Showing papers in "AAPG Bulletin in 2011"
TL;DR: Pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the Barnett Shale as discussed by the authors, which can provide storage space as well as permeability pathways for gas molecules through the shale.
Abstract: The identification of organoporosity (microscale and nanoscale pores within organic matter in shales), its importance to storage and perhaps transfer of gas molecules through shales, and methods for gathering three-dimensional images of the pores, such as by argon-ion milling and/or field emission scanning electron microscopy, have all been well documented and discussed for unconventional gas shales. However, other types of pores exist within shales that can be important to storage and migration of gas (and oil), and other technologies are available for their identification and imaging. The different pore types found in the Barnett and Woodford shales are described and classified in this article. Scanning electron microscopy revealed the presence of porous floccules in both the Barnett and Woodford shales, which appear similar to laboratory-produced floccules and to those in other ancient shales. Published experimental and observational studies indicate that floccules are hydraulically equivalent to coarser grains and are transported by traction processes. Current-induced microsedimentary structures and textures within the Barnett and Woodford shales, as well as the preserved floccules, suggest such processes were active during transport and deposition. Pore spaces between the floccules are open and can provide storage space as well as permeability pathways for gas molecules through the shales. Pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the shale. They are referred to here as “organopores.” Porous fecal pellets are also common in the Barnett Shale. Preserved fossil fragments such as organic-walled spores and inorganic sponge spicules have hollow central chambers, which may remain partially or completely open even after burial. Intraparticle pores occur between grains of various minerals (e.g., pyrite framboids). Microchannels within shale matrix, which may be the bounding surfaces of scours or microsedimentary structures, may also provide permeability pathways for hydrocarbon migration. Mircrofractures are also common, and their initiation might be related to mineral crystal structure. When present in sufficient quantity, these pore types offer potential gas (and oil) molecule storage spaces and permeability pathways through the shales.
713 citations
TL;DR: For example, the authors showed that high-magnification observations both in modern and ancient sediments demonstrate that mudstones are texturally and mineralogically heterogeneous; this variability is not always readily apparent.
Abstract: Mudstone is the most abundant sedimentary rock and variously acts as sources, seals, and shale gas reservoirs in petroleum systems. Many important physicochemical properties of mudstones are strongly influenced by the mineralogy and size of deposited grains, and by diagenetic changes (precompaction and postcompaction); these are commonly predictable. The diverse composition of mudstones reflects input and hydrodynamic segregation of detrital materials to basins, primary production within basins, and diagenetic processes (both precipitation and dissolution) in the sediment. High-magnification observations both in modern and ancient sediments demonstrate that mudstones are texturally and mineralogically heterogeneous; this variability is not always readily apparent. Although some mud is indeed deposited by suspension settling out of low-energy buoyant plumes, textural analyses reveal that it is commonly dispersed by a combination of waves, gravity-driven processes, and unidirectional currents driven variously by storms and tides. Such dispersal mechanisms mean that muddy successions are typically organized into packages that can be interpreted using sequence stratigraphy. Early bioturbation homogenizes mud, whereas early chemical diagenesis can result in highly cemented zones developing, especially at stratal surfaces. The nature of deeper burial diagenesis, which involves compaction, mineral dissolution, recrystallization, mineral reorientation and lithification, and petroleum generation, is preconditioned by depositional and early diagenetic characteristics of the mud. Although the petrophysical properties of homogeneous mudstones are reasonably well known, the quantitative implications of heterogeneity for petroleum expulsion, retention, petroleum migration, seal capacity, acoustic anisotropy, and identification of shale gas reservoir sweet spots are essentially unexplored. Future work should seek to redress this position.
410 citations
TL;DR: In this paper, seismic reflection data and extensive drill cores from acreage located approximately 50 km (31 mi) south of Fort McMurray provide important insights into the sedimentologic organization of reservoir and non-reservoir deposits in the upper one third of the reservoir interval.
Abstract: The bitumen of the Lower Cretaceous McMurray Formation in Alberta arguably represents one of the most important hydrocarbon accumulations in the world. In-situ development relies on heat transfer through the reservoir via horizontal steam injection wells placed 4 to 6 m (13–20 ft) above horizontal producers near the base of the sandstone reservoirs. Given this technology, understanding the distribution of the resource is paramount for a successful development program. Sedimentary facies provide a direct control on bitumen distribution and recovery. Most facies models developed to describe and predict sedimentary units of the McMurray Formation consider fluvial, estuarine, and/or deltaic depositional settings. In-situ development, however, requires a particularly high-resolution sedimentologic interpretation. High-quality three-dimensional seismic reflection data and extensive drill cores from acreage located approximately 50 km (31 mi) south of Fort McMurray provide important insights into the sedimentologic organization of reservoir and nonreservoir deposits in the upper one third (40 m [131 ft]) of the reservoir interval. Geomorphologic characteristics of the strata observed in seismic time slices reveal that a fluvial depositional setting was prevalent. Ichnologic and palynologic data, as well as sedimentary structures suggestive of tidal processes, indicate a marine influence in the upper reaches of a fluvial system characterized by channels that were 390 to 640 m (1280–2100 ft) wide and 28 to 36 m (92–118 ft) deep. The complex stratigraphic architecture consists of a mosaic of large-scale depositional elements, including abandoned channels or oxbow lake fills, point bars associated with lateral accretion, point bars associated with downstream accretion, counter point bars, and sandstone-filled channels. Reservoir deposits are primarily associated with point bars and sandstone-filled channels.
