence of atomic H/C ratios of type-II and -I kerogen to this same value at a reflectance of $$2.0\%{\mathrm{R}}_{\mathrm{o}}$$ indicates that the primary gas-generation limits for humic coal and type-III kerogen also apply to oil-prone kerogen. Although gas generation from source rocks does not exceed vitrinite reflectance values greater than $$2.0\%{\mathrm{R}}_{\mathrm{o}}$$ , trapped hydrocarbon gases can remain stable at higher reflectance values. Distinguishing trapped gas from generated gas in hydrous-pyrolysis experiments is readily determined by $${\delta }^{2}\mathrm{H}$$ of the hydrocarbon gases when a $$^{2}\mathrm{H}$$ -depleted water is used in the experiments. Water serves as a source of hydrogen in hydrous pyrolysis and, as a result, the use of $$^{2}\mathrm{H}$$ -depleted water is reflected in the generated gases but not pre-existing trapped gases.

Description: The Woodbine and Eagle Ford Groups of the southwestern East Texas basin compose an emerging play, which has generated considerable interest because of its potential for new hydrocarbon production from both sandstone and mudrock reservoirs. However, the play’s stratigraphic and depositional relations are complex and directly relate to the play’s exploration challenges. Productive Woodbine and Eagle Ford (sub-Clarksville) sandstones intertongue with a poorly defined, subregional mudrock-dominated interval that thins southwestward toward the San Marcos arch. We propose dividing this succession into two intervals: (1) the Lower unit, a high-gamma-ray unit at the base of this mudrock succession that is inferred to be equivalent to the Maness Shale of the Washita Group and to part of the lower Eagle Ford Group on the San Marcos arch, and (2) an Upper unit, a basinward-thickening zone of consistently lower gamma-ray-log facies inferred to be equivalent to the Woodbine Group, Pepper Shale, and the Eagle Ford Group of the East Texas basin. Because the Cenomanian–Turonian boundary occurs within the Eagle Ford Group of the East Texas basin and the lower Eagle Ford section of the San Marcos arch, most of the Maness-through-Eagle Ford succession exists as a much-thinned section on the arch. Basinwide integration of the Woodbine sequence-stratigraphic framework shows that the number of fourth-order sequences in the unit decreases westward from 14 in the basin axis to no more than 9 in the most active part of the Eaglebine play because of their systematic depositional pinch out approaching the western basin margin. The Eagle Ford Group consists of three fourth-order sequences capped by the sub-Clarksville sandstones that accumulated after the major late Cenomanian–early Turonian flooding event recorded by a basinwide transgressive systems tract (TST) at the base of the unit. Depositional systems of the Woodbine Group vary within the study area, even between stratigraphically adjacent systems. On-shelf siliciclastic systems include fluvial-dominated-delta; incised-valley-fill fluvial and nearshore-marine; and wave-dominated-delta deposits.

Description: We measured the permeability of 30 samples extracted from 6 sets of compaction bands and the adjacent host rocks of the Jurassic aeolian Aztec Sandstone exposed in the Valley of Fire State Park in Nevada using core flooding experiments. The results show that the permeability within the high-angle compaction bands (three sets) is consistently three orders of magnitude lower than that of the host rocks. For the bed-parallel compaction bands, the measured permeability reduction is about half an order to three orders of magnitude for two sets of bands, and there is no detected permeability reduction for the samples from one set. For the samples that show permeability reduction within high-angle and bed-parallel compaction bands, the results are generally consistent with the data estimated from two-dimensional segmented image analyses in previous studies. Permeability of the samples used in the laboratory experiments was also obtained numerically based on three-dimensional tomographic images scanned from micro-samples and lattice-Boltzmann flow simulations. In addition, backscatter electron images (BEI) and energy dispersive spectroscopy images (EDSI) of thin sections were used to estimate the clay content inside and outside the bands. Large differences exist between the lab-based and image-based permeability and porosity measurements of compaction bands and host rocks. Possible factors causing these differences are different sample sizes and heterogeneities within the host rocks, calibration on the image segmentation, and incomplete characterization of clay minerals and fines migration during lab-based experiments. Given the wide range of permeability reductions within compaction bands of different orientations by different investigators, their impact on fluid flow should be evaluated case by case, one should consider their dimensions and distributions.

Description: Subsurface pressures strongly influence the migration and trapping of hydrocarbons and impact the safety and efficiency of drilling operations. The pore pressure field of the northern Gulf of Mexico (GOM) was analyzed at 1000-ft (305-m) depth intervals from 2500 to 17,500 ft (762 to 5334 m) below the sea floor. Two variables were mapped: 12,976 initial hydrocarbon reservoir pressure gradient values and 43,276 observations on drilling fluid (mud) weight. Because of the acute importance of assessing estimate uncertainty, ordinary kriging was employed, providing explicit evaluations of confidence surrounding mapped values. Expected values and confidence intervals for the distribution of both variables were estimated by $$9\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{mi}}^{2}$$ ( $$23.3\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{km}}^{2}$$ ) grid cells across the GOM for each of the 15 depth intervals. Estimation variances were also used to clip each map to specific extents, within which a uniform minimum threshold of certainty was exceeded. Characteristic of young basins with high sedimentation rates, mean pore pressure exceeded hydrostatic pressure throughout the GOM. Four provinces of internally consistent pressure regimes were defined: three south of Louisiana and one off the Texas coast. They reflect geologic controls on pressure arising from regional patterns of sedimentation and the resultant timing and geometry of salt tectonism. One GOM-wide (shallow) vertical transition in the pressure field was found in the mud weight data, and a second vertical transition (deep) occurred in both variables. Hot spot analysis was also applied to identify specific contiguous areas of abnormally high or low rates of change in pressure gradient and mud weight between depth-adjacent intervals.

Description: As one of the six subbasins in the lacustrine Bohai Bay basin, the Jizhong subbasin is characterized by a dominance of the petroleum reserves located in buried-hill traps of Paleozoic and Proterozoic marine carbonates, particularly the latter. This paper documents the revitalization of exploration of the buried-hill play and discusses other play fairways not previously considered through use of case studies. Discovery of the largest field, Renqiu field, in 1975 led to the establishment of the buried-hill play. In this play, oil derived from the Paleogene lacustrine source rocks charged into and accumulated in the underlying Proterozoic marine carbonate reservoirs. A number of buried-hill fields were discovered within a time span of ca. 10 yr in the subbasin. With more and more large buried-hill structures at depths of less than 5000 m (〈16,400 ft) being drilled, the annual reserve addition showed a rapid decline until 2006. The application of new technologies including reprocessing of merged three-dimensional seismic data, improved logging, and testing techniques, together with innovative exploration ideas, made it possible to revitalize the buried-hill play. The exploration success lies with the focus change from targeting the conventional shallow to moderately buried hills to the unconventional buried-hill pools, which include deeply buried hilltop, hillslope, and intrahill pools. Case studies of one conventional buried-hill field (Renqiu field) and three unconventional buried-hill fields (Chang-3, Wengu-3, and Niudong-1 fields), together with modern geological investigations, indicate that there still exists significant exploration potential for the buried-hill play in the Jizhong subbasin. The potential largely lies with the unconventional buried hills. The Baxian, Wuqing, and Baoding depressions are favorable fairways for the deeply buried hill pools, represented by the Niudong-1 field. The Wenan slope is the favorable fairway for the intrahill pools, represented by the Chang-3 and Wengu-3 fields.

Description: Total dissolved solids (TDS) concentrations of 258 Lower Cretaceous McMurray Formation water samples in the Athabasca oil sands region (54 to 58°N and 110 to 114°W) were mapped using published data from recent government reports and environmental impact assessments. McMurray Formation waters varied from nonsaline (240 mg/L) to brine (279,000 mg/L) with a regional trend of high salinity water approximately following the partial dissolution front of the Devonian Prairie Evaporite Formation. The simplest hydrogeological explanation for the observed formation water salinity data is that Devonian aquifers are locally connected to the McMurray Formation via conduits in the sub-Cretaceous karst system in the region overlying the partial dissolution front of the Prairie Evaporite Formation. The driving force for upward formation water flow is provided by the Pleistocene glaciation events that reversed the regional Devonian flow system over the past 2 m.y. in the Athabasca region. This study demonstrates that a detailed approach to hydrogeological assessment is required to elucidate TDS concentrations in McMurray Formation waters at an individual lease-area scale. The observed heterogeneity in formation water TDS and the potential for present day upward flow has implications for both mining and in situ oil sands resource development.

