ALBERT

Description: No Abstract available.

Description: No Abstract available.

Description: We describe the structure, microstructure, and petrophysical properties of fault rocks from two normal fault zones formed in low-porosity turbiditic arkosic sandstones, in deep diagenesis conditions similar to those of deeply buried reservoirs. These fault rocks are characterized by a foliated fabric and quartz-calcite sealed veins, which formation resulted from the combination of the (1) pressure solution of quartz, (2) intense fracturing sealed by quartz and calcite cements, and (3) neoformation of synkinematic white micas derived from the alteration of feldspars and chlorite. Fluid inclusion microthermometry in quartz and calcite cements demonstrates fault activity at temperatures of 195°C to 268°C. Permeability measurements on plugs oriented parallel with the principal axes of the finite strain ellipsoid show that the Y axis (parallel with the foliation and veins) is the direction of highest permeability in the foliated sandstone (10 •2 md for Y against 10 •3 md for X, Z, and the protolith, measured at a confining pressure of 20 bars). Microstructural observations document the localization of the preferential fluid path between the phyllosilicate particles forming the foliation. Hence, the direction of highest permeability in these fault rocks would be parallel with the fault and subhorizontal, that is, perpendicular to the slickenlines representing the local slip direction on the fault surface. We suggest that a similar relationship between kinematic markers and fault rock permeability anisotropy may be found in other fault zone types (reverse or strike-slip) affecting feldspar-rich lithologies in deep diagenesis conditions.

Description: This work discusses concepts related to the occurrence of salt along weakness planes, such as faults and fractures, which resemble igneous intrusions and may result in peculiar seismic features. We suggest that mechanisms for the formation of these structures basically involve the creation of extensional faults (commonly associated with crestal collapse grabens), which are rotated and migrated to structural flanks by domation, creating interesting seismic features here referred to as halokinetic rotating faults. At the time of their formation, some of these faults may be incipiently intruded by salt as a way of relieving sporadic intense internal overpressure episodes in the salt body, by regional compression, and/or by buoyancy effects compensating the density difference between salt and surrounding sediments. The relatively low overburden pressure at the crest of the diapir and the original high dip angles of these fault planes favor salt intrusions near the diapir apex. The process may occur in several cycles along the salt dome evolution, creating several generations of salt apophyses positioned in the diapir apex and flanks, resulting in different dips and areas of extension. These intrusions sometimes resemble the branches of Christmas tree structures, which are commonly formed by extrusive mechanisms. Although well and seismic data point to the occurrence of salt along fault planes, we recognize that salt is not a low-viscosity fluid, and the mechanisms to allow its penetration along fault planes remain unknown. Some of the possible mechanisms, which are commonly associated with a later phase of regional compression, are discussed in this work. The implications for petroleum exploration may have been overlooked in the recent exploration campaigns in the deep-water regions of the Brazilian margin. Halokinetic rotating faults, when partially filled with salt, are sometimes responsible for common pitfalls observed in seismic and well data interpretation. When fault planes present subhorizontal dips and high reflectivity, caused by the presence of salt, they have been mistakenly interpreted as flatspots, a well-known seismic hydrocarbon indicator. When drilled and proved to correspond to thin evaporite intervals in well data, these salt apophyses have also been misinterpreted as younger localized evaporitic events overlying the main salt body.

Description: The Cretaceous rocks of Florida have been recognized as potentially suitable reservoirs for geologic carbon dioxide (CO 2 ) sequestration. Specifically, the upper member of the Upper Cretaceous Lawson Formation, together with the lower part of the Paleocene Cedar Keys Formation, is presented here as a potential composite CO 2 storage reservoir that is mainly composed of porous dolostone sealed by thick anhydrites of the overlying middle Cedar Keys Formation. Many of the porous intervals within the Cedar Keys-Lawson storage reservoir display lateral continuity and have an average porosity range of 20%–30%. The estimated CO 2 storage capacity for the reservoir is approximately 97 billion t of CO 2 , which means the Lawson and Cedar Keys Formations composite reservoir could potentially support CO 2 sequestration for hundreds of large-scale power plants in the southeastern United States for their entire 40-yr lifespan. Because most of the previous research on the Lawson Formation is concentrated in north-central and northeastern Florida and southern Georgia, this study further characterizes the formation and its CO 2 sequestration potential in south-central and southern Florida.

Description: Geochemical reactions that may occur on CO 2 injection into a sandstone formation in Missouri (MO) were investigated by means of geochemical modeling. Five possible injection sites were considered: two in the northwestern part of the state, two in the northeastearn part, and one in the southwestern part. The Geochemist Workbench software was used to investigate solubility trapping and mineral precipitation. Modeling was performed for two periods: an injection period of 10 yr and a postinjection period where the reactions proceeded to equilibrium. The work presented substantial challenges. Among them are uncertainty in kinetic constants for the dissolution and precipitation of minerals on CO 2 injection. Model results include equilibrium values for CO 2 stored via solubility trapping ranging from 49-g CO 2 /kg free formation water in Northeast MO to 78-g CO 2 /kg free formation water for Southwest MO. Mineral trapping is significantly lower, between 2.6- and 18.4-g CO 2 /kg free formation water. The model shows siderite and dawsonite as the major carbonate minerals formed, in this order. On a volumetric basis, northwest MO sequestration values were slightly greater than those obtained for northeast MO because of the somewhat greater depth and higher injection pressure at the injection target (Lamotte Sandstone) at the northwestern sites. However, the greater thickness of the aquifer for the northeastern sites provided overall greater sequestration capacity. Greene County was altogether unfit for sequestration because of the low total dissolved solids value of the formation water.

Description: We present a new hypothesis for the Jurassic plate-tectonic evolution of the Gulf of Mexico basin and discuss how this evolution influenced Jurassic salt tectonics. Four interpretations, some based on new data, constrain the hypothesis. First, the limit of normal oceanic crust coincides with a landward-dipping basement ramp near the seaward end of the salt basin, which has been mapped on seismic data. Second, the deep salt in the deep-water Gulf of Mexico can be separated into provinces on the basis of position with respect to this ramp. Third, paleodepths in the postsalt sequence indicate that salt filled the Gulf of Mexico salt basin to near sea level. Fourth, seismic data show that postsalt sediments in the central Louann and the Yucatan salt basins exhibit large magnitudes of Late Jurassic salt-detached extension not balanced by equivalent salt-detached shortening. In our hypothesis, Callovian salt was deposited in preexisting crustal depressions on hyperextended continental and transitional crust. After salt deposition ended, rifting continued for another 7 to 12 m.y. before sea-floor spreading began. During this phase of postsalt crustal stretching, the salt and its overburden were extended by 100 to 250 km (62–155 mi), depending on location. Sea-floor spreading divided the northern Gulf of Mexico into two segments, separated by the northwest-trending Brazos transform. The eastern segment opened from east to west, leaving the Walker Ridge salient in the center of the basin as the final area to break apart. In some areas, salt flowed seaward onto new oceanic crust, first concordantly over the basement as a parautochthonous province, then climbing up over stratigraphically younger strata as an allochthonous province.

