This study developed new concepts and interpretative methods for mapping reservoir heterogeneity and connectivity of a fault controlled Wilcox clastic reservoir in Texas, USA. The application of high-resolution seismic enhancement in this study allows for better delineation of subsurface geologic features, detailed mapping of reservoir heterogeneities and more accurate identification of depositional, structural, and stratigraphic characteristics that control reservoir connectivity and fluid flow. Seismic enhancement in this study pertains to amplitude preserving neural network implementation of the Volterra integral equation of the first kind from a plane-wave solution of poro-viscoelasticity (Sun, et al., 2003). This enhancement amounts to an advanced spiked deconvolution of post-stack seismic data that broadened the dominant seismic frequency from 16Hz for the conventional seismic to 65Hz for the enhanced seismic. Bed resolution is improved from 175ft to 45ft and fault offset resolution is improved from 80ft to 20ft. High-resolution seismic interpretation was validated through synthetic seismograms, stratigraphic surface comparisons, and most importantly using a comprehensive model-based knowledge of regional tectonics and depositional environments. Stratigraphic features that were not resolvable in conventional seismic data can now be interpreted using the enhanced seismic data. An Upper Wilcox reservoir was identified as a transgressive sheet sand overlaying a progradational deltaic seismic facies. An Upper Middle Wilcox reservoir was identified as a probable lobate gravity flow, and a Middle Wilcox reservoir was identified as a transgressive sheet sand with over and underlying progradational deltaic seismic facies. Geobody extraction from seismic inversion volumes delineates reservoir compartments and flow units. Reservoir connectivity analysis performed on the Middle Wilcox reservoir determined the probable drainage area for a producing well by comparing estimates of compartmentalized hydrocarbon volumes with production information. The methodology developed could help extract connected geobodies defined by sand, porosity, permeability, and hydrocarbon indicators, to map in detail the internal structure of produced reservoir and to locate new development prospects. Enhanced seismic may thus enable us to find bypassed hydrocarbons and to provide better methods for improving recovery in the studied and other mature fields.

Using injection and production data, we can evaluate the connectivity between injector and producer well pairs to characterize their interwell regions and provide a tool for waterflood management. The capacitance model (CM) has been suggested as a phenomenological method to analyze the injection and production data for these purposes. Early studies involving reservoir simulation have shown CM to be a valuable tool but also have revealed several shortcomings. Many of these deficiencies have become more transparent in analyzing field data. This work consists of two parts: in the first part, we investigate some of the shortcomings of the CM and attempt to overcome them by modifying the algorithms. In the second part, we relate the problem of interwell connectivity to the rigorous concept of Multiwell Productivity Index (MPI) and provide a semi analytical approach. We have developed two modifications on the CM: the segmented CM that can be used where bottomhole pressures (BHP) are unknown and may change during the analysis interval, and the compensated CM that overcomes the requirement to rerun the model after adding a new producer or shutting in an existing producer. If both BHP changes and shut-in periods occur, the segmented and compensated CMs can be used simultaneously to construct a single model for a period of data. We show several hypothetical cases and a field case where these modifications generate a more reliable evaluation of interwell connectivity and increase the R2 of the model up to 15%. On the other hand, the MPI-based approach can predict the reservoir performance analytically for homogeneous cases under specific conditions. In the heterogeneous cases, this approach provides a robust connectivity parameter, which solely represents the reservoir heterogeneity and possible anisotropy and hence allows improved information exchange with the geologist. In addition, this connectivity parameter is insensitive to possible variations of skin factor and changes in number of wells. A further advantage of the new method is the flexibility to incorporate additional information, such as injector BHP, into the analysis process. We applied this approach on several hypothetical cases and observed excellent evaluation of both reservoir performance and connectivity.

