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A finite element numerical model was used to analyze a quasi-steady-state, three-dimensional hydraulic head distribution measured in the vicinity of a fault partially displacing the Hickory aquifer system in central Texas. The spatial distribution of permeability of major stratigraphic units and fault rock was obtained utilizing kriging, forward modeling and geophysical inverse modeling. Core-scale permeability data, quasi-steady-state hydraulic head data and full-reservoir pump test data were used for analysis. The final permeability model provides a close match to the observed hydraulic head distribution with a correlation coefficient of 0.88.

The fault-rock permeability varies systematically with spatial position along the fault from a maximum of 20 md to a minimum of 0.0001 md. The highest permeabilities of 10-20 md (a 50 fold reduction of the sandstone protolith permeability) occur in the lowest portion of the fault, where the fault displaces sandstone-dominant strata. Pump test data also clearly show fluid flow is focused through this region of the fault. The fault-rock permeability decreases progressively up dip along the fault in a fashion closely reflecting the increase of mudstone strata cut by the fault. Where the mudstone-rich Lower Middle Hickory is faulted against the sandstone-dominant Lower Hickory, permeabilities of 4 md are inferred. Where the mudstone-rich Lower Middle Hickory is faulted against itself, the permeability 0.03 md.

The 10-20 md permeability inferred in the lower part of the fault is about a factor of 10 greater than that inferred from core-scale measurements of fault-rock samples as well as from earlier simple 1-D model estimates. This difference may reflect upscaling issues, but additional analysis is needed to more definitively reconcile the different estimates.

Multilevel monitoring systems provides a direct measure of effects of faults and stratigraphic heterogeneities upon fluid flow in an aquifer. Variations of drawdown histories in zones straddling a fault permits identification of delay times and changes in the functional form of the response curves associated with the fault. Analysis of vertical gradient variation with time, allows to separate hydraulic responses of the zones straddling low permeability faults, resolve geometry of the faulted region and obtain additional constraints for conceptual model and defining parameters.

Finding and developing oil and gas resources requires accurate geological information with which to formulate strategies for exploration and exploitation ventures. When data are scarce, statistical procedures are sometimes substituted to compensate for the lack of information about reservoir properties. The most modern methods incorporate geostatistics.

Even the best geostatistical methods yield results with varying degrees of uncertainty in their solutions. Geological information is, by its nature, spatially limited and the geoscientist is handicapped in determining appropriate values for various geological parameters that affect the final reservoir model (Massonnat, 1999).

This study focuses on reservoir models that depend on geostatistical methods. This is accomplished by quantifying the uncertainty in outcome of reservoir simulations as six different geological variables are changed during a succession of reservoir simulations. In this study, variations in total fluid produced are examined by numerical modeling. Causes of uncertainty in outcomes of the model runs are examined by changing one of six geological parameters for each run.

The six geological parameters tested for their impact on reservoir performances include the following: 1) variogram range used to krig thickness layers, 2) morphology around well 14, 3) shelf edge orientation, 4) bathymetry ranges attributed for each facies, 5) variogram range used to simulate facies distribution, 6) extension of the erosion at top of the reservoir.

The parameters were assigned values that varied from a minimum to a maximum quantity, determined from petrophysical and core analysis.

After simulation runs had been completed, a realistic, 3-dimensional reservoir model was developed that revealed a range of reservoir production data.

The parameters that had the most impact on reservoir performance were: 1) the amount of rock eroded at the top of the reservoir zone and 2) the bathymetry assigned to the reservoir facies.

This study demonstrates how interaction between geological parameters influence reservoir fluid production, how variations in those parameters influence uncertainties in reservoir simulations, and it highlights the interdependencies between geological variables.

The analysis of variance method used to quantify uncertainty in this study was found to be rapid, accurate, and highly satisfactory for this type of study. It is recommended for future applications in the petroleum industry.