Description: Three aspects of basement structure and rift-related salt distribution have especially influenced the evolution of the deep-water northern Gulf of Mexico: (1) creation of a basement high (Toledo Bend flexure), separating a chain of interior basins from the central Louann salt basin, (2) segmentation of the central Louann salt basin by the Brazos transfer fault into eastern and central domains, and (3) salt provinces formed during basin opening. The Toledo Bend flexure was reactivated as a hinge during the Cenozoic uplift of the North American craton. This uplift triggered gravity gliding, forming fold belts in the seaward parts of the continental margin. The geometry of the Toledo Bend flexure influenced the position of these fold belts. The Brazos transfer fault separates the west sector of the study area from the central and east sectors. Most of the salt in the deep-water northern Gulf of Mexico lay in the central sector, which sourced most of the Sigsbee salt canopy. The western sector was narrower and was subdivided by the East Breaks basement high. Splitting the Callovian salt basin in two as the gulf opened created a southward-thinning wedge of salt at the seaward end of the northern Gulf of Mexico. We divide this wedge into a series of provinces on the basis of the geometry of the base of the deep salt. Original salt thickness influenced diapir location, the geometry of the Sigsbee canopy, the geometry and style of later compressional fold belts, and petroleum systems.

Description: Recent ultradeep exploration in the northern Gulf of Mexico has revealed a broad diffuse zone of salt-cored folding beneath the present continental shelf. This zone is a pillow fold belt, where salt pillows grew halokinetically and were then mildly shortened. Below the Louisiana shelf, a contractional early-to-late Miocene pillow fold belt is separated by a partly welded canopy from an overlying early Miocene–to–Pliocene extensional system. This anomalous juxtaposition raises two paradoxes: (1) Why was mid-Miocene shortening close to the Miocene shelf break, where extension is expected? and (2) Why did shortening below the canopy overlap in time with extension above the canopy? Coastal uplift can explain both paradoxes. Cenozoic uplift and exhumation of the north rim of the Gulf of Mexico created the observed coastal offlap and truncation around the rim. Uplift tilted the continental margin and overpowered the influence of the paleoshelf break, causing shortening much farther updip than before uplift. Physical models confirm that this hypothesis is mechanically sound. Our other models had two stacked detachments, each pinned in different locations. Because of this, deep shortening below the canopy was coeval with shallow extension above the canopy. The deep detachment was pinned far inland, equivalent to the uplifted continental interior. Extension above this deep detachment was partly balanced by shortening far downdip to form a pillow fold belt where a network of thrusts linked the squeezed pillows. In contrast, the shallow extensional system above the canopy was pinned farther seaward, equivalent to the upper continental slope.

Description: The process and mechanisms of secondary hydrocarbon migration in the Tazhong uplift, Tarim Basin, were investigated based on the analysis of the regional structure and by integrating geologic, hydrodynamic, and geochemical parameters. Parameters successfully analyzed included the fluid potential, fluid properties, production outputs, and diamantane index. The results indicated that hydrocarbons migrated into the Tazhong uplift from the northern part of the Manjiaer depression through a series of injection points (IPs) during four orogenies, that is, the early Caledonian (510 Ma), the late Caledonian (439 Ma), the late Hercynian–Indosinian (290 Ma), and the Yanshanian–Himalayan (208 Ma). A total of six IPs were identified at the intersections of the northeast-trending faults and the northwest-trending flower strike faults. The hydrocarbons migrated from the IPs into traps along regional trends from northwest to southeast and from northeast to southwest. The hydrocarbon migration process and patterns determined the distribution of hydrocarbon properties and production rates in the Tazhong uplift. With increasing distance from the IPs, daily hydrocarbon production decreases, and the hydrocarbons become progressively heavier and display lower gas:oil ratios.

Description: Determination of turbidite event magnitude and frequency remains subjective and difficult to define. This is because turbidite sedimentation events commonly include both sand and mud, with the mud component commonly excluded from bed thickness studies because of the inability to establish a genetic link to the turbidity current. Pelagic mudrock is defined as fine-grained marine sediment derived primarily from biogenic particles, whereas hemipelagic mudrock includes both biogenic and terrigenous particles. Unfortunately, these compositional definitions do not account for differences in depositional process. Scanning electron microscopy, field emission scanning electron microscopy, and x-ray diffraction analyses of 70 samples from El Rosario Formation outcrops (Baja California, Mexico) and core from the Woodford Shale (Oklahoma) illustrate this distinction. Furthermore, these laboratory measurements are calibrated to 192 outcrop samples to provide a robust method for field identification of clay fabric and mineralogy to define turbidite sedimentation units. Pelagites show organized layering of clay platelets, few flocculates, and a lower proportion of high-density minerals. Hemipelagites have disorganized and chaotic clay fabrics characterized by visible flocculates and contain a higher proportion of denser particles. There may also be a corresponding change in clay mineralogy, for example, smectite in pelagites versus kaolinite in hemipelagites. These results indicate a settling velocity greater than shear velocity in pelagites, whereas hemipelagites record the opposite condition. Turbidity currents support and suspend denser grains, generate disorganized and chaotic clay fabrics, and provide more time for flocculation. Discrimination between pelagites and hemipelagites has important implications in the determination of turbidite event frequency and magnitude, which affects vertical connectivity and continuity of sand, deposited from multipartite turbidity currents. In addition, distinction between pelagites and hemipelagites provides a better understanding of mudrock reservoir architecture.

Description: The Molasse deposits of the Central Eastern Alps are partly incorporated into a fold and thrust belt that recently has come into exploration focus. The structural style and timing of deformation varies significantly alongstrike. Regional three-dimensional seismic and well data interpretation indicate three different structural segments from east to west: (1) The Sierning imbricates have a decollement close to the base of the Molasse sequence and consist of varying numbers of thrust sheets alongstrike. Early Miocene shortening of the Molasse is at least 6.2 km (3.9 mi). Overthrusting of the internal Penninic and Helvetic wedge since the Oligocene accommodated at least 25 km (15.5 mi) of additional shortening. (2) The Regau segment is dominated by one to two small thrust sheets above a shallow detachment. This segment is dominated by overthrusting of the Alpine wedge. (3) The Perwang imbricates consist of an Oligocene wedge with complex deformed thrust sheets above a detachment horizon in Upper Cretaceous marls. Minimum shortening in the imbricates is 18.5 km (11.5 mi) with overthrusting 33.3 km (20.7 mi). All shortening estimates have an uncertainty of approximately 20% to 35%. The laterally varying thrust-belt architecture results from predeformational conditions (e.g., sediment thickness, mechanical stratigraphy, and basement dip). In the Sierning imbricates, hydrocarbon trap definition and charge issues are exploration risks. In the Regau segment, exploration is focused on the subthrust play. The Perwang imbricates have hydrocarbon shows but no economic discoveries. Charge and seal issues are the main risks. The petroleum systems in the context of the structural evolution are not yet fully understood.

Description: Quartz is the principal framework mineral in clastic sediment reservoirs. In a frontier basin with sparse wells, the source of quartz in sandstones may be a predictor of the availability of medium- to coarse-grained quartz sand from plutonic sources, likely to provide good reservoirs. The Scotian Basin, offshore eastern Canada, was used to test this hypothesis because of its well-understood provenance history and geographic variability in known medium- to coarse-grained reservoir sandstones. The sources of detrital quartz in fine-grained sandstones were determined using hot-cathode cathodoluminescence (CL), supplemented by other petrographic techniques. The CL color shift for different quartz types was calibrated against the CL properties of representative source rocks in the hinterland, because generalizations in the literature do not precisely match our basin-specific observations. Grain size of sandstone exerts a strong control over quartz type, with plutonic-hypabyssal quartz and high-grade metamorphic quartz more abundant in coarse-grained sandstones and low-grade metamorphic quartz more abundant in fine-grained sandstones. Nevertheless, the analysis of fine-grained sandstones shows that plutonic-hypabyssal quartz is more abundant in fine-grained sandstones of the Sable subbasin than in those of the Abenaki subbasin. The abundance of plutonic-hypabyssal quartz correlates with the abundance of medium- to coarse-grained sandstone reservoirs in the Sable subbasin. This study suggests that, in frontier basins, the abundance of plutonic-hypabyssal quartz in fine-grained sandstones can be used as an indicator of available medium- to coarse-grained sandstone reservoir.

