Mercury Injection Capillary Pressure Research Articles

Describing the Full Pore Size Distribution of Tight Sandstone and Analyzing the Impact of Clay Type on Pore Size Distribution

Understanding the pore size distribution (PSD) of tight sandstone and the effect of clay minerals on the PSD is important for reservoir evaluation. Due to the complex shape of clay minerals, the multiscale pore size of tight sandstone, and the limitation of different experimental methods, it is hard to characterize the full PSD of tight sandstone, especially the point of connection (POC) of different derived PSD curves. In this paper, a more comprehensive technique integrated different precision methods of N2/CO2 low-pressure adsorption isotherms (N2/CO2-LPAI), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and synchrotron X-ray computed tomography (XCT) to investigate the full PSD for three typical tight sandstones in China. Two different forms of PSD data presentations, differential pore volume versus diameter (dV/dR) and the log differential pore volume versus diameter (dV/dlogR), were firstly used to determine the POC. The full integrated PSD curves and scanning electron microscopy (SEM) images were carried out on the different clay-rich tight sandstones. The results show that the pores are classified into three types: intercrystalline pores (less than 0.01 μm), clay-related pores and residual intergranular pores (0.01 μm to 10 μm), and microfractures and dissolution pores (greater than 10 μm). The percentage of intercrystalline pores has a small relation on the porosity and connectivity, while there is a strong correlation among microfractures, dissolution pores, porosity, and especially connectivity. The microfractures and dissolution pores are the main connection channels, so a little change of the main connection channels will have a great effect on the permeability of the tight sandstones.

Petrophysical properties of the Green Canyon Block 955 hydrate reservoir inferred from reconstituted sediments: Implications for hydrate formation and production

We explore the petrophysical behavior of the two interbedded lithofacies (sandy silt and clayey silt) that constitute the Green Canyon Block 955 hydrate reservoir in the deep-water Gulf of Mexico by performing experiments on reconstituted samples of the reservoir material. Sandy silts reconstituted to the in situ porosity have a permeability of 11.8 md (1.18 × 10−14 m2), which is similar to the intrinsic permeabilities measured in intact cores from hydrate reservoirs of similar grain size offshore Japan (Nankai Trough) and offshore India. Reconstituted clayey silts have a much lower intrinsic permeability of 3.84 × 10−4 md (3.84 × 10−19 m2) at the in situ stress. The reconstituted sandy silt is less compressible than the clayey silt. Mercury injection capillary pressure measurements demonstrate that the largest pores with the clayey silt are still smaller than the pores remaining after 90% hydrate saturation in sandy silt. We interpret that the methane solubility in pores of clayey silt is always less than that necessary to form hydrate, which explains why no hydrate is present in the clayey silt. We upscale the reservoir properties to estimate the behavior of interbedded sandy silt and clayey silt. We find the upscaled intrinsic horizontal and vertical permeabilities for the entire reservoir interval are 8.6 md (8.6 × 10−15 m2) and 1.4 × 10−3 md (1.4 × 10−18 m2). We estimate that during reservoir production, a maximum vertical strain of approximately 12% will result. Ultimately, this study will inform reservoir simulation models with petrophysical properties at scales of both individual lithofacies and reservoir formation.

Pore structure and controlling factors of dolomite-bearing high-salinity shale reservoir in Qianjiang Formation, Jianghan Basin, China

High-salinity shale is a unique and promising shale-oil reservoir in continental basins. We have collected representative samples from different lithologies from wells in the Qianjiang Depression to test the pore structure and basic character from prospective high-salinity oil-bearing shales. We conducted field emission scanning electron microscopy and X-ray diffraction analyses to study the high-salinity shale pore morphology and composition, respectively. We used mercury injection capillary pressure to understand the high-salinity shale macropore distribution, and we used low-pressure nitrogen (N2) adsorption to study the mesopore distribution. The results show that the high-salinity shale-oil reservoir mainly is composed of carbonate (dolomite and calcite), clay, and saline minerals (anhydrite, glauberite, and halite). Many intergranular pores were developed in the high-salinity shale. The mesopores and macropores both were developed well in argillaceous dolomite. The average pore volume of macropores is 0.0588 ml/g, which accounts for approximately 59% of the total pore volume. Therefore, in the high-salinity shale-oil reservoirs that we tested, macropores were more important than other pores. The symbiosis of dolomite and calcite improved the porosity of the high-salinity shale-oil reservoir, and the salt minerals increased the pore complexity.

