Segregating Porosity-Permeability Transform Using Velocity and Pore Structure in Carbonate Rock

Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.

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Determination of NMR T2 Cutoff and CT Scanning for Pore Structure Evaluation in Mixed Siliciclastic–Carbonate Rocks before and after Acidification

Energies ◽

10.3390/en13061338 ◽

2020 ◽

Vol 13 (6) ◽

pp. 1338 ◽

Cited By ~ 2

Author(s):

Mengqi Wang ◽

Jun Xie ◽

Fajun Guo ◽

Yawei Zhou ◽

Xudong Yang ◽

...

Keyword(s):

Pore Structure ◽

Carbonate Rocks ◽

Carbonate Rock ◽

Experimental Results ◽

Normal Distribution Function ◽

Core Samples ◽

Irreducible Water Saturation ◽

Significant Difference ◽

Before And After ◽

Structure Evaluation

Nuclear magnetic resonance (NMR) is used widely to characterize petrophysical properties of siliciclastic and carbonate rocks but rarely to study those of mixed siliciclastic–carbonate rocks. In this study, 13 different core samples and eight acidified core samples selected amongst those 13 from the Paleogene Shahejie Formation in Southern Laizhouwan Sag, Bohai Bay Basin, were tested by scanning electron microscopy (SEM), micro-nano-computed tomography (CT), and NMR. SEM and CT results revealed a complex pore structure diversity, pore distribution, and pore-throat connectivity in mixed reservoirs. Sixteen groups of NMR experiments addressed changes in these properties and permeabilities of mixed siliciclastic–carbonate rocks before and after acidification to determine its effects on such reservoirs. NMR experimental results showed no “diffusion coupling” effect in mixed siliciclastic–carbonate rocks. Distributions of NMR T2 cutoff values (T2C) are closely related to the pore structure and lithologic characteristics before and after acidification. The T2C index separates irreducible and movable fluids in porous rocks and is a key factor in permeability prediction. Centrifugation experiments showed that, before acidification, the T2C of mixed siliciclastic–carbonate rocks with 60–90% siliciclastic content (MSR) ranged widely from 1.5 to 9.8 ms; the T2C of mixed siliciclastic–carbonate rocks with 60–90% carbonate content (MCR) ranged from 1.8 to 5.6 ms. After acidification, the T2C of MSR ranged widely from 2.6 to 11.6 ms, the T2C of MCR ranged from 1.5 to 5.6 ms, and no significant difference was observed between MCR reservoirs. Based on an analysis of the morphology of NMR T2 spectra, we propose a new T2 cutoff value prediction method for mixed siliciclastic–carbonate rocks based on a normal distribution function to predict various T2C values from morphological differences in NMR T2 spectra and to calculate the irreducible water saturation (Swir), i.e., the ratio of irreducible total fluid volume to effective porosity. The reliability of the proposed method is verified by comparing predicted T2C and Swir values with those from NMR experimental results. New experiments and modeling demonstrate the applicability of NMR for the petrophysical characterization of mixed siliciclastic–carbonate rock reservoirs. Our results have potential applications for identification and evaluation of mixed siliciclastic–carbonate rock reservoirs using NMR logging.

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INTERPRETATION OF MULTI-FREQUENCY DIELECTRIC PERMITTIVITY MEASUREMENTS FOR ASSESSMENT OF WATER SATURATION IN CARBONATE FORMATIONS WITH COMPLEX PORE STRUCTURE

10.30632/spwla-2021-0034 ◽

2021 ◽

Author(s):

Zulkuf Azizoglu ◽

◽

Zoya Heidari ◽

Keyword(s):

Spatial Distribution ◽

Dielectric Permittivity ◽

Pore Structure ◽

Carbonate Rock ◽

Water Saturation ◽

Dielectric Dispersion ◽

Pore Scale ◽

Rock Samples ◽

Wide Range ◽

Permittivity Measurements

Broadband relative dielectric dispersion measurements are considered interesting options for assessment of water-filled pore volume. Conventional models such as Complex Refractive Index Model (CRIM) and Maxwell Garnett (MG), often overlook or oversimplify the complexity of pore structure, geometrical distribution of the constituting fluids, and spatial distribution of minerals. This yields to significant errors in assessment of water saturation especially in rocks with complex pore structure. Therefore, it becomes important to quantify the impacts of pore structure and spatial distribution of minerals on broadband relative dielectric dispersion measurements to be able to make decisions about reliability of water saturation estimates from these measurements in a given formation. The objectives of this paper are (a) to quantify the impacts of pore structure and spatial distribution of minerals on relative dielectric permittivity measurements in a wide range of frequencies, (b) to propose a new simple and physically meaningful workflow, which honors pore geometry and spatial distribution of minerals to enhance fluid saturation assessment using relative dielectric permittivity measurements, (c) to verify the reliability of the introduced model in the pore-scale domain. First, we perform numerical simulations of relative dielectric dispersion measurements in the frequency range of 20 MHz to 1 GHz in the pore-scale domain. The input to the numerical simulator includes pore-scale images of actual complex carbonate rock samples. We use a physically meaningful model which honors spatial distribution of the rock constituents for the multi-frequency interpretation of relative dielectric response. To verify the reliability of the model in multiple frequencies, we apply the model to the results of relative dielectric simulations in the pore-scale domain on 3D computed tomography scan (CT-scan) images of carbonate rock samples, which are synthetically saturated to obtain a wide range of water saturation. We successfully verified the reliability of the introduced model in the pore-scale domain using carbonate rock samples with multi-modal pore-size distribution. Estimated water saturations from the results of simulations at 1 GHz resulted in an average relative error of less than 4%. We observed measurable improvements in fluid saturation estimates compared to the cases which CRIM or MG models are used. Results demonstrated that application of conventional models to estimate water saturation from relative dielectric response is not reliable in frequencies below 1 GHz.

