TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA comprehensive set of experimental data from preserved reservoir sandstone is used to demonstrate features important to oil-wet systems not usually included in water-wet three-phase relative permeability models. The data are described by a generalized version of the relative permeability model developed by Jerauld (1997). The impact of these features on immiscible and miscible water-alternating-gas performance is estimated with type pattern simulations.The sandstone reservoir studied shows large amounts of spontaneous imbibition of oil and traps water during secondary drainage. Oil relative permeability is almost a function of oil saturation alone while water relative permeability is significantly lower in the presence of trapped gas. Unlike most systems, the trapped gas saturation depends on the relative amounts of oil and water. While two-phase trapped gas values are consistent with values in the literature for similar sandstones, three-phase trapped gas levels are approximately a factor of two lower. The residual oil saturations for waterflooding and gasflooding followed by waterflooding are the same. Furthermore, the incremental oil production during the waterflood following gasflooding was minimal.Two different lithologies show the same general behavior. Experiments run with different pressure drops demonstrate that the low trapped gas saturations are not due to capillary desaturation. CT scans show that little redistribution of gas occurs during trapping.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPrimary drainage capillary pressure (P c ) data are key to determining hydrocarbons-in-place. In this paper, a methodology will be described that can be used by practicing engineers and geologists to obtain high quality P c data, and to analyze those data to make accurate calculations of hydrocarbon-in-place.The steps in the methodology include: 1. Determine the appropriate P c measurement technique and experimental conditions in order to obtain reliable data for the specific reservoir and rock type. 2. Determine the quantity of data required to sufficiently characterize important facies or rock-types. 3. Analyze the data from various sources, test methods and conditions for quality and consistency. 4. Use an appropriate grouping technique to correlate the P c data for each rock type. These grouping techniques include J-function-, permeability-, porosity-, or grain density-based correlations. 5. Scale the laboratory data to reservoir conditions, based on the IFT and the contact angle for laboratory and reservoir fluids and the maximum capillary pressure needed to cover the reservoir relief. 6. Model capillary pressure for use in geologic models and reservoir simulation. 7. Integrate the data with other data sources (wireline resistivity data; Dean Stark saturation measurements of core taken with oil-based mud).This methodology is based on the experience gained by measurement and modeling of several thousand capillary pressure data sets from carbonate and clastic reservoir rocks. The methodology can be used for measuring and modeling capillary pressure in a more efficient and reliable way.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractA state-of-the-art special core analysis (SCAL) program for the Dukhan Arab C and Arab D carbonate reservoirs was designed to provide reliable relative permeability and capillary pressure models for use in field-wide reservoir studies. The workflow process for the design and its implementation of such a program is described with a specific focus on four key requirements: 1) measurements must be on representative rock samples (the right samples), 2) measurements must be made under conditions representative of displacement processes in the reservoir (the right conditions), 3) measurements must be made using precision equipment and techniques (the right equipment), and 4) trained and experienced technologists are needed to conduct the measurements and model the data (the right people). Results from the Arab D program are presented to demonstrate consistent saturation function models (capillary pressure and relative permeability) for simulation. The steady-state relative permeability methods, coupled with centrifuge, provide data over the range of saturation conditions encountered in the reservoir for both water-oil and gas-oil fluid pairings; this range of data coverage is significantly greater than is typically available in the industry and hence reduces uncertainty in the resultant relative permeability models. The water-oil relative permeability behaviors suggest a mixed-wet character with a preference to oil; however, one reservoir rock type (RRT) shows mixed wet character with a neutral preference for oil and water. The gas-oil relative permeability measurements are made on a unique apparatus capable of conducting the testing with reservoir fluids at reservoir conditions in the presence of irreducible water saturation. Centrifuge USBM wettability measurements were conducted on samples in the native, cleaned and restored state. Based on the measurements, it is concluded that the wettability restoration method used in this study was effective for a high-permeability Dukhan Arab D limestone core, but wettability restoration cannot be achieved for the moderately low-permeability limestone core. In general, restoration of carbonate cores to native state wettability is less successful than for siliciclastic cores. This is thought to be due to the complex pore structure of carbonates and the potential for change of pore structure through diagenesis after migration of petroleum.

Digital rock physics (DRP) has received considerable attention in recent years as an alternative to laboratory measurement, especially for the prediction of reservoir properties for which the right laboratory measurements are difficult to perform or require long measurement times such as the special core analysis (SCAL) properties relative permeability and capillary pressure. While measurement of these reservoir properties can certainly be challenging to execute, there is a long history of successful, high-quality laboratory SCAL measurements. Before adoption of a DRP approach to generate reservoir properties that have significant impact on expected reservoir performance, it is important that the uncertainties introduced by use of DRP are better understood. To this end, we have utilized samples from a large Middle Eastern carbonate reservoir to benchmark vendor DRP predictions of water-oil imbibition relative permeability and capillary pressure against high-quality SCAL results that were measured using consistent laboratory methods. Considerable scatter are observed in the DRP predictions that do not exist in the measured SCAL data and cannot clearly be attributed to sample heterogeneity. Wettability, which is an important input into digital rock predictions but is especially challenging to quantify in the laboratory, is shown to have a significant impact on DRP predictions of relative permeability and capillary pressure. Nevertheless, the dependence of the DRP results on wettability is inconsistent with the SCAL data. Given the additional scatter and inherent uncertainties associated with use of the DRP approach, we find that a high-quality laboratory program employing consistent test methods remains the best approach to obtain SCAL data to support reservoir definition development, and depletion objectives. Introduction Accurate, high-quality special core analysis (SCAL) data (e.g., relative permeability and capillary pressure) are integral to reservoir performance prediction and effective reservoir management. Achieving high-quality SCAL measurements in the laboratory is by no means an easy task, but can be accomplished provided that four key requirements are met:measurements must be on rock samples representative of the reservoir (the right samples),measurements must be made under conditions representative of displacement processes in the reservoir (the right conditions),measurements must be made using the appropriate test methodologies and using precision equipment and techniques (the right equipment), andtrained and experienced technologists are needed to ensure that appropriate samples are selected, to conduct the measurements, and to model the data (the right people). Several prior publications elaborate on the four key requirements (Braun 1981, Gomes 2008, Hassler 1945, Honarpour 2006, Honarpour 2005, Honarpour 2004, Johnson 1959, Wang 2008). It is important to note that both relative permeability and capillary pressure data are necessary to define displacement processes in reservoir simulation, and methods to measure and to integrate SCAL data should consider both types of data (Bhatti 2012, Kralik 2010, Meissner 2009).

A novel special core analysis (SCAL) study was conducted utilizing samples from a Middle Eastern Carbonate Reservoir in order to gain insights into flow behavior across stylolitic intervals. This study included relative permeability and capillary pressure measurements performed on individual core plug and core plug composite samples, as well as a unique waterflood experiment on a four-inch diameter whole core composite. All laboratory flow measurements were performed at reservoir conditions of temperature, pressure, and net confining stress. As part of this study, it was demonstrated that wettability restoration remains a significant challenge for carbonate core samples, with implications for coring and core analysis program design and interpretation of historic SCAL data. Core-scale simulation using measured relative permeability and capillary pressure data along with whole core rock properties provides an opportunity to validate laboratory results across laboratory scales and can also serve as an intermediate to mechanistic modeling studies at larger scales. In this paper, the novel technical approach and significant findings for the special core analysis study are presented, with implications for modeling of displacement processes across stylolitic intervals in complex carbonate reservoirs. General recommendations for the design of special core analysis programs are also presented.