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  • 1
    Publication Date: 2017-11-16
    Description: This paper shows how nonuniform source–receiver spacing in a three-dimensional (3-D) land acquisition creates footprints that could easily be mistaken for geology. In a 3-D time-migrated seismic volume from the midcontinent United States, amplitude extraction along the top of the Mississippian limestone formation shows a sinkhole-like feature, which is justified from a depositional perspective. However, an inspection of the acquisition layout shows that the sinkhole is a replica of the fold distribution. In land surveys where source and receivers seldom have a regular distribution and for unconventional plays that are not developed through patterned drilling, a thorough review of processing and acquisition parameters is necessary before interpreting amplitude maps.
    Print ISSN: 0149-1423
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  • 2
    Publication Date: 2017-11-16
    Description: We use experimental (analog) models to examine the three-dimensional (3-D) fault geometries and interactions that develop during two phases of noncoaxial extension. In the models, a homogeneous layer of wet clay undergoes two phases of extension whose directions differ by 45°. The resulting fault pattern varies significantly with depth. At shallow levels, second-phase normal faults accommodate most second-phase extension. At depth, both second-phase normal faults and reactivated, first-phase faults with oblique slip accommodate most second-phase extension. A variety of interactions occurs between first-phase and second-phase faults. One interaction involves the upward propagation of second-phase faults from tips of reactivated, blind, first-phase faults. These hybrid faults have deep segments that strike subperpendicular to the first-phase extension direction and shallow segments whose strike varies with depth, becoming increasingly subperpendicular to the second-phase extension direction at shallow levels. A second interaction involves the nucleation of second-phase normal faults on the surfaces of reactivated, first-phase faults. These splay faults propagate upward and laterally from their nucleation sites into the hanging walls of the first-phase faults. As they propagate, they commonly encounter and link with different first-phase faults. The resulting composite faults have zigzag geometries in both map and cross-sectional views. A third interaction involves either the termination of second-phase antithetic normal faults against or near first-phase faults or the offset of first-phase faults by second-phase antithetic normal faults. The 3-D fault patterns and interactions within our models closely resemble those within the Taranaki basin of offshore New Zealand and Milne Point on Alaska’s North Slope.
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  • 3
    Publication Date: 2017-11-16
    Description: Fresh cores from tight-rock samples of subsurface hydrocarbon reservoirs retain mobile fluids. These fluids have complex chemical compositions and a large spectrum of molecules with different diameters and polarities. When investigated using high-resolution field-emission scanning electron microscopy (SEM), the imposed vacuum over hours of time causes pore fluids trapped in the rock sample to flow and interact with the mineral matrix. This paper reports the capillary fluid dynamics effect observed on freshly milled cross sections of tight chalk at high resolution. Multiphase fluid dynamic simulations confirm the aggregation of heavier fluid molecules on the geometrical irregularities of the pore space. As a consequence of this pitfall, the differentiation of solid organic matter versus variably viscous hydrocarbons from SEM data is subject to a fundamental revision.
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  • 4
    Publication Date: 2017-11-16
    Description: This study analyzed crude oils from the lower part of the third member of the Eocene Shahejie Formation (Es 3 L ) and three prospective source rocks from the Shulu sag, Bohai Bay basin, eastern China, using a variety of organic geochemical methods. Biomarker characteristics were used to interpret source rock organic matter input and depositional environment, and oil–source rock correlation. The biomarker data indicate that the crude oils originated from the Es 3 L source rock, which contains a mixture of plankton and land plant organic matters deposited in brackish–fresh water under reducing conditions. The oil in the Es 3 L is self-sourced instead of migrated from the overlying source rocks. The petroleum generation potential of the Es 3 L source rock was evaluated using organic geochemistry. Total organic carbon (TOC) values for approximately 100 samples are between 1.02 and 4.92 wt. %, and hydrogen indices range from 285 to 810 mg hydrocarbons/g TOC. The Es 3 L source rock contains mainly type II and III kerogen, and most of the samples are thermally mature. The data show that the Es 3 L source rock has good potential for liquid hydrocarbon generation. The Es 3 L rock also acts as the oil reservoir, having very low bulk porosity and permeability. Various types of storage space in the marlstone and carbonate rudstone in the Es 3 L of the Shulu sag include (1) fractures, (2) intergranular pores, (3) dissolution pores, (4) organic matter pores, (5) intragranular pores, and (6) seams around gravels. Pore size ranges from nanometers to millimeters. Because the oil was generated and stored in Es 3 L strata, which lack any obvious trap and seal and have low permeability, the unit represents a continuous petroleum accumulation.