Description: The three-dimensional (3-D) geometry of fractures and fault-related dolomite is difficult to access with classical subsurface prospection tools. Therefore, we have investigated an outcrop to improve the subsurface prediction for complex dolomite bodies. This outcrop is located in the Etoile massif (southeastern France) within a fault-bend anticline. The sedimentary units are of Upper Triassic to lower Barremian age. The fold results from the Pyreneo-Provençal shortening during the Late Cretaceous to the Eocene. The anticline hosts three types of dolomite bodies: (1a) massive dolomite of middle to late Oxfordian age, (1b) syndepositional stratabound dolomite of Tithonian age, and (2) isolated dolomite bodies associated with fractures and faults. Large-scale geometries of fault-related dolomite bodies have been modeled in 3-D. The 3-D geometries of these bodies show diapir-, finger- and wall-like structures. These bodies are located close to the main thrusts, in strata of middle Oxfordian to early Barremian age and are linked to the compressive fold-bending phase during the Late Cretaceous. Fault-related dolomitization occurred because of magnesium removal from the hydraulic brecciation and the pressure solution of type 1 dolomite with overpressured fluids. These fluids flushed upward along the main thrust and laterally by following the reservoir property contrasts in the host rocks. Fault-related dolomite bodies are either spread far apart from faults in grainy limestones with good initial reservoir properties or are restricted to fault vicinity in muddy limestones with poor initial reservoir properties. The study of the structural and stratigraphic framework was essential in the understanding of the dolomitization process.

Description: An interpretation of geologic structure at King Sound in the Canning Basin was completed using airborne gravity gradient, magnetic, and seismic data. During the Late Devonian and Mississippian periods, the elevated part of the basement in the north was rimmed by carbonate reefs and redeposited carbonate debris, whereas in the south, siliciclastic submarine fans and turbidites were deposited along the margin of the basement in a deep-marine environment. Three principal lithologic units were identified from the vertical gravity gradient ( G DD ) in the basin: (1) the Fairfield Group carbonates of high density are interpreted to be the source of prominent positive gravity anomalies; (2) forereef debris and carbonate clastics reworked from carbonates higher up the slope or from the carbonate platform are interpreted to be the source of medium-density responses; and (3) turbidites, debris flows, and associated clastic basinal sequences of low density are interpreted to be the source of prominent negative gravity anomalies. Depth slices of G DD indicate the channelized nature of turbidite flows. In the lower section of the basin, intrasedimentary intrusives were identified from magnetic, G DD , seismic, and well data. Depth to magnetic basement calculation indicates that the surface of the Archean to Paleoproterozoic basement ranges from 3200 to 130 m (10,499–427 ft) below sea level. The northwest- and northeast-oriented south-dipping faults cut the basement and propagate upward into the sediments. A three-dimensional geologic model constructed for King Sound satisfies all known geologic constraints and is consistent with the gravity, magnetic, seismic, and well data.

Description: The evolution of porosity in shales with increasing maturity was examined in a suite of five New Albany Shale samples spanning a maturity range from immature (vitrinite reflectance, R o 0.35%) to postmature (R o 1.41%). Devonian to lower Mississippian New Albany Shale samples from the Illinois Basin used in this study contain marine type II kerogen having total organic carbon contents from 1.2 to 13.0 wt. %. Organic petrology, CO 2 and N 2 low-pressure adsorption, and mercury intrusion capillary pressure techniques were used to quantify pore volumes, pore sizes, and pore-size distributions. Increasing maturity of the New Albany Shale is paralleled by many changes in the characteristics of porosity. The total porosity of 9.1 vol. % in immature New Albany Shale decreases to 1.5 vol. % in the late mature sample, whereas total pore volumes decrease from 0.0365 to 0.0059 cm 3 /g in the same sequence. Reversing the trend at even higher maturity, the postmature New Albany Shale exhibits higher porosity and larger total pore volumes compared to the late mature sample. With increasing maturity, changes in total porosity and total pore volumes are accompanied by changes in pore-size distributions and relative proportions of micropores, mesopores, and macropores. Porosity-related variances are directly related to differences in the amount and character of the organic matter and mineralogical composition, but maturity exerts the dominant control upon these characteristics. We conclude that organic matter transformation due to hydrocarbon generation and migration is a pivotal cause of the observed porosity differences.

Description: In this case study, we used simulated seismic data from outcrops on Svalbard to analyze what seismic facies are composed of, what the dominating factors in forming the facies are, and which consequences this has for the interpretation results. Seismic facies analyses can be used to interpret environmental setting, depositional processes, and lithology. Here, we found that noise is the most important factor in forming the seismic facies. Noise is defined as all reflections that cannot be ascribed directly to the reservoir model. Effects from overburden and processing dominated, and the low-frequency content of the seismic section complicated the seismic facies analyses. The main reason for this is that the analysis relies heavily on identified internal patterns and low-angle terminations. Such patterns and terminations are easily created by the seismic method itself, by overburden effects, and by artifacts generated when processing the data. External form, strong amplitudes, and continuous reflections are robust seismic observations, whereas the internal pattern and terminations are commonly deceptive. Identification of boundaries based on predefined patterns of terminations does not work here, and uncritical use of seismic facies analysis in this interpretation case will create wrong reservoir models. Because of the size of the outcrops, the results from this analysis are relevant for reservoir-scale seismic interpretation and detailed interpretation for prospect evaluation in mature basins. For seismic interpretation at a more regional scale, it is probably less relevant.

Description: The Ordovician carbonate platform at the Yijianfang outcrop of the Bachu uplift region in the western Tarim Basin contains four types of genetic facies associations developed in the calciclastic slope-fan depositional system: an olistostrome zone, fan channels, lobes, and a marginal slope. The olistostrome zone is characterized by olistoliths and slump fans, whereas the fan channels and lobes are further divided into proximal and distal facies. The marginal slope deposits constitute the background sedimentation in which the calciclastic slope fans are intercalated. From proximal to distal parts of the fan channels and lobes, their scale gradually becomes smaller, and the size and sorting of grains become finer and better, respectively. Analysis of the stratigraphic framework indicates that the fans formed in the lower strata of the Upper Ordovician Lianglitage Formation in four high-frequency sequences (i.e., Pss1–Pss4). Field paleocurrent measurements indicate northeast-southwest depositional strike for the early platform margin of the Lianglitage Formation. Sediments in the calciclastic slope fans were derived from the platform margin, and evolution of the calciclastic slope fans was generally progradational from Pss1 to Pss2 and then continuously retrogradational from Pss2 to Pss4. The calciclastic slope fans in the outcrop area are not reservoir-prone rocks, but interpretation on these fans can provide useful information about potential hydrocarbon reservoirs along the platform margin. The P -wave velocity, S -wave velocity, and density variations in each genetic facies may be used to identify the subsurface calciclastic slope-fan depositional system.

