Active fault participation in the diagenetic modification of sandstone reservoir properties
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In sedimentary basins undergoing regional strain, faults have a potential for influencing subsurface fluid flow by providing some of the driving energy for fluid movement. Variable displacement on faults in the slip direction results in systematic volume changes in the surrounding sedimentary rocks. Compressed and dilated volumes are distributed according to position relative to the fault. Intermittent seismic slip produces rapid pressure changes and high hydraulic gradients capable of causing movement of large fluid volumes or of maintaining pressure differentials if pore fluid migration is obstructed. As a result of the hydraulic gradients generated by individual faults, subsurface fluids may either be transferred between formations juxtaposed across the fault or vertically transported along the fault. Faults may thus provide the means of mixing of subsurface fluids, and are potentially zones of intense diagenetic modification. An appreciation of fault-influenced diagenetic modification is particularly pertinent to an understanding of the heterogeneity of sandstone reservoirs where pore water and hydrocarbon migration from source to reservoir rocks are an integral part of the hydrocarbon accumulation process. Mineralogical and fabric modifications to rock components may result in either significant enhancement of porosity or extensive cementation and compaction that overprints regional burial diagenetic assemblages. Inactive ormore » cemented faults may behave as hydrocarbon seals. The potential contribution of faults to sandstone reservoir heterogeneity should always be considered in models of burial diagenesis and hydrocarbon migration.« lessKeywords:
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Pore water in sedimentary rocks is normally in motion. In general, gravity-induced flow driven by the elevation gradient predominates in a basin with orogenic deformation; however, in a basin with continuous deposition, compaction-induced flow driven by the excess fluid-pressure gradient predominates. Subsurface water flow is considered to have a controlling influence on the migration of widely dispersed petroleum. Therefore, the analysis of a basin-wide flow system, particularly its paleohydrogeologic conditions, is essential for understanding the history of petroleum migration and entrapment. The nonlinear finite element method has been used to simulate coupled processes of sediment deformation and fluid flow in sedimentary sequences. By activates and deactivating elements at various stages in the computation process, the sequential deposition and erosion during evolution of a sedimentary basin can be modeled. Simulated results indicate that excess fluid pressure occurs when a basin is progressively loaded by overlying sediments. An excess pressure gradient will cause pore fluid to flow vertically and horizontally, depending upon the regional stratigraphy and structure, toward the sediment surface. In sandstone-shale sequences, pore fluid in shales tends to flow toward adjacent sandstones, increasing the effectiveness of petroleum accumulation. The downward flow from overlying shales to sandstones, plays an important rolemore » in providing resistance to the upward migration of petroleum. The concentrated fluid flux in sandstones tends to flow parallel to the bedding plane toward highest position of permeable strata, such as crests of anticlines, pinch-outs, or outcrops.« less
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The Mobil operated Beryl Field is located in UK Block 9/13, on the west flank of the South Viking Graben. Hydrocarbons are produced from five Jurassic and Triassic sandstone reservoirs within several large, faulted-bounded structural traps. Within Beryl Field, extensive data, including 150 wells, and a 20 year production history provides an excellent opportunity to study fault-fluid interactions in the subsurface. Individual fault compartments within the field exhibit a complex charge and seal history with temporal variations over both geologic and production time scales. Sealing faults play an important role in subsurface fluid distribution within the field as demonstrated by different oil-water contacts (up to 1000 ft), distinct pressure cells (up to 2000 psi differential) and unique geochemical and PVT parameters observed between adjacent fault-bounded compartments. Both membrane (sand-on-sand) and juxtaposition (sand-to-shale) fault seals are interpreted in the field. Based upon cored fault rocks, clay smear deformation is the primary mechanism responsible for the seal potential of the membrane seal fault zones. Broad deformation zones comprised of clay smear and dense cataclastic shear bands typically surround larger faults and locally minor diagenesis is observed. The history of hydrocarbon production and gas/water injection in the field has highlighted the temporal variabilitymore » of fault seal behavior within the field. Examples of faults that sealed over geologic time but which broke-down during production are observed. Faults control fluid movement within the reservoir and degrade reservoir productivity adjacent to fault damage zones. Incorporation of fault transmissibilities and seal potentials into reservoir simulation models is necessary to evaluate reservoir and fault behavior under changing production conditions. An understanding of how faults influence reservoir behavior through production time is critical to the success of the field development plan.« less