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Current geologic thinking is that there are two, and only two distinct types of brittle fractures, joints and shear fractures (faults). For over a half century, it has been debated that a third type of fracture, referred to as hybrid fractures, could exist and that joints and shear fractures may be end members of a continuous spectrum of brittle fractures. Hybrid fractures are hypothesized to form under mixed compressive and tensile stress states and have structural characteristics intermediate to those of joints and shear fractures. While this hypothesis is accepted in many modern structural geology textbooks used at the college and graduate level, no unchallenged evidence exists for the existence of hybrid fractures.

Following the general methodology of a previously performed study by W.F. Brace (1964), but incorporating several key modifications to the experimental methods, a series of dog-bone triaxial experiments were performed on Carrara marble at room temperature, an axial extension rate of 2x10-2 mm s-1, and confining pressures between 7.5 and 170 MPa. The experiments provide strong evidence for the existence of hybrid fractures on the basis of the progressive change in fracture orientation, surface morphology, and failure strength between end-member joints and shear fractures. At the lowest confining pressures (7.5 to 60 MPa), fractures are oriented approximately parallel to the maximum principal stress, s1, form at an axial stress s3, of approximately -7.75 MPa (i.e. the uniaxial tensile strength), and display fracture surfaces characterized by many reflective cleavage faces, consistent with jointing. At the highest confining pressures (130 to 170 MPa), fractures are oriented from 13.4&Mac176; to 21.6&Mac176; to s1, form under completely compressive stress states with s3 between 0 and 4.3 MPa, and are characterized by powdery white surfaces with short slip lineations, consistent with shear fracturing. At intermediate confining pressures (70 to 120 MPa), fractures are oriented from 3.7&Mac176; to 12.4&Mac176; to s1, form under mixed stress conditions with s3 ranging from –10.6 to –3.0 MPa, and display both reflective cleavage faces and powdery white surfaces with short slip lineations, consistent with hybrid fracturing.

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Examination of physical and acoustic properties of carbonate-rich sediments was conducted on a suite of cores off of the coasts of Molokai and Lanai Islands, Hawaii. Carbonate mineralogy, grain size, grain density, porosity, bulk density and velocity measurements were systematically collected. In addition, bulk sediment d18O values were analyzed. Generally, there is a positive correlation between velocity, bulk density, percent sand, and high magnesium calcite and a negative relationship between velocity, percent clay, porosity, water content and low magnesium calcite. Down-core, bulk sediment d18O variability is a direct indicator of climate and sea level fluctuations. Glacial sediments, deposited during sea level lowstands, are isotopically heavy and characteristically have higher velocity, bulk density, sand and high magnesium calcite values, and lower measured clay content, porosity, water content and low magnesium calcite values than interglacial sediments. Property variability is influenced by regional differences in slope morphology, depositional controls, and water depth as well as physical, chemical, and biological processes and the properties of regional (intermediate) water masses. Identification of the glacial-interglacial transition and related physical and acoustic properties may be applied to high resolution seismic data interpretation and may enhance our understanding of the regional environmental conditions responsible for property formation.

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Numerical simulations indicate that hydrocarbon migration and entrapment in stacked fault-bounded reservoirs are mainly affected by the following factors: charge time, faults, pressure and geological structures. The charge time for commercial hydrocarbon accumulation is much longer in oil-water systems than in oil-gas-water systems.

Faults are classified into charging faults and "back doors" – faults other than charging faults in stacked fault-bounded reservoirs. The lower the displacement pressure of a fault, the higher its updip oil transportation ability. The downdip oil transportation ability of a fault is usually low and cannot cause commercial downdip oil accumulation.

Back doors affect both hydrocarbon percent charge and hydrocarbon migration pathways. Updip back doors improve updip oil charge. The lower the displacement pressure of an updip back door, the more efficient the updip oil charge before 3,000 years. Back doors whose displacement pressure is equal to or higher than 28.76 psi are effective sealing faults in oil-water systems. On the contrary, only sealing faults result in commercial gas accumulations in stacked fault-compartmentalized reservoirs. Otherwise gas is found over oil. Downdip back doors generally have a few effects on downdip hydrocarbon charge.