239 citations
TL;DR: In this article, the structural setting, stratigraphy, depositional environment and facies, fracturing, and production challenges of the Haynesville shale-gas play are discussed.
Abstract: The Upper Jurassic Haynesville Shale is currently regarded as one of the most prolific emerging shale-gas plays in the continental United States. It has estimated play resources of several hundred trillion cubic feet and per-well reserves estimated as much as 7.5 bcf. The reservoir spans more than 16 counties along the boundary of eastern Texas and western Louisiana. Although this basin has a long history of exploration and analysis of its Mesozoic section, a comprehensive subsurface study characterizing the Haynesville Shale has not been conducted. This article is the first to address the structural setting, stratigraphy, depositional environment and facies, fracturing, and production challenges of the Haynesville shale-gas play. Basement structures and salt movement influenced carbonate and siliciclastic sedimentation associated with the opening of the Gulf of Mexico. The Haynesville Shale is an organic- and carbonate-rich mudrock that was deposited in a deep partly euxinic and anoxic basin during the Kimmeridgian to the early Tithonian, related to a second-order transgression that deposited organic-rich black shales worldwide. The Haynesville Basin was surrounded by carbonate shelves of the Smackover and Haynesville lime Louark sequence in the north and west. Several rivers supplied sand and mud from the northwest, north, and northeast into the basin. Haynesville mudrocks contain a spectrum of facies ranging from bioturbated calcareous mudstone, laminated calcareous mudstone, and silty peloidal siliceous mudstone, to unlaminated siliceous organic-rich mudstone. Framboidal to colloidal pyrite is variably present in the form of concretions, laminae, and individual framboids and replaces calcite cement and mollusk shells. Haynesville reservoirs are characterized by overpressuring, porosity averaging 8 to 12%, Sw of 20 to 30%, nanodarcy permeabilities, reservoir thickness of 200 to 300 ft (70 to100 m), and initial production of as much as 30 mmcf/day. Reservoir depth ranges from 9000 to 14,000 ft (3000 to 4700 m), and lateral drilling distances are 3000 to 5000 ft (1000 to 1700 m). Typical Haynesville wells exhibit a steeper decline curve (80% in the first year) than other shale-gas plays, which is attributed to a very high overpressure.
217 citations
TL;DR: In this paper, a process-based classification scheme based on the relative importance of primary, secondary, and tertiary processes is presented, which permits a semiquantitative classification of clastic coastal depositional systems.
Abstract: Existing classification schemes and models for clastic coastal depositional systems do not consider the potential amplifying or moderating effects of coastal morphology on depositional processes and do not provide a mechanism for the dynamic prediction of changes in coastal depositional style. A new process-based classification scheme based on the relative importance of primary, secondary, and tertiary processes is presented. This scheme permits a semiquantitative classification of clastic coastal depositional systems. In addition, it provides the basis for new models for clastic shorelines that convolve the effects of basin shape, coastal morphology, accommodation space, sediment supply, shoreline trajectory, and shelf width parameters on depositional processes. The end result is a marked improvement in the predictive capabilities of models. The models can describe and predict the likelihood of primary, secondary, and tertiary depositional processes acting in shoreline depositional environments via either a matrix or a decision tree approach. They are also dynamic in nature and can be applied to predict along-strike, updip, and downdip, or vertical changes in the dominance of depositional processes acting at any given location through geologic time. The key implications of these models are that given sets of known parameters, dominant and subordinate depositional processes or ranges of potential dominant and subordinate depositional processes acting at a coastline can be predicted. This provides an auditable methodology for determining reservoir modeling scenarios and reducing and managing the uncertainties in predictions of changes in clastic coastal depositional processes through time and space.
211 citations
TL;DR: In this article, the authors analyzed more than 900 wireline logs from the Middle Devonian Marcellus Formation and provided a predictive sequence-stratigraphic model that can be used to further explore the basin more tectonically complex than accounted for by simple flexural models.
Abstract: Analysis of more than 900 wireline logs indicates that the Middle Devonian Marcellus Formation encompasses two third-order transgressive-regressive (T-R) sequences, MSS1 and MSS2, in ascending order. Compositional elements of the Marcellus Formation crucial to the successful development of this emerging shale gas play, including quartz, clay, carbonate, pyrite, and organic carbon, vary predictably within the proposed sequence-stratigraphic framework. Thickness trends of Marcellus T-R sequences and lithostratigraphic units reflect the interplay of Acadian thrust-load-induced subsidence, short-term base-level fluctuations, and recurrent basement structures. Rapid thickening of both T-R sequences, especially MSS2, toward the northeastern region of the basin preserves a record of greater accommodation space and proximity to clastic sources early in the Acadian orogeny. However, local variations in T-R sequence thickness in the western, more distal, area of the basin may reflect the reactivation of inherited Eocambrian basement structures, including the Rome trough and northwest-striking cross-structural discontinuities, induced by Acadian plate convergence. Episodes of block displacement locally warped the basin into northeast-southwest–trending regions of starved sedimentation and/or erosion adjacent to depocenters in which regressive systems tract deposits were ponded. Block movement appears to have initiated in late Early Devonian time, resulting first in thinning and local erosion of the Oriskany sandstone in northwest Pennsylvania. This study, in addition to providing the basis for a predictive sequence-stratigraphic model that can be used to further Marcellus exploration, tells of a foreland basin more tectonically complex than accounted for by simple flexural models.
