Mercury Injection Capillary Pressure Tests Research Articles

Quantitative characterization of the carbonate rock microstructure considering topological features: a case study from the Gaoshiti–Moxi block of the Sichuan Basin

The precise characterization of the rock microstructure is crucial for predicting the physical characteristics, flow behavior, and mechanical properties of rocks. This is particularly important for carbonate rocks, which depict a complex microstructure with multimodal pore radius distribution and natural fractures. Here, topological features that are typically ignored are taken into account to quantify the carbonate microstructure. Carbonate samples used are obtained from the Gaoshiti–Moxi block of the Sichuan Basin, which showed remarkable potential for oil and gas. Specifically, nuclear magnetic resonance (NMR), X-ray micro-computed tomography (micro-CT), and mercury injection capillary pressure (MICP) techniques are performed to describe the topological and geometric characteristics. The results indicate that NMR and MICP techniques can describe more rock pores than micro-CT. However, due to the presence of pore shielding in MICP tests, the pore radius obtained by MICP is smaller than that obtained by micro-CT and NMR. Furthermore, the effective method used for characterizing the pore structure is NMR technology. The hardest part is that the coefficient between the pore radius and T2 relaxation time is difficult to calculate. Therefore, a better calculation method must be found. In addition, micro-CT is an irreplaceable technique for obtaining a large number of topological and geometric features, and multi-phase or single-phase flow simulations can be conducted via digital rock models. However, for carbonates, micro-CT is not sufficient to describe the complete pore systems because macropores cannot be fully represented and sub-resolution micropores cannot be described. Those macropores and micropores have a very important effect on their seepage properties. Therefore, multi-scale digital rock modeling involving small and large pores is essential for complex rocks, which is of great significance for the analysis of pore systems and the simulation of rock physical properties.

Prediction of permeability of tight sandstones from mercury injection capillary pressure tests assisted by a machine-learning approach

Mercury injection capillary pressure analysis is a methodology for determining different petrophysical properties, including bulk density, porosity, and pore throat distribution. In this work, distinct parameters derived from mercury injection capillary pressure tests was considered for the prediction of permeability by coupling machine learning and theoretical approaches in a dataset composed of 246 tight sandstone samples. After quality checking the dataset, the feature selection was carried out by correlation analysis of different theoretical permeability models and statistical parameters with the measured permeability. Finally, porosity, median capillary pressure, Winland model, and mean pore-throat radius (corresponding to the saturation range 0.4-0.8) were chosen as the input features of the machine learning model. As the machine learning approach, a support vector machine (SVM) model with a radial basis function kernel was proposed. Furthermore, the model and its metaparameters were trained with a particle swarm optimization (PSO) algorithm to avoid over-fitting or under-fitting. In contradiction to the theoretical models, the implemented SVM-PSO model could acceptably predict the experimentally measured permeability values with an R2 rate of over 0.88 for training and testing datasets. The introduced approach could reduce the mean relative errors from about 10 to values less than 0.45. The improvements were more significant for low permeability samples. This successful implementation shows the potential of coupled usage of theoretical and machine learning methodologies for improved prediction of permeability of tight sandstone rocks. Cited as: Abbasi, J., Zhao, J., Ahmed, S., Jiao, L., Andersen, P., Cai, J. Prediction of permeability of tight sandstones from mercury injection capillary pressure tests assisted by a machine-learning approach. Capillarity, 2022, 5(5): 91-104. https://doi.org/10.46690/capi.2022.05.02

Diagenetic facies characteristics and quantitative prediction via wireline logs based on machine learning: A case of Lianggaoshan tight sandstone, fuling area, Southeastern Sichuan Basin, Southwest China

