Wettability is a key parameter that affects the petrophysical properties of reservoir rocks. The objective of the present work is to investigate the influence of temperature and pressure on the wettability of reservoir rocks. An experimental method for the measurements of contact angle at elevated temperature and pressure has been developed, in which a Pendant Drop Interfacial Tension Cell was modified. Experimental results of contact angle and interfacial tension for two different crude oil-brine-quartz/calcite and mineral oil-distilled water systems over a range of temperatures and pressures are reported. Contact angle for the systems studied increased with pressure, increased with temperature for sandstone system and decreased with temperature for carbonate system. Introduction Wettability has been defined as the relative ability of a fluid to spread on a solid surface in the presence of another fluid. Knowledge of wettability is important for the estimation of oil reserves and for the prediction of production performance. It affects the distribution of water, oil, and gas within a reservoir rock, which in turn affects the displacement behavior and relative permeability characteristics. Wettability is also important to the success of enhanced oil recovery operations. Even though wettability is considered to be a key factor affecting oil production and enhanced oil recovery, almost all of the available data on wettability of core sample, contact angle and interfacial tension for crude oil-brine systems are for room temperature and pressure. The effects of temperature and pressure on floe wettability of reservoir rocks are not well understood. Several methods have been proposed for the measurement of wettability contact angle method is used for measuring floe wettability of a specific surface. Contact angle measurement can be achieved by several different methods, such as tilting plate method, sessile or pendant drop method, vertical rod method, tensiometric method, cylinder method, and capillary rise method (Adamson, Johnson and Dettre, Good, Neumaton and Good, Popiel and McCaffery). Pendant drop method, first suggested by Worthington, was initially used for measuring the interfacial tension between two immiscible fluids. In this method, interfacial tension is calculated using the empirical equations developed by Andreas et al. along with the measurements of drop shape. The apparatus used for interfacial tension measurement by pendant drop method was further developed and modified to measure the contact angle of liquid-rock systems. McCaffery presented an apparatus for measuring interfacial tension and contact angle at elevated temperature and pressure. He reported the measurements of interfacial tension for n-dodecane/water and n-octane/water systems, and contact angle for refined oil/brine/quartz systems. Hjelmeland used this method and reported measurements of interfacial tension and contact angles for stock tank oil, recombined reservoir oil and brine systems. Previous studies about the effects of temperature and pressure on interfacial tension and contact angle indicate that observed trends will depend on the systems studied. This phenomenon has not been well explained until now and the factors influencing wettability of reservoir rocks have not been well understood. P. 117

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFeasibility of drilling with pure supercritical carbon dioxide to serve the needs of deep underbalanced drilling operations has been analyzed. A case study involving underbalanced drilling to access a depleted gas reservoir illustrates the need for such a study. For this well, nitrogen was initially considered as the drilling fluid. Dry nitrogen, due to its low density, was unable to generate sufficient torque in the downhole motor. Mixture of nitrogen and water, stabilized as foam, generated sufficient torque, but made it difficult to maintain underbalanced conditions. This diminished the intended benefit of using nitrogen as the drilling fluid. CO 2 is likely to be supercritical at downhole pressure and temperature conditions, with density similar to that of a liquid and viscosity comparable to a gas. A computational model was developed to calculate the variation of density and viscosity in the tubing and the annulus with pressure, temperature and depth. A circulation model was developed to calculate the frictional pressure losses in the tubing and the annulus, and also calculates important parameters such as the jet impact force and the cuttings transport ratio. An attempt was made to model the temperatures in the well using an analytical model. Corrosion aspects of a CO 2 based drilling system are critical and were addressed in this study. The results show that the unique properties of CO 2 , which is supercritical in the tubing and changes to vapor phase in the annulus, are advantageous in its role as a drilling fluid. It has the necessary density in the tubing to turn the downhole motor and the necessary density and viscosity to maintain underbalanced conditions in the annulus. The role of a surface choke is crucial in controlling the annular pressures for this system. A carefully designed corrosion control program is essential for such a system. Results of this study are also important for CO 2 sequestration and CO 2 based enhanced oil recovery operations.

The recovery model proposed by Civan4,5 was extended to account for additional mechanism of mass transfer from matrix to fracture. This led to triple exponential functions that offered significant improvement in the agreement between experimental and predicted oil recovery during imbibition. Inclusion of contact angle in the time scaling group resulted in significantly improved correlation amongst the imbibition recovery for samples with varying shapes and sizes, flow boundary conditions, and fluid and rock properties. The analysis presented here allows the estimation of a representative contact angle. Three distinct exponential terms were identified for experimental data analyzed. Such functions matched the cumulative oil recovery for early as well as late time.

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The use of permeability tensors is required when modelling fluid flow in anisotropic and heterogeneous reservoirs presenting multiple zones of directional permeability, or those categorized as naturally fractured reservoirs. A general procedure for characterizing complex reservoirs utilizing their permeability tensor is being developed by integrating data and methods from different disciplines. Permeability tensors for geologically defined fracture patterns are derived, and finally these small-scale descriptors are incorporated into a reservoir simulation program capable of handling full tensor permeabilities. The application and convenience of the method presented in this paper is illustrated with a field example from a naturally fractured reservoir. Introduction For many years, substantial research has been conducted in the areas of geosciences and engineering in order to characterize naturally fractured reservoirs. Numerous approaches have been presented to properly overcome this difficult task. Geoscientists have focused their research towards understanding the process of fracturing (rock mechanics), and the subsequent description of fracture characteristics such as density and orientation. Engineers, on the other hand, have focused their attention to the description of the fluid flow in the fracture systems, and in the development of accurate models (reservoir simulators) to reproduce the history, and predict the hydrocarbon production, for these complex systems. One of the first matrix-fracture models was presented by Warren and Root(1), who presented an idealized sugar cube model with two classes of porosity, a primary porosity that is intergranular, and a secondary porosity that is induced by fractures. Even though the sugar cube model has been widely accepted as the forerunner of the modern interpretation of dual-porosity systems, its limitations in describing the behaviour of some complex fractured reservoir systems have been observed. It is now well known that almost all fracture systems are much more complicated than the suggested model of three orthogonal sets of uniform fractures. One of the most important factors that has been identified as a necessary addition to improve the overall description of such complex reservoirs is the definition of a nine-component permeability tensor for the fracture system. This tensor is used to model fluid flow in complex reservoirs with multiple zones of directional permeability, where the orientation and magnitude of the principal permeabilities may vary between different zones in the reservoir. Snow(2, 3) studied the convenience of using mathematical equivalents of parallel plate openings to simulate fractures dispersed in orientation, distributed in aperture, and of arbitrary spacing. Models for fractured media which contained any number of planar conductors of any orientation and any fine aperture were presented. A key assumption was that all of the conduits have smooth parallel plane walls of indefinite extent (infinite fractures), and an rbitrary aperture. As a result, a permeability tensor could be obtained by superposition of contributions due to the fractures, and due to the permeable matrix. Long et al.(4, 5) addressed the more realistic scenario of finite or discrete fracture systems, where properties such as shape, orientation and location of the fractures in an impermeable matrix were considered to be random variables.