Description: This study estimates reservoir quality and free-gas storage capacity of the Barnett Shale in the main natural-gas producing area of the Fort Worth basin by mapping log-derived thickness, porosity, and porosity-feet. In the Barnett Shale, the density porosity (DPHI) log curve is a very useful tool to quantitatively assess shale gas resources, and gamma-ray (GR) and neutron porosity log curves are important factors in identifying the shale gas reservoir. The key data were digital logs from 146 wells selected based on the availability of GR and density log curves, log quality, and good spatial distribution. The Barnett Shale pay zone was determined on the basis of (1) DPHI 〉5%, (2) high GR values (commonly 〉~90 API units), (3) no significant intercalated carbonate-rich beds, and (4) individual pay zones being thick enough to be commercially successful for the current design of horizontal wells. In the study area, the Barnett Shale pay zone varies from about 165 ft (50 m) to 420 ft (128 m) in thickness (H). Average DPHI values of individual wells for the pay zone vary from 8.5 to 14.0%. Porosity-feet maps of the pay zone show that areas of high DPHI-H values coincide with areas of high natural gas production, indicating that log-derived porosity-feet maps are a good method for evaluating reservoir quality and assessing natural gas resource in the Barnett Shale play. A limitation to this method is shown in the northwestern corner of the study area, which is located in the liquids-rich window with lower thermal maturity.

Description: We use sediment ages and mercury (Hg) concentrations to estimate past and future concentrations in the South River, Virginia, where Hg was released between 1930 and 1950 from a manufacturing process related to nylon production. In a previous study, along a 40 km (25 mi) reach, samples were collected from 26 of 54 fine-grained deposits that formed in the lee of large wood obstructions in the channel and analyzed for grain size, Hg concentration, and organic content. We also obtained radiometric dates from six deposits. To create a history that reflects the full concentration distribution (which contains concentrations as high as 900 mg/kg [900 ppm]), here, we treat the deposits as a single reservoir exchanging contaminated sediments with the overlying water column, and assume that the total sediment mass in storage and the distribution of sediment ages are time invariant. We use reservoir theory to reconstruct the annual history of Hg concentration on suspended sediment using data from our previous study and new results presented here. Many different reconstructed histories fit our data. To constrain results, we use information from a well-preserved core (and our estimate of the total mass of Hg stored in 2007) to specify the years associated with the peak concentration of 900 mg/kg. Our results indicate that around 850 kg (1874 lb) of Hg was stored in the deposits between 1955 and 1961, compared to only 80 kg (176 lb) today. Simulations of future Hg remediation suggest that 100-yr timescales will be needed for the South River to remove Hg-contaminated sediments from the channel perimeter through natural processes.

Description: SONAR, historical and aerial photographs, and vibracoring were used to assess the type and thickness distribution of sediments impounded by Gold Ray Dam on the Rogue River in southern Oregon. From these data, a volume of about 400,000 cubic yards ( $$\sim 306,000\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ) of sediment was determined for the inundated area of the reservoir. Overall, sediment volumes in the impounded part of the reservoir were less than expected. There are three possibilities that may explain the perceived absence of sediment: (1) the gradient of the Rogue River in this stretch is less, and therefore sediment yields are less; (2) the extraction of gravels and/or other impediments upstream decreased the availability of sediments delivered into the reservoir; and/or (3) sediment was deposited by a prograding delta that filled in the inundated area of the floodplain upstream from Gold Ray Dam. The amount of sediment deposited on this inundated floodplain may have been as much as 1,800,000 cubic yards ( $$1,380,000\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ), bringing the total amount of sediment impounded by Gold Ray Dam to $$\sim 2,200,000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{cubic}$$ yards ( $$\sim 1,700,000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ ). Applied sedimentology is not only vital to developing a depositional model for the filling of a reservoir, but also providing insights into depositional and erosional changes that will occur upon the removal of a dam. In particular, the processes of delta formation, reoccupation of abandoned channels, and avulsion are paramount in determining sediment accumulation and distribution in reservoirs.

Description: Diagenesis significantly impacts mudstone lithofacies. Processes operating to control diagenetic pathways in mudstones are poorly known compared to analogous processes occurring in other sedimentary rocks. Selected organic-carbon-rich mudstones, from the Kimmeridge Clay and Monterey Formations, have been investigated to determine how varying starting compositions influence diagenesis. The sampled Kimmeridge Clay Formation mudstones are organized into thin homogenous beds, composed mainly of siliciclastic detritus, with some constituents derived from water-column production (e.g., coccoliths, S-depleted type-II kerogen, as much as 52.6% total organic carbon [TOC]) and others from diagenesis (e.g., pyrite, carbonate, and kaolinite). The sampled Monterey Formation mudstones are organized into thin beds that exhibit pelleted wavy lamination, and are predominantly composed of production-derived components including diatoms, coccoliths, and foraminifera, in addition to type-IIS kerogen (as much as 16.5% TOC), and apatite and silica cements. During early burial of the studied Kimmeridge Clay Formation mudstones, the availability of detrital Fe(III) and reactive clay minerals caused carbonate- and silicate-buffering reactions to operate effectively and the pore waters to be Fe(II) rich. These conditions led to pyrite, iron-poor carbonates, and kaolinite cements precipitating, preserved organic carbon being S-depleted, and sweet hydrocarbons being generated. In contrast, during the diagenesis of the sampled Monterey Formation mudstones, sulfide oxidation, coupled with opal dissolution and the reduced availability of both Fe(III) and reactive siliciclastic detritus, meant that the pore waters were poorly buffered and locally acidic. These conditions resulted in local carbonate dissolution, apatite and silica cements precipitation, natural kerogen sulfurization, and sour hydrocarbons generation. Differences in mud composition at deposition significantly influence subsequent diagenesis. These differences impact their source rock attributes and mechanical properties.

Description: During the Alleghenian Orogeny, Upper Silurian–Pennsylvanian sediments were deformed by occasional gently dipping planar forethrusts and abundant, large, steeply dipping kink bands that extend down to the Silurian Syracuse Salt decollement. As the internal bedding dip within the kink bands is frequently steep, kink bands are poorly imaged in seismic reflection data. Therefore, they can have the appearance of steep reverse faults; however, geosteering data indicate that where these structures intersect the wellbore, they are folds, not faults. Kink bands occur on a range of scales, and their upward extent is controlled by a series of detachment levels, including at the organic-rich Marcellus and Geneseo Shales; a hierarchy of kink bands is therefore recognized. The detachment levels were sites of kink band reflection, resulting in upward converging pairs of kink bands that formed pop-down structures that protruded into the underlying salt. The dips of the thrusts and kink bands calculated from seismic interpretation fit well with theoretical models and published empirical descriptions: reverse structures dipping at less than 45° are thrusts, those with dip angles over 45° are kink bands. Areas of thick, primary salt are dominated by large anticlines, with their hinterlandward flanks defined by kink bands that extend to the present-day topographic surface. The structures may have initiated as sinusoidal folds, which became increasingly asymmetrical as they developed. The recognition of this style of deformation can improve the accuracy of horizontal well placement and has implications for reservoir permeability and integrity.

Description: Changes in elemental chemistry have been used to define stratigraphic correlations between wellbores in petroleum basins. Few publications, however, relate defined chemical stratigraphy to physical correlations, and none have been found that do so in fluvial systems. Here, chemostratigraphy is applied to Permian fluvial sediments within the Beaufort Group of the Karoo Basin in South Africa, and a correlation between three logged sections is defined. This correlation is tested against physically determined chronostratigraphic correlations achieved using Heli-LIDAR data to provide a high-resolution correlation between two sections 7 km (4.4 mi) apart, and mapping of strata using Google Earth to produce a correlation between sections 25.5 km (15.8 mi) apart. The chemostratigraphic characterization that is defined using data from fine-grained lithologies resulted in the recognition of eight chemostratigraphic packages, with thicknesses between 50 and 250 m (164 and 820 ft) over a stratigraphic interval of approximately 900 m (2953 ft). Two distinctive changes in geochemical composition of the coarser lithologies (fluvial channel belts) were seen over this interval. In the two sections that are 7 km (4.4 mi) apart, higher resolution subdivision of chemostratigraphic packages was achieved to produce four correlative geochemical units (30–60 m [98–197 ft] in thickness) that provide a high-resolution correlation. The chemostratigraphic and chronostratigraphic correlations are in close agreement in both the 7-km- (4.4-mi) and the 25.5-km- (15.8 mi) spaced sections. The thickness of the study interval and spacing of sections is analogous to published chemostratigraphy studies on subsurface sequences; thereby, ground truthing the use of chemostratigraphy for correlation in subsurface fluvial systems that are, to some degree, analogous to the Beaufort Group sediments of this paper.