Coupled nano-petrophysical and organic-geochemical study of the Wolfberry Play in Howard County, Texas U.S.A.

This research investigates the use of mercury injection capillary pressure (MICP) analysis for pore structure characterization and wettability droplet analysis for mm-scale assessment of wetting properties, on rotary side-wall core samples in the bottom section of Lower Spraberry (Leonard shale) and Wolfcamp A units from Element Petroleum's Rogers #3804 E well in the Midland Basin, Howard county, Texas. Porosity, permeability, total organic carbon (TOC), pyrolysis and X-ray diffraction data were also acquired for both the Rogers #3804 E and Wright 44 #1 E wells. The roles of organic matter quantity, quality and maturity, along with mineralogy, and grain size, are considered in the development of multiple pore systems at nm-μm sizes and their implications for petroleum production. The Lower Spraberry unit is found to contain greater porosity and permeability (and associated lower tortuosity) than the Wolfcamp A unit. More importantly, the two formations show disparate pore-throat size distributions, with the Lower Spraberry unit samples containing more inter- and intra-particle pores (43.1 ± 27.1 nm in pore-throat diameters) conducive to petroleum movement and production, while the Wolfcamp A unit samples possesses smaller pores (10.5 ± 5.45 nm) that are probably organic matter-hosted. The amount of S1 (an indicator of oil content) is closely related to the proportion of pore volume controlled by 2.8–50 nm in pore-throat sizes that are likely organic matter-related. Differences in the behavior of petroleum production from the Rogers #3804 E (with slow decline) and Wright 44 #1 E (with steep decline) wells are manifested in the oil saturation index (S1 vs. TOC), which is tantalizingly linked to the differences in the predominant pore-throat size distributions observed above.

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

Controls on reservoir properties in organic-matter-rich shales: Insights from MICP analysis

Mercury injection capillary pressure (MICP) analysis was used to study organic-matter-rich Devonian shales varying in maturity from marginally mature to postmature to discuss controls on drainage and imbibition in shale reservoirs. Six samples come from the New Albany Shale; their total organic carbon (TOC) ranged from 3.3 to 8.4% and vitrinite reflectance (Ro) from 0.54 to 1.42%. One Marcellus Shale sample with Ro 2.50% was used to extend the maturity range to the advanced dry gas window. Three coal samples of varying rank were also included for comparison. Porosity of the shales ranges from 1.5 to 5.0%, and MICP-derived permeability ranges from 0.17 to 9.9 mD. Injection capillary pressure curves have a range of entry pressures from 0.055 to 0.421 MPa, and no relationship of entry pressure with maturity was revealed. Maturity, however, has an influence on pore size distribution, with the higher-maturity samples having significantly lower volumes of pores with throats less than 10 nm in diameter. Withdrawal capillary pressure curves document a wide range of withdrawal efficiencies from 55% to almost 100%, and pores having throats between 3 and 50 nm in diameter play a major role in the ability of mercury to be released from the pore system. The obtained data provide valuable information about shale properties and their behavior not only in the air-mercury system but also under reservoir conditions.