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Comparison of Oil Recovery and Carbonate Rock’s Properties Alterations by CO2 Miscible Flooding

Volume 8: Polar and Arctic Sciences and Technology; Petroleum Technology ◽

10.1115/omae2018-78723 ◽

2018 ◽

Author(s):

Jinju Han ◽

Youngjin Seo ◽

Juhyun Kim ◽

Sunlee Han ◽

Youngsoo Lee

Keyword(s):

Pore Structure ◽

Oil Recovery ◽

Carbonate Rock ◽

Flow Path ◽

Carbonate Reservoir ◽

Rock Properties ◽

Co2 Flooding ◽

Miscible Flooding ◽

The Impact ◽

Indiana Limestone

This present study indicates experimental investigation about the impact of CO2 flooding on oil recovery and rock’s properties alteration in carbonate reservoir under the miscible condition. In order to compare the effect to initial pore characteristic, two type of carbonate rock was used; an Edward white represents homogeneous mainly consisted micropore, whereas an Indiana limestone represented heterogeneous mainly consisted macropore in this study. Under the miscible condition (9.65 MPa and 40°C), five pore volume of CO2 were injected into oil-wet carbonate rock, which was fully saturated with oil and connate water. After CO2 flooding, several analyses for each sample conducted to investigate oil recovery and rock properties change in porosity, permeability, and pore structure by chemical and physical reaction between CO2, water, and carbonate mineral before and after CO2 flooding by using core analysis, MICP, SEM, ICP, and X-ray CT techniques. From the results of oil recovery, it was more effective and larger in Edward white than in Indiana limestone. Because homogeneous characteristic with a large ratio of low permeable micropore in Edward white contributed to occur long reaction time between oil and CO2 for enough miscibility as well as to displace stably oil by CO2. Conversely, heterogeneous pore structure mainly consisted of high permeable conduit (macropore) in Indiana limestone has brought ineffective and low oil production. From the analysis of rock’s properties alteration, we found that, for the homogeneous sample, dissolution dominantly changed pore structure and became better flow path by improving permeability and reducing tortuosity. While plugging by precipitation of mineral particles was not critically affected rock’ properties, despite the sample mainly consisted small pores. In the case of the heterogeneous sample, both dissolution and precipitation critically affected change of rock’s properties and pore structure. In particular, superior precipitation in complex pore network seriously damaged flow path and change of rock’s properties. The largest porosity change markedly appeared in inlet section because of exposing rock surface from fresh CO2 during a long time. In conclusion, it shows that CO2 miscible flooding in carbonate reservoirs significantly affected to alteration of rock’s properties such as porosity, permeability, tortuosity, and pore connectivity, in particular in heterogeneous system compared with in homogeneous system. These experimental results can be useful to characterize carbonate rock as well as to study rock properties alteration on CO2 EOR and CCS processes.

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Extracting Pore Structure Parameter of Carbonate Rock from Well Logging Data

Proceedings 76th EAGE Conference and Exhibition 2014 ◽

10.3997/2214-4609.20141304 ◽

2014 ◽

Author(s):

H. Cai

Keyword(s):

Pore Structure ◽

Carbonate Rock ◽

Well Logging ◽

Structure Parameter ◽

Pore Structure Parameter

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Reservoir Pore Structure Classification Technology of Carbonate Rock Based on NMR T 2 Spectrum Decomposition

Applied Magnetic Resonance ◽

10.1007/s00723-013-0511-5 ◽

2014 ◽

Vol 45 (2) ◽

pp. 155-167 ◽

Cited By ~ 17

Author(s):

Xinmin Ge ◽

Yiren Fan ◽

Yingchang Cao ◽

Yongjun Xu ◽

Xi Liu ◽

...

Keyword(s):

Pore Structure ◽

Carbonate Rock ◽

Spectrum Decomposition

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Correlation of Pore Structure and Permeability by SEM-Image Analysis

Proceedings, annual meeting, Electron Microscopy Society of America ◽

10.1017/s0424820100180896 ◽

1990 ◽

Vol 48 (1) ◽

pp. 428-429

Author(s):

C. A. Callender ◽

Wm. C. Dawson ◽

J. J. Funk

Keyword(s):

Image Analysis ◽

Pore Structure ◽

Imaging System ◽

Pore Space ◽

Simulation Models ◽

Image Analyzer ◽

Imaging Data ◽

Sem Images ◽

Thin Sections ◽

Rock Types

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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