Description: Between 2005 and 2014 in Pennsylvania, about 4000 Marcellus wells were drilled horizontally and hydraulically fractured for natural gas. During the flowback period after hydrofracturing, 2 to $$4\times {10}^{3}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{m}}^{3}$$ (7 to $$14\times {10}^{4}\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{ft}}^{3}$$ ) of brine returned to the surface from each horizontal well. This Na-Ca-Cl brine also contains minor radioactive elements, organic compounds, and metals such as Ba and Sr, and cannot by law be discharged untreated into surface waters. The salts increase in concentration to $$\sim 270\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{kg}/{\mathrm{m}}^{3}$$ ( $$\sim 16.9\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{lb}/{\mathrm{ft}}^{3}$$ ) in later flowback. To develop economic methods of brine disposal, the provenance of brine salts must be understood. Flowback volume generally corresponds to ~10% to 20% of the injected water. Apparently, the remaining water imbibes into the shale. A mass balance calculation can explain all the salt in the flowback if 2% by volume of the shale initially contains water as capillary-bound or free Appalachian brine. In that case, only 0.1%–0.2% of the brine salt in the shale accessed by one well need be mobilized. Changing salt concentration in flowback can be explained using a model that describes diffusion of salt from brine into millimeter-wide hydrofractures spaced 1 per m (0.3 per ft) that are initially filled by dilute injection water. Although the production lifetimes of Marcellus wells remain unknown, the model predicts that brines will be produced and reach 80% of concentration of initial brines after ~1 yr. Better understanding of this diffusion could (1) provide better long-term planning for brine disposal; and (2) constrain how the hydrofractures interact with the low-permeability shale matrix.

Description: Lacustrine basins are key oil-productive areas of the world. Because fewer lacustrine exist than marine basins, lacustrine systems are relatively less well studied. This paper investigates fluvial-lacustrine depositional environments and their representation in wireline logs in the lower part of the Green River Formation, Uinta Basin, Utah. The five principal depositional environments of the lower Green River Formation are (1) deep lacustrine, (2) shallow lacustrine, (3) lacustrine delta, (4) coastal plain, and (5) alluvial plain. Deep-lake environments are characterized by laminated oil shales and fine-grained carbonates. These facies exhibit anomalously high neutron porosity, and low bulk density relative to other settings. Shallow-lake environments are dominated by weakly laminated to massive gray mudstones, and limestones, with occasional thin high-bulk-density sandstones. Lacustrine deltas (both sand-prone and mud-prone) grade from shallow-lake muds to ripple-laminated to cross-bedded sandstones. The upward decrease in clay can be seen in the gamma-ray, neutron-porosity, and bulk-density profiles of deltaic intervals. Coastal plain mudstones have a greenish hue, and frequently contain organic matter. Channels in coastal plain settings are typically thin, isolated, and heterolithic. Alluvial plain channels tend to be sandier, thicker, and less isolated than coastal plain channels. Alluvial mudstones are reddish with abundant pedogenic features. The vertical association of depositional environments in the lower Green River indicates both high-amplitude and high-frequency lake-level fluctuations. However, the macro-scale trend shows a rapid deepening of the lake lower in the section, followed by a gradual filling of the accommodation, and a gradual flooding near the top of the studied interval. The lower Green River depositional environments form key petroleum system components. Oil shales in the deep lacustrine settings are the major source rock, and coastal plain muds are a potential minor source. Regional seals are formed by deposits of tight lacustrine shale and carbonate deposited in both marginal and deep lacustrine settings. Delta, coastal plain, and alluvial plain sands form the principal reservoirs. Some deep lacustrine mudstones and carbonates are also potential unconventional reservoirs. Correlation of outcrop observations from well log expressions allows depositional environments to be interpreted in the Uinta Basin and other lacustrine basins.

Description: Polygonal faults are compaction-related normal faults that develop in very fine-grained sedimentary successions. Despite their ubiquity, few studies have highlighted the application of polygonal fault mapping to identifying deep-water sandstone reservoirs. We use three-dimensional seismic and borehole data from the Måløy slope, offshore Norway to demonstrate that the distribution, cross-sectional geometry, and throw characteristics of polygonal faults can be used to locate deep-water sandstone reservoirs. We identify two tiers of polygonal faults in the Cretaceous to lower Paleogene succession. The lowermost tier is stratigraphically restricted to the lower Barremian-to-lowermost Turonian succession and likely formed during the early Turonian. The uppermost tier spans the entire Cretaceous succession and likely formed during the Maastrichtian. An abrupt decrease in the thickness of the upper tier occurs where a 92-m (302-ft) thick, sandstone-rich slope fan is developed in the upper Turonian interval. Furthermore, the lower tips of faults in the upper tier, which are defined by anomalously high throw gradients, cluster at the top of the sandstone, resulting in decoupling of this tier from the underlying, lower Turonian tier. We interpret that faults in the upper tier nucleated above the reservoir across the entire slope and that the slope-fan sandstone acted as a mechanical barrier to downward fault propagation, resulting in abrupt thinning of the tier at the sandstone pinchout. We demonstrate polygonal faults are not simply an academic curiosity; mapping of these enigmatic structures can have practical applications for the delineation of a variety of reservoir types in hydrocarbon-bearing sedimentary basins worldwide.

Description: Predicting spatial distribution, dimension, and geometry of diagenetic geobodies, as well as heterogeneities within these bodies, is challenging in subsurface applications, and can impact the results of reservoir modeling. In this outcrop–based study, we generated a data set of the dimensions of fracture–related dolomite geobodies hosted in Ediacaran (Khufai Formation) limestones of the Oman Mountains that are up to several hundreds of meters long and a few tens of meters wide. The dolomite formed under burial conditions by fluids that interacted with siliciclastic layers, as demonstrated by the enriched Fe (up to 4.4%) and Mn (up to 0.8%) contents and $$^{87}\mathrm{Sr}/^{86}\mathrm{Sr}$$ ( $$\sim 0.710$$ ) signatures. Dolomitization probably occurred during the Hercynian Orogeny (or pre-Permian) because dolomitization predates some folding and pre-Permian rocks have seen intense deformation related to the Carboniferous Hercynian Orogeny. Moreover, dolomitization occurred between the onset and termination of bedding-parallel stylolitization and thus most likely before deep burial related to the Alpine Orogeny. Hence, dolomitization most likely occurred before deep burial related to the Alpine Orogeny and during or following the intense deformation related to the Carboniferous Hercynian Orogeny had affected pre–Permian rocks. The clumped–isotope signature yields a temperature of approximately 260°C (500°F), interpreted as the apparent equilibrium temperature obtained during uplift after deepest burial during the Late Cretaceous. Lateral transects across the dolomite bodies show that zebra dolomite textures are common throughout the body and that vugs are more common at the rim than the center of the bodies. Moreover, a weak geochemical trend exists with more depleted $$^{18}\mathrm{O}$$ , Fe, and Mn concentrations in the core than at the rim of the dolomite bodies. These results show that minor heterogeneities exist within the dolomite bodies investigated. These data contrast with previous studies, in which more significant variation is reported in width of the dolomitization halo and texture for larger dolomite bodies that formed in host rocks more permeable than the examples from the Oman Mountains.

Description: Understanding and predicting reservoir presence and characteristics at regional to basin scales is important for evaluating risk and uncertainty in hydrocarbon exploration. Simulating reservoir distribution within a basin by a stratigraphic forward model enables the integration of available prior information with fundamental geologic processes embedded in the numerical model. Stratigraphic forward model predictions can be significantly improved by calibrating the models to independent constraints, such as thicknesses from seismic or well data. A three-dimensional basin-scale stratigraphic forward-modeling tool is coupled with an inversion algorithm. The inversion algorithm is a modification of the neighborhood algorithm (a type of genetic algorithm), which is designed to sample complex multimodal objective functions and is parallelized on computer clusters to accelerate convergence. The process generates a set of representative geological models that are consistent with prior ranges for uncertain parameters, calibration constraints, and associated tolerance thresholds. The workflow is first demonstrated on two data sets: a synthetic example based on a clastic passive margin and a real hydrocarbon exploration example for slope and basin-floor stratigraphic traps in the Neocomian (Lower Cretaceous) of the West Siberian Basin. The analysis of calibrated models provides constraints on stratigraphic controls, and allows prediction of locations with higher potential to develop stratigraphic traps. These locations are related to complex interactions between paleobathymetry, subsidence, eustatic fluctuations, characteristics of sediment-input sources, and sediment-transport parameters. Results show the potential of stratigraphic forward modeling combined with inverse methods as an additional tool to support conventional play-based exploration and reservoir-presence prediction.