Description: Reservoir properties of Upper Triassic–Middle Jurassic sandstones, Spitsbergen, are studied as part of a CO 2 storage pilot project in Longyearbyen. The reservoir formations show large contrasts in sandstone compositions, with unexpected low permeability despite moderate porosity values. Petrographic analyses were performed to investigate the influence and distribution of diagenesis. It is concluded that, because of various compaction, cementation, and dissolution processes, the sandstone porosity is mainly isolated molds and micropores and associated with fibrous illite and chamosite, explaining the low permeability. Diagenesis and the distribution of quartz cement is influenced by lithofacies and detrital compositions. Mineralogically immature sandstones (De Geerdalen Formation) show a homogeneous distribution of quartz cement overgrowths on quartz grains, distributed interstitial to labile grains and other cements (e.g., late calcite). The main silica source was from the dissolution of adjacent feldspar and labile grains as part of the chemical compaction. In contrast, quartz-dominated sandstones (Knorringfjellet Formation) show a heterogeneous patchy distribution of quartz cement influenced by the sedimentary bioturbation pattern, with silica sourced also from dissolution at clay-rich microstylolites. Phosphatic beds at the base and top of the formation are strongly influenced by marine eogenesis and reworking processes and associated with concentration of iron-rich authigenic minerals. The highest porosity appears in sand-supported conglomerate where moldic clay-mineral ooids contributed to reduce quartz cementation. The stratigraphic change from mineralogical immature (Triassic) to mature (uppermost Triassic–Jurassic) sandstone compositions is detected in wide areas of the Barents Shelf and has considerable implications for the distribution of sandstone reservoir properties.

Description: Innovative seismic forward modeling is used to illustrate the sensitivity within seismic data, and its application in the interpretation of onlap and pinch-out of terminating deep-water sandstones, two critical components in deep-water exploration and production. Sandstone quality, net-to-gross estimates, volume calculations, vertical connectivity, and stratigraphic trapping are all dependent on the sandstone extent and their seismic characteristics in these settings. However, seismic resolution is commonly insufficient to resolve the critical reservoir parameters. Seismic modeling of termination styles based on integrated outcrop and subsurface properties allows for depth- and resolution-focused predictive models to be built for improved subsurface analysis. This technique is currently underused as a method to better understand the sensitivity of seismic data to the target lithologies and their geometries. The Grès d'Annot Formation is a well-studied sand-prone deep-water system of Paleogene age, deposited in a bathymetrically complex setting. Six end-member termination styles are discussed, including three sand-prone styles—simple onlap (O s ), draping onlap (O d ), and bed thickening (O t )—and three heterolithic styles—advancing pinch-out (P a ), convergent pinch-out (P c ), and convergent thickening and pinch-out (P ct ). Local thickening close to the system margins is common in both sand-prone and heterolithic terminating strata and plays an important function in the appropriate distribution of sandstone. The outcrops are interpreted as potential (process) analogs for the complex sandstone distribution and termination patterns observed in plays like the Paleogene of the Gulf of Mexico and the Jurassic of the northern North Sea.

Description: Cenozoic rifted lacustrine basins in east China display three main basin types: (1) basins with steeply dipping boundary fault, whose hanging walls tilt along pivot points; (2) basins with listric boundary faults, whose hanging walls bend along flexural bending points; and (3) basins formed by earlier extensional rifting with later strike-slip movement superimposed. The sequence development is intimately linked to the tectonic movements in the area, where second-order sequences are regionally correlatable from basin to basin and relate to the large-scale tectonic movements in the region. Third-order sequences are related to local tectonic activity and are correlatable within basins, between subbasins, and sometimes, between neighboring basins. Detailed sequence-stratigraphic analysis and mapping of depositional systems demonstrate that sand-body distribution patterns are related to sequence-stratigraphic frameworks. For the three kinds of basins, the positions of pivot point zones, flexural bend zones, and strike-slip faults plus the syndepositional faults all control the distribution of depositional systems, systems tract, and sand bodies. These controlling factors can be attributed to different structural and stratigraphic features that change the accommodation. Structural elements include boundary faults, syndepositional faults, and abrupt changes in dip. Stratigraphic controls include preexisting surfaces with local channelization, paleobathymetric lows, and onlap onto clinoform slopes. The lowstand sand bodies deposited at the downdip end of these controlling factors constitute the current and future exploration targets for conventional reservoirs.

Description: Outcrops provide valuable information for the characterization of fracture networks. Sampling methods such as scanline sampling, window sampling, and circular scanline and window methods are available to measure fracture network characteristics in outcrops and from well cores. These methods vary in their application, the parameters they provide and, therefore, have advantages and limitations. We provide a critical review on the application of these sampling methods and apply them to evaluate two typical natural examples: (1) a large-scale satellite image from the Oman Mountains, Oman (120,000 m 2 [1,291,669 ft 2 ]), and (2) a small-scale outcrop at Craghouse Park, United Kingdom (19 m 2 [205 ft 2 ]). The differences in the results emphasize the importance to (1) systematically investigate the required minimum number of measurements for each sampling method and (2) quantify the influence of censored fractures on the estimation of fracture network parameters. Hence, a program was developed to analyze 1300 sampling areas from 9 artificial fracture networks with power-law length distributions. For the given settings, the lowest minimum number of measurements to adequately capture the statistical properties of fracture networks was found to be approximately 110 for the window sampling method, followed by the scanline sampling method with approximately 225. These numbers may serve as a guideline for the analyses of fracture populations with similar distributions. Furthermore, the window sampling method proved to be the method that is least sensitive to censoring bias. Reevaluating our natural examples with the window sampling method showed that the existing percentage of censored fractures significantly influences the accuracy of inferred fracture network parameters.

Description: In western Greece, the Ionian and pre-Apulian zones represent, respectively, the basin and the transitional zone (slope) to the Apulian platform. The Apulian platform constitutes the weakly deformed foreland of the external Hellenides. The pre-Apulian zone appears in the Ionian Islands and the eastern Ionian Sea, whereas the Apulian platform is exclusively found in the Ionian Sea. The Ionian zone consists of Triassic evaporites, Jurassic–upper Eocene (mostly pelagic carbonates, minor cherts, and shales), overlain by the Oligocene flysch. Organic-rich source rocks occur within Triassic evaporites and Jurassic–Cretaceous pelagic argillaceous-siliceous rocks. The pre-Apulian zone consists of Triassic to Miocene deposits, mainly mixed neritic-pelagic carbonates. Hydrocarbon source rocks include pelagic and hemipelagic deposits rich in marine organic material, although terrigenous organic matter is also found in siliciclastic layers. Apulian platform source rocks are mainly the organic-rich shales within the Triassic Burano evaporites. Western Greece contains major petroleum systems, which extend into the Ionian Sea. Ionian, pre-Apulian, and Apulian petroleum systems contribute to the probable hydrocarbon accumulations within the big offshore (Ionian Sea) anticlines. Western Greece contains important oil and gas shale reservoirs with a potential of unconventional exploration. Promising areas for hydrocarbons need systematic and detailed three-dimensional seismic data. Exploration for conventional petroleum reservoirs, through the interpretation of seismic profiles and the abundant surface geologic data, will provide the subsurface geometric characteristics of the unconventional reservoirs. Their exploitation should follow that of conventional hydrocarbons to benefit from the anticipated technological advances, eliminating environmental repercussions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Description: The Livingstone Range anticlinorium marks a hanging-wall ramp across which the Livingstone thrust cuts up eastward approximately 1000 m ([~]3280 ft) between regional decollements in the Devonian and the Jurassic strata. It is well exposed and provides actualistic models for exploration of analogous subsurface structures. More than 30 km (

