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).

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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.

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A workflow for generating internally consistent sets of saturation functions from capillary pressure and relative permeability data for use in numeric reservoir simulation is described. This workflow was implemented in software that was developed to facilitate the filtering and grouping of these data using a variety of screening criteria. Such implementation ensures the application of consistent practices, based on the physics of multiphase displacement in porous media, when developing relative permeability and capillary pressure models. The data are reviewed to confirm that they are of acceptable quality prior to use in saturation function development. The workflow described here conforms to the displacement categories defined in the simulation model, e.g. families of reservoir facies. In addition to grouping and analyzing SCAL data (capillary pressure, relative permeability, wettability) for a specific reservoir, the software can access a larger database that contains all available SCAL data. The database also provides convenient access to analog data for reservoirs in which sufficient SCAL data have not been generated. To our knowledge, such a systematic method for the development of consistent capillary pressure and relative permeability saturation functions based on families of reservoir facies for simulation has not been presented in the literature.Saturation endpoints are first established by analyzing the appropriate capillary pressure data (e.g., primary drainage P c for S wir , primary imbibition water-oil P c for S orw , primary drainage gas-oil P c for S org , etc.). This analysis involves fitting the data to a consistent constitutive equation that contains the saturation endpoint as a regression parameter. The resulting models should be compared to any available field data to ensure consistency (e.g., primary drainage P c vs. calibrated log S w (z)). Once the saturation endpoints have been established, the grouped relative permeability data are analyzed, starting with the bounding water-oil primary drainage data. After defining the bounding primary drainage curves, the primary imbibition k row -k rw curves can be developed. Individual imbibition k row -k rw tests generally correspond to unique imbibition scanning curves rather than the bounding primary imbibition curve, suggesting the measured imbibition curves be scaled to the bounding primary drainage k ro curve to ensure consistency. Secondary drainage k ro -k rwo data, if available, are similarly scaled. Three-phase gas-oil primary drainage k rog -k rg and primary imbibition k ro -k rgo data are treated in an analogous manner. This process is applied to each group of capillary pressure and relative permeability data. Experience has shown that this approach properly represents the displacement physics, facilitating accurate reservoir performance predicitions and history matches.