150 citations
TL;DR: In this article, the authors adopt the concept of a closed-system shale, in which simultaneous cooking of kerogen, oil, and gas yields gas with light 13C ethane and heavy 13C methane.
Abstract: Isotopically reversed gases (13C methane 13C ethane 13C propane) occur in fractured mixed clastic-carbonate reservoirs of the Permian and the Triassic in the foothills at the western edge of the Western Canada sedimentary basin (WCSB). The 13C methane values (–42 to –24), gas dryness, and organic maturity (Ro 2.2) are indicative of mature gases, and gas maturity generally increases with reservoir age and from the southeast to the northwest. The 13C ethane values range from 44 to 25, with the less negative values in isotopically normal gases to the northeast of the gas fields we studied. To explain the gas isotope reversals observed in the WCSB foothills, we adopt the concept of a closed-system shale, in which simultaneous cooking of kerogen, oil, and gas yields gas with light 13C ethane and heavy 13C methane. This gas was released from shales and trapped in fractured folds of brittle clastic-carbonate rocks during deformation and thrust faulting of the Laramide orogeny, creating some of the most prolific gas pools. These gases are actually mature shale gases. Local high abundances of H2S and CO2 are most likely the products of thermochemical sulfate reduction (TSR) reactions in anhydrite-rich interbeds and underbeds that admixed to the released shale gas during the tectonic event. No evidence exists that TSR is responsible for the isotope reversals. Variations in 13C ethane are likely caused by local differences in thermal history, the timing of gas release from shale, and the timing of the fault and fold development. Less negative 13C ethane values (resulting in isotopically normal gases) to the northeast of the fields and in the underlying Devonian carbonates likely reflect a more open shale system where the earliest generated gas was lost. We suggest that isotopic reversals are restricted to closed-system maturation, and that their magnitude may be related to the relative volume of gas retained in shales.
134 citations
TL;DR: In this paper, the authors identify 12 lithofacies based on sand-grain populations, cement types, and clay matrix content, and show that careful petrographic assessment of the heterogeneity can be upscaled by correlation with log properties to yield tools for field-scale reservoir quality prediction.
Abstract: Understanding the controls and distribution of reservoir quality is important for the economic success of tight-gas reservoirs in which diagenesis interacts with primary depositional variations in environment and texture to exert a strong control on pore networks, rock mechanical properties, and natural fractures. In the Upper Cretaceous Williams Fork Formation of the Piceance Basin, framework grain composition is a major control on compaction and the occurrence of authigenic phases. Alteration of volcanic grains in the upper Williams Fork led to grain-coating clay precipitation. Ferroan dolomite cement is found only in the deeper marine-influenced intervals in which dolostone fragments are present. This study shows that careful petrographic assessment of lithofacies heterogeneity can be upscaled by correlation with log properties to yield tools for field-scale reservoir quality prediction. Twelve lithofacies are identified based on sand-grain populations, cement types, and clay matrix content. Sandstones of the highest reservoir quality are those with grain-coating clays that inhibit quartz cementation; these sandstones can be identified based on high-density porosity log values. Sandstones with the poorest reservoir qualities are tightly cemented with carbonate and quartz cement or are rich in clay matrix. Carbonate-cemented intervals are identified by low-density porosity. Clay matrix–rich samples have high gamma-ray and low-density porosity values. The presence of abundant potassium feldspar in the upper intervals results in high gamma-ray readings even in the clean (clay matrix–free) sandstone.
113 citations
TL;DR: In this article, the authors identify Pleistocene fluvial, estuarine, marine and deltaic depositional systems 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.
Abstract: 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 (35 m [115 ft]) single-story incised valley was described in detail, placing particular emphasis on the recognition criteria and the controls on valley formation and preservation potential of different systems tracts in an inner-shelf location. The 3-D characterization of this system allowed differentiation of sand-prone point-bar deposits and mud-prone abandonment channel facies. The sinuous but continuous mud-filled channel may act as a lateral muddy barrier or baffle that can potentially subdivide a reservoir system into discrete compartments.
113 citations
TL;DR: In this article, the electrical resistivity log has proven to be a powerful tool for lithology discrimination, correlation, porosity evaluation, hydrocarbon indication, and calculation of water saturation.
Abstract: The electrical resistivity log has proven to be a powerful tool for lithology discrimination, correlation, porosity evaluation, hydrocarbon indication, and calculation of water saturation. Carbonate rocks develop a variety of pore types that can span several orders of magnitude in size and complexity. A link between the electrical resistivity and the carbonate pore structure has been inferred, although no detailed understanding of this relationship exists. Seventy-one plugs from outcrops and boreholes of carbonates from five different areas and ages were measured for electrical resistivity properties and quantitatively analyzed for pore structure using digital image analysis from thin sections. The analysis shows that in addition to porosity, the combined effect of microporosity, pore network complexity, pore size of the macropores, and absolute number of pores are all influential for the flow of electric charge. Samples with small pores and an intricate pore network have a low cementation factor, whereas samples with large pores and a simple pore network have high values for cementation factor. Samples with separate-vug porosity have the highest cementation factor. The results reveal that (1) in carbonate rocks, both pore structure and the absolute number of pores (and pore connections) seem more important in controlling the electrical resistivity, instead of the size of the pore throats, as suggested by previous modeling studies; (2) samples with high resistivity can have high permeability; large simple pores facilitate flow of fluid, but fewer numbers of pores limit the flow of electric charge; and (3) pore-structure characteristics can be estimated from electrical resistivity data and used to improve permeability estimates and refine calculations of water saturation.