Description: The velocity of elastic waves is the primary datum available for acquiring information about subsurface characteristics such as lithology and porosity. Cheap and quick (spatial coverage, ease of measurement) information of permeability can be achieved, if sonic velocity is used for permeability prediction, so we have investigated the use of velocity data to predict permeability. The compressional velocity from wireline logs and core plugs of the chalk reservoir in the South Arne field, North Sea, has been used for this study. We compared various methods of permeability prediction from velocities. The relationships between permeability and porosity from core data were first examined using Kozeny's equation. The data were analyzed for any correlations to the specific surface of the grain, Sg, and to the hydraulic property defined as the flow zone indicator (FZI). These two methods use two different approaches to enhance permeability prediction from Kozeny's equation. The FZI is based on a concept of a tortuous flow path in a granular bed. The Sg concept considers the pore space that is exposed to fluid flow and models permeability resulting from effective flow parallel to pressure drop. The porosity-permeability relationships were replaced by relationships between velocity of elastic waves and permeability using laboratory data, and the relationships were then applied to well-log data. We found that the permeability prediction in chalk and possibly other sediments with large surface areas could be improved significantly using the effective specific surface as the fluid-flow concept. The FZI unit is appropriate for highly permeable sedimentary rocks such as sandstones and limestones that have small surface areas.

Description: Multiple methods are currently used to collect, prepare, extract, and analyze near-surface migrated hydrocarbons from marine sediments to evaluate subsurface petroleum generation and entrapment. Few have been rigorously tested to evaluate their effectiveness. A Gulf of Mexico field calibration survey over the Marco Polo field was undertaken as part of an industry-funded research project to better understand previously published and unpublished seabed geochemical results and determine which gas and liquid hydrocarbon extraction methods best characterize migrated hydrocarbons in near-surface sediments. The Marco Polo calibration data set demonstrates the importance of targeted coring and sampling depth. To improve the detection of seabed migrated thermogenic hydrocarbons, core samples should be collected along major migration pathways (cross-stratal leakage features) identified by conventional deep seismic and high-resolution sea floor imaging. Not all targeted cores hit the designated feature, and thus, collecting replicates along key migration features is critical. Collecting sediment samples below the near-surface transition zone known as the "zone of maximum disturbance" is also important to avoid possible alteration effects and interference by recent organic matter. Geochemical analysis should include a full range of hydrocarbon types: light hydrocarbon gases (C1-C5), gasoline range (C5-C10+), and high-molecular-weight (HMW) hydrocarbons (C15+). The interstitial sediment gas data should be plotted on a total hydrocarbon gas ({Sigma} C1-C5) versus wet gas fraction ({Sigma} C2-C5/{Sigma} C1-C5) chart to identify background, fractionated, and anomalous populations. Compound-specific isotopic analysis on selected anomalous samples is critical to correctly identify migrated subsurface gases from near-surface generated microbial gases. Microdesorption bound gases did not provide gas compositions or compound-specific isotope ratios similar to the Marco Polo reservoir gases, and thus, the bound gas extraction is not recommended. A gasoline range analysis provides a new range of hydrocarbons rarely examined in surface geochemical studies that assist in identifying thermogenic hydrocarbons. Extraction gas chromatography and total scanning fluorescence (TSF) maximum fluorescence intensity provided information on the presence of thermogenic HMW hydrocarbons but did not work as well with the low-level microseepage samples. The TSF fluorogram signature was similar for both seep and regional reference (background) samples and did not help to identify migrated thermogenic hydrocarbons. The Marco Polo calibration study provides a framework to better understand how best to collect (targeted deep cores) and extract migrated hydrocarbons from near-surface marine sediments and to evaluate the results.

Description: The deeply buried synrift play of the South Viking Graben is characterized by highly variable reservoir quality. An integrated approach incorporating petrophysics, petrography, and one-dimensional basin modeling methods was applied to investigate these variations. Analysis shows that average porosities below 4000 m (〉13,123 ft) (vertical depth below sea floor) range from approximately 5% to as much as about 25% in comparable quartz arenitic sandstones. From porosity-depth trends, three porosity categories can be recognized (normal-, low-, and high-porosity sandstones). Normal-porosity sandstones fall along the regional average porosity-depth trend. Low-porosity sandstones have been subject to extensive quartz cementation as a consequence of a higher degree of thermal maturity and plot below the regional porosity-depth trend. High-porosity sandstones plot above the regional porosity-depth trend. Here, quartz cementation has been inhibited by grain-coating microquartz, and thus porosity has been preserved. Hydrocarbon emplacement has previously been thought to have inhibited quartz cementation in the study area, but this study concludes that the reservoirs are mainly water-wet, allowing for continued quartz cementation despite the presence of hydrocarbon pore fluids. Predicting the distribution of microquartz-coated sandstones and the degree of thermal maturity is therefore fundamental for successful exploration in the deeply buried parts of the synrift play. This study presents a regional and stratigraphic framework for such predictions that may be incorporated into play models in the area.

Description: The Livingstone Range anticlinorium (LRA) marks a major hanging-wall ramp where the Livingstone thrust cuts approximately 1000 m ([~]3281 ft) between regional decollement in the upper part of the Devonian Palliser Formation and the Jurassic Fernie Formation. Prethrusting and folding jasper {+/-} fluorite {+/-} sphalerite veins with halos of altered dolomitic host rock with high 87Sr/86Sr ratios (0.7094-0.7101) relative to most Paleozoic carbonate rocks (0.7081-0.7091) record percolation of fluids along basement faults that may also have contributed anomalously radiogenic strontium to diagenetically altered Paleozoic carbonate rocks throughout the Western Canada sedimentary basin. Fluid flow that occurred during thrust-propagation folding is recorded by dolomite {+/-} calcite veins, with{delta} 18O values that are similar to those of host rocks (-7.92 to -1.08{per thousand} Peedee belemnite). Anomalously high equilibrium temperatures (250 {+/-} 50{degrees}C) as determined by oxygen-isotope thermometry and slightly higher 87Sr/86Sr ratios relative to adjacent host rocks indicate that they formed from formation fluids and hot basement fluids in a rock-dominated system. Calcite veins with very low{delta} 18O values (-18 to -9{per thousand}) precipitated along faults that were active while the LRA was transported eastward by underlying thrust faults, uplifted, and rapidly cooled by infiltrating meteoric water. Thrusting created heating in the foreland basin ahead of the deformation because of the influx of thick insulating foreland basin sediments, causing thermal maturation of hydrocarbons. As thrusting deformation advanced through the rocks, infiltrating meteoric waters cooled the rocks and hydrocarbon maturation stopped. Structural traps accumulated hydrocarbons only if they were juxtaposed over both thermally favorable and hydrocarbon-favorable source rocks.