Tight sandstone has low porosity and permeability, a complex pore structure, and strong heterogeneity due to strong diagenetic modifications. Limited intervals of Lianggaoshan Formation in the Fuling area are cored due to high costs, thus, a model for predicting diagenetic facies based on logging curves was established based on few core, thin section, X-ray diffraction (XRD), scanning electron microscopy (SEM), cathodoluminescence, routine core analysis, and mercury injection capillary pressure tests. The results show that tight sandstone in the Lianggaoshan Formation has primary and secondary intergranular pores, secondary intragranular pores, and intergranular micropores in the clay minerals. The compaction experienced by sandstone is medium to strong, and the main diagenetic minerals are carbonates (calcite, dolomite, and ferric dolomite) and clay minerals (chlorite, illite, and mixed illite/montmorillonite). Four types of diagenetic facies are recognized: carbonate cemented (CCF), tightly compacted (TCF), chlorite coating and clay mineral filling (CCCMFF), and dissolution facies (DF). Primary pores develop in the CCCMFF, and secondary pores develop in the DF; The porosities and permeabilities of CCCMFF and DF are better than that of CCF and TCF. The diagenetic facies were converted to logging data, and a diagenetic facies prediction model using four machine learning methods was established. The prediction results show that the random forest model has the highest prediction accuracy of 97.5%, followed by back propagation neural networks (BPNN), decision trees, and K-Nearest Neighbor (KNN). In addition, the random forest model had the smallest accuracy difference between the different diagenetic facies (2.86%). Compared with the other three machine learning models, the random forest model can balance unbalanced sample data and improve the prediction accuracy for the tight sandstone of the Lianggaoshan Formation in the Fuling area, which has a wide application range. It is worth noting that the BPNN may be more advantageous in diagenetic facies prediction when there are more sample data and diagenetic facies types.

Diagenetic facies classification and characterization of a high-temperature and high-pressure tight gas sandstone reservoir: A case study in the Ledong area, Yinggehai Basin

A high-temperature and high-pressure tight gas sandstone reservoir, located in the Ledong area of the Yinggehai Basin, shows considerable resource potential. However, the diagenetic characteristics of this reservoir remain unclear. In this study, reservoir petrology and diagenetic characteristics were systematically investigated through different experimental methods. Further, the porosity and diagenetic evolution models were constructed. The methods employed included petrophysical analysis, observation of core and thin sections, and grain-size distribution analysis. Furthermore, scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy, cathodoluminescence, carbon and oxygen isotope analysis, digital image analysis, mercury injection capillary pressure tests, and micro-CT imaging were also employed. In the study area, gravity-flow channel sediments composed of feldspathic litharenite primarily developed in a restricted submarine canyon. And tight sandstones in target formation have an average porosity of 9.34% and permeability of 1.79 mD. Mechanical compaction and cementation (mainly illite and ferrocalcite) were regarded as crucial roles in the densification process. Further, the diagenetic evolution model indicated that the reservoir underwent a high degree of thermal diagenetic evolution. Five diagenetic facies types were classified and characterized at multiple scales. Moreover, a vertical distribution model of different diagenetic facies was also developed considering the overpressure, depth of formation, thickness and frequency of mudstones, and injection concentration of the CO2. This study helps to improve the understanding of the diagenetic characteristics and diagenetic facies types in high-temperature and high-pressure clastic reservoirs.

Multi-scale pore structure characterization of lacustrine shale and its coupling relationship with material composition: An integrated study of multiple experiments

Characterization of microscopic pore system of organic-rich shales is of great importance for understanding the occurrence mechanism and flow behavior of shale oil. Currently, there are numerous studies on pore structure characteristics of shales, but research about the coupling relationship between shale material composition and its microscopic pore system is relatively weak. In this paper, we conducted mercury injection capillary pressure (MICP), Low-temperature N2 adsorption (LTNA) and broad ion beam scanning electron microscope (BIB-SEM) experiments combined with low-field nuclear magnetic resonance (NMR) to quantitatively characterize the full-scale pore structure of typical lacustrine shales in the northern Songliao Basin, China, and analyzed the coupling relationship between multi-scale pore structure and material composition. Results show that these shales are mainly develops inorganic interparticle pores related to clay minerals, and a small amount of organic matter pores were also present. A pore size classification scheme for I-micropore (0–20 nm in diameter), II-micropore (20–50 nm), mesopore (50–150 nm), macropore (>150 nm) within shales was proposed by combining fractal theory with MICP tests. The full-scale characterization of shale revealed that it mainly developed micropores and mesopores, and the pore size was distributed primarily in the region less than 150 nm. The pore specific surface area of these shales was relatively high with a mean value of 20.76 m2/g and mainly controlled by clay minerals. The coupling relationship analysis of different pore types and shale material composition reveals that clay minerals and carbonate minerals govern the development of II-micropores and macropores respectively, whereas organic matter controls the development of I- micropores. It's worth mentioning that organic matter inhibits the formation of mesopores, and the microfractures formed in the shale are dominated by shrinkage OM pores. Based on our observations, the applicability of different experimental methods for characterizing the pore structure of shales is also summarized. The difference between these experiments revealed that the method proposed in this paper is an effective way to characterize the full-scale pore structure of shale.