107 citations
TL;DR: In this article, an integrated approach was applied that emphasized integration of seismic data with available conventional core, wireline logs, and age-equivalent outcrops to characterize the three-dimensional geomorphology of a deeply buried (5500-6500 m [18,045-21,325 ft] Ordovician unconformity and the related paleokarst drainage system.
Abstract: High-quality three-dimensional seismic data acquired in the central Tabei Uplift, Tarim Basin, western China, provide a rare opportunity to characterize in exceptional detail the three-dimensional geomorphology of a deeply buried (5500–6500 m [18,045–21,325 ft]) Ordovician unconformity and the related paleokarst drainage system. An integrated approach was applied that emphasized integration of seismic data with available conventional core, wireline logs, and age-equivalent outcrops. The exceptional quality of the seismic data allowed a seismic detection limit of karstified features of less than 75 75 m (246 246 ft) horizontally and 6 m (20 ft) vertically. Interpreted geomorphologic and depositional elements include fluvial channels and canyons, fluvial valleys, sinkholes, and tower karsts and hills. The modern tower karst-drainage system in Guilin, China, is very similar to the mapped Ordovician karst-drainage system and is used as a modern analog. The interaction between the surface karst-drainage system and the shallow-subsurface cave-passage system is evidenced by the observation that surface canyons appear to initiate in areas associated with intense sinkhole development. Also, surface river valleys tend to correspond to dip-oriented surface depressions partly related to near-surface cave collapse. During burial into the deeper subsurface, the combination of intrastratal collapse (karstified strata) and suprastratal collapse (postkarst-deposited strata) created large damage zones hundreds of meters thick and kilometers wide. Coalesced-collapsed paleocave systems can be interpreted from the unique circular pattern of faults (observed in map view) that are associated with seismic bright spots.
TL;DR: In this paper, the authors define three tectonostratigraphic provinces that characterize primary basin depocenters: (1) a disconnected salt-stock-canopy province in Mississippi Canyon; (2) an amalgamated salt stock-canope 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 Keathly Canyon.
Abstract: 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.
TL;DR: In this article, the maturation and hydrocarbon expulsion histories of the Paleogene Shahejie 3 Formation (E2s3), which is the most important source rock in the offshore Bohai Bay Basin, are modeled.
Abstract: The offshore Bohai Bay Basin, located in the central Bohai Bay Basin, north China, one of the most petroliferous basins in China. In this article, based on formation-testing temperature, drill-stem tests, and bottom-hole temperature data, 80 thermal gradient values at the depth interval of 0 to approximately 3000 m (~9843 ft) in the offshore Bohai Bay Basin were obtained. The basinwide average thermal gradient is 31.8 4.6C/km. Based on the above thermal gradient data and the corresponding average weighted thermal conductivity data, 80 measured terrestrial heat flow values were obtained. These values range from 33.5 to 84.0 mW/m2, with an average value of 60.8 8.7 mW/m2. The heat flow and thermal gradient distribution in this region generally show higher values in the uplifts and lower ones in the sags. A thermal history, derived from vitrinite reflectance and apatite fission-track) data, indicates that Paleogene cooling occurred after a period of much higher paleogeothermal gradient (3854C/km). Tectonic subsidence analysis reveals that the area experienced initial synrift subsidence during the Paleogene followed by subsequent thermal subsidence since the Neogene. Thermal and tectonic subsidence histories of this area are of great significance to petroleum exploration and hydrocarbon resource assessment because they bear directly on issues of petroleum source rock maturation. The maturation and hydrocarbon expulsion histories of the Paleogene Shahejie 3 Formation (E2s3), which is the most important source rock in the offshore Bohai Bay Basin, are modeled. Results show that the Shahejie 3 Formation is in a high mature stage at the present day, and the Bozhong and Qikou sags are the most important kitchens. The Huanghekou sag became the third most important hydrocarbon kitchen in the early Neogene. Based on this hydrocarbon kitchen evolution, oil and gas mainly accumulated after 12 Ma. The evolution of kitchen areas may provide new insights for the understanding of the oil and gas exploration potential of the offshore Bohai Bay Basin.
TL;DR: In this article, two methods were explored to extract the 3D positions of natural fractures from a LIDAR survey collected at a roadcut through the Cretaceous Austin Chalk: a manual method using the University of California, Davis, Keck Center for Active Visualization in the Earth Sciences and a semiautomated method based on mean normal and Gaussian curvature surface classification.
Abstract: 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.
TL;DR: In this article, the field-scale architecture and static connectivity of fluvial sandstones of the lower Williams Fork Formation through analysis and reservoir modeling of analogous outcrop data from Coal Canyon, Piceance Basin, Colorado.