Description: Pleistocene fluvial, estuarine, marine, and deltaic depositional systems were identified in the uppermost 80 m (262 ft) of the central Gulf of Thailand modern continental shelf, situated approximately 70 m ([~]230 ft) below sea level. Integration of offshore three-dimensional (3-D) seismic reflection data, high-resolution shallow-penetration two-dimensional (2-D) seismic reflection sparker and boomer profiles, and shallow geotechnical borehole measurements enabled the identification of seven depositional sequences. The 3-D plan-view images at successive time slices exhibit single meandering channels (as much as 600 m [1969 ft] wide) and channel belts (as much as 10 km [6.2 mi] wide) deposited in the shelf during times of subaerial exposure. Additional geomorphic features imaged include incised valleys, interfluves, oxbow lakes, neck and chute cutoffs, and point-bar meander scrolls showing evidence of expansion and translation. The high-resolution 2-D profiles, with a tuning thickness of approximately 25 cm ([~]9.8 in.), enabled the discrimination of high-frequency stratigraphic discontinuities (sequence boundaries) and allowed a detailed bed-scale seismic facies characterization of fluvial (point bars), deltaic (clinoforms), estuarine, and marine deposits within a sequence-stratigraphic context. The complete succession shows that most fluvial systems lie within incised valleys in the lower parts of each depositional sequence, fluvial channels show a degradational stacking pattern, and no evidence of fluvial aggradation is observed; aggradation is limited to hemipelagic sedimentation during marine incursions. A shallow (

Description: With almost 200 coal-burning power plants in the region, the Ohio River Valley is an important region to evaluate potential formations for carbon dioxide (CO2) storage. In this study, we consider whether injection-induced stress changes affect the viability of the Rose Run Sandstone, considered as a potential effective storage unit. Our study uses a coupled geomechanical and reservoir simulator that couples fluid flow to induced stress and strain in all the significant stratigraphic units from the surface to the crystalline basement. The pressure and stress variations were modeled during CO2 injection, focusing on injection from a single well. The model uses a constant pressure condition on the boundary of the system. Both reservoir and surface deformation were simulated, and the possibility of reaching shear failure in the reservoir was tested. Carbon dioxide injection in the Rose Run Sandstone aquifer is not likely to cause any significant surface deformation. To consider the potential of increasing injectivity, simulation of a static fracture with a half-length of 300 m (984.3 ft) was considered. As the modeling shows that, with constant injection rate, the fracture can propagate beyond the propped length, a dynamic fracture propagation was also studied. This was achieved by allowing the fracture to grow as a function of a propagation criteria based on effective stress. Because of the favorable stress state of the Rose Run Sandstone, the propagation is primarily in the lateral direction, and no upward fracture propagation through the cap rock has been observed in the model. Finally, we demonstrate that dynamic fracture propagation significantly increases the possible injection rates, and its modeling is useful for determining optimal injection rates.

Description: A by-product of petroleum extraction, produced waters (PWs) containing selenium (Se), arsenic (As), and low-molecular-weight organics (LMWOs) may be generated. Pilot-scale constructed wetland treatment systems (CWTSs) were designed and built to evaluate the removal of these constituents from simulated fresh PW (SFPW). Study objectives were to characterize a fresh PW and determine the constituents of concern (COC); formulate an SFPW; design and build a pilot-scale CWTS for SFPW; and measure performance (i.e., COC removal rates and extents). The treatment goals for this study were to decrease Se concentration in SFPW from approximately 50 {micro}g/L to less than 5 {micro}g/L via microbial reduction; decrease As concentration in SFPW from approximately 20 {micro}g/L to less than 5 {micro}g/L via iron coprecipitation; and decrease LMWO concentration in SFPW from approximately 25 mg/L to less than 1 mg/L via biodegradation. To determine COC removal rates and extents and environmental factors, measurements included analysis of Se, As, LMWOs, dissolved oxygen, conductivity, pH, oxidation-reduction potential, alkalinity, hardness, and temperature. Mean outflow Se concentrations ranged from less than 1 to 47.1 {micro}g/L. Mean outflow As concentrations ranged from 5.7 to 9.5 {micro}g/L, and the mean outflow LMWO concentrations were less than 1 mg/L for all treatments and the untreated control. Organic carbon amendments had a significant effect on Se removal and no effect on As or LMWO removal. This pilot-scale study illustrates that CWTSs can enhance Se removal from SFPW and that removal can be achieved to meet stringent discharge limits. More research is needed to advance the techniques of As removal in CWTSs designed to simultaneously target Se.

Description: One method to beneficially use water produced from coalbed methane (CBM) extraction is subsurface drip irrigation (SDI) of croplands. In SDI systems, treated CBM water (injectate) is supplied to the soil at depth, with the purpose of preventing the buildup of detrimental salts near the surface. The technology is expanding within the Powder River Basin, but little research has been published on its environmental impacts. This article reports on initial results from tracking water and solutes from the injected CBM-produced waters at an SDI system in Johnson County, Wyoming. In the first year of SDI operation, soil moisture significantly increased in the SDI areas, but well water levels increased only modestly, suggesting that most of the water added was stored in the vadose zone or lost to evapotranspiration. The injectate has lower concentrations of most inorganic constituents relative to ambient groundwater at the site but exhibits a high sodium adsorption ratio. Changes in groundwater chemistry during the same period of SDI operation were small; the increase in groundwater-specific conductance relative to pre-SDI conditions was observed in a single well. Conversely, groundwater samples collected beneath another SDI field showed decreased concentrations of several constituents since the SDI operation. Groundwater-specific conductance at the 12 other wells showed no significant changes. Major controls on and compositional variability of groundwater, surface water, and soil water chemistry are discussed in detail. Findings from this research provide an understanding of water and salt dynamics associated with SDI systems using CBM-produced water.

Description: Using a process-based approach, a pilot-scale constructed wetland system was designed and built for treating water produced from an oil field in sub-Saharan Africa. The characteristics of the oil field-produced water were compared with water quality guidelines for irrigating crops and watering livestock to identify constituents of concern (COC) requiring treatment. The COC identified in the produced water include oil, grease, and metals (Zn, Ni, Fe, Mn). A pilot-scale constructed wetland treatment system was then designed and built based on biogeochemical pathways (i.e., sorption, oxidation, and reduction) for transferring and transforming the identified COC to achieve target concentrations meeting water quality guidelines. The pilot-scale treatment system consisted of three series of wetland cells, with four cells in each series. Two series of subsurface flow wetland cells were constructed with each cell having a two-layer hydrosoil of pea gravel and medium-size gravel planted with Phragmites australis. In addition, a series of free water surface wetland cells was constructed, with each cell containing sandy hydrosoil and planted with Typha latifolia. The design allows adjustment of parameters (i.e., hydraulic retention time and organic content of the hydrosoil) to promote the conditions needed to achieve treatment of COC through the identified biogeochemical pathways. This study provides an example of the design and construction of a pilot-scale wetland treatment system using a process-based approach.

Description: One of the many factors affecting the petroleum potential of thin-skinned thrust belts and their foreland plates is late orogenic normal, reverse, and strike-slip faulting, which occurs in the foreland plates and occasionally extends into the overlying thin-skinned thrust belts. This tectonism is typically active during the late stages of convergent orogeny, when subduction-driven thin-skinned thrusting ceases and the remaining convergence and geometric adjustment occur mainly within the foreland plate. The distribution, character, and orientation of particular structures generated during this collisional event, however, is to a great extent determined by the geometries of crustal blocks and orientations of preexisting faults and other weak zones within the foreland plates. As a result, despite the similar orogenic stress field, the dominant geometric expressions in various parts of the orogenic system may be different. Because massive petroleum generation and migration in both the thrust belt and in the foreland plate commonly occur later in the orogenic phase, late orogenic faulting can critically affect the whole petroleum system, including the generation, migration, and preservation of hydrocarbons. The potential existence of late orogenic tectonics should then be examined thoroughly, especially when exploring for petroleum at deeper structural levels of thrust belts and the underlying foreland plates. This is demonstrated by three examples from the Vienna Basin, Eastern Carpathians, and Dinarides-Hellenides, all parts of the European Alpine system. Several other examples, including the Rocky Mountain Laramide uplifts, the Eastern Cordillera in Colombia, and Timan-Pechora inverted structures in Russia, are mentioned to document the common occurrence of late orogenic faulting in orogenic systems.