Experimental investigation of the pore structure characteristics for the high-salt formation in Qianjiang depression, China

Special attention has recently been paid to the high-salt formation in Qianjiang depression as its abundant oil resources with ultra-low permeability and porosity. However, the complex pore structure characteristic of the high-salt formation has not been well understood so far because of its pore size ranging from nanometer to micrometer scale. This paper aims to investigate the complex pore structure characteristic of the target high-salt formation based on an integrated experimental approach involving X-ray diffraction (XRD), scanning electron microscope (SEM), mercury injection capillary pressure (MICP), casting lamella observation and nuclear magnetic resonance (NMR) techniques. XRD analysis results indicate that the target formation mainly includes clastic mineral, carbonate mineral and salt mineral, and the content of them are 32.16%, 36.59%, and 24.65%, respectively. The results of SEM and casting lamella observation indicate that storage space of target formation can be divided into intercrystal pores, solution pores, and fractures. Solution pores have great impact on oil production, which includes dolomite dissolved pore and glauberite dissolved pore. Based on the MICP test results, the samples can be divided into pore type and fracture-pore type. The average pore radius of pore type samples and fracture-pore type samples are 0.0144 μm and 0.40 μm, respectively. Pore size distribution (PSD) results from MICP indicate that single peaks appeared in PSD curves of pore type samples and multi-peaks appeared in PSD curves of fracture-pore type samples. Permeability contribution peaks of pore type samples range from 0.01 to 0.03 μm, and permeability contribution peaks of fracture-pore type samples range from 1 to 10 μm. Comparing the permeability contribution of pore type samples and fracture-pore type samples reveals that mesopores and macropores make the vast majority of permeability contribution of the two kind type samples. A method to get permeability contribution of pore throats from PSD results has been introduced in this paper based on T2 NMR test. Comparing the PSD results from MICP and T2 NMR test results shows that T2 NMR test can identify smaller pore throat.

Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf

Knowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.

Comparison of the pore structures of Lower Silurian Longmaxi Formation shales with different lithofacies in the southern Sichuan Basin, China

The growing research on the features of shale pore structures has deepened the understanding of shale oil and gas storage capacity. Nevertheless, few studies have focused on the differences of the specific parameters that are characteristic of the nanopore structure in shales with different lithofacies. Such parameters include the full-scale ranges of the pore specific surface area and pore volume distribution, porosity and fractal dimension. In this paper, a dozen Longmaxi Formation shale samples from the southern Sichuan Basin were studied to determine the differences in these parameters. A set of laboratory experiments were performed, such as geochemical experiments, X-ray diffraction, N2 and CO2 isothermal adsorption, mercury injection capillary pressure tests and scanning electron microscopy experiments. The results of this study indicate that shale samples can be classified into 5 types of lithofacies based on their mineral composition. The surface porosity of organic matter particles is 8–16 times greater than that of mineral particles. The major contributors to the pore volume and surface area of shale samples are mesopores and micropores, respectively. The full-scale pore size distribution is mainly from 0.4 to 0.6 nm, 2–7 nm, and 10–20 nm for the pore volume and from 0.3 to 1.0 nm and 1.5–7 nm for the pore surface area. The average values of the porosity, fractal dimension, pore volume and pore surface area of the M-2 shales are almost equal to those of the S group shales. This result indicates that the M-2 shale has a large gas storage capacity similar to that of shales with siliceous lithofacies. The development of organic matter pores that contribute to more than 50% of the porosity leads to the high porosity and fractal dimension of the M-2 shales and S group shales. In addition to organic matter, illite minerals also play an important role in the constitution of the majority of the storage space in the CM-1 shale.