Abstract: This study addresses the field-scale architecture and static connectivity of fluvial sandstones of the lower Williams Fork Formation through analysis and reservoir modeling of analogous outcrop data from Coal Canyon, Piceance Basin, Colorado. The Upper Cretaceous lower Williams Fork Formation is a relatively low net-to-gross ratio (commonly 30%) succession of fluvial channel sandstones, crevasse splays, flood-plain mudstones, and coals that were deposited by meandering river systems within a coastal-plain setting. The lower Williams Fork outcrops serve as proximal reservoir analogs because the strata dip gently eastward into the Piceance Basin where they form natural gas reservoirs. Three-dimensional architectural-element models (3-D reservoir models) of the lower Williams Fork Formation that are constrained to outcrop-derived data (e.g., sandstone body types, dimensions, stratigraphic position) from Coal Canyon show how static sandstone body connectivity is sensitive to sandstone body width and varies with net-to-gross ratio and well spacing. With a low well density (e.g., 160-ac well spacing), connectivity is low for net-to-gross ratios less than 20%, connectivity increases between net-to-gross ratios of 20 to 30%, and levels off above a net-to-gross ratio of 30%. As well density increases, static connectivity increases more linearly with an increasing net-to-gross ratio. For a 20-ac well spacing, static connectivity can range from approximately 35 to 75% and 45 to 80% for net-to-gross ratios of 10 and 15%, respectively, depending on sandstone body width. Given the lower net-to-gross ratio and continuity of lower Williams Fork deposits, this underscores the importance of representative sandstone body statistics (e.g., sandstone body type, dimensions) to aid in subsurface correlation and mapping and to constrain reservoir models.
TL;DR: In this article, a high-resolution, three-dimensional, reservoir-scale model of an outcrop analog from the Upper Cretaceous Ferron Sandstone Member of central Utah is presented.
Abstract: Fluviodeltaic stratigraphic architecture and its impact on fluid flow have been characterized using a high-resolution, three-dimensional, reservoir-scale model of an outcrop analog from the Upper Cretaceous Ferron Sandstone Member of central Utah. The model contains two parasequence sets (delta complexes), each with five or six parasequences, separated by an interval of coastal plain strata. Each parasequence contains one or two laterally offset teardrop-shaped delta lobes that are 6 to 12 km (4–7 mi) long, 3 to 9 km (2–6 mi) wide, 5 to 29 m (16–95 ft) thick, and have aspect ratios (width/length) of 0.4 to 0.8. Delta lobes have a wide range of azimuthal orientations (120) around an overall east-northeastward progradation direction. In plan view, delta lobes in successive parasequences exhibit large (as much as 91) clockwise and counterclockwise rotations in progradation direction, which are attributed to autogenic lobe switching. In cross-sectional view, parasequence stacking is strongly progradational, but a small component of aggradation or downstepping between parasequences reflects relative sea level fluctuations. We use flow simulations to characterize the impact of this heterogeneity on production in terms of the sweep efficiency, which is controlled by (1) the continuity, orientation, and permeability of channel-fill sand bodies; (2) the vertical permeability of distal delta-front heteroliths; (3) the direction of sweep relative to the orientation of channel-fill and delta-lobe sand bodies; and (4) well spacing. Distributary channel-fill sand bodies terminate at the apex of genetically related delta lobes and provide limited sand body connectivity. In contrast, fluvial channel-fill sand bodies cut into, and connect, multiple delta-lobe sand bodies. Low, but non-zero, vertical permeability within distal delta-front heteroliths also provides connectivity between successive delta-lobe sand bodies.
TL;DR: In this paper, the Hidden Valley Fault is exposed in Canyon Lake Gorge (central Texas) and cuts the Cretaceous Glen Rose Formation, and the authors explore the relationship between deformation mechanisms and fault displacement along 830 m (2723 ft) of a normal fault typical of those in carbonate reservoirs and aquifers around the world.
Abstract: The Hidden Valley fault is exposed in Canyon Lake Gorge (central Texas) and cuts the Cretaceous Glen Rose Formation. This exposure provides an opportunity to explore the relationship between deformation mechanisms and fault displacement along 830 m (2723 ft) of a normal fault typical of those in carbonate reservoirs and aquifers around the world. The fault zone has five domains: gently deformed footwall damage zone, intensely deformed footwall damage zone, fault core, intensely deformed hanging-wall damage zone, and gently deformed hanging-wall damage zone. Footwall deformation is more intense and laterally extensive than hanging-wall deformation, and the intensely deformed hanging-wall damage zone is narrow and locally absent. The fault core contains thin clay-rich gouge or smear in most places but is locally represented by only a slickensided surface between limestone layers. The 55- to 63-m (180–207-ft) fault throw across a 43- to 98-m (141- to 322-ft)-wide fault zone is accommodated by slip along the fault core, layer tilting (synthetic dip development) in footwall and hanging-wall damage zones, and distributed faulting in footwall and hanging-wall damage zones. Total offset across the fault overestimates actual stratigraphic offset by 8 to 12 m (26–39 ft) or about 14 to 21%. In our interpretation, the Hidden Valley fault zone records both early extensional folding of the Glen Rose Formation and subsequent normal faulting that propagated downward from the overlying competent Edwards Group. The damage zone width is thus established before fault breakthrough.
TL;DR: In this article, deformation bands in a high-porosity carbonate rock from the Eisenstadt-Sopron Basin, on the border between Austria and Hungary, were investigated using a combination of microstructural and petrophysical methods.