Reservoir permeability is one of the important parameters derived from well test analysis. Small-scale permeability measurements in wells are usually made using core plugs, or more recently, probe permeameter measurements. Upscaling of these measurements for comparisons with permeability derived well tests (Pressure Build-Up) can be completed by statistical averaging methods. Well Test permeability is often compared with one of the core plug averages: arithmetic, geometric and harmonic. A question that often arises is which average does the well test-derived permeability represent and over what region is this average valid? A second important question is how should the data sets be reconciled when there are discrepancies? In practice, the permeability derived from well tests is often assumed to be equivalent to the arithmetic (in a layered reservoir) or geometric (in a randomly distributed permeability field) average of the plug measures. These averages are known to be members of a more general power-average solution. This pragmatic approach (which may include an assumption on the near-well geology) is often flawed due to a number of reasons, which is tried to be explained in this study. The assessment of in-situ, reservoir permeability requires an understanding of both core (plug and probe) and well test measurements &amp / #8211 / in terms of their volume scale of investigation, measurement mechanism, interpretation and integration. Pressure build-up tests for 26 wells and core plug analysis for 32 wells have valid measured data to be evaluated. Core plug permeabilities are upscaled and compared with pressure build-up test derived permeabilities. The arithmetic, harmonic and geometric averages of core plug permeability data are found out for each facies and formation distribution. The reservoir permeability heterogeneities are evaluated in each step of upscaling procedure by computing coefficient of variation, The Dykstra-Parson&amp / #8217 / s Coefficient and Lorenz Coefficients. This study compared core and well test measurements in South East of Turkey heavy oil carbonate field. An evaluation of well test data and associated core plug data sets from a single field will be resulting from the interpretation of small (core) and reservoir (well test) scale permeability data. The techniques that were used are traditional volume averaging/homogenization methods with the contribution of determining permeability heterogeneities of facies at each step of upscaling procedure and manipulating the data which is not proper to be averaged (approximately normally distributed) with the combination of Lorenz Plot to identify the flowing intervals. As a result, geometrical average of upscaled core plug permeability data is found to be approximately equal to the well test derived permeability for the goodly interpreted well tests. Carbonates are very heterogeneous and this exercise will also be instructive in understanding the heterogeneity for the guidance of reservoir models in such a system.

>Magister Scientiae - MSc / This study describes porosity and permeability distribution in the deep marine play of the central Bredasdorp Basin, Block 9, offshore South Africa using methods that include thin section petrography, X-ray diffraction, and scanning electron microscopy, in order to characterize their porosity and permeability distributions, cementation and clay types that affect the porosity and permeability distribution. The study includes core samples from nine wells taken from selected depths within the Basin. Seventy three thin sections were described using parameters such as grain size measurement, quantification of porosity and permeability, mineralogy, sorting, grain shape, matrix, cementation, and clay content. Core samples were analyzed using x-ray diffraction for qualitative clay mineralogy and phase analysis. Scanning electron microscope analysis for qualitative assessment of clays and cements. X-ray diffraction (XRD) and scanning electron microscope (SEM) analyses were conducted on fifty-four (54) and thirty-five (35) samples respectively to identify and quantify the clay mineralogy of the sandstones. The SEM micrographs are also useful for estimating the type and distribution of porosity and cements. Analyses of these methods is used in describing the reservoir quality. Detrital matrix varies in abundance from one well to another. The matrix consists predominantly of clay minerals with lesser amounts of detrital cements. X-ray diffraction analyses suggest these clays largely consist of illitic and kaolinite, with minor amounts of chlorite and laumontite. Because these clays are highly illitic, the matrix could exhibit significant swelling if exposed to fresh sea water, thus further reducing the reservoir quality. The majority of the samples generally have significant cements; in particular quartz cement occurs abundantly in most samples. The high silica cement is possibly caused by the high number of nucleation sites owing to the relatively high abundance of detrital quartz. Carbonate cement, particularly siderite and calcite, occurs in variable amounts in most samples but generally has little effect on reservoir quality in the majority of samples. Authigenic, pore-filling kaolinite occurs in several samples and is probably related. to feldspar/glauconite alteration, it degrades reservoir quality. The presence of chlorite locally (plate 4.66A & B) and in minute quantities is attributed to a late stage replacement of lithic grains. Don't put references to plates and figures in abstract. A high argillaceous content is directly responsible for the low permeability obtained in the core analysis. Pervasive calcite and silica cementation are the main cause of porosity and permeability destruction. Dissolution of pore filling intergranular clays may result in the formation of micro porosity and interconnected secondary porosity. Based on the combination of information derived from thin section petrography, SEM and XRD, diagenetic stages and event sequences are established for the sandstone in the studied area. Reservoir quality deteriorates with depth, as cementation, grain coating and pore infilling authigenic chlorite, illite and kaolinite becomes more abundant.

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