Characteristics and quantitative evaluation of volcanic effective reservoirs: A case study from Junggar Basin, China

The Permian Jiamuhe Formation in Jinlong-2 Block is an unconventional volcanic reservoir that has been a major target of oil production in the northwest margin of the Junggar Basin, China. This study focuses on analyses of geological, well-logging and production data to understand the characteristics and to set up quantitative evaluation method on volcanic reservoirs. The geological data reveals that the lithology mainly includes andesitic (welded) breccia, andesitic/basaltic brecciated lava and andesite. The reservoir space is mainly composed of stomata and dissolution pore, followed by intercrystalline pore and intergranular pore, therefore is characterized by low to medium low porosity (ϕ) and ultra-low to low permeability (k). The mercury injection capillary pressure curves have shown that the microscopic pore and throat of effective reservoirs mainly express in fine pore type with unimodal coarse state, partial coarse state and bimodal partial coarse state. Moreover, limits (ϕ ≥ 8%, k ≥ 0.03 × 10-3μm2) of effective volcanic reservoirs have been determined by oil test and cross plot of porosity and resistivity. Thus, based on the analysis of macroscopic and microscopic characteristics, we optimize the K-means clustering analysis method and typical Fisher's discriminant method to set up quantitative classification and evaluation criteria and discriminant functions, which divide the volcanic effective reservoir into 3 classes accordingly. Our results have been applied to the development test area, the average daily oil production of deployed horizontal wells is 204 bbl/d, and the average cumulative oil production for one year is 68 Mbbl. This quantitative classification method may provide strong technical supports for the efficient development of volcanic reservoir.

An improved method in petrophysical rock typing based on mercury-injection capillary pressure data

ABSTRACT Petrophysical rock typing plays a major role in carbonate reservoir characterization and geological modeling for reservoir simulation. In this study, based on 1120 samples of mercury-injection capillary pressure data, we have analyzed the contributions to rock permeability for the thick Cretaceous carbonate reservoir of Mishrif Formation in H Oilfield in Iraq. The analyses have been carried out for three types of pore-throat frequency distribution, i.e., monomodal, bimodal, and trimodal. The results show that for the bimodal and trimodal samples, the pore-throat frequency distribution of the first pore system contributes more than 95% of rock permeability. Further, the Thomeer function has been used to fit the mercury-injection capillary pressure curve, in which the displacement pressure, pore geometry factor, and bulk volume have been extracted. These three parameters have been utilized to characterize the pore structure and to fit with the rock permeability so as to obtain the reservoir classification parameter Mode. Then, we have established the relationship between permeability and mode, permeability and R35, and the correlation coefficients are 0.81 and 0.75, respectively. And permeability derived from Mode is more accurate than R35. The Modes of 1120 samples have been arranged in ascending order and plotted on the semi-logarithmic scales. After interpolation, derivation, and filtering, five rock types have been divided at the change in slope. The combination of Mode and this slope method is considered an improved method. The classification results of Mode, Winland R35, and Flow Zone Indicator have been compared with those of pore-throat distribution, T2 distribution of nuclear magnetic resonance, and conventional logging responses. The results demonstrate that the classification results of Mode are significantly better than those of Winland R35 and Flow Zone Indicator.

New fractal-dimension-based relation model for estimating absolute permeability through capillary pressure curves

This paper developed a new general power-law relation model to predict absolute permeability, which innovatively integrating Poiseuille's law and fractal capillary pressure model. The proposed model took into account the assumption of Poiseuille's law and Purcell theory characterizing the porous media as capillary tubes of various radii. Kewen Li fractal capillary pressure model was preferred to characterize capillary pressure curves and derive the new permeability relation model due to its higher fitting accuracy compared with Brooks-Corey model. Further, a randomly collected dataset containing 151 rock samples was used to calibrate the coefficients and another 53 rock samples were used to validate the feasibility of this new model. The proposed permeability model can predict absolute permeability through 5 basic parameters as follows: porosity, displacement pressure, capillary pressure at irreducible wetting phase saturation, irreducible wetting phase saturation and the fractal dimension. The fractal dimension, an indicator of the porous media heterogeneity, has a great impact on flow capacity in natural rock system. For rock samples with fractal dimension Df > 3, the capillary pressure matching results of Kewen Li power-law model are much better than those of Brooks-Corey capillary pressure model. 151 mercury injection capillary pressure (MICP) curves were all well fitted by Kewen Li model to estimate the basic parameters, and the absolute permeability of these rock samples were predicted through the new relation model. Then this study performed a comparison between the measured permeability in laboratory and calculated permeability through the new relation model. The regression Coefficient of Determination (R2) for measured and calculated permeability of 151 rock samples was 0.967. Besides, the new model consistently obtained attractive prediction results for another 53 validation rock samples. The new relation model can be widely used to estimate the absolute permeability for various rock types, including limestone, sandstone, dolomite, and from tight rocks to high permeability rocks.