Description: The presence of hydrocarbon seeps at the surface is indirect evidence of the presence of mature source rocks within a geological system at depth. Chemical changes in the environment of surface rocks caused by hydrocarbon seeps cause mineralogical alterations. To determine the nature of the alterations and the influences of lithology and type of seep, rock samples were collected from altered and unaltered evaporite and marly limestone formations in the Dezful embayment, southwest Iran. Reflectance spectroscopy, bulk rock/wet chemical analyses, and sulfur, carbon, and oxygen isotopic analyses were used to delineate surficial alterations and relate alterations to hydrocarbons seeping from underlying reservoirs. In addition, the boosted regression trees (BRT) method was used to predict the presence of alterations from spectral indices. Comparisons of geochemical data and spectral data of altered evaporites and altered marly limestones showed that the minerals within alteration facies have distinctive spectral, chemical, and isotopic signatures. Gas-induced alterations were characterized by the formation of gypsum and native sulfur and depletion in $$^{34}\mathrm{S}$$ . The released $${\mathrm{H}}_{2}\mathrm{S}$$ in natural gas reacted with gypsum in the evaporite sediments and calcite in the marly limestone formations, which led to precipitation of secondary gypsum and native sulfur. Oil-induced alterations were characterized by formation of secondary calcite and depletion in $$^{13}\mathrm{C}$$ . The oxidation of seeping oil and reactions between this oil and host rocks caused precipitation of secondary calcite within both formations. The combination of fieldwork data and spectral-geochemical data showed a connection exists between surficial alterations and underlying petroleum reservoirs, which can be used in exploration campaigns.

Description: We present the results of a seismic interpretational study of amplitude anomalies in the East Falkland basin using an extensive grid of approximately 8000 line kilometers (4971 line miles) of high-resolution two-dimensional seismic reflection data. We mapped 474 discrete amplitude anomalies developed within a dominantly hemipelagic and highly reflective megasequence of the Cretaceous to early Cenozoic that is distributed in a northeast–southwest swath across the basin. The amplitude anomalies range from a kilometer to over 25 km (15.5 mi) in lateral extent, have sharp lateral amplitude cutoffs, sometimes at faulted margins, and are invariably associated with reflections with negative acoustic impedance contrasts. They exhibit class III amplitude versus offset (AVO) responses, frequency shadows, and push-down effects, from which the amplitude anomalies are interpreted as related to free gas. All the amplitude anomalies are characterized by vertical clustering, and based on this strong spatial association we refer to these mappable groups of amplitude anomalies as vertical anomaly clusters (VACs). We suggest that VACs form by strongly focused vertical hydrocarbon migration in a heterogeneous stacked sequence of poor-quality reservoirs interbedded with layers with lower permeability, and where the necessary bottom-to-top cross-stratal flow exploits a well-developed fault and fracture network. Similar vertical associations of gas-related amplitude anomalies could be expected in many other basins, so VACs may be a useful direct hydrocarbon indicator with specific genetic significance for hydrocarbon migration mechanisms.

Description: This paper, second of a two-part series, discusses the results of the experimental work conducted to estimate the different compressibilities of coal under both unconstrained and constrained conditions. Under unconstrained conditions, the shrinkage or swelling compressibility ( C m ) was measured, which was found with certainty to be a pressure-dependent parameter. The model proposed to estimate $${C}_{\hbox{ m }}$$ was able to effectively predict the variation trend, although the modeled values were larger than those calculated using experimental results. The pore-volume compressibility $$({C}_{\hbox{ p }})$$ under uniaxial strain conditions for helium depletion was found to be a constant positive value. The value of $${C}_{\hbox{ p }}$$ for methane depletion, however, was found negative, indicating that the pore volume (cleat) increases with depletion. Moreover, its absolute value increased with decreasing methane pressure. Consistent with field permeability observations, the permeability increases with methane depletion, and the rate of increase at lower pressures is higher than at high pressures. The proposed pore-volume compressibility model was well able to predict the variation.

Description: This paper, the first of a two-part series, provides a sound background of the volumetric response of sorptive porous media to gas depletion under in situ boundary conditions in producing reservoirs. As a first step, the overall rock matrix deformation is split into two separate components, elastic deformation caused by mechanical decompression and the nonelastic swelling or shrinkage strain induced by adsorption or desorption of gas. The shrinkage or swelling compressibility is estimated by the first derivative of pure adsorption or desorption strain with variations of gas pressure. The pore volume, or fracture, compressibility is then estimated by application of a semi-empirical model under uniaxial strain conditions. Based on the proposed model, both shrinkage or swelling and pore volume compressibilities show strong pressure dependence for sorbing gases and are thus variables for which gas production is controlled by desorption of gas. In Part 2, the experimental work under best-replicated in situ conditions is described in detail along with the results obtained and application of the theory presented in this paper.

Description: Wireline logs were used to document the stratigraphic framework of Upper Devonian–Mississippian strata in the Arkoma Basin, and maps of high-gamma ray (HGR) log response were used to analyze the spatial distribution of potential source rocks in the Woodford–Chattanooga and Fayetteville–Caney shale-gas systems. The Woodford–Chattanooga shale is a transgressive deposit that accumulated on an arid continental margin influenced by marine upwelling and minimal sediment influx. A broad HGR depocenter along the southwestern margin of the basin includes two areas of higher accommodation containing the thickest HGR concentrations. Basin-wide patterns of HGR likely reflect broad tectonic influence on accommodation. The proportion of chert in the formation increases eastward and southward, likely reflecting latitudinal and bathymetric influence on the accumulation of siliceous ooze. The Lower Mississippian Burlington sequence, which lies between the two shale-gas systems, comprises carbonate ramp and distal shale deposits. Proximal ramp facies form an apron around the southern flank of the Ozark uplift and grade radially basinward into distal facies. An Upper Mississippian succession in the east includes lowstand deposits of the Batesville delta, which onlap the relict Burlington ramp. Basinwide, the succession includes the transgressive Fayetteville–Caney shale overlain by regressive deposits of the proximal Pitkin Limestone and distal upper Fayetteville (Arkansas) and "false" Caney (Oklahoma) shale. The HGR shale is concentrated in an area of intermediate accommodation on the western margin of the Mississippi Embayment and just basinward of the Pitkin Limestone pinchout in Arkansas, and in an area of relatively high accommodation in Oklahoma.

Description: In this work, an unsteady-state diffusion model was developed to describe gas transport in coal structures for horizontal well production. The model assumes unsteady-state diffusion of gas through the matrix according to Fick’s law, Darcy flow through the cleat network (natural fractures), and that gas adsorption can be described by the Langmuir equation. Then the model using Laplace integral transformation was solved. Using the new model, dimensionless-type curves for pressure-transient and rate-decline analyses were used to analyze transient transport characteristics. The differences for unsteady-state diffusion between horizontal and vertical well models and the differences for horizontal well production between unsteady-state diffusion and pseudosteady-state diffusion were specifically analyzed. Several scenarios confronting real coal beds were studied and discussed fully through simulating well production under different conditions. The research results showed that the unsteady-state diffusion model would be another choice with which to analyze well tests.

Description: Triassic mudstones in the Junggar Basin of northwest China, especially those of the Upper Triassic Baijiantan Formation, which formed during a lake-flooding event, are the most important set of cap rocks in the basin. These mudstones presumably have hydrocarbon generation potential, although this potential has not been documented. Here, we provide new organic geochemical and geological background data on these mudstones, and discuss their hydrocarbon generation potential. Geochemical analyses were performed on available samples collected from more marginal shallow-lake facies in the central basin area. These analyses indicated that these rocks contain about 1.0% total organic carbon (TOC). The organic matter type is predominantly type III kerogen derived mainly from terrestrial higher plants. The organic matter underwent maturation in uplifted areas and reached higher maturity levels in depressions within the basin. Thus, the Triassic mudstones may have a potential for hydrocarbon generation during the lake-flooding period, especially for gas, and hence deserve attention in future exploration. More research needs to be conducted on the generation potential of these units (including oil besides gas), as few deep-lake facies samples from depressions in the basin are currently available for investigation.

