Reservoir rock typing is a process by which geological facies are characterized by their dynamic behavior. The dynamic behavior of the facies is assessed by studying the rock texture, the diagenetic processes which overprinted the initial fabric, and the interaction between the rock itself and the fluids. Porosity, permeability and pore size distributions characterize the rock texture while capillary pressure, relative permeability and wettability describe the rock-fluid interaction. Reservoir rock typing is a synergetic process between geology and petrophysics/SCAL. It is therefore a process by which various petrophysical parameters and dynamic measurements obtained from SCAL are integrated in a consistent manner with geological facies (lithofacies) to estimate their flow (dynamic) behavior. The relationships between lithofacies and reservoir rock types (RRTs) is complex because of the inter-play between facies, diagenetic processes and the rock-fluid interaction (wettability changes) in the reservoir. Similar lithofacies, deposited under the same depositional environments, may exhibit different petrophysical properties due to diagenesis. Therefore, lithofacies deposited under similar geological conditions may experience different diagenetic processes resulting in different petrophysical groups with distinct porosity-permeability relationship, capillary pressure profile and water saturation (Sw) for a given height above the Free Water Level (FWL). On the contrary, lithofacies deposited in different depositional environments, might exhibit similar petrophysical properties and dynamic behavior. The authors emphasize on the need to have a good understanding of the original facies, depositional environments, subsequent diagenetic processes and rock-fluid interaction (via SCAL) to be able to unravel the relationships between lithofacies, petrophysical groups and rock types. A workflow for carbonate rock typing addressing some of the industry pitfalls and the differences between lithofacies, petrophysical groups and rock types are presented in this paper. Introduction -NomenclatureBefore proceeding into the rock type description and its link with geology and SCAL, it is important to provide a few basic definitions of the common technical terminologies found in the literature such as lithofacies, facies associations, petrophysical groups, rock types and flow units. In this paper we define lithofacies or lithofacies types as a depositional facies, or lithotype, based on sedimentary texture (Dunham 1962; Embry and Klovan 1971), grain types (skeletal grains, peloids, ooids, etc.), and, optionally, sedimentary structures (cross-bedding, bioturbation, lamination, etc.). Typical lithofacies types are skeletal wackestone, skeletal-peloid packstone or cross-bedded ooid grainstone. Facies associations are groups or bins of lithofacies from the same depositional environment/facies tracks with common φ-k relationships/trends. Petrophysical groups are units of rocks (can consist of multiple lithofacies) with similar petrophysical ...

The application of an improved model for the estimation of pore-size distributions in reservoir core samples is presented. The technique has been applied to a series of nine samples of hydrocarbon reservoir rocks. Excellent agreement with the experimental nuclear magnetic resonance data was obtained. Of particular interest is the fact that, in two cases, broadly similar distributions were obtained for two different samples taken from the same source. This may be of significance in the prediction of the bulk petrophysical properties of the reservoirs.

Summary An experimental research program to investigate the effects of liquid saturation upon non-Darcy flow coefficients is presented. The presence of a wetting phase fluid plays an important role in high velocity flow of a gas well, producing condensate or water, and in propped fractures containing liquid saturations. This study initially examines the errors commonly encountered but ignored in evaluating the permeabilities and the coefficient of inertial resistance during the flow of gases through porous media. Experimental techniques, such as constant overburden pressure, changing overburden pressure, forward flow, and backpressure flow, are applied to optimize and obtain accurate evaluations of Klinkenberg parameters and inertial resistance coefficients for a selection of Omani reservoir cores. Gas-slippage factor significantly influences the derived viscous and inertial coefficients from high-velocity gas flow data. An increasing wetting phase saturation increases the non-Darcy coefficient up to thirty-fold. Analysis of the experimental data revealed that unique relationships exist between the non-Darcy flow coefficients and the equivalent liquid permeability, porosity, and liquid saturation. Heterogeneity of the core as mapped by pore-scale measurements provide an insight into the mechanism for such a large increase in the non-Darcy coefficients. Introduction Anomalies have been reported in the literature in laboratory-determined equivalent liquid permeability, kL, from single-phase gas permeability measurements.1 It is often found that kL evaluated for the same dry reservoir core varies from laboratory to laboratory, and that at times the repeatability of evaluated kL from the same laboratory is difficult.2,3 As kL is an important core characterization parameter, this report initially aims to outline the correct experimental and analytical procedure in obtaining the representative kL values for dry cores. Klinkenberg-corrected permeabilities are used as industry standards in correlating permeability data of reservoir cores. Any core analysis or Special Core Analysis (SCAL) study is based on kL measurements to correlate the absolute permeability of the chosen cores. Permeability is regarded as a fundamental reservoir property, and core measurements are used extensively to validate both the well-test data and log-derived data. The prevalence of non-Darcy flow in gas wells is well known. An important rock parameter that is often used in various pressure calculations and production profiles is the coefficient of inertial resistance, known as ß. The use of ß as an independent reservoir characterization parameter, which in turn depends on rock parameters, such as porosity, tortuosity, and core heterogeneity, is important for gas wells producing at high rates (non-Darcy flow). The non-Darcy coefficient in such wells is usually determined from analysis of multirate pressure test data. Such data, however, are not always available; hence, calculation of the non-Darcy term requires a knowledge of the coefficient of inertial resistance. The measurement of ß in the laboratory is thus examined from steady-state gas-flow data in the transition from laminar to non-Darcy flow. In the gas condensate wells, liquid saturation could build up owing to retrograde condensation, which is caused by a large pressure drop. In the presence of a liquid phase, the non-Darcy effect in the gas phase can increase considerably, thereby causing a loss of productivity. High liquid saturation in the vicinity of a wellbore may also be caused by acidizing or mud filtrate invasion. The increase in the inertial effect in liquid-saturated porous media has been clearly demonstrated by Gewers and Nichol,4 who carried out experimental measurements on micro-vugular carbonates with a static liquid phase 0% to 30%. Their work was later extended by Wong5 for a mobile phase using same cores and increasing the liquid saturation from 40% to 70%. The inertial resistance coefficient increased eight-fold on increasing the liquid saturation from 40% to 70%. The same behaviour was expected to be observable in sandstones.6 However, non-Darcy measurements performed on Berea sandstones7 and Ottawa sand propped fractures8 (10/20, 20/40) showed the values to increase up to three times that of dry case for immobile liquid saturations up to 20%. Noman and Archer9 repeated the measurements on sandstone cores from North Sea gas wells and again found the increases not as rapid as that reported for carbonates. This study is based on a selection of sandstone reservoir cores from central Oman. It focuses the effect of increasing fluid saturation from 0% to 60% on the non-Darcy coefficient. Data from capillary pressure measurements are used to examine the influence of heterogeneity on the non-Darcy coefficient; Purcell10 has shown the relationship between capillary pressure and permeability. This is achieved by relating the magnitude of non-Darcy coefficients with mean pore throat radius. The relationship beween capillary pressure and pore radius, r, whereEquation 1 is used to indicate the heterogeneity of the samples used. Capillary pressure data are used to obtain the pore size distribution function, D(r), where D(r) is defined asEquation 2 The deviation from the mean pore-throat radius, r, is used in this study to indicate a degree of heterogeneity at the core-scale measurements. While heterogeneity is a complex phenomenon with a number of contributing factors, only pore radius derived from capillary pressure is used. For consistency, mean radii are calculated from similar fluid saturations used in determining the non-Darcy coefficients.

No abstract