Predicting carbonate formation permeability using machine learning

It is imperative to characterize the formation permeability to simulate the flow behavior at subsurface conditions. An accurate characterization at the core scale is possible when large samples are available, but often this is not the case, as such samples are hard to recover. Instead, drill cuttings (small pieces) are usually the only source available, especially in real-time conditions. Thus, mercury injection capillary pressure measurements, which are applicable to small pieces, have been used to infer the formation permeability. The challenge is that capillary pressure measurements entail further interpretations, as they can be converted to the pore-throat size distribution but not directly to the permeability. Thus, researchers have proposed different empirical and theoretical relations to predict the permeability. The present study uses machine learning, a data-driven approach, to predict carbonate formation permeability. The data-driven approach does not impose any restriction on the spatial distribution of the pore-throat sizes in the network of connected pores, but rather trains models based on the existing data. The present study is based on 193 carbonate samples whose data (porosity, permeability, and mercury injection capillary pressure measurements) are available in the literature. The permeability values vary from nanodarcies to darcies. We propose two new correlations, with and without grouping analysis, for permeability prediction. The results are promising, as the averaged R2 score obtained with 50 iterations is larger than 0.96. The study provides a valuable tool for permeability prediction based on numerical methods that distinguish the pore structure by taking into account underlying trends in the measurements.

A New Multiphysics Method for Simultaneous Assessment of Permeability and Saturation-Dependent Capillary Pressure in Hydrocarbon-Bearing Rocks

Summary Cost-effective exploitation of heterogeneous/anisotropic reservoirs (e.g., carbonate formations) relies on accurate description of pore structure, dynamic petrophysical properties (e.g., directional permeability, saturation-dependent capillary pressure), and fluid distribution. However, techniques for reliable quantification of permeability still rely on model calibration using core measurements. Furthermore, the assessment of saturation-dependent capillary pressure has been limited to experimental measurements, such as mercury injection capillary pressure (MICP). The objectives of this paper include developing a new multiphysics workflow to quantify rock-fabric features (e.g., porosity, tortuosity, and effective throat size) from integrated interpretation of nuclear magnetic resonance (NMR) and electric measurements; introducing rock-physics models that incorporate the quantified rock fabric and partial water/hydrocarbon saturation for assessment of directional permeability and saturation-dependent capillary pressure; and validating the reliability of the new workflow in the core-scale domain. To achieve these objectives, we introduce a new multiphysics workflow integrating NMR and electric measurements, honoring rock fabric, and minimizing calibration efforts. We estimate water saturation from the interpretation of dielectric measurements. Next, we develop a fluid-substitution algorithm to estimate the T2 distribution corresponding to fully water-saturated rocks from the interpretation of NMR measurements. We use the estimated T2 distribution for assessment of porosity, pore-body-size distribution, and effective pore-body size. Then, we develop a new physically meaningful resistivity model and apply it to obtain the constriction factor and, consequently, throat-size distribution from the interpretation of resistivity measurements. We estimate tortuosity from the interpretation of dielectric-permittivity measurements at 960 MHz by applying the concept of capacitive formation factor. Finally, throat-size distribution, porosity, and tortuosity are used to calculate directional permeability and saturation-dependent capillary pressure. We test the reliability of the new multiphysics workflow in the core-scale domain on rock samples at different water-saturation levels. The introduced multiphysics workflow provides accurate description of the pore structure in partially water-saturated formations with complex pore structure. Moreover, this new method enables real-time well-log-based assessment of saturation-dependent capillary pressure and directional permeability (in presence of directional electrical measurements) in reservoir conditions, which was not possible before. Quantification of capillary pressure has been limited to measurements in laboratory conditions, where the differences in stress field reduce the accuracy of the estimates. We verified that the estimates of permeability, saturation-dependent capillary pressure, and throat-size distribution obtained from the application of the new workflow agreed with those experimentally determined from core samples. We selected core samples from four different rock types, namely Edwards Yellow Limestone, Lueders Limestone, Berea Sandstone, and Texas Cream Limestone. Finally, because the new workflow relies on fundamental rock-physics principles, permeability and saturation-dependent capillary pressure can be estimated from well logs with minimum calibration efforts, which is another unique contribution of this work.