Description: The Mississippian section of the United States mid-continent Anadarko Basin (Oklahoma and Kansas) has been a prolific hydrocarbon reservoir since the 1920s, yet large-scale regional correlations between individual stratigraphic units remain difficult because of the complex and heterogeneous nature of the carbonate facies. New sedimentologic and carbon isotopic data from a nearly continuous Mississippian core (Pan American 1 Albert Severin) from the Anadarko Basin, Oklahoma (Garfield County), United States, provides insight into the potential of carbon-isotope chemostratigraphy as a correlation tool in complex stratigraphic successions for which biostratigraphic data are not available. The carbon isotopic composition ( $${\delta }^{13}\mathrm{C}$$ ) of whole-rock samples was analyzed to determine if stratigraphic trends reflect global changes in the carbon cycle. A large positive shift (+5.6) in the lower Tournaisian (Kinderhookian), consistent values (averaging +2.3) in the upper Tournaisian through middle Viséan (upper Kinderhookian–Meramecian), and a negative shift (–2.3) in the uppermost Viséan (lower Chesterian) correspond to trends in the carbon isotopic compositions ( $${\delta }^{13}\mathrm{C}$$ values) from other regional data sets, including the global type section at Arrow Canyon, Nevada. Further analysis of the data reveals that isotopic compositions are not facies dependent, suggesting that marine chemistry and depositional changes in the Anadarko Basin reflect global environmental changes during the Mississippian. These inferences demonstrate the potential of the Pan American 1 Albert Severin core to be a Mississippian-type section for the Anadarko Basin, and that stable-isotope chemostratigraphy can be used as a correlation tool to better understand the subsurface in complex successions, such as the Mississippian limestone of the United States mid-continent.

Description: Porosity and permeability are key petrophysical variables that link the thermal, hydrological, geochemical, and geomechanical properties of subsurface formations. The size, shape, distribution, and connectivity of rock pores dictate how fluids migrate into and through micro- and nano-environments, then wet and react with accessible solids. Three representative samples of cap rock from the Eau Claire Formation, the prospective sealing unit that overlies the Mount Simon Sandstone, a potential $${\mathrm{CO}}_{2}$$ storage formation, were interrogated with an array of complementary methods. neutron scattering, backscattered-electron imaging, energy-dispersive spectroscopy, and mercury porosimetry. Results are presented that detail variations between lithologic types in total and connected nano- to microporosity across more than five orders of magnitude. Pore types are identified and then characterized according to presence in each rock type, relative abundance, and surface area of adjacent minerals, pore and pore-throat diameters, and degree of connectivity. We observe a bimodal distribution of porosity as a function of both pore diameter and pore-throat diameter. The contribution of pores at the nano- and microscales to the total and the connected porosity is a distinguishing feature of each lithology observed. Pore:pore-throat ratios at each of these two scales diverge markedly, being almost unity at the nanoscale regime (dominated by illitic clay and micas), and varying by one and a half orders of magnitude at the microscale within a clastic mudstone. Individual minerals, primarily illite and glauconite, have unmistakable pore and pore-throat signatures and contribute disproportionately to connected reactive surface area. The pore types created or evolved during diagenesis mediate profound differences between bulk and pore-network-accessible mineral associations in the mudstones. Results of this study can ultimately be used to inform reactive-transport simulations of effective reactive surface area.

Description: $${\mathrm{CO}}_{2}$$ geologic sequestration has been recognized as a potential greenhouse gas mitigation strategy. Regional $${\mathrm{CO}}_{2}$$ geologic storage in deep saline formations will likely involve the injection of $$\sim 10$$ to 100 million metric tons (11 to 110 million tons) of $${\mathrm{CO}}_{2}$$ per year using a network of $$\sim 10$$ to 50 wells over an area covering $$\sim 10\mbox{--}100$$ sq. miles ( $$26\mbox{--}259\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }{\mathrm{km}}^{2}$$ ). Some of the wells will be injecting into closed volumes because of symmetry, thus providing the bounding case in terms of pressurization and brine efflux. This study describes a parametric analysis of the problem using characteristics typical of the Arches Province in the United States Midwest where Paleozoic rocks form broad arch and platform structures. Two-dimensional radial-cylindrical models developed with the numerical simulator STOMP (Subsurface Transport Over Multiple Phases) are utilized to investigate the impact of well spacing, injection depth, and reservoir characteristics of the injection zone (Mount Simon) and cap rock (Eau Claire) on system performance. Multiple linear regression analysis is then used to develop correlation equations between these design variables and performance metrics, such as cumulative $${\mathrm{CO}}_{2}$$ -mass injected and $${\mathrm{CO}}_{2}$$ -plume extent. The correlations are tested on new synthetic test sites, and are found to predict the performance metrics quite accurately. These results serve as a proxy simulator to quickly evaluate various design options, instead of having to run time-consuming numerical simulations, and can therefore be applied for developing optimal injection strategies for regional $${\mathrm{CO}}_{2}$$ storage in the Arches Province.

Description: Production from ubiquitous oil and gas fields in coastal Louisiana and consequent reservoir compaction has been proposed as an important process contributing to coastal subsidence and land loss in this region. As revealed by three consecutive leveling surveys (in 1965, 1982, and 1993), an unexpected aspect of the subsidence is that the rate of subsidence actually increased after the cessation of production. To explain the accelerated postdepletion subsidence, we propose a mechanism involving time-dependent drainage and compaction in the overlying and underlying shales after depletion. We show that the shale compaction is induced by slow drainage of pore fluid from the shale to the depleted reservoir. We estimate the significance of postdepletion compaction in the bounding shale using a relatively simple analytic model in which time-dependent shale compaction is driven by pore pressure diffusion with two sets of rheological constitutive equations: one accounting for poroelastic effects and one accounting for viscoplastic deformation of the shale matrix. Our modeling shows that despite its very low permeability, after about 10 years, vertical compaction due to pressure drainage in the shale exceeds that due to depletion and compaction of the sand reservoir. Consequently, the calculated subsidence rate due to the shale compaction is higher than the subsidence induced by reservoir depletion, thus demonstrating that postdepletion compaction in the reservoir-surrounding shale may explain the observed acceleration of subsidence after depletion.

Description: Faults are important components of hydrocarbon and other reservoirs; they can affect trapping of fluids, flow pathways, compartmentalization, production rates, and through these, production strategies and economic outcomes. Displacement gradients on faults are associated with off-fault deformation, which can be manifest as faulting, extension fracturing, or folding. In this work, displacement gradients—both in the slip direction and laterally—on a well-exposed large-displacement (seismic-scale) normal fault within the Balcones fault system of south-central Texas are correlated with anomalous deformation patterns adjacent to the fault. This anomalous deformation consists of two superimposed small-displacement fault systems, including (1) an earlier set that formed in response to a displacement gradient in the slip direction, and (2) a later set of oblique faults that formed in a perturbed stress-and-strain field in response to a lateral displacement gradient on the fault. Bed dip, fault-cutoff relationships, and small-displacement fault patterns in the adjacent rock volume inform strain and paleostress estimates. Results indicate that seismically resolvable displacement gradients on and bed dips adjacent to the seismic-scale fault provide a means by which the smaller (subseismic-scale and off-fault) deformation features can be predicted both in terms of orientation and intensity. Specifically, lateral displacement gradients on a normal fault with dip-slip displacement will generate fault-strike-parallel extension, causing anomalously oriented (in the far-field stress context) deformation features adjacent to the fault. Displacement gradient analysis can be used to help predict the characteristics of subseismic-scale deformation within a reservoir adjacent to a seismic-scale normal fault.

Description: Forty-one crude oil samples from the North Slope of Alaska have variable diamondoid and biomarker concentrations, indicating different extents of oil cracking. Some of the samples are mixtures of high- and low-maturity components containing high concentrations of both diamondoids and biomarkers. Compound-specific isotope analysis of diamondoids (CSIAD) shows that the Shublik Formation accounts for the higher maturity component in several mixed oil samples, whereas biomarkers, especially those providing information on the age of the source rock, show either a Cretaceous Hue-gamma ray zone (GRZ) or Triassic Shublik source for the lower maturity component. Oil samples in this study mainly correlate to six source rocks based on their biomarker characteristics and CSIAD. Chemometrics of selected source-related biomarker and isotope ratios helps to classify the oil samples into different genetic families. The source rocks include carbonate and shale organofacies of the Triassic Shublik Formation, Jurassic Kingak Shale, Lower Cretaceous Pebble shale, Lower Cretaceous Hue-GRZ, and Cenozoic Canning Formation. Oil presumed to originate from a seventh source rock interval, the Carboniferous–Permian Lisburne Group, was not clearly differentiated from well-established Shublik oil by any geochemical age-related parameter or CSIAD, which suggests that the Lisburne is not an effective source rock for any of the studied oil samples. Four oil samples collected from wells located north of the Barrow arch show unique biomarker characteristics, but age-related biomarker parameters indicate likely Triassic source rock organofacies that is not represented by any of the samples from south of the arch. The source rock for these four oil samples appears to be a clay-rich equivalent of the calcareous Shublik Formation that occurs to the north of the Barrow arch.