Abstract: Deformation bands are commonly found in porous silicilastic sediments, where strain is accommodated by rotation, translation, and fracturing of individual grains instead of by the formation of a sharp discontinuity. We investigated deformation bands in a high-porosity carbonate rock from the Eisenstadt-Sopron Basin, on the border between Austria and Hungary, using a combination of microstructural and petrophysical methods. We used cathodoluminescence and electron microprobe analyses to assess the distribution and chemical composition of the carbonate particles, deformation bands, and cements. The earliest deformation bands formed before the cementation of the limestone, mainly by rotation of elongated bioclasts to an orientation parallel to the deformation bands. Further movement along the bands after the generation of blocky cement around the bioclasts resulted in cataclastic deformation of both allochems and cement. Moreover, we documented a reduction of porosity from 22 to 35% in the host rock to 2 to 5% in the deformation bands by microcomputed tomography and conventional helium porosimetry. Permeability is reduced as much as three orders of magnitude relative to the host rock, as documented by pressure decay probe permeametry. The observations indicate a change in physical properties of the rock caused by cementation during the generation of deformation bands, which results in a change of deformation mechanism from grain rotation and compaction to cataclastic deformation along a single band. The reduction of porosity and permeability, which is even stronger than observed in most silicilastic rocks, affects the migration of fluids in groundwater or hydrocarbon reservoirs.
TL;DR: In this paper, a detailed analysis of three-dimensional seismic data from the lower Congo Basin, offshore Angola, reveals numerous fluid-flow features in the Miocene to Holocene succession and the potential for large, shielded traps underneath basinward overhanging salt structures.
Abstract: Analysis of three-dimensional seismic data from the lower Congo Basin, offshore Angola, reveals numerous fluid-flow features in the Miocene to Holocene succession and the potential for large, shielded traps underneath basinward overhanging salt structures. The fluid-flow evidence includes present-day sea floor pockmarks clustered above salt structures, Pliocene–Pleistocene stacked paleopockmarks and Miocene pockmark fields. Other fluid-flow features include high-amplitude cylindrical pipe structures 60 to 300 m (197–984 ft) wide and 25 to 300 m (82–984 ft) high within lower and middle Miocene strata, thick (150 m [492 ft]) high-reflectivity zones within the Pliocene succession associated with bottom-simulating reflections, and subvertical low-amplitude chimneys originating from the deeper section (1 km [0.6 mi] beneath the sea floor). The Miocene pockmark fields occur at a specific horizon, suggesting a regional fluid expulsion event at ca. 12 Ma, and the Miocene fluid-flow regime is interpreted to be dominated by thermogenic fluids supplied via carrier beds and leaking vertically above structural highs. The Pliocene–Pleistocene fluid-flow regime was dominated by short-distance vertical fluid migration and expulsion related to early stage diagenetic processes involving biogenic methane and pore water. The present-day fluid-flow regime is inferred to be dominated by thermogenic fluids primarily controlled by kilometer-scale salt-flank-controlled migration. The study emphasizes the use of seismically imaged fluid-flow features in hydrocarbon systems analysis by documenting the evolution of an overburden plumbing system through time, involving several fluid types and flow regimes, depending on the spatiotemporal availability of thermogenic and diagenetic fluids and the tectonostratigraphic occurrence of aquifers, traps, and seals.
TL;DR: In this article, three-dimensional seismic data sets over the Albian western Golden Lane margin and time-equivalent basinal deposits of Poza Rica field were used to investigate the linked architecture of a steep-sided carbonate platform (El Abra Formation) and a thick accumulation of redeposited carbonate sediment at the toe of the slope and in the basinal area (Tamabra Formation).
Abstract: Two three-dimensional seismic data sets over the Albian western Golden Lane margin and time-equivalent basinal deposits of Poza Rica field allowed us to investigate the linked architecture of a steep-sided carbonate platform (El Abra Formation) and a thick accumulation of redeposited carbonate sediment at the toe of the slope and in the basinal area (Tamabra Formation). Regional seismic cross sections show that the most aggrading Albian platform has an eroded platform top, a scalloped margin, and a channelized slope that are equivalent to a 20-km (12.4-mi)-wide, westward-thinning, thick toe-of-slope apron made of chaotic, contorted, mounded, moderate- to high-amplitude reflections. Detailed reflection geometries in the Albian toe-of-slope and basinal deposits consist of chaotic to short, discontinuous, low-amplitude reflection at the toe of the slope of the Golden Lane platform, laterally changing to a discontinuous mounded, shingling reflection, which ultimately turns into high-amplitude parallel reflections. We interpret this lateral change to reflect the seismic signature of the change from the block- and debris-flow–dominated toe-of-slope area, to debris-flow and concentrated density flow deposits in the basin that ultimately grade laterally into pelagic deposits. On a flattened seismic slice, mounded reflections correspond to lobate to fan-shaped seismic events several kilometers wide that are interpreted as a carbonate basin-floor fan. Comparison between core and seismic data shows a dominance of debris flows in the lower two Albian sequences (Albian 1 and Albian 2) that grade vertically into more lobate concentrated density flows and turbidites in the upper two Albian sequences (Albian 3 and Albian 4). Seismic data used in this study, combined with core observations, do not support the interpretation of the Albian Tamabra Formation being of shallow-water origin. Seismic features identified as basin-floor fan, channel, and debris-flow deposits have a shape and size that are similar to those of other redeposited basinal carbonate deposits elsewhere. The seismic architecture shows that the Poza Rica field is a typical example of thick accumulation of grainy porous carbonate deposits in a basinal setting. This example shows the potential of a large hydrocarbon accumulation in a tectonically modified stratigraphic trap around shallow-water carbonate platforms.
