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Three techniques for describing pore size distributions were investigated to explain large differences in Klinkenberg b factors for heterogeneous, high permeability, carbonate core samples. Gas expansion permeametry was used to determine gas permeametry was used to determine gas permeability and Klinkenberg-corrected permeability and Klinkenberg-corrected permeability on a select group of Middle permeability on a select group of Middle East carbonate cores. Samples with similar high permeabilities (600 - 900 md) showed a factor of 20 variation (0.6–12.8) in Klinkenberg b factors. Mercury injection derived pore size distributions were compared with petrographic image analysis (PIA) and scanning electron microscopy (SEM) analysis results to identify a basis for the range in b factor values. No method provided a direct correlation with Klinkenberg b values. All methods indicated that samples with high permeability and high b values also had an permeability and high b values also had an increase in the distribution of larger pores. PIA results indicated pores. PIA results indicated statistically a linear relationship between the number of throats and b factor. Introduction The complex nature of carbonate porosity often raises significant questions in the interpretation of various field and laboratory tests. Among these are single well tracer tests and unsteady state displacement tests. A better understanding of the relationship between the rock structures and transport properties is the first step in improving these interpretations. Petrophysical properties were measured on Petrophysical properties were measured on a group of Middle East carbonate samples. Items determined included Klinkenberg gas slip factor, krypton surface areas, and pore size distribution determined from pore size distribution determined from mercury injection. These measurements were combined with SEM and petrographic image analyses to describe and compare the samples. Klinkenberg Gas Slip Factor Adzumi in 1937 and Klinkenberg in 1941 introduced the concept of gas slip to explain deviations from Darcy's Law. The gas slip phenomena is considered to occur when the diameter of the porous media approaches the mean free path of the f lowing gas. The result is a non-zero velocity for the gas at the pore wall and a higher measured permeability. The mean free path of the gas is reduced with increasing mean pressure. At infinite mean pressure, the mean free path of the gas is equal to the mean free path of a liquid and the measured permeability is equal to the liquid permeability. The Klinkenberg b factor defines the slope of the line for measured gas permeability versus the reciprocal mean pressure. This relationship is shown in Figure 1. P. 143

Reservoir characterization of the Haygood Limestone (Ferry Lake Anhydrite, Early Cretaceous) at Caddo-Pine Island field in Caddo Parish, Louisiana, has enhanced the design of a proposed waterflood recovery program. Analyses to evaluate reservoir geology, formation injectivity, porosity types and pore size distributions include conventional core description, thin section petrography, X-ray diffraction, X-ray computed tomography (CT), and petrographic and scanning electron image analysis (PIA and SEM-IA). The Haygood Limestone is a thin, very fine calcarenite to fine calcirudite (intraclast bioclast packstone to grainstone) which is overlain and underlain by bedded anhydrite. The reservoir interval has an average porosity of 17.0%, an average permeability of 10.89 md and is characterized by a homogeneous pore network with a narrow pore size distribution. The base and the top of the Haygood are characterized by thin nonreservoir zones which effectively enhance the in situ stratigraphic trap. These zones possess decreased porosity and permeability and heterogeneous pore networks with broad pore size distributions. Porosity types include interparticle, moldic, intraparticle and microporosity. Interparticle and moldic pores are the dominant pore types, and are variably reduced by bladed to equant calcite and blocky anhydrite cements. Microporosity is locally significant, establishing a bimodal pore system and increasing bound (irreducible) water content. Introduction Hydrocarbon production from near the base of Ferry Lake Anhydrite (Early Cretaceous, Albian) at Caddo-Pine Island field in Caddo Parish, Louisiana, is associated with a thin, high energy carbonate bed known locally as the Haygood Limestone. To aid design of a proposed waterflood recovery program, reservoir characterization studies to determine porosity types, pore size distribution and reservoir have been completed. Available well data from five wells in the field include conventional cores, routine core analysis results and well logs. In addition to standard techniques, X-ray computed tomography and image analysis were also used to characterize the Haygood reservoir. METHODS An evaluation of conventional core (macroscopic and microscopic) and core analysis data for five wells in the field has allowed for reservoir characterization in terms of facies types, facies distribution and continuity, and porosity types and distribution (Figure 1). Thin section petrograpy, X-ray diffraction, X-ray computed tomography (CT), and petrographic and scanning image analysis (PIA and SEM-IA) were employed to assess reservoir geology, pore types and porosity distribution. A two-step technique was used for porosity evaluation by CT. Slab samples were placed into an aluminum pressure vessel, evacuated and CT scanned. P. 843^

The geometric structure of pore space in some carbonate rocks can be correlated with petrophysical measurements by quantitatively analyzing binaries generated from SEM images. Reservoirs with similar porosities can have markedly different permeabilities. Image analysis identifies which characteristics of a rock are responsible for the permeability differences. Imaging data can explain unusual fluid flow patterns which, in turn, can improve production simulation models.Analytical SchemeOur sample suite consists of 30 Middle East carbonates having porosities ranging from 21 to 28% and permeabilities from 92 to 2153 md. Engineering tests reveal the lack of a consistent (predictable) relationship between porosity and permeability (Fig. 1). Finely polished thin sections were studied petrographically to determine rock texture. The studied thin sections represent four petrographically distinct carbonate rock types ranging from compacted, poorly-sorted, dolomitized, intraclastic grainstones to well-sorted, foraminiferal,ooid, peloidal grainstones. The samples were analyzed for pore structure by a Tracor Northern 5500 IPP 5B/80 image analyzer and a 80386 microprocessor-based imaging system. Between 30 and 50 SEM-generated backscattered electron images (frames) were collected per thin section. Binaries were created from the gray level that represents the pore space. Calculated values were averaged and the data analyzed to determine which geological pore structure characteristics actually affect permeability.

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