Description: The amount of oil that maturing source rocks expel is expressed as their expulsion efficiency, which is usually stated in milligrams of expelled oil per gram of original total organic carbon ( $${\mathrm{TOC}}_{\mathrm{o}}$$ ). Oil-expulsion efficiency can be determined by heating thermally immature source rocks in the presence of liquid water (i.e., hydrous pyrolysis) at temperatures between 350°C and 365°C for 72 hr. This pyrolysis method generates oil that is compositionally similar to natural crude oil and expels it by processes operative in the subsurface. Consequently, hydrous pyrolysis provides a means to determine oil-expulsion efficiencies and the rock properties that influence them. Smectite in source rocks has previously been considered to promote oil generation and expulsion and is the focus of this hydrous-pyrolysis study involving a representative sample of smectite-rich source rock from the Eocene Kreyenhagen Shale in the San Joaquin Basin of California. Smectite is the major clay mineral (31 wt. %) in this thermally immature sample, which contains 9.4 wt. % total organic carbon (TOC) comprised of type II kerogen. Compared to other immature source rocks that lack smectite as their major clay mineral, the expulsion efficiency of the Kreyenhagen Shale was significantly lower. The expulsion efficiency of the Kreyenhagen whole rock was reduced 88% compared to that of its isolated kerogen. This significant reduction is attributed to bitumen impregnating the smectite interlayers in addition to the rock matrix. Within the interlayers, much of the bitumen is converted to pyrobitumen through crosslinking instead of oil through thermal cracking. As a result, smectite does not promote oil generation but inhibits it. Bitumen impregnation of the rock matrix and smectite interlayers results in the rock pore system changing from water wet to bitumen wet. This change prevents potassium ion ( $${\mathrm{K}}^{+}$$ ) transfer and dissolution and precipitation reactions needed for the conversion of smectite to illite. As a result, illitization only reaches 35% to 40% at 310°C for 72 hr and remains unchanged to 365°C for 72 hr. Bitumen generation before or during early illitization in these experiments emphasizes the importance of knowing when and to what degree illitization occurs in natural maturation of a smectite-rich source rock to determine its expulsion efficiency. Complete illitization prior to bitumen generation is common for Paleozoic source rocks (e.g., Woodford Shale and Retort Phosphatic Shale Member of the Phosphoria Formation), and expulsion efficiencies can be determined on immature samples by hydrous pyrolysis. Conversely, smectite is more common in Cenozoic source rocks like the Kreyenhagen Shale, and expulsion efficiencies determined by hydrous pyrolysis need to be made on samples that reflect the level of illitization at or near bitumen generation in the subsurface.

Description: This paper describes reservoir properties in the Triassic Skagerrak Formation in the Central North Sea. This prolific sandstone reservoir often possesses anomalously high porosity for its depth of burial. Simple statistical analysis of wire-line-log-derived porosity data is used to derive empirical trends as a function of both depth and vertical effective stress that show variations between neighboring hydrocarbon fields and between different parts of the basin. Porosity data from the Josephine (J) Ridge (Quadrant 30 of the United Kingdom Continental Shelf [UKCS]) show a marked degradation with depth, but the porosities are significantly higher than in similarly deeply buried areas such as the Puffin high to the west (Quadrant 29) or the Forties–Montrose high to the north (Quadrant 22). To understand the porosity patterns better the data have been analyzed by plotting against vertical effective stress. This allows a better comparison to be made between fields and wells within the high-pressure–high-temperature (HPHT) realm. High pressure here refers to fluid pressures above 10,000 psi ( $$703\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{kg}/\mathrm{cm}$$ ), whereas high temperatures are above 300°F (149°C). Results show that porosity and fractional effective reservoir (the proportion of net sandstone with a porosity greater than a predetermined cutoff) decrease systematically with increasing vertical effective stress. Data from the different J Ridge fields fall on a common compaction trend even though they are derived from structures with marked variations in present-day depth of burial and static formation overpressure. Trends from the other areas of the Central Graben (the Puffin and Forties–Montrose highs) indicate more indurate reservoir states. The observed porosity trends are independent of fluid type within the reservoir and the absolute magnitude of overpressure. The main observed hydrocarbon effect is the result of buoyancy forces. The analysis supports the contention that, after accounting for facies-related grain-size variations, compaction controls average reservoir properties. Differences in compaction state between areas are postulated to relate primarily to structurally controlled timing of overpressure development relative to burial, and how these affect the resultant vertical effective stress history. Both the Puffin and Forties–Montrose highs are directly attached to the basin margins across stepped faults. These marginal terraces were open to lateral fluid flow for longer probably because across-fault seals were only established late in the burial history when higher temperatures promoted cementation and the destruction of permeability within fault cores. As a result, they developed overpressures in the last 5–10 m.y. or so and are largely normally compacted. The J Ridge horst block is hydrologically more isolated within the basin center by across-fault juxtaposition seals. Here, overpressure development appears to have started earlier, possibly between 50 and 60 Ma, retarding compaction and allowing preservation of higher porosities. Compaction continues to present day driven by the large static vertical effective stress gradients in these deeply buried reservoirs. The observed empirical trends offer a means of predicting average reservoir properties in deep untested exploration targets.

Description: The First Eocene reservoir at the Wafra Field produces heavy oil from very porous dolomites at depths of $$\sim 1000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\hbox{ to }\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }1300\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{ft}$$ (300 to 400 m) in the Paleocene–Eocene Umm Er Radhuma Formation. Porosity is commonly 30–50%, permeability is commonly 100–2000 md, and those reservoir characteristics were determined largely by diagenesis. Early diagenesis is dominated by dolomitization, dissolution associated with dolomitization, and precipitation of sulfates. Petrographic and stable isotopic characteristics support dolomitization and sulfate precipitation in evaporated (refluxing) seawater during shallow burial. The highest permeabilities occur in subtidal facies. Low-permeability tidal-flat facies stratify the reservoir. Heavy oil preferentially filled high-permeability dolomites; whereas, low-permeability tidal-flat facies are commonly filled with water because their pore throats are too small to allow migration of viscous oil into the rock. This reservoir’s very high porosity is probably related to its shallow burial and early oil emplacement. Late-stage diagenesis is dominated by bacterial sulfate reduction (BSR) that caused dissolution of sulfate nodules, calcite cementation, sulfur precipitation, and oil biodegradation. The BSR is indicated by very low $${\updelta }^{13}\mathrm{C}$$ compositions of calcite cements ( $$-17.1$$ to $$-34.9$$ , Peedee Belemnite standard), which require an organic carbon source; probably oil. The oxygen isotopic compositions of the calcites support precipitation from formation waters similar to those in the reservoir now. The BSR probably started during initial oil emplacement and continues to the present. The BSR was heterogeneous resulting in produced oils with gravities of 14–21° API. Even heavier oils are present that could not flow during primary production. Primary production was likely greatest in areas and intervals with lighter, less viscous oil.

Description: This study examines the geochemical record of diagenesis in the Middle Permian Yates shelf, exposed in Slaughter Canyon, New Mexico. This diagenetic history significantly modified lithologies, depositional fabrics, and pore systems. Early diagenesis was dominated during sea level highstands by marine cementation and reflux dolomitization, and during sea level lowstands by meteoric cementation and stabilization—the focus of this study. This early diagenesis variably overprinted primary marine isotopic signatures, potentially leading to erroneous chemostratigraphic correlations or paleoclimate reconstructions. Four correlative sections through one m-scale cycle were analyzed for their $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ values. They show significant (2–4) $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ variability in coeval, texturally well-preserved calcites. The $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ values of marine cements, brachiopods, bulk carbonate, micritic matrix, and the first generation of meteoric spar (from high to low values) delineate an "inverted J curve," indicating the variable alteration of components by diagenetic fluids. Numerical models indicate that the observed stable isotope trend is most consistent with diagenetic alteration in a partially closed system by meteoric fluids mixed with a progressively diminishing contribution of recycled marine waters. In the Yates shelf, marine cements provide a more robust primary isotopic record than micritic matrix; however, neither preserves primary seawater isotopic values. Furthermore, common criteria used to diagenetically screen samples proved inadequate (e.g., textural preservation, staining, luminescence, depletion near sequence boundaries). Instead, diagenetic resetting is resolved by analyzing multiple, closely spaced, independently correlated sections, and by delineating trends between primary and later diagenetic components in populations of isotopic data.