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  • 5
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2017-11-16
    Description: The Fort Worth basin in northcentral Texas is a major shale-gas producer, yet its subsidence history and relationship to the Ouachita fold-thrust belt have not been well understood. We studied the depositional patterns of the basin during the late Paleozoic by correlating well logs and constructing structure and isopach maps. We then modeled the one-dimensional (1-D) and two-dimensional subsidence history of the basin and constrained its relationship to the Ouachita orogen. Because the super-Middle Pennsylvanian strata were largely eroded in the region, adding uncertainty to the subsidence reconstruction, we used PetroMod 1-D to conduct thermal-maturation modeling to constrain the post-Middle Pennsylvanian burial and exhumation history by matching the modeled vitrinite reflectance with measured vitrinite reflectance along five depth profiles. Our results of depositional patterns show that the tectonic uplift of the Muenster uplift to the northeast of the basin influenced subsidence as early as the Middle Mississippian, and the Ouachita orogen became the primary tectonic load by the late Middle Pennsylvanian when the depocenter shifted to the east. Our results show that the basin experienced 3.7–5.2 km (12,100–17,100 ft) of burial during the Pennsylvanian, and the burial depth deepens toward the east. We attributed the causes of deep Pennsylvanian burial and its spatial variation to flexural subsidence that continued into the Late Pennsylvanian in response to the growth of the Ouachita orogen and southeastward suturing of Laurentia and Gondwana. The modeling results also suggest that the Mississippian Barnett Shale reached the gas maturation window during the Middle–Late Pennsylvanian.
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  • 6
    Publication Date: 2017-11-16
    Description: The geochemistry and reservoir characteristics of the lacustrine shale in the Eocene Dongying depression are described in detail based on thin-section and field-emission–scanning electron microscope observations of well cores combined with x-ray diffraction, physical property testing, and geochemical indicators. The Eocene Shahejie (Es) Formation Es4s–Es3x shale member is predominantly carbonate, clay minerals, and quartz. Six lithofacies were identified: (1) laminated limestone (organic-rich laminated limestone and organic-poor laminated limestone), (2) laminated marl, (3) laminated calcareous mudstone, (4) laminated dolomite mudstone, (5) laminated gypsum mudstone, and (6) massive mudstone. The Es4s–Es3x shale samples from three cored wells had total organic carbon (TOC) contents in the range of 0.58 to 11.4 wt. %, with an average of 3.17 wt. %. The hydrocarbon generation potential (free hydrocarbons [S1] + the hydrocarbons cracked from kerogen [S2]) values range from 2.53 to 87.68 mg/g, with an average of 24.19 mg/g. The Es4s–Es3x shale of the Dongying depression has a high organic-matter content with very good or excellent hydrocarbon generation potential. The organic maceral composition is predominantly sapropelinite (up to 95%). The hydrogen index (being S2/TOC) versus the maximum yield temperature of pyrolysate ( T max ) indicates that the organic matter is predominantly type I kerogen, which contains a high proportion of convertible organic carbon. The Es4s–Es3x shale is thermally mature and within the oil window, with the vitrinite reflectance values ranging from 0.46% to 0.74% and the T max value ranging from 413°C to 450°C, with the average being 442°C. The shale contains interparticle pores, organic-matter pores, dissolution pores, intracrystalline pores, interlaminar fractures, tectonic fractures, and abnormal-pressure fractures. The primary matrix pore storage is secondary recrystallized intercrystal pores and dissolution pores that formed during thermal maturation of organic matter. The TOC content and effective thickness of the organic-rich shales are the primary factors for hydrocarbon generation. The reservoir capacity is related to the scale, abundance, and connectivity of pore spaces, which are controlled by the characteristics of the lithofacies, mineral composition, TOC content, and microfractures.