Description: The material properties of sedimentary rocks are controlled by a range of parameters, including grain size, sorting, and modification of the original sediment through the diagenetic processes of compaction and cementation. To isolate the effects of diagenesis and explore how they modify permeability, we quantified changes in grain and pore morphology accompanying progressive diagenesis of a simple system: a well-sorted, variably quartz-cemented quartz arenite of relatively uniform grain size. The most common type of authigenic cement in sandstones, quartz overgrowths, is responsible for significant porosity and permeability reduction. The distribution of overgrowths is controlled by available pore space and the crystallographic orientations of individual quartz grains. We show that progressive quartz cementation modifies the grain framework in consistent, predictable ways. Detailed microstructural characterization and multiple regression analyses demonstrate that both the number and length of grain contacts increase as the number of pores increases and the number of large well-connected pores decreases with progressive diagenesis. The aforementioned changes progressively alter pore shape and reduce pore-size variability and bulk permeability. These systematic variations in the pore network correlate with changes in permeability, such that we can use our data to calibrate the Kozeny-Carmen relation, demonstrating that it is possible to refine predictions of permeability based on knowledge of the sedimentary system.

Description: This study is an investigation of aquitard characteristics and hydrocarbon entrapment in the Upper Devonian strata of the Bashaw area of Alberta, Canada. Oil and gas are trapped at two stratigraphic levels, the Leduc-aged Bashaw Reef Complex (D-3) and the Camrose Member-Nisku Formation (D-2), which are separated by a low-permeability aquitard of the Ireton Formation, a marl with variable carbonate content. The Ireton aquitard provides the principal control to cross-formational fluid flow in the area. Over much of the Bashaw Reef Complex, the Ireton aquitard ranges from approximately 25 m (~82 ft) thick to less than 1 m ( 32.8 ft) of Ireton aquitard. Where the overlying Ireton aquitard drape is less than 10 m (

Description: Terrestrial light detection and ranging (LIDAR) surveys offer potential enrichment of outcrop-based research efforts to characterize fracture networks and assess their impact on subsurface fluid flow. Here, we explore two methods to extract the three-dimensional (3-D) positions of natural fractures from a LIDAR survey collected at a roadcut through the Cretaceous Austin Chalk: (1) a manual method using the University of California, Davis, Keck Center for Active Visualization in the Earth Sciences and (2) a semiautomated method based on mean normal and Gaussian curvature surface classification. Each extraction method captures the characteristic frequencies and orientations of the primary fracture sets that we identified in the field, yet they extract secondary fracture sets with varying ability. After making assumptions regarding fracture lengths and apertures, the extracted fractures served as a basis to construct a discrete fracture network (DFN) that agrees with field observations and a priori knowledge of fracture network systems. Using this DFN, we performed flow simulations for two hypothetical scenarios: with and without secondary fracture sets. The results of these two scenarios indicate that for this particular fracture network, secondary fracture sets marginally impact ([~]10% change) the breakthrough time of water injected into an oil-filled reservoir. Our work provides a prototype workflow that links outcrop fracture observations to 3-D DFN model flow simulations using LIDAR data, an approach that offers some improvement over traditional field-based DFN constructions. In addition, the techniques we used to extract fractures may prove applicable to other outcrop studies with different research goals.

Description: Experimental modeling is used to study the geometry and evolution of structures and related secondary faults along releasing bends and offsets and restraining bends on strike-slip faults. The controls of the relative positions of adjacent strike-slip faults on the geometry of the structures and the difference in geometries between bends and offsets are investigated. A new method of laser scanning is used to map the geometry and evolution of the structures and related faults. The models show that oblique releasing bends connecting approaching faults result in spindle-shaped basins, whereas transverse bends result in more S-shaped or rhomboidal basins. Offsets result in the distribution of strain over a wider area and a larger number of faults compared with preexisting bends, which result in fewer well-defined basin-bounding faults. Secondary faults include R, R', and Y Riedel shears near the main strike-slip faults and oblique normal faults in the center of the basin. Fault patterns exhibit en echelon geometries with a progressive step down into the deepest parts of the basin. Symmetric, asymmetric, and double basins may form in any of the structural settings, depending on the slip distribution among faults on the basin margins. For restraining bends, oblique (45{degrees}) bends connecting approaching faults result in spindle-shaped uplifts, whereas transverse or oblique (135{degrees}) bends connecting overlapping faults result in more rhomboidal or rectangular uplifts. The fold trends are at increasingly higher angles with the strike faults for transverse and oblique (135{degrees}) bends. Secondary faults include en echelon reverse faults, which typically form along the steep limbs of asymmetric uplifts, normal faults, which are transverse or oblique to the axis of the structure, and R, R', and Y Riedel shears near the main strike-slip faults. The aspect ratios of the basins and uplifts increase with increasing displacement on the strike-slip faults. The results of these models can be used to interpret the structural and fault geometries in surface and subsurface structures formed along strike-slip faults.

Description: We undertake a multidisciplinary investigation into the distribution of asphalt in the Anacacho Limestone in an effort to decipher the potential roles of fractures and faults on secondary hydrocarbon migration. Field relationships between fractures, faults, and asphalt are evaluated at an asphaltic limestone mine near Uvalde, Texas. Based on their distributions, geometries, and structural relationships, we infer that normal faults provided vertical flow paths through the Anacacho Limestone, whereas strata-bound fractures enhanced lateral permeability. Variograms calculated from 75 subsurface measurements indicate that the asphalt concentration is anisotropically correlated and that the longest correlation length points in the mean strike direction of fractures and faults. A globally positioned laser rangefinder is used to measure faults and stratigraphic contacts within the mine. That data are then combined with lithologic descriptions from surrounding subsurface wells to construct a three-dimensional (3-D) model of the Anacacho Limestone. When an ordinary block-kriging algorithm populates the model with asphalt concentration estimates, the high values align along a trend that connects the two largest normal fault zones at the mine. The 3-D model provides a framework to numerically simulate secondary hydrocarbon migration. We test numerous hydrocarbon migration scenarios by adjusting simulation parameters within physically realistic ranges until producing an oil saturation field that agrees with asphalt concentration estimates. Our best match simulation indicates that oil entered the Anacacho Limestone through normal faults, that regional aquifer flow impacted oil flow, and that fractures increased the horizontal permeability of the formation by an order of magnitude along their strike direction.

Description: Vertical permeability is a critical parameter to estimate when modeling tidally influenced deltaic successions. The Campanian Sego Sandstone, in the Book Cliffs of Utah, is an outcrop analog for tidal systems with primary reservoirs being deposited as tidal bars in both confined and unconfined settings. A simple sand-shale model was used to quantify the effective vertical permeability using the shale character of the Sego Sandstone. Shale lengths, widths, thicknesses, and frequencies were measured from high-resolution light detection and ranging point clouds. Shales in confined tidal bars are approximately three times as long (mean, 16.3 m [53.5 ft]) and as wide (mean, 5.52 m [18.1 ft]). Within unconfined tidal bars, shales are roughly equidimensional (mean length, 18.6 m [61.0 ft]; mean width, 18.3 m [60.0 ft]). The different shale dimensions of confined and unconfined tidal bars result in different effective vertical permeability distributions, indicating that these two bar types behave differently under conditions of fluid flow. In analogous reservoirs, composed primarily of tidal bars, it is essential to differentiate and map confined and unconfined tidal environments.