On the magnitude of capillary pressure (suction potential) in tight rocks

In this study, we review the concepts of capillary pressure and total suction. We propose that for shales and siltstones, capillary pressure (matric suction) is not the only dominant source of suction. Therefore, total suction, which is the sum of matric and osmotic pressure (electrostatic forces), provides a better description of the physical process behind water imbibition. We investigate the application of a dew-point psychrometer to measure total suction and compare that to mercury injection capillary pressure (MICP) measurements. The MICP method, traditionally used in energy industry, does not capture the impact of pores smaller than 3 nm. It is also limited to measuring only matric suction, ignoring electrostatic forces. Our results indicate that the suction values typically assumed in the literature from MICP tests significantly underestimate the total suction in shales and siltstones. Total suction for samples from the Montney Formation in Canada can be as high as 250 MPa at water saturations between 1 and 5%. The magnitude of suction measured in this work explains the significant water uptake by this class of reservoirs during hydraulic fracturing. Total suction in the present experiments correlate well to mineralogy and porosity of the samples. The results of this paper suggest that measurements of capillary pressure in unconventional reservoirs are generally inappropriate to describe the behavior of rocks. The order of magnitude of suction reported here has major implications in modelling basin-wide fluid migration, water imbibition into tight rocks, and describing rock's mechanical response after hydraulic fracturing.

Pore structure and fluid uptake of the Yeso, Abo, and Cisco Formations in the Permian Basin in southeast New Mexico, USA

There is a need for a petrophysical understanding of producing formations in the Northwest Shelf in southeast New Mexico. Working with six rotary sidewall core samples (dolomite, limestone, and sandstone), we have investigated the utility of mercury injection capillary pressure (MICP), contact angle, fluid imbibition, as well as logging analyses to evaluate the characteristics of pore structure and fluid uptake of the Yeso (Paddock and Blinebry members), Abo, and Cisco Formations. Results from MICP tests provide a variety of pore structure data including bulk and particle densities, porosity, pore-throat size distribution, permeability, and tortuosity. Two Abo dolomite samples indicate the highest porosities at greater than 15%, compared with 4%–7% for the other two dolomite samples from the Paddock and Blinebry members within the Yeso Formation. Most of the pore-throat sizes for these samples fall within the range of [Formula: see text]. The only exceptions are the Paddock member sample, which possesses a higher percentage of larger pores ([Formula: see text]), and the dolomite sample from the Cisco Formation, which has most of its pore-throat sizes falling within the range of [Formula: see text]. From contact angle measurements, all samples are found to be oil-wet because n-decane spreads onto the rock surface much quicker than the other hydrophilic fluids (deionized water and brine). Imbibition tests reveal well-connected pore networks in all samples, with the highest values of imbibition slopes being recorded for the Abo samples. In addition, we used the crossplot of porosity and water saturation obtained from log analyses to derive a value for permeability at field scales. The porosity and permeability values, from log analyses as well as laboratory MICP and gas pycnometry-permeameter measurements, and at different observational scales, are generally consistent. The overall results provide a snapshot of the pore structure characteristics, from limited samples but using integrated approaches and scales, of these formations.

Influence of viscoelastic surfactant fracturing fluid on coal pore structure under different geothermal gradients

Abstract Deep coal bed methane generally has a higher formation temperature than shallower coal, which can have important consequences for hydraulic fracturing. In this study, the pore characteristics of coal samples treated by viscoelastic surfactant (VES) fracturing fluid as a function of temperature (293.15–353.15 K) were qualitatively and quantitatively analyzed using mercury injection capillary pressure tests (MICP) and low-temperature N2 gas adsorption (N2GA). The Angulo model and Frenkel–Halsey–Hill (FHH) model were used to describe the fractal characteristics of the coal pores. The results indicated that VES fracturing fluid was most effective for pore changes at temperatures below 323.15 K. The mechanism of VES fracturing fluid on coal pores at variable temperatures was analyzed and addressed from two aspects: (1) the ability of fracturing fluid to enter pores and contact the pore surface; and (2) the ability of fracturing fluid to scavenge minerals on the pore surface. The wettability of VES fracturing fluid on pore surface was analyzed from the surface tension, carboxyl and hydroxyl groups of the coal. The influence of temperature on the solubility of minerals (e.g., calcite, kaolinite, and other inorganic minerals) in VES fracturing fluid was analyzed.

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

ABSTRACTPore 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).