Geopressure enhances the updip oil transportation of a fault and improves the positive effects of updip back doors during updip oil charge. Geopressure and updip back doors result in more efficient updip oil charge. A physical barrier is not necessarily a barrier to oil migration with the aid of geopressure and the updip back doors.

The chance for hydrocarbon charge into reservoirs along growth faults is not equal. Any one of the above controlling factors can change the patterns of hydrocarbon charge and distribution in such complex geological structures. Generally, lower reservoirs and updip reservoirs are favored. Reservoirs along low-permeability charging faults may be bypassed. Gas can only charge the updip reservoirs. Both updip and downdip back doors can facilitate oil penetrating a barrier fault to charge reservoirs offset by the barrier fault.

Interreservoir migration among stacked fault-compartmentalized reservoirs is an important mechanism for hydrocarbon accumulation and trap identification. The interreservoir migration is a very slow process, even though the displacement pressures of bounding faults may be very low.

Flow units in the Oxfordian Smackover Formation at Vocation and Appleton Fields were identified, mapped, and ranked as part of an integrated reservoir characterization project. Pore categories by origin, pore and pore throat geometries, pore-scale diagenetic history, and core-scale depositional attributes were logged with conventional petrographic and lithological methods. Resulting data were combined with core descriptions, mercury-injection capillary pressure data, and wireline log data to produce flow unit maps at field scale.

Appleton and Vocation Fields produce from grainstone buildups and microbial reefs. Classification of microbial fabrics within reefs was found to have significant influence on pore facies and flow unit quality rankings and ultimately on reservoir quality in these fields in particular and in southwest Alabama in general. Microbial reefs are composed of five fabric categories and growth forms that reflect variations in water energy, sedimentation rate and substrate. They include Type I layered thrombolite with characteristic mm/cm-scale crypts, Type II reticulate and "chaotic" thrombolite, Type III dendroidal thrombolites, Type IV isolated stromatolitic crusts , and Type V oncoidal packstone/grainstones that grew on soft to firm substrates in high-energy conditions. Types I, II, and III buildups are the most productive reservoirs. Of these, Type III buildups contain the highest quality reservoir rocks, which consist of extensively dolomitized reticulate and dendritic fabrics that have well-connected intercrystalline and vuggy porosity. Types IV and V microbialites are poor reservoir rocks because Type IV reefs are rarely in communication with the bulk of the reservoir and Type V oncoids exhibit separate vug porosity with low to moderate permeability.

Results of this work have improved our understanding of complex grainstone and microbial reef reservoirs. In so doing, the results have improved our ability to characterize and model complex reservoir architecture, pore systems and flow unit quality from pore to core to field scale. This study should enable more accurate and economical development of these fields and of others like them.

The Rodessa Formation is one of the major oil and gas reservoirs in the East Texas Basin. In Van Field, the upper Rodessa Formation consists of interbedded biotic and abiotic mudstones to grainstones. The lower Rodessa is composed of interbedded sandstones, shales, and limestones called the Carlisle Member. Based on core and well log interpretation, the Rodessa Formation was deposited on a broad, restricted, shallow marine platform interpreted to be lagoonal, subtidal, and intertidal.

Both Rodessa limestone and sandstone have been altered significantly by diagenetic processes that include micrtization, cementation, dissolution, neomorphism and compaction. Dissolution is the main factor that resulted in enhanced porosity and permeability while cementation adversely affected porosity. Diagenesis is interpreted to have begun in the marine phreatic environment and continued through the fresh water phreatic and shallow burial environments.

Two reservoir units have been identified from core and well log interpretation. The potential reservoir within the Rodessa Formation occurs in the Carlisle Member which is composed mainly of medium to coarse grained sandstone with porosities and permeabilities in ranges of 8 to 11 percent and 46 to 896 millidarcies, respectively. The water saturation analysis has also shown the reservoir to be hydrocarbon bearing, having water saturation below 46 percent.