Bimodal  Behavior of Mercury-Injection Capillary Pressure Curve and Its Relationship to Pore Geometry, Rock-Quality and Production Performance in a Laminated and Heterogeneous Reservoir

Leal, Libny; Barbato, Roberto; Quaglia, A.; Porras, J.; Lazarde, Hugo

doi:10.2523/69457-ms

Cited by 4 publications

(3 citation statements)

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“…A routine test for indicating heterogeneity of a rock sample is mercury injection capillary pressure (MICP) test (Thomeer ; Swanson ; Leal et al . ; Kewen ; Pini, Krevor and Benson ; Al‐Khidir et al . ).…”

Section: Real 3d Digital Samplesmentioning

confidence: 99%

3D multi‐fractal analysis of porous media using 3D digital images: considerations for heterogeneity evaluation

Karimpouli

Tahmasebi

2018

Geophysical Prospecting

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Pore structure heterogeneity is a critical parameter controlling mechanical, electrical and flow transport behaviour of rock. Multi‐fractal analysis method was used for a heterogeneity comparison of three‐dimensional rock samples with different lithology. Six real digital samples, containing three sandstones and three carbonates, were used. Based on the mercury injection capillary pressure test on these samples, we found that the carbonate samples are more heterogeneous than sandstones, but primary results of multi‐fractal behaviours for all samples were similar. We show that if multi‐fractal is used to evaluate and compare heterogeneity of different samples, one needs to follow some considerations such as (1) all samples must have the same size in pixel, (2) samples volume must be bigger than representative volume element, (3) multi‐fractal dimensions should be firstly normalized to a determined porosity value and (4) multi‐fractal results should be interpreted based on resolution of the imaging tool (effects of fine scale sub‐resolution pores are missed). Results revealed that using normalized fractal dimensions, the real samples were divided to less and high heterogeneous groups. Moreover, the study of scale effect also showed that porous structures of these samples are scale invariant in a wide range of scales (from one to eight times bigger).

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Section: Real 3d Digital Samplesmentioning

confidence: 99%

3D multi‐fractal analysis of porous media using 3D digital images: considerations for heterogeneity evaluation

Karimpouli

Tahmasebi

2018

Geophysical Prospecting

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“…[5][6][7][8] This is accomplished either in cored wells with directly measured porosity and permeability or in uncored wells using separate porosity and permeability well log models. Nevertheless, the model can be used to predict permeability if the pore-throat radius has been independently estimated or if a rock type based on the pore-throat radius has been assigned.…”

Section: Comparison With Other Permeability Modelsmentioning

confidence: 99%

Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping

Jennings

Lucia

2001

SPE Annual Technical Conference and Exhibition

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA fundamental component in the construction of most reservoir performance models is an empirical relationship between permeability as measured in a limited number of cored wells and other petrophysical properties measured in well logs. This paper presents a permeability model specially designed for carbonates. The model relates permeability to interparticle porosity, makes special accommodation for separate-vug porosity, and includes a rock-fabric classification scheme with an important dual petrophysical-geological significance. Methods to estimate the separate-vug porosity from sonic logs and the rock-fabric from initial saturation are presented.The dual petrophysical-geological significance of the rockfabric classification is important for providing a link to geological models for use in distributing permeabilities between wells. Porosity and permeability are highly variable and difficult to predict spatially in most carbonate reservoirs, but rock-fabric changes tend to be systematically organized in a predictable manner within a sequence stratigraphic framework. Carbonate Rock-Fabric Petrophysical ClassificationPermeability and capillary properties of interparticle pore space can be related to interparticle porosity and geologic descriptions of particle size and sorting called rock fabrics. 1,2 These rock fabrics were initially grouped into three categories called rock-fabric petrophysical classes on the basis of porosity, permeability, and capillary properties 1 (Fig. 2):Class 1 is composed of grainstones, dolograinstones, and large crystalline dolostones.Class 2 is composed of grain-dominated packstones, fine and medium crystalline, grain-dominated dolopackstones, and medium crystalline, mud-dominated dolostones.Class 3 includes mud-dominated limestones and fine crystalline, mud-dominated dolostones.

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“…It can supply information about core porosity, pore geometry, recovery efficiency, and permeability of the reservoir rocks (Wardlaw and McKellar ; Owolabi and Watson ; Leal et al . ). Neasham () classified dispersed clay in sandstone in three categories: (a) discrete particles; (b) inter‐grown crystal linings on pore walls; and (c) crystals bridging across pores.…”

Section: Pore Geometry From Micpmentioning

confidence: 97%

Effect of pore geometry on Gassmann fluid substitution

Yan

Han

2015

Geophysical Prospecting

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A B S T R A C TAlthough there is no assumption of pore geometry in derivation of Gassmann's equation, the pore geometry is in close relation with hygroscopic water content and pore fluid communication between the micropores and the macropores. The hygroscopic water content in common reservoir rocks is small, and its effect on elastic properties is ignored in the Gassmann theory. However, the volume of hygroscopic water can be significant in shaly rocks or rocks made of fine particles; therefore, its effect on the elastic properties may be important. If the pore fluids in microspores cannot reach pressure equilibrium with the macropore system, assumption of the Gassmann theory is violated. Therefore, due to pore structure complexity, there may be a significant part of the pore fluids that do not satisfy the assumption of the Gassmann theory. We recommend that this part of pore fluids be accounted for within the solid rock frame and effective porosity be used in Gassmann's equation for fluid substitution. Integrated study of ultrasonic laboratory measurement data, petrographic data, mercury injection capillary pressure data, and nuclear magnetic resonance T 2 data confirms rationality of using effective porosity for Gassmann fluid substitution. The effective porosity for Gassmann's equation should be frequency dependent. Knowing the pore geometry, if an empirical correlation between frequency and the threshold pore-throat radius or nuclear magnetic resonance T 2 could be set up, Gassmann's equation can be applicable to data measured at different frequencies. Without information of the pore geometry, the irreducible water saturation can be used to estimate the effective porosity.

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Bimodal Behavior of Mercury-Injection Capillary Pressure Curve and Its Relationship to Pore Geometry, Rock-Quality and Production Performance in a Laminated and Heterogeneous Reservoir

Cited by 4 publications

References 0 publications

3D multi‐fractal analysis of porous media using 3D digital images: considerations for heterogeneity evaluation

3D multi‐fractal analysis of porous media using 3D digital images: considerations for heterogeneity evaluation

Predicting Permeability From Well Logs in Carbonates With a Link to Geology for Interwell Permeability Mapping

Effect of pore geometry on Gassmann fluid substitution

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