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

Description: This study presents a lithology-based sequence-stratigraphic framework and depositional model for Lower Cretaceous, mixed siliciclastic-carbonate sediments of the Mid-Atlantic coastal plain (eastern United States). Lithologic data from cores and cuttings were integrated with wireline logs and two-dimensional seismic data to document lithofacies variability and stacking patterns across the Albemarle Basin of eastern North Carolina. Ten facies associations are defined, which are variably present within siliciclastic- and carbonate-dominated depositional profiles interpreted to extend from onshore lowland coastal plain to deep-shelf depositional environments. Three depositional sequences (0, 1, 2) were identified, each with component upward-shoaling parasequences. Seismic reflectors typically coincided with key sequence-stratigraphic surfaces, which guided correlations between wells. Parasequences are grouped into parasequence sets with progressive progradational or retrogradational (highstand and transgressive systems tracts, respectively) stacking patterns. Transgressive parasequences are thinner, uniform in thickness, and tend to be more dominated by molluskan carbonate facies. Highstand parasequences have more variable thickness, are siliciclastic dominated, and tend to be progradational on seismic data. Late highstand deposits of sequence 1 are dominated by restricted carbonate facies that likely reflect increased aridity. Lowstand deposits were not recognized from onshore well and seismic data. The sequence-stratigraphic framework developed documents the complex spatial and temporal facies relationships within a wave-dominated, mixed carbonate-siliciclastic passive-margin succession. The strata studied document the complex interplay of lithofacies within a transition zone between near-shore carbonate-dominated strata to the south (Southeast Georgia Embayment) and siliciclastic-dominated marginal-marine successions to the north (Baltimore Canyon Trough). It also provides a useful stratigraphic calibration set for coeval offshore sediments that have been identified as potential areas for hydrocarbon exploration.

Description: High-resolution carbon isotope signatures were integrated with core descriptions and gamma-ray logs and used as a correlation tool for better age control to refine the sequence-stratigraphic framework of the Shu’aiba Formation in Saudi Arabia. The carbon isotope variations of the shallow carbonate Shu’aiba Formation correlate well with the Tethyan pelagic record and indicate an original marine $${\mathrm{C}}^{13}$$ signature for the Lower Cretaceous (Aptian) Shu’aiba Formation. Carbon isotope values of the Shu’aiba Formation range from 1.5 to 6 with minimal or no diagenetic effects. Oxygen isotope values range from –2.7 to –6.7 but were reset during diagenesis and cannot be applied for chemostratigraphic analysis. The Shu’aiba strontium isotope records range from 0.707356 to 0.707454 and differ slightly from the standard Aptian record because of diagenesis. The Shu’aiba Formation platform is a large-scale composite sequence (~7 m.y.) composed of seven lower Aptian high-frequency sequences and two additional upper Aptian prograding sequences. Carbon isotope data were calibrated with core descriptions and gamma-ray logs to construct two detailed high-resolution stratigraphic cross sections. Carbon isotope data help refine the internal stratigraphic architecture of the Shu’aiba Formation especially on the slope and open-marine settings across the lower to upper Aptian boundary. The carbon isotope values of the Hawar "dense" unit in the base of the Shu’aiba Formation record major depletion corresponding to the global dissociation of methane hydrates, followed by major positive excursion associated with the deposition of Lithocodium and Bacinella facies coeval with the global oceanic anoxic event 1a. The rudist buildups on the platform have a value of approximately 4.5 at their base in most wells with a general uniform carbon isotope trend, followed by a gradual depletion to the top of the Shu’aiba Formation. Although some variations are observed in carbon isotope values associated with the lateral facies change from lagoon, margin, slope, open-marine, and basinal settings, carbon isotope trends are still similar and can be correlated fieldwide. Little evidence exists of meteoric diagenesis associated with the depletion of carbon isotope values. However, oxygen isotope records were possibly affected by meteoric diagenesis associated with subaerial exposure surfaces but did not get affected by the late Aptian hiatus, despite the massive karstification observed in cores. The good correlation between the original carbon isotope fluctuations and the third-order sequence framework of the Shu’aiba Formation fits well with the established carbon isotope curves that have been used as a proxy for global sea level changes during the Early Cretaceous. This study also shows that small-scale parasequences (fifth-order or higher) can be calibrated with carbon isotope curves, but they most likely represent relative sea level changes with local effects instead of global signatures. Application of high-resolution carbon isotope stratigraphy for the Shu’aiba Formation significantly constrain the stratigraphic framework and will lead to better geologic and simulation models for reservoir characterization and development.

Description: The Khufai Formation is the oldest carbonate platform of the Cryogenian to lowermost Cambrian Huqf Supergroup. A stratigraphic characterization of this unit includes detailed facies descriptions, a sequence-stratigraphic interpretation, and evaluation of lateral heterogeneity and overall ramp evolution. The Khufai Formation comprises one and one-half depositional sequences with a maximum flooding interval near the base of the formation and a sequence boundary within the upper peritidal facies. Most of the deposition occurred during highstand progradation of a carbonate ramp. Facies tracts include outer-ramp and midramp mudstones and wackestones, ramp-crest grainstone shoal deposits, and extensive inner-ramp, microbially dominated peritidal deposits. Outcrops in the Oman Mountains are deep-water deposits, including turbiditic grainstone and wackestone interbedded with siliciclastic-rich siltstone and crinkly laminite. Facies patterns and parasequence composition are variable both laterally across the outcrop area and vertically through time because of a combination of ramp morphology, siliciclastic supply, and possible syndepositional faulting. The lithostratigraphic boundary between the Khufai Formation and the overlying Shuram Formation is gradational and represents significant flooding of the carbonate platform. The stratigraphic characterization presented here along with the identification of key facies and diagenetic features will help further future exploration and production of hydrocarbons from the Khufai Formation.

Description: Intrasalt carbonates of the Ediacaran–Cambrian Ara Group constitute a significant reservoir element of the intrasalt "stringer" play in Oman, in which dolomitic carbonates are encased in salt at depths of 3 to 7 km (1.9 to 4.3 mi). These reservoir carbonates have significant microbial influences. Although Ara Group reservoirs are mostly latest Precambrian, the models developed here may be applicable to younger microbially dominated carbonate reservoirs in basins of higher salinity when higher organisms are excluded, in lacustrine settings where calcified invertebrates are not a significant source of carbonate, or after periods of mass extinction before faunal recovery. A broad range of carbonate facies provides the context in which to understand the origin of the microbialite-dominated reservoirs developed across both ramp and rimmed shelf profiles. Major facies associations include carbonate-evaporite transition zone, deep ramp and slope, subtidal microbialites, clastic-textured carbonates, and restricted peritidal carbonates. Microbialites are subdivisible into a number of facies that all have significance in terms of understanding environmental history as well as reservoir properties, and that help in predicting the location of reservoir fairways. Microbially influenced facies include shallow subtidal thrombolites with massive clotted textures and very high initial porosities ( $$ 〉 50\%$$ ), shallow subtidal pustular laminites with cm-scale variability of lamina morphology, deeper subtidal crinkly laminites that show mm-scale variability of lamina morphology, and intertidal tufted laminates that show mm- to cm-scale tufted textures. Other reservoir facies are more conventional grainy carbonates including ripple cross-stratified grainstone–packstone, hummocky cross-stratified grainstone–packstone, flat pebble conglomerate, ooid and intraclast grainstone–packstone, and Cloudina grainstone–packstone. These facies are almost invariably dolomitized and all have moderate to excellent reservoir quality. These facies comprise carbonate platforms, broken up during salt tectonics, that range up to 160 m (525 ft) in thickness and extended laterally, prior to halokinesis, for tens to over 50 km (31 mi). The distribution of reservoir facies follows sequence stratigraphic predictions, with microbialites occurring in every accommodation profile. Late highstand and early transgressive systems tracts favor greater lateral extent of thrombolite build-ups, whereas later transgressive to early highstand system tracts favor greater lateral discontinuity and compartmentalization of buildup reservoir facies. Pustular laminites occur in close association with thrombolite buildups but form laterally extensive sheets in late transgressive to late highstand periods. Crinkly laminites form during late transgressive to early highstand systems tracts and may represent maximum flooding intervals when the flux of carbonate sediment was greatly reduced allowing pelagically derived organics to accumulate.

