The Spraberry Formation is traditionally thought of as deep-water turbidites in the central Midland Basin. At Happy Spraberry field, Garza County, Texas, however, production is from a carbonate interval about 100 feet thick that has been correlated on seismic sections with the Leonardian aged, Lower Clear Fork Formation. The "Happy field" carbonates were deposited on the Eastern Shelf of the Midland Basin and consist of oolitic skeletal grainstones and packstones, rudstones and floatstones, in situ Tubiphytes bindstones, and laminated to rippled, very-fine grained siltstones and sandstones. The highest reservoir "quality" facies are in the oolitic grainstones and packstones where grain-moldic and solution-enhanced intergranular porosity dominate. Other pore types present include incomplete grain moldic, vuggy, and solution-enhanced intramatrix. The purpose of this study was to relate pore geometry measured by digital petrographic image analysis to petrophysical characteristics, and finally, to reservoir quality. Image analysis was utilized to obtain size, shape, frequency, and total abundance of pore categories. Pore geometry and percent porosity were obtained by capturing digital images from thin sections viewed under a petrographic microscope. The images were transferred to computer storage for processing with a commercial image analysis program trademarked as Image Pro Plus (Version 4.0). A classification scheme was derived from the image processing enabling "pore facies" to be established. Pore facies were then compared to measured porosity and permeability from core analyses to determine relative "quality" of reservoir zones with different pore facies. Pore facies are defined on pore types, sizes, shapes, and abundances that occur in reproducible associations or patterns. These patterns were compared with porosity and permeability values from core analyses. Four pore facies were identified in the Happy field carbonates; they were examined for evidence of diagenetic change, depositional signatures, and fractures. Once the genetic categories were established for the four pore facies, the pore groups could be reexamined in stratigraphic context and placed in the stratigraphic section across Happy field. Finally, the combined porosity and permeability values characteristic of each pore facies were used to identify and rank good, intermediate, and poor flow units at field scale.

Multiphase flow in porous media is a wide-ranging phenomenon, covering such topics as the motion of immiscible fluids, where the interaction with the medium is by exchange of heat and/or mass between phases, to fluid-solid phase flow accompanied by clogging and leaching. The present study is limited to the flow of immiscible fluids (oil and surfactant), where fine solids (clay) migration occurs during the motion. It is divided into two parts: (a) experimental and (b) theoretical. / The experimental investigations have been performed in order to evaluate: (a) the factors (e.g., porosity, temperature and injection pressure) that affect the injected surfactant flow rate through oil/soil mixtures, (b) the role of clay mineral concentration on the uptake and displacement of oil by the injected surfactant, (c) the portion of the oil displaced by the injected surfactant in the medium, under the testing conditions, (d) the effect of injection head on the rate of oil uptake during the injection process. / The theoretical analysis leads to a new diffusion model which accounts for the simultaneous movement of oil, fines and surfactant. The conclusion to be drawn from this part is that the new simplified model, together with further refinement, lead to a better understanding of the behaviour and prediction of the multiphase flow through a porous medium.

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