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Research Article| November 01, 2003 Fluid-flow properties of faults in sandstone: The importance of temperature history Quentin J. Fisher; Quentin J. Fisher 1Rock Deformation Research Group, School of Earth Sciences, University of Leeds, Leeds LS2 9JT, UK Search for other works by this author on: GSW Google Scholar Martin Casey; Martin Casey 1Rock Deformation Research Group, School of Earth Sciences, University of Leeds, Leeds LS2 9JT, UK Search for other works by this author on: GSW Google Scholar Simon D. Harris; Simon D. Harris 1Rock Deformation Research Group, School of Earth Sciences, University of Leeds, Leeds LS2 9JT, UK Search for other works by this author on: GSW Google Scholar Robert J. Knipe Robert J. Knipe 1Rock Deformation Research Group, School of Earth Sciences, University of Leeds, Leeds LS2 9JT, UK Search for other works by this author on: GSW Google Scholar Geology (2003) 31 (11): 965–968. https://doi.org/10.1130/G19823.1 Article history received: 13 May 2003 rev-recd: 04 Aug 2003 accepted: 06 Aug 2003 first online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Quentin J. Fisher, Martin Casey, Simon D. Harris, Robert J. Knipe; Fluid-flow properties of faults in sandstone: The importance of temperature history. Geology 2003;; 31 (11): 965–968. doi: https://doi.org/10.1130/G19823.1 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGeology Search Advanced Search Abstract Sandstone rheology and deformation style are often controlled by the extent of quartz cementation, which is a function of temperature history. Coupling findings from deformation experiments with a model for quartz cementation provide valuable insights into the controls on fault permeability. Subsiding sedimentary basins often have a transitional depth zone, here referred to as the ductile-to-brittle transition, above which faults do not affect fluid flow or form barriers and below which faults will tend to form conduits. The depth of this transition is partly dependent upon geothermal gradient. In basins with a high geothermal gradient, fault-related conduits can form at shallow depths in high-porosity sandstone. If geothermal gradients are low, and fluid pressures are hydrostatic, fault-related conduits are only formed when the sandstones have subsided much deeper, where their porosity (and hence fluid content) is low. Mineralization of faults is more likely to occur in areas with high geothermal gradients because the rocks still have a high fluid content when fault-related fluid-flow conduits form. The interrelationship between rock rheology and stress conditions is sometimes a more important control on fault permeability than whether the fault is active or inactive. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.
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Anomalously high (up to +8°C) and low (−2°C) groundwater temperatures, as compared to undisturbed geothermal profiles, have been observed in unconsolidated siliciclastic aquifers off‐set by normal‐faults in the Lower Rhine Embayment, Germany. High hydraulic head gradients, induced by pumping, over the same faults suggest that they form effective barriers to lateral groundwater flow. Numerical analysis of the geothermal data presented here shows that the observed thermal anomalies can be explained under the assumption that the faults form a sub‐vertical pathway that is connecting deep and shallow aquifers that are elsewhere separated by confining units. The hydraulic head and temperature observations taken together are consistent with the hypothesis that these faults behave as a conduit‐barrier systems. Such behavior would arise from clay‐smearing and drag of sand along the fault plane. Most current models of fault hydrology in unconsolidated sedimentary sequences assume faults to be effective barriers to fluid flow. Therefore our findings can have important consequences for the assessment of contaminant flow or hydrocarbon migration in sedimentary aquifer systems cut by faults.
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Hydrocarbon columns in Pliocene sands of offshore SE Trinidad occur in 3-way closure, primarily in the footwall of normal faults. Multiple reservoir sands and numerous fault blocks result in a large number of individual hydrocarbon accumulations. Fault-plane sections demonstrate that fault sealing is unrelated to juxtaposition of intercalated shales. These fault-zone capillary seals were studied by (1) inferring their fluid-flow properties from the pattern of trapped hydrocarbons and (2) direct examination and measurement of cored faults. Buoyancy pressures for hydrocarbon columns were calculated from fluid property data for each reservoir and fault block. Buoyancy pressures range widely, increasing nonlinearly with fault displacement and percent shale in the faulted section, but do not vary systematically with stratigraphic position or depth. Small-displacement faults observed in core are narrow zones of cataclasis within porous sandstone. Mercury injection tests indicate fault-zone displacement pressures that coincide with buoyancy pressures calculated for hydrocarbon columns sealed by large-displacement faults. The agreement between measured displacement pressures and calculated buoyancy pressures indicates that (1) the reservoirs are filled to their capacity, dictated by the displacement pressure of the fault zones, and (2) the fault-zone seals are primarily the product of deformation of the sands, with some enhancement by incorporation more » of argillaceous material into the fault zones. The observed relationship between fault displacement and calculated buoyancy pressure of the hydrocarbon columns implies that fault-zone continuity is a factor that needs to be assessed in fault-zone seal analysis. « less
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The pore spaces in sedimentary basins are mostly filled with water. Oil and gas are the exceptions and most of the information we have about fluid flow in sedimentary basins is derived from the composition of water and the pressure gradients in the water phase. It is therefore important to characterise and understand the variations in the composition of these waters. All the porewater may be referred to as subsurface water but the water that is analysed from exploration wells or is produced during oil production is usually called formation water or oil field brines.
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