Summary Pore geometrical parameters for the M_1 petrophysical rock type of the Arab D limestone in Ghawar field have been related to static and dynamic reservoir properties and geological facies (Clerke et al. 2008). The M_1 bimodal pore system is the most common and important member of a new set of ultimate recovery petrophysical rock types (URPRT), which uses a new pore system classification for the Arab D limestone. The dynamic reservoir property results for the bimodal M_1 are reviewed here. The roles played by the pore system parameters describing the macropores (M) and micropores (Type 1) within the M_1 in permeability, imbibition oil relative permeability, and microscopic displacement efficiency are examined in detail. All pore systems are analyzed by the Thomeer method using an extensive mercury injection capillary pressure (MICP) data set in conjunction with dynamic experiments performed on samples prepared using the same wettability restoration. Effects commonly ascribed to wettability changes are observed by changes in the distribution of porosity between the M and Type 1 subsystems. An extensive study of the pore systems of the Ghawar Arab D limestone gathered a large and comprehensive MICP data set (484 samples) (Clerke et al. 2008; Cantrell and Hagerty 1999, 2003; Clerke 2003, 2004; Ahr et al. 2005). All MICP data were type-curve matched by Thomeer functions (Clerke et al. 2008; Thomeer 1960). The study of this carefully prepared MICP data is the foundation for a new pore system classification. The new classification is built upon intrinsic, fundamental, and separate maximum pore-throat diameter modal elements named "porositons" (Clerke 2008; Ahr et al. 2005). Porositons are stable and recurring modes in the statistics of the Thomeer maximum pore-throat diameter of these carbonate pore systems. Porositon combinations are used to construct meaningful petrophysical rock types. Petrophysical rock types (PRTs) are defined by Clerke et al. (2008) as objects or combinations of objects that are present in the 3D space of the Thomeer pore-system parameters. Porositons are a new PRT object type; other PRT objects are clusters, trends, and surfaces. By constructing PRTs from porositons, strong relationships are found connecting the geological facies, PRTs, and reservoir-flow properties of these complex multimodal carbonate rocks (Clerke et al. 2008). These relationships demonstrate that these PRTs are important for defining ultimate recovery.

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The M_1 nested bimodal pore system is prevalent in many large limestone oil reservoirs in Saudi Arabia. Within this pore system is contained a large portion of these fields' oil in place. Very low initial water saturation in these large structural relief carbonate reservoirs results in oil emplaced into pores controlled by M macropore throats and also into pores controlled by much smaller Type 1 micropore throats. Approximately, seventy-five percent of the M_1 oil portion is stored in the macropore system and about 25% is stored in the Type 1 micropore system. This prevalent M_1 petrophysical rock type (PRT) is an example of nested bimodal pore system consisting of an instance from the distribution of Macro possibilities (M porositon) and an instance from the Type 1 micro porositon distribution. The maximum pore-throat diameters of the Type 1 micro porositon are on the average 53 times smaller than the M macro porositon average maximums. M porosity average is 17% with a mean maximum pore-throat diameter of 58 microns. The Type 1 microporosity average is 5.6% with a mean maximum pore-throat diameter of 1.1 microns. Thus, common in Arab-D carbonate reservoir matrix is a bimodal pore network with a very large hydraulic contrast between a fine network of well-sorted tubular Type 1 micropore throats, connected and adjacent to a network of much larger diameter moderately-sorted M macropore throats. In a previous publication by Clerke, it was shown that the very small micropore throats' contribution to the total permeability is commonly below the resolution and reproducibility of the permeability measuring device when in the presence of many much larger pore throats. The micropore network is permeable if only at a small value. For the two phase flow occurring in a waterflood for oil recovery, the M_1 PRT requires an understanding of the two phase recovery processes in each pore subsystem considering capillarity in the combined pore network. This paper demonstrates that the Type 1 micropores are themselves a permeable network to water and to both oil and water when under waterflood. Hence for our carbonate reservoirs, "pores with throat diameters less than one micron when filled with oil in a bimodal M_1 pore system contribute to oil recovery through a time dependent spontaneous imbibition process and thereby contribute to oil recovery by waterflood." Further, it is demonstrated that the multimodality porositon classification proposed by Clerke are a form of dynamic rock type that classify the position and the type of internal pore level capillarity spatial gradients that affect ultimate oil recovery. New high-precision laboratory data has been obtained at very low phase pressure: water imbibition into oil saturated M_1 pore systems at near zero phase pressures (spontaneous imbibition) and dispersion of D2O into water filled M_1 pore systems. These pore systems can now be analyzed to obtain the magnitude, direct time dependence and scaling behavior of this important and previously overlooked portion of the total carbonate oil recovery by waterflood.

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Extensive and detailed studies of the pore systems of the Ghawar Arab D limestone have been captured in very large mercury injection capillary pressure data sets1–3 in which all data have been analyzed using Thomeer functions4–6. These data give new insight into the pore geometry dependence of the reservoir dynamical properties: permeability and imbibition oil relative permeability7 and yield ultimate recovery rock types with algorithms for rock type based reservoir simulation studies of ultimate recovery. New carbonate petrophysical concepts are established. The dominant subgroup of the examined carbonate limestone pore systems comprise the major Arab D reservoir section are denoted as an M_1 bimodal pore system3. The M_1 bimodal pore system consists of a macropore system (M), with a well defined and wide distribution of pore throat diameters and geometries, in conjunction with Type 1 microporosity with equally well defined and narrow distribution of pore throat diameters and geometries. This bimodal M_1 pore system results in a mixed wet reservoir condition in the bulk of the reservoir. The role played by the macro and micro pores of the M_1 pore system has been related to the reservoir dynamical properties: permeability and relative permeability7. This work demonstrates fundamentally new pore geometry based formulations for calculating permeability and imbibition oil relative permeability and therefore delineates the pore geometry based variation in microscopic displacement efficiency for variations within these systems. For these reservoir rocks, the appropriate pore geometrical parameters to perform ultimate recovery rock typing have been identified. This paper presents data and formulations for improved pore system based models of permeability and imbibition oil relative permeability in the M_1 bimodal pore system that reproduce measured laboratory data over a range of oil relative permeability from 1 to 0.0001 for seven waterflood composites. The relative permeability formulation uses two attributes of the pore system: permeability (already shown to be a function of pore geometrical parameters) and the volume of Type 1 microporosity alone. Both of these can be extracted from appropriate processing of appropriate well log data. These results show that shifts of the oil relative permeability curve to increasing water saturation (the right) commonly ascribed to wettability changes, result in this case from increasing the amount of Type 1 microporosity in the M_1 bimodal system which add an "ineffective" water saturation to the relative permeability water saturation axis. Introduction Extensive and detailed studies have been performed on the Arab D limestone pore systems in a major oil reservoir in Saudi Arabia. These studies have created connections between the three major languages of the subsurface: depositional geological facies, petrophysical rock types and reservoir static and dynamic properties1–7 as required for integrated reservoir characterization. These connections were made possible by a fundamentally significant observation regarding the limestone pore system geometries. It was observed that the spectrum of maximum pore throat diameters (Pd's) captured in this large mercury injection capillary pressure data set (MICP) could be characterized by four distinct Gaussian modes3 that have been termed "porositons" or "phitons" (figure 1).