Pore types, origins and control on reservoir heterogeneity of carbonate rocks in Middle Cretaceous Mishrif Formation of the West Qurna oilfield, Iraq

Carbonates in Upper Cretaceous Mishrif Formation of the West Qurna oilfield in Iraq are characterized by complicated rocks and pores types, and strong heterogeneity. Based on the cores and cast thin sections of three wells, pore types were identified, and pore origins were analyzed from the perspective of sedimentary and diagenesis features. Porosity and permeability measurement, and high pressure mercury injection capillary pressure tests were conducted to determine the relationships between pores and reservoir heterogeneity. Six types of pores are identified, and they are intragranular pores, moldic pores, residual moldic pores, intergranular pores, micropores and intercrystal pores. The pore origins were controlled by the sedimentary environments and diagenesis. Pore types were controlled by lime mud contents, bioclastic textures, types and abundance that were controlled by sedimentary environments. Pore occurrence was determined by various diagenesis, while pore occurrence was mainly attributed to dissolution, which was influenced by the mineral composition of bioclastics. In addition, pores were altered by micritization, cementation and compaction. Results from the comparison of reservoir parameters show that the reservoir physical properties and pore structure of the each dominant pore type are similar. The study proves that reservoir characteristics are controlled by dominant pore types and reveals that pore type is a crucial cause for strong reservoir heterogeneity of carbonates.

Petrophysical and microfacies analysis as a tool for reservoir rock typing and modeling: Rudeis Formation, off-shore October Oil Field, Sinai

Petrographically, the Lower Miocene Rudeis reservoir rock samples in October oil field can be summed up into three reservoir rock types RRTs. The RRT1 samples are mostly calcareous to ferruginated sandstones, sometimes are fossiliferous, whereas the RRT2 and RRT3 samples are carbonate rocks of grainstone and packstone microfacies, respectively. Cementation by sparite and compaction are the most important porosity-reducing diagenetic factors, whereas dissolution and leaching out as well as fracturing are the most dominant porosity-enhancing factors. The petrophysical and reservoir quality studies include measuring density, porosity, permeability measurements as well as reservoir quality index (RQI), flow zone indicator (FZI) and reservoir potential index (RPI) calculations. The permeability-porosity plot is the key-factor for discriminating the petrophysical behaviour into these three rock reservoir types. Petrophysically, the studied sandstone RRT1 samples have the best storage capacity and reservoir quality (the RQI, FZI and the RPI indicate poor to very good reservoir quality), whereas the RRT3 samples have the least prospective properties (the RQI, FZI and the RPI indicates impervious reservoir quality). Based on the FZI values, the studied Rudeis Formation was discriminated into a number of hydraulic flow units (6 HFUs). HFU 5–6 are the best reservoir zones; they are assigned in the central parts of the studied area, whereas the least quality (HFU 1–3) was assigned to the south. In addition, the mercury injection capillary pressure tests (MICP) indicates that, the RRT1 samples are ranked as IV (fair) to VI (impervious) ranks, the RRT2 as V (poor) to VI, whereas the RRT3 samples are impervious samples. Wettability of the studied RRT1 samples is mostly neutral.

Evaluation of Accessible Porosity Using Mercury Injection Capillary Pressure Data in Shale Samples

We present a novel approach to correct accessible/fluid-saturated porosity values calculated using mercury injection capillary pressure (MICP) for shale samples. On the basis of recent studies, accessible porosity of shale samples calculated from the MICP test is corrected to consider conformance and grain compressibility. However, we show here that the shale samples experience an additional phenomenon during the MICP test that has not yet been addressed, i.e., compression of inaccessible/unfilled pores. Therefore, we propose a general approach consisting of three distinct corrections to accurately estimate accessible porosity of the shale sample using MICP data: (1) conformance, (2) grain compressibility, and (3) inaccessible pore compressibility. First, we develop a mathematical model to estimate both pore and grain compressibility using MICP data and then calculate accessible porosity using the above-mentioned corrections. In the mathematical formulation, we divide the shale matrix into three constitue...