TL;DR: In this paper, the porosity-depth trend of Miocene mudrocks in the Lower Kutai Basin has been analyzed and it has been shown that porosity reduction is controlled by chemical compaction and that cementation has caused the mudrock to become overcompacted, relative to the prevailing effective stress.
Abstract: Lateral drainage and high temperatures in the shelfal area of the Lower Kutai Basin provide an exceptional opportunity to study compaction of Miocene mudrocks and overpressure generation. Previous workers agreed that the principal mechanism of overpressure generation is disequilibrium compaction, but sonic and resistivity logs in several fields display reversals at a transition zone into high overpressure, indicating that overpressure is generated by unloading processes. The transition zone coincides with the vitrinite reflectance threshold for gas generation. Extreme overpressures in some wells are associated with reversals on density logs too, interpreted to result from opening cracks. The density-depth trends through the mudrocks are similar in all wells and independent of overpressure until extreme overpressures are encountered. This observation strongly suggests that porosity reduction is controlled by chemical compaction and that cementation has caused the mudrocks to become overcompacted, relative to the prevailing effective stress, at burial depths of approximately 3 km (1.9 mi) where the top of overpressure is encountered. Hence, the Lower Kutai Basin contains a unique reported example, to date, of a Neogene succession in which high overpressures are generated by unloading processes with no contribution from disequilibrium compaction. Density logs from the Peciko field have been used to derive the empirical porosity-depth trend ϕ = 0.434 e −0.164 z for mudrocks in the depth range 6000 to 15,000 ft (1800 to 4600 m), where z is depth in thousands of feet. The corresponding temperature range is 85 to 170°C, so this compaction curve applies for mudrocks in the chemical compaction regime, where no discrete smectite is present.
TL;DR: In this paper, the sequence-stratigraphic framework and depositional systems of an Oligocene lacustrine rift succession in the Liaozhong depression of Bohai Bay Basin in northeastern China were investigated using seismic profiles, complemented by well logs and cores.
Abstract: The sequence-stratigraphic framework and depositional systems of an Oligocene lacustrine rift succession in the Liaozhong depression of Bohai Bay Basin in northeastern China were investigated using seismic profiles, complemented by well logs and cores. Seven sequences are identified on the basis of unconformities on basin margins and correlative conformities in the basin center. Depositional systems are associated with systems tracts within sequences. Lowstand systems tracts are dominated by sublacustrine fans; transgressive systems tracts are mainly composed of beach-bar deposits; and highstand systems tracts are characterized by deep lacustrine fan or braid-delta deposits. Episodic tectonic movement was the principal factor that controlled the development of the sequences. Lake-level changes resulting from climatic oscillations may have controlled the development of these sequences. The balance between tectonic subsidence and sediment supply controlled the type of lake basin. The Bohai Bay Basin was a balanced-fill basin in the early and middle stages of the Dongying Formation and evolved into an overfilled basin at the end of deposition of the Dongying Formation. This study enhances the understanding of depositional system configuration and systems tracts in a typical rift basin and proposes that the most favorable sandstone reservoirs are developed in sublacustrine fan deposits. Relative lowstand sublacustrine fan deposits capped by relative highstand prodelta or deep lacustrine mudstones form the highest potential lithostratigraphic traps.
TL;DR: The Moxizhuang field is a small oil field in the central Junggar Basin containing several low-saturation, low-resistivity oil reservoirs, which display a complex correlation between oil saturation and porosity and permeability that is atypical of both the filled and drained reservoirs.
Abstract: The Moxizhuang field is a small oil field in the central Junggar Basin containing several low-saturation, low-resistivity oil reservoirs, which display a complex correlation between oil saturation and porosity and permeability that is atypical of both the filled and drained reservoirs. Biomarker associations of crude oil and grains containing oil inclusions (GOIs) of both the present-day water-bearing zones (water zones) and the oil- and water-bearing zones (low-oil-saturation pay zones) were analyzed to investigate the mechanisms for the formation of the low-saturation, low-resistivity oil accumulations. The biomarker assemblage and hierarchical cluster analysis indicate that oil in the Moxizhuang field was mostly generated from Permian source rock deposited in brackish to hypersaline anoxic environments. The pay zones and several water zones display GOI values as much as 38%, greater than the generally accepted threshold GOI value for an oil column (5%). These GOI values are similar to those for high-saturation oil reservoirs in the Bohai Bay Basin and oil zone samples from Australian basins, suggesting that both pay zones and water zones were high-saturation oil reservoirs in the geologic past. Geologic history analysis shows that the Moxizhuang field was located on the north wing of a paleoanticline during oil charge in the Late Cretaceous to Paleogene. This anticline has gradually evolved into a south-dipping monocline since the Neogene, causing northward remigration of accumulated oil. Differential lateral leakage of accumulated oil in different sandstone layers during the remigration phase led to the formation of the water zones with high GOI values (completely drained reservoirs) and the low-saturation, low-resistivity pay zones (partially preserved reservoirs) and caused the complex correlation between oil saturation and porosity and permeability. Compared with other postaccumulation physicochemical alteration processes, lateral leakage has rarely been recognized. Recognizing differential lateral leakage of accumulated petroleum with the existence of high-quality unfaulted cap rocks has important implication for petroleum exploration in sedimentary basins having complex evolution histories.
