Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid. / text

The application of surfactants and polymers in carbonate reservoirs has a high potential with emerging technology of the manufacture of these chemicals. Tertiary or enhanced oil recovery with chemicals (CEOR) will become more relevant with decreasing new exploration of oil deposits and high remaining oil saturations in huge carbonate oil reservoirs. However, in several oil deposits, high reservoir brine salinity and moderate to high reservoir temperature are encountered. Under such conditions, many chemicals will be insoluble or degrade fast. A selection of commercial and research surfactants and polymers has been investigated for their application under brine salinity of up to 18 percent by weight with significant hardness and a moderate reservoir temperature of 70 °C. Chemical systems were tested towards outcrop limestone rock samples and calcite platelets in combination with a crude oil, which was modified by different organic acids regarding its wetting potential. Wettability alteration from preferentially oil-wet core plugs was pursued with ethoxylated tertiary amines and quaternary ammonium compounds. The main mechanism of wettability alteration towards more water-wet was proposed as extraction of carboxylate anions from the oil phase and the solid samples into aqueous micelles. Thus, high surfactant concentrations would result in improved recovery. From screening of different surfactant combinations in tertiary core flooding, one promising system of an alkyl ether sulfate and hexadecyltrimethylammonium combined with a terpolymer (TP) from acrylic acid, ATBS and NVP is proposed for the examined conditions. Low to moderate adsorption of the single surfactants and their combination as well as a favorable, stabilized phase behavior when combined with the polymer emphasize the applicability of the system. However, long term stability can be an issue with respect to the sulfate surfactant degradation at 70 °C. Analysis of mixed ionic surfactant systems after adsorption testing has been successfully pursued with a combined TC/TNb-determination.