Interplay between permeability and compressibility in shale samples

In this study, we present a new approach to evaluate shale permeability as a function of effective pressure using Mercury Injection Capillary Pressure (MICP) experiments. Traditional approaches to describe permeability from MICP data often use pore size distribution and porosity and ignore intrusion effects. However, recent studies suggest that significant misinterpretation of pore size distribution and porosity can be realized owing to ignorance of pore compressibility in shale samples. We evaluate permeability variation with pressure using MICP data while considering for pore compressibility and intrusion correction.A shale sample often undergoes three stages during MICP tests: conformance, compression and intrusion. By identifying different pressure regions associated with these stages, we characterize pore compressibility as a function of pressure using compression stage and re-evaluate pore size distribution and porosity based on intrusion stage. We then integrate intrusion correction and pore compressibility values to Katz-Thompson correlation to evaluate permeability as a function of pressure.Identifying true intrusion and applying pore compressibility allow us to alter key variables in Katz-Thompson correlation, thus significantly lowers the final estimation of permeability. We observe 10–30% permeability reduction in the samples analyzed after corrections.This paper improves the accuracy of permeability predictions from MICP data; the outcome can be further applied to improve predictions of reservoir performance.

Experimental investigations on the geometry and connectivity of pore space in organic-rich Wufeng and Longmaxi shales

The nano-scale pore systems of organic-rich shale reservoirs were investigated from Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations in southeast Sichuan Basin. These two formations are the most important target plays of shale gas development in China. The purpose of this article is to assess the geometry and connectivity of multi-scale pore systems, and to reveal the nature and complexity of pore structure for these over-mature gas shales. To achieve these objective, total organic carbon, mineralogy, image analyses by focused ion beam-SEM, low pressure nitrogen adsorption, mercury injection capillary pressure (MICP) and spontaneous fluid [deionized (DI) water and n-decane] imbibition were performed.Most of the visible pores from SEM work in Wufeng and Longmaxi shales are within nm- and μm-size regimes and belong to organic matter (OM) pores. The shapes of OM pore in Longmaxi samples are elliptical, bubble-like, irregular or rounded. Wufeng pores are mainly irregular, linear and faveolated, even though two shales have small depth difference, as well as similar thermal maturity, kerogen type and TOC content. Nano-scale pores in Longmaxi are mainly associated with narrow platelike or slitlike pores with pore size of 3–50 nm; while inkbottle pores are dominant in Wufeng samples and over 88% of the pore volume is contributed by pores with diameter <20 nm. Overall, porosity, pore volume and surface area values from Wufeng samples are much higher than those in Longmaxi, which is mainly correlated with the different TOC contents and mineral compositions. MICP tests show that a total of 5 inflection points (indicative of different connected pore networks) are identified in all pressure regions for Longmaxi, while only 2 for Wufeng in high pressure region with the associated permeability at nano-darcy range. Imbibition curves of n-decane are divided into three stages: the initial stage (Stage Ⅰ), linear imbibition stage (Stage Ⅱ) and late imbibition stage (Stage Ⅲ), and the slopes of linear imbibition stage are around 0.5, suggesting well-connected pore spaces for n-decane. In contrast, imbibition curves for DI water are divided in two stages with linear slopes of between 0.25 and 0.5, indicating moderately-connected pore networks for the movement of DI water. This is consistent with the mixed-wet nature of these shales, with observed weak wettability for hydrophilic, while complete wetting for hydrophobic fluids.

An integrated approach for determination of pore-type distribution in carbonate-siliciclastic Asmari Reservoir, Cheshmeh-Khosh Oilfield, SW Iran

This paper presents an integrated pore type study at microscopic (core data), mesoscopic (well logs) and megascopic scales (3D seismic data) in the mixed carbonate-siliciclastic Asmari Reservoir of the Cheshmeh-Khosh Oilfield, SW Iran. Firstly, pore types are determined in a microscopic scale based on petrographic studies of thin sections. Well logs and nuclear magnetic resonance (NMR) log data are employed for pore type determination based on a velocity deviation log (mesoscopic scale). For each pore type subclass, a suite of physical rock properties including average poroperm values, T2 distribution, capillary pressure, pore size distribution and depositional texture are calculated. For this purpose, the NMR log, mercury injection capillary pressure data and core descriptions are interpreted in an integrated approach. Capillary pressure and pore size distribution in each pore type class are determined by mercury injection capillary pressure tests and synthesis of a continuous capillary pressure log from the NMR log (pseudo Pc curves). For dynamic behavior examination of the reservoir, the pore types are analysed in the framework of hydraulic flow units. Finally, 3D post-stacked seismic data are converted to a cube of pore types based on acoustic impedance inversion and seismic attributes. The methodology of this study is accomplished by using core and log data from three key wells and a 3D post-stack seismic data from the studied field. Lastly, a map of pore type distribution is established to provide a clue on the high and low permeable zones of the field. The presented methodology signifies reservoir anatomy on micro to mega scales.