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  • 7
    Publication Date: 2017-11-16
    Description: A succession of four deep-water lobe complexes deposited within a salt-controlled minibasin have been imaged in unprecedented detail on high-resolution, high-frequency, three-dimensional seismic-reflection data. The ponded interval was deposited over approximately 2.7 m.y. and consists of four discrete sequences, each of which contains one lobe complex. A systematic change exists in the shape and orientation of the lobe complexes through time: the two older lobe complexes are oriented broadly north–south and are up to 10 km (6 mi) long by 5 km (3 mi) wide, whereas the youngest lobe complexes are oriented southeast–northwest and have a rounder shape (9 km [6 mi] long by 8 km [5 mi] wide). The north–to-south migration of the feeder-channel entry point and the change in lobe-complex orientation are attributed to growth of the basin-bounding salt structures. Each lobe complex is composed of a feeder channel, multiple individual lobes formed of a trunk channel, and a diverging network of smaller distributary channels, commonly fringed by a high-amplitude band. The lobes are on average 1.6 km (1 mi) long by 1.3 km (0.8 mi) wide and are fed by trunk channels that range from 60 to 200 m (197 ft to 656 ft) wide, with thicknesses up to 15 m (49 ft). Variations in lobe shape and spatial location are driven by the response of the lobes to topographic growth along the edge of the basin and inherited seabed relief generated by previous lobe growth. In areas where lobe development is constrained by structural growth along the edge of the basin, the lobes become elongated and divert away from the growing topography. Lobe complexes of similar scales have been described in detail in outcrops and in unconfined settings on the sea floor, but this is the first study to describe these systems in such detail in the subsurface, resolving the individual lobes and lobe elements within a ponded intraslope basin. The high-resolution plan-view images help bridge the gap between the fine-scale sedimentological studies that have been carried out on lobe complexes and sheet sands in outcrop for the past 20 yr and more recent research on less well-resolved seismically imaged systems. The sheet sands described in outcrop studies can be correlated with features seen in the plan-view amplitude extraction maps. We record densely channelized lobes passing laterally into more branched, thinner channels and lobe elements then terminating in a high-amplitude fringe. We relate these seismic characteristics to outcrop facies of channelized, amalgamated, and layered sheets.
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  • 8
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    American Association of Petroleum Geologists (AAPG)
    Publication Date: 2017-11-16
    Description: Compaction disequilibrium is a widely accepted cause of overpressure, especially in clay-rich, rapidly deposited sediments. Clay diagenesis has been associated with the occurrence of overpressure greater than the compaction disequilibrium overpressure. These observations have led to the expectation that overpressure will be greater than the compaction disequilibrium contribution when clay diagenesis occurs within an overpressured mudstone. Clay diagenesis have been reported in a Pliocene section of a well from the Gulf of Mexico, offshore Louisiana. Pressure and log data from that well indicate that despite clay diagenesis, the overpressure can be attributed solely to compaction disequilibrium. This paper examines the whole mudstone and clay mineralogy composition and petrophysical characteristics of the offshore Louisiana well with clay diagenesis, but without a diagenesis contribution to overpressure and contrasts that data with results from other clay diagenesis and petrophysical studies. The comparison suggests that the offshore Louisiana well was relatively smectite poor compared with wells from regions associated with a clay diagenesis contribution to overpressure. The lower smectite content resulted in a lower percentage of reacted volume that was insufficient to allow the load transfer often associated with clay diagenesis. Petrophysical features of the offshore Louisiana well and nearby wells differ from the features associated with clay diagenesis in other Gulf of Mexico wells and a limited number of international wells. Comparison of location, age, depositional package, clay mineralogy, and petrophysical features suggests that provenance may control the occurrence of Gulf of Mexico mudstones that do not experience increased overpressure as a result of clay diagenesis.
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  • 9
    Publication Date: 2017-10-17
    Description: Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO 4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.
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  • 10
    Publication Date: 2017-10-17
    Description: This study evaluates the proportion, length, and effective properties of thin (0.003–0.7 m [0.01–2.3 ft]) shale beds and drapes in tidally influenced channels within a compound valley fill with a focus on estimating geologically based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial–tidal systems with primary reservoirs being deposited as tidally influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging–derived digital outcrop models have been used to characterize shale length, width, thickness, and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in valley 1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in valley 2 (V2) were abundant, short, common, and equidimensional, suggesting deposition by more tidally influenced meandering rivers. Short, frequent, and equidimensional shales in valley 3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone–shale model was used to estimate the effects of shales on vertical to horizontal permeability ratio ( \[{k}_{v}/{k}_{h} \] ). The unique character of each depositional unit was reflected in resultant \[{k}_{v}/{k}_{h} \] distributions. The valley fill deposits, V1, V2, and V3, had average \[{k}_{v}/{k}_{h} \] ratios of 0.11, 0.09, and 0.17, respectively. More tidally influenced reservoirs such as the studied V2 had short but frequent shales, which resulted in low \[{k}_{v}/{k}_{h} \] estimates. Estimates of \[{k}_{v}/{k}_{h} \] for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.
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