TL;DR: In this paper, an integrated approach incorporating petrophysics, petrography, and one-dimensional basin modeling methods was applied to investigate the variations in the deeply buried synrift play of the South Viking Graben.
Abstract: 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.
TL;DR: In this article, a new method of laser scanning is used to map the geometry and evolution of structures and related secondary faults along releasing bends and offsets and restraining bends on strike-slip faults.
Abstract: 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) bends connecting approaching faults result in spindle-shaped uplifts, whereas transverse or oblique (135) 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) 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.
TL;DR: In this article, the authors analyzed the subsurface pressure data from Taranaki Basin using direct (e.g., repeat formation tester) and indirect measurements (drilling parameters and wireline log data such as sonic and resistivity).
Abstract: Analysis of subsurface pressure data from Taranaki Basin using direct (e.g., repeat formation tester) and indirect measurements (drilling parameters and wireline log data such as sonic and resistivity) indicates the presence of three pressure zones: a near-hydrostatic regime (zone A) that extends across the entire basin and to varying depths; an underlying overpressured regime (zone B), with pressures approximately 1100 psi (7.584 MPa) above hydrostatic, that extends throughout the Manaia graben and north along the eastern basin margin at depths of 1900 to 4100 m (6234–13,451 ft); and a third regime (zone C), with approximately 2100 psi (14.479 MPa) overpressure, that directly underlies zone A and zone B in different parts of the basin (although well penetrations are limited). The primary cause of overpressure is interpreted to be disequilibrium compaction preserved in upper Eocene and Oligocene marine shales. In parts of the basin, hydrocarbon generation (and in particular cracking to gas at high maturities) is interpreted to contribute to overpressures. The overpressures drain laterally and vertically into permeable units. Intervening transition zones (seals) comprise lithologic boundaries, diagenetic zones, and fault planes. Oligocene carbonates, although commonly thin, provide an effective barrier to vertical hydraulic communication over much of the basin. The Manaia graben is a partially closed system, with overpressures retained by a complex combination of a top shale seal overlying a regional sequence boundary, lithologic barriers within fault compartments, fault planes, and subcropping sequences; episodic fault breach enables vertical transfer of fluids from zone B to zone A in a dynamic fault valve process. To date, all oil reserves have been found in zone A, a large proportion of gas-condensate reserves are within zone B, and no commercial reserves have been established within zone C. The spatial definition of these zones and the appropriate pressure regime is important for well design, drilling safety, determining hydrocarbon column heights and gas expansion factors, and for exploration migration analysis. Regional analysis of pressure regimes can identify subsurface barriers and seals. Faults, in particular, are key elements in fluid migration and the focusing of liquids at abrupt pressure transitions. The strength of fault planes and diagenetic zones is the likely control on dynamic fluid release. Zone C has been very lightly explored and may represent a potential for large dry-gas accumulations; the zone may be sealed by a diagenetic zone crosscutting lithologic boundaries (conventional mapping horizons).
TL;DR: This article 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.
Abstract: 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.
TL;DR: In this article, a migration simulator based on the invasion-percolation theory was proposed to explain the irregularity of migration pathways in heterogeneous media, where the buoyancy of a hydrocarbon column was used as the driving force with capillary pressure as the resisting force.
Abstract: Carriers are important links between sources and traps for hydrocarbon migration and accumulation in a petroleum system. Oil and gas commonly migrate along narrow and irregular pathways in porous media, even in macroscopically homogeneous media. A migration simulator based on the invasion-percolation theory, which couples the buoyancy of a hydrocarbon column as the driving force with capillary pressure as the resisting force, satisfactorily explains migration processes in heterogeneous media. In macroscopically homogeneous carriers, migration pathways are generally perpendicular to equipotential lines, but locally, the pathways can be irregular because of the influence of microscopic heterogeneity. The degree of irregularity of these pathways depends on the difference between competing driving and resisting forces. When numerous pathways form in a migration-accumulation system, the flux of migrating hydrocarbons may vary among these pathways. In macroscopically heterogeneous carriers, the irregularity of migration pathways is exacerbated. When the driving force is relatively weak, hydrocarbons tend to migrate in carriers where the hydraulic conductivity is relatively large. These pathways differ from those predicted only on the basis of flow potential. Simulation of the migration process in the Middle Jurassic carrier beds of the Paris Basin demonstrates the characteristics of the migration simulator in the analysis of migration pathway heterogeneity. Results are comparable to or superior to those achieved with previous simulation approaches.
TL;DR: Kietzmann et al. as mentioned in this paper presented a study of the relationship between geology and ecology, and the results showed that geology can be classified into three categories: geology, ecology and ecology.
Abstract: Fil: Kietzmann, Diego Alejandro. Universidad de Buenos Aires. Facultad de Ciencias Exactas y Naturales. Departamento de Geologia; Argentina. Consejo Nacional de Investigaciones Cientificas y Tecnicas; Argentina
TL;DR: Based on structural analysis, at least six early fault segments are identified in the northern boundary of the Chezhen Basin and these fault segments were important in controlling stratal architecture and distribution as discussed by the authors.
Abstract: 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.