Description: The J sandstone comprises less than 46 m (151 ft) of sandstone-dominated strata within the mudrock-dominated lower Upper Cretaceous succession of northwestern Nebraska. The unit is a prolific hydrocarbon producer in this region (Denver-Julesburg Basin), but its lithostratigraphic and sequence-stratigraphic framework, critical for reservoir characterization and mapping, is poorly known. We have achieved an improved understanding of depositional history and sequence stratigraphy by describing and correlating cores and wireline logs from wells within Sioux, Dawes, and Box Butte counties, Nebraska, and Niobrara and Goshen counties, Wyoming. Coals, paleosols, fluvial or inner estuarine sandstones, estuarine mudstones, fluvial conglomerate, shoreface sandstone, and reworked volcanic fallout (bentonite) lithofacies were identified. Trace fossil assemblages representing stressed expressions of the Skolithos and Cruziana ichnofacies are common. These lithofacies are arranged vertically into three erosionally based cycles, each less than 28 m (92 ft) thick, and each grade upward from fluvial or inner estuarine sandstones into estuarine mudstones and in turn into shoreface sandstones. The lateral and vertical stacking patterns of the lithofacies are complex, however, and the upper cycles appear to fill space eroded into the underlying ones. Northeast-southwest-elongate isochore trends appear in all three cycles. Lithofacies transition downdip from inner estuarine sandstones in the northeast to estuarine basin mudstones and shoreface sandstones toward the southwest. Detrital mineralogy indicates an easterly (cratonic) provenance for the entire unit. Our data suggest that the J sandstone in northwestern Nebraska accumulated in wave-dominated estuarine settings, as part of a long-lived transgressive systems tract. The unit as a whole occupies a complexly incised landscape cut during a third-order lowstand ca. 98 Ma. Coeval cycles of similar magnitude throughout the Western Interior suggest that the three cycles represent eustatic fluctuations. The highest quality reservoirs occur at the base of the unit in inner estuarine lithofacies in the central and southwestern parts of the study area.

Description: The Chezhen Basin has highly representative structural features of the Jiyang depression, Bohai Bay area. The structural geometry and the boundary fault linkage exert a strong influence on basin development and depositional environment. Based on structural analysis, at least six early fault segments are identified in the northern boundary of the Chezhen Basin. These fault segments are important in controlling stratal architecture and distribution. The antecedent structures controlled subbasin initiation and development. The Cenozoic rift initiated in the early Eocene with the development of six isolated fault segments associated with deposition of the Es4 member. During the deposition of the lower Es3 member, these six fault segments quickly linked and formed the present architecture frame. Fault linkage has not resulted in a redistribution of displacement. With the expansion of the Chezhen Basin, the depocenters of the upper strata were kept in nearly the same sites until the early Miocene, then the activity of the Chengnan fault ceased. Fault linkage is a significant event in basin evolution, and its process may be very rapid. However, the fault linkage exerted considerable control on sedimentation and evolution of the basin. This study demonstrates that it is necessary to integrate structural and stratigraphic data to reconstruct the temporal and spatial evolution of normal fault zones.

Description: A hydrostratigraphic model has been proposed based on the spatial distribution of aquitards, aquifers, aquicludes, recharge-discharge areas, salinity, mineralization, hydraulic head, diagenesis, and biodegradation information overlain with source rock potential, nature, and dispersal of hydrocarbons in the Mandapeta-Endamuru area, Krishna Godavari rift basin. This has resulted in understanding the verticolateral hydrodynamics and accumulation of gaseous hydrocarbons and variance in their geochemical properties. Three hydrogeologic systems are identified within the Mesozoic, and the associated gaseous hydrocarbons are characterized by their wetness and fingerprint Gastar diagrams. Temporal distribution of the salinity isolith in the vertical geologic column defines the intensity of meteoric infiltration and saline water percolation. In the Mandapeta subbasin, older formations are found to be less saline than the younger ones, indicating salinity inversion. Reservoirs of higher hydraulic heads are associated with gaseous hydrocarbons. The observed variation in hydraulic heads of the Mandapeta and Gollapalli aquifers is attributed possibly to the intervening Red bed aquitard acting as a seal. Areas of fault conduits are identified that facilitated the upward migration of hydrocarbons while allowing the percolation of infiltrated waters and further causing selective segregation of minerals. Vertical superimposition of different hydrogeologic systems and relative formation contacts also controlled the diffusion and nature of gaseous hydrocarbons. A composite hydrogeologic model has been framed based on studies for understanding the recharge-discharge dynamics incorporating seismic inputs.

Description: Mesozoic tectonic inversion in the Neuquen Basin of west-central Argentina was investigated by analyzing a three-dimensional seismic and borehole data set over prominent inversion structures related to transpressional tectonics along the Huincul arch. This conspicuous strike-slip deformation has been active since the Early Jurassic to Early Cretaceous and caused the reactivation of normal faults and the inversion of Triassic half grabens, some of which are imaged by the seismic data. Detailed structural and stratigraphic mapping allowed the identification of two main fault systems associated with inversion structures: (1) deep faults that affected basement and synrift strata where preexisting faults were selectively reactivated during inversion based on their length and (2) shallow faults that affected postrift and syninversion strata. Normal faults formed at high angle to the reactivated half-graben bounding fault as a result of hanging-wall expansion and internal deformation as it accommodated the shape of the curved footwall during oblique inversion. Structural restorations suggest that contraction during inversion was initially accommodated by folding and internal deformation of synrift sedimentary wedges, followed by displacement along half-graben bounding faults. We suspect that during late inversion, the weight of the overburden inhibited additional fault displacement and folding became the main shortening-accommodating mechanism. Natural examples described in this study exhibit significant along-strike variation in structural style and high structural complexity associated with relatively small amounts of inversion, which suggest the need for incorporating more complex deformation scenarios into analog models. Fault framework development and its linkage to a specific mechanism (e.g., hanging-wall deformation because of oblique inversion) enables the predictive analysis of subseismic faulting and fracture distribution, which can impact our understanding of the petroleum systems in the Neuquen Basin's northern embayment, especially regarding the significant fault development within the Cuyo Group, which may impact the Los Molles petroleum system.

Description: Primary basins form stratigraphically continuous successions on autochthonous salt and, therefore, in the northern Gulf of Mexico, contain all the components of a petroleum system (source, reservoir, trap, and seal). Most primary basins are encased entirely in salt or in some combination of salt and welds. Petroleum exploration in the deep-water Gulf of Mexico is currently focused on primary basin targets and increasingly those at their lateral boundaries. However, as these boundaries are commonly poorly imaged, robust structural models are critical to interpretation of their structural evolution and relative petroleum system risk. Using three-dimensional seismic data, we define three tectonostratigraphic provinces that characterize primary basin depocenters: (1) a disconnected salt-stock-canopy province in Mississippi Canyon; (2) an amalgamated salt-stock-canopy province in northern Atwater Valley, southeastern Green Canyon, Walker Ridge, and southern Keathley Canyon; and (3) a bucket-weld province in western Green Canyon, Garden Banks, and northern Keathley Canyon. We recognize six trap types in the primary basins: (1) autochthonous salt-cored folds, (2) turtle structures, (3) base-of-salt truncations, (4) salt feeders, (5) salt ridges, and (6) bucket welds. Most primary basin explorations to date have targeted traps in one of the first four styles. Future primary basin exploration will increasingly focus on the traps formed by bucket welds and salt-cored ridges. The contrasting evolution of these features has implications for reservoir continuity, charge access, and trap configuration. Of primary basin boundary trap types, salt feeders have the lowest petroleum system risk followed by bucket welds, with salt-cored ridges having the highest risk.