Experimental investigation of the pore structure characteristics of the Garau gas shale formation in the Lurestan Basin, Iran

Gas storage and flow characteristics of shale gas reservoirs are greatly affected by their complex pore structure. These structures contain a wide range of pore size distribution with significant contribution of nanometer scaled pores. In this work an integrated experimental approach including geochemical and mineralogical analysis, Mercury Injection Capillary Pressure (MICP) and helium expansion porosimetry along with nano-scale Field Emission-Scanning Electron Microscopy (FE-SEM) imaging techniques was used to characterize pore structure of Garau formation, a shale gas play recently explored in the western Iran.MICP was used in this study as an acceptable laboratory method to identify pore throat size down to three nanometers. FE-SEM image analysis was also applied for better understanding of distribution, connectivity and nature of sub-micron pore systems. Experimental measurements were made on 23 plugs collected from two depth intervals from two wells in the Garau formation. X-Ray Diffraction mineralogy (XRD) analysis represents that shale samples are calcite rich with low clay contents. The kerogen analysis shows kerogen type II with Total Organic Carbon (TOC) values ranging from 0.41 to 3.18%. The total porosity obtained from helium expansion test, varies between 0.1 and 3.6% under ambient test conditions and between 0.1 and 1.2% under overburden stress test conditions suggesting high stress dependency of the porosity in the studied samples. Based on the MICP test results, the pore throat sizes in the Garau shale samples belong to the mesopores and macropores realm. In addition, two types of pore size distributions are observed in the samples according to their mineralogical compositions. The majority of pores in the first group with high calcite contents are in macro-scale (>50 nm) with the dominant pore radius of around 50 μm, while the dominating pore radii in the second group with illite traces are found to be in the meso-scale (5–50 nm). Furthermore, comparing the MICP and helium porosimetry test results shows that the total porosity of the Garau shale increases with the increase of the meso-scale pore volume. Observations from FE-SEM images were also in good agreement with MICP test results. FE-SEM analysis revealed that pores are located both in the organic matter and inorganic matrix whether in isolated or interconnected types. These observations showed that a portion of kerogen body is occupied by nano-scaled pores with different shapes and sizes; as a result, samples with higher TOC contents and maturity offers generally higher total porosity values.

Non-linear behaviour of electrical parameters in porous, water-saturated rocks: a model to predict pore size distribution

SUMMARY In this paper, two separate but related goals are tackled. The first one is to demonstrate that in some saturated rock textures the non-linear behaviour of induced polarization (IP) and the violation of Ohm’s law not only are real phenomena, but they can also be satisfactorily predicted by a suitable physical-mathematical model, which is our second goal. This model is based on Fick’s second law. As the model links the specific dependence of resistivity and chargeability of a laboratory sample to the injected current and this in turn to its pore size distribution, it is able to predict pore size distribution from laboratory measurements, in good agreement with mercury injection capillary pressure test results. This fact opens up the possibility for hydrogeophysical applications on a macro scale. Mathematical modelling showsthatthechargeabilityacquiredinthefieldundernormalconditions,thatisatlowcurrent, will always be very small and approximately proportional to the applied current. A suitable field test site for demonstrating the possible reliance of both resistivity and chargeability on current was selected and a specific measuring strategy was established. Two data sets were acquired using different injected current strengths, while keeping the charging time constant. Observed variations of resistivity and chargeability are in agreement with those predicted by the mathematical model. These field test data should however be considered preliminary. If confirmedbyfurtherevidence,thesefactsmayleadtochangingtheprocedureofacquiringfield measurements in future, and perhaps may encourage the design and building of a new specific geo-resistivity meter. This paper also shows that the well-known Marshall and Madden’s equations based on Fick’s law cannot be solved without specific boundary conditions.