Description: Basin-scale correlations in the subsurface generally rely on lithostratigraphic information synthesized from wireline logs, and, in some cases, well cuttings, and cores. However, lithostratigraphic boundaries are often diachronous, and, as such, the correlations based upon them may not provide reliable timelines. In this paper, we use $${\delta }^{13}{\mathrm{C}}_{\mathrm{carb}}$$ data from well cuttings and a core to generate chronostratigraphic logs of Late Ordovician strata spanning the Black River Group, Trenton Group, and Utica Shale across the subsurface of New York State. Although particular $${\delta }^{13}{\mathrm{C}}_{\mathrm{carb}}$$ values may be impacted by (primary) variability in local dissolved inorganic carbon reservoirs and/or (secondary) diagenetic alteration, it is possible to identify spatially and stratigraphically coherent patterns in $${\delta }^{13}{\mathrm{C}}_{\mathrm{carb}}$$ , which can be used to effectively correlate time-equivalent strata on a basin-wide (or even global) scale, including across lithologies (e.g., between limestone and calcareous shale). The present study emphasizes the use of well cuttings, as these are commonly collected during drilling and can provide the maximum lateral resolution for subsurface correlation. Parallel geochemical (percent carbonate and total organic carbon) and isotopic ( $${\delta }^{18}{\mathrm{O}}_{\mathrm{carb}}$$ and $${\delta }^{13}{\mathrm{C}}_{\mathrm{org}}$$ ) data are used to understand the origin of stratigraphic and spatial variability in the $${\delta }^{13}{\mathrm{C}}_{\mathrm{carb}}$$ signal and to identify diagenetic alteration. Stratigraphically coherent $${\delta }^{13}{\mathrm{C}}_{\mathrm{carb}}$$ trends across New York were used to identify six isotopically distinct packages of time-equivalent strata within these formations. Pairing chemostratigraphic and lithostratigraphic data improves our ability to document the diachronous nature of lithologic contacts, including the base of the Utica Shale, which is progressively younger moving west through New York.

Description: Well-exposed three-dimensional fluvial outcrops of the high net-sand content middle Wasatch Formation in Three Canyon, Uinta Basin, Utah, were used to create and develop a new methodology for describing the architecture of fluvial systems. The methodology builds on the works of Campbell, Jackson, Allen, and Miall, and addresses sedimentary processes, scale, and temporal context for reservoir and non-reservoir bodies. The methodology developed herein is a three-level hierarchical framework that classifies meso- and macroscale architecture of fluvial systems. The three-level hierarchy contains, from smallest to largest: stories, elements, and archetypes. Eight story types provide the foundational building blocks of this framework and account for sedimentation in both channel-belt and floodplain-belt elements, including (1) downstream accreting; (2) laterally accreting; (3) erosionally-based fine-grained fill; (4) fine-grained fill associated with laterally accreting; (5) levee; (6) splay; (7) crevasse or overbank channels; and (8) floodplain fines. Two types of elements are recognized: (1) channel belt and (2) floodplain belt. An archetype consists of a channel-belt element and its genetically related floodplain-belt elements. Two distinct upward-stacking patterns differentiate braided and meandering archetypes. In deconstructing the evolution of archetypes, three distinct associations between channel-belt elements and their adjacent splays are documented: (1) unassociated splays; (2) associated coeval splays; and (3) associated non-coeval splays.Width and thickness for stories, channel-belt elements, and archetypes are documented providing dimensional constraints for analog high-net-sand-content fluvial systems. Additionally, this methodology provides object-based models with shape-defined reservoir and nonreservoir geobodies that realistically compare to fluvial systems.

Description: Bohai Bay Basin, located in eastern China, is considered a Cenozoic rifted basin. The basin is atypical in terms of its Neogene–Quaternary postrift subsidence history in that it experienced intensive tectonic reactivation, rather than the relative tectonic quiescence experienced during this stage by most rift basins. This Neogene–Quaternary tectonic reactivation arose principally in response to two tectonic events: (1) activity on a dense array of shallow faults and (2) accelerated tectonic subsidence that occurred during the postrift stage. These two events were neither strictly temporally nor spatially equivalent. The dense array of shallow faults form a northwest–southeast-trending belt in the central part of the basin, with displacement induced by the reactivation of older northeast- and northwest-trending basement faults and an associated substantial component of strike-slip displacement occurring after 5.3 Ma. The intensive reactivation of these faults contributed to the atypically accelerated rate of postrift tectonic subsidence of the basin that commenced ca. $$12\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{Ma}$$ . However, this was not the sole cause of this accelerated tectonic subsidence: A combination of geological activity deep within the crust led to the buildup of intraplate stresses, and this, combined with ongoing thermal subsidence, acted as an additional contributory factor that drove unusually high rates of subsidence for this basin. This episode of accelerated postrift tectonic reactivation resulted in conditions favorable for hydrocarbon accumulation.

Description: Conventional basin and petroleum systems modeling uses the vertical backstripping approach to describe the structural evolution of a basin. In structurally complex regions, this is not sufficient. If lateral rock movement and faulting are inputs, the basin and petroleum systems modeling should be performed using structurally restored models. This requires a specific methodology to simulate rock stress, pore pressure, and compaction, followed by the modeling of the thermal history and the petroleum systems. We demonstrate the strength of this approach in a case study from the Monagas fold and thrust belt (Eastern Venezuela Basin). The different petroleum systems have been evaluated through geologic time within a pressure and temperature framework. Particular emphasis has been given to investigating structural dependencies of the petroleum systems such as the relationship between thrusting and hydrocarbon generation, dynamic structure-related migration pathways, and the general impact of deformation. We also focus on seal integrity through geologic time by using two independent methods: forward rock stress simulation and fault activity analysis. We describe the uncertainty that is introduced by replacing backstripped paleogeometry with structural restoration, and discuss decompaction adequacy. We have built two end-member scenarios using structural restoration, one assuming hydrostatic decompaction, and one neglecting it. We have quantified the impact through geologic time of both scenarios by analyzing important parameters such as rock matrix mass balance, source rock burial depth, temperature, and transformation ratio.

Description: Deposits of wave-dominated shorelines are typically considered to act as relatively simple hydrocarbon reservoirs and are commonly modeled as "tanks of sand." However, important heterogeneities that can act as barriers to fluid flow occur at the parasequence, bedset, and bed scales, especially in viscous oil or low-permeability oil fields. Heterogeneities at the parasequence and bedset scales have been well studied, but discontinuous mudstone beds occurring within the shoreface have received little attention. The Book Cliffs and Wasatch Plateau are among the best-exposed and best-studied deposits of wave-dominated shallow-marine systems in the world. Two parasequences within these outcrops have been studied in detail to investigate the distributions of intrashoreface shales and to propose models for the controls on their distribution. A data set consisting of 30 km (18.6 mi) of virtual outcrops derived from oblique helicopter-mounted light detection and ranging (LIDAR) scanning with supporting stratigraphic sections makes it possible to collect a large quantity of accurate geometric data of depositional elements from inaccessible cliffs. Nine-hundred and twenty-one discontinuous mudstone beds were measured. These occur as ellipses with long axes oriented normal to the paleoshoreline. Lengths and widths of these mudstone beds exhibit a lognormal distribution, with means of 21.9 and 13.8 m (71.9 and 45.3 ft), respectively. Within the shoreface succession, the number of mudstone beds increases downward whereas size does not vary significantly with stratigraphic height. An average of 100 m (328 ft) cumulative length of shale exists per 100 m (328 ft) of horizontal outcrop; this increases threefold near both wave-dominated deltas and bedset boundaries that reflect minor sea-level fluctuations during progradation.

Description: This paper presents a novel graphical enhancement technique that can be easily practiced to interpret reservoir fluid gradients with formation pressure-test data. The method has various applications including mapping reservoir fluid nature and trends, identifying formation pressure changes because of facies changes, or the presence of baffles or barriers, and compartmentalization; diagnosing fluid-contact levels and transition-zone intervals; quality control of data; and judging the reliability of gradient interpretation. The scatter-plotting technique is very useful, not only for real-time decision making at the well site during both wireline- and drillpipe-conveyed formation-tester operations, but also in routine data interpretation and reservoir studies with petrophysical logs, pressure, and fluid data.