Applications of nuclear magnetic resonance (NMR) logging in tight sandstone reservoir pore structure characterization

Tight sandstone reservoir evaluation and characterization faced great challenge by using conventional well logging data due to the complicated pore structure. To improve tight sandstone reservoir identification, the pore structure should be first characterized. In this study, using the tight Chang 8 Formation of Pengyang Region, west Ordos Basin as an example, 20 core samples were drilled for laboratory nuclear magnetic resonance (NMR) and mercury injection capillary pressure (MICP) experiments. A model, which was used to construct capillary pressure (Pc) curves from NMR data, was proposed, and the corresponding models were established based on classified power function (CPF) method to classify formations into three types. Based on these relationships, the NMR T2 distributions were transformed as pseudo Pc curves and pore throat radius distributions. After these relationships were extended into field applications, consecutive pseudo Pc curves were acquired, and the pore structure evaluation parameters and permeability were also predicted. Comparisons of predicted parameters with core-derived results illustrated the reliability of our proposed model and method.

Qualitative and quantitative prediction of diagenetic facies via well logs

Drilled cores, thin section petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), routine core analysis (RCA), and mercury injection capillary pressure (MICP) tests were used to establish a predictable model for diagenetic facies and reservoir quality using well logs in sandstones of the Paleogene Dongying Formation in Nanpu Sag, Bohai Bay Basin, Eastern China. The results show that the sandstones are texturally and compositionally immature, and have primary intergranular pores, secondary intergranular and intragranular pores, moldic pores, and micro-pores associated with diagenetic clay minerals. The sandstones have undergone low to moderate mechanical compaction, but a high degree of framework-grain dissolution. Diagenetic minerals are dominantly of carbonates (calcite, dolomite, and Fe-dolomite) and clay minerals (illite, mixed layer illite/smectite and kaolinite). Four types of diagentic facies are recognized: tightly compacted, carbonate cemented, clay mineral filling, and dissolution facies. Porosity, permeability and oil saturation ranges among these diagenetic facies were determined from routine core analyses. The diagenetic facies were then translated to conventional well logs by core-log calibration, and the well log expressions (in terms of natural gamma ray, neutron porosity, bulk density, sonic transit time, and resistivity logs) of various diagenetic facies were summarized. The mineralogical composition obtained from the Elemental Capture Spectroscopy (ECS) logs was then used for the diagenetic facies prediction. The diagenetic facies predicted with the comprehensive conventional log analyses were combined with the ECS log profile, and were calibrated with the XRD, SEM analysis and logging interpretation results. For wells without ECS log, the diagenetic facies can be quantitatively predicted by the mathematical calculations of reservoir quality index (RQI) via the GR, AC and DEN log curves. Reservoir quality or oil bearing properties can be evaluated and predicted by translating the diagenetic facies to well logs.

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.

The Impact of Microstructure of Filtration Materials on Its Auto-Activation for Manganese Removal from Groundwater

The study investigates the impact of pore structure parameters of three chemically non-active filtration materials on the auto-activation time and the height of the filtration zone for manganese removal from groundwater. At a technical scale, the activation is a long process which may require a period of up to three months. The process can be shortened by the use of porous filtration materials. In this study, three filtration materials (silica sand, chalcedonite sand, GAC—granulated activated carbon) were investigated using subcritical nitrogen adsorption and mercury injection capillary pressure measurements. These methods provide a comprehensive evaluation of pore structure parameters, including specific surface area (SSA), micro- and mesopore volumes, and an extended range of pore size distribution (PSD). The studied materials provided a wide range of micro- and mesopore volumes as well as SSA. In order to investigate the auto-activation time of filtration material—the time required to achieve the requested quality of the filtrate—and the height of the filtration zone, a pilot experiment was conducted for 1950 h. The pilot installation consisted of three-meters-high (10 cm diameter) filtration columns filled with the tested filtration materials. The results indicate that the internal pore structure and the investigated auto-activation parameters are correlated. Both auto-activation time and the size of the filtration zone were influenced by the mesopore volume and the associated SSA of the tested materials. The micropore volume was less effective in improving the autoactivation parameters. The research results indicated the importance of pore structure characteristics which should be considered prior to time-consuming pilot and technological tests.

Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing.

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

3D pore system reconstruction using nano-scale 2D SEM images and pore size distribution analysis for intermediate rank coal matrix

This paper comprises the analysis of scanning electron microscopy (SEM) images, nuclear magnetic resonance (NMR) and mercury injection capillary pressure (MICP) data to quantify the pore distribution in coal matrix. We first generate the 3D pore system in the coal matrix based on the statistics of pore distribution obtained from 2D SEM images, and then extract the pore network using the maximal ball method. The influence of the reconstructed cube size and the 2D image resolution on the accuracy of the reconstructed 3D coal sample was analysed when generate the 3D digital coal smaple. It was observed that the highest resolution which was achieved for the studied samples (6 nm) resulted in the underestimation of porosity of the studied sample, and it is recommended for future to create several models with different resolution to find the most representative model, instead of apriori using the highest possible resolution. The extracted pore network was then used to analyse pore size distribution and perform capillary pressure simulation using pore network modeling. A comparison of the pore network analysis with NMR and measured MICP data demonstrated that the pore network extraction method simplified the results of distribution and underestimated the size of elongated pores and microfractures. The simulated and laboratory measured MICP shows significant difference partically bucease the network extraction method was not suitable for the studied samples and this could be overcomed by our future study of model MICP using direct simulation method in the reconstructed 3D model.

Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

Generating pseudo-capillary pressure curves from nuclear magnetic resonance (NMR) data: a case study from the Cooper Basin, Australia

This study evaluates the accuracy of generating pseudo-capillary pressure curves from laboratory nuclear magnetic resonance (NMR) analysis and NMR wireline log data by comparing threshold pressures and curve characteristics to rock-derived mercury injection capillary pressure (MICP) analysis. Accurate production of pseudo-capillary pressure curves from NMR data could negate or reduce the need for expensive and rig-time-consuming core acquisition and subsequent MICP analysis. Successful application of this technique will allow production of pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost and help to better constrain petroleum reserves and improve near field exploration prediction outcomes. The Tindilpie-11 well in the Cooper Basin, Australia, was used as a case study because of extensive existing conventional ore analysis and presence of an NMR wireline log covering the sampled intervals in the Permian-aged Patchawarra Formation. Six core samples underwent MICP and laboratory NMR analyses, with capillary pressure curves generated for each method. Six pseudo-capillary pressure curves were also generated from the NMR wireline log data at the coincident sample depths. The pseudo-capillary pressure curves generated from laboratory NMR data closely resemble the MICP results (mean threshold pressure error of 0.63 MPa absolute [91.4 psi]) and proved the applicability of this approach. The NMR wireline log data used is an average over a ∼1.6 m interval, which has likely led to discrepancies when compared with laboratory NMR pseudo-capillary pressure curves and MICP curves. Nonetheless, this study confirms the applicability of using laboratory NMR data to generate pseudo-capillary pressure curves that resemble MICP results. Continued development of NMR log technology and reduced logging speeds will improve the data resolution and ultimately provide high density NMR data that can be used to create pseudo-capillary pressure curves for large stratigraphic intervals at a significantly reduced cost. KEY POINTS Pseudo-capillary pressure curves derived from NMR data. Reservoir characterisation requiring minimal rock acquisition for ground truthing. Case study on the Patchawarra Formation (Cooper Basin, Australia) using SCAL data.

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

AbstractTo reveal the effect of shale reservoir characteristics on the movability of shale oil and its action mechanism in the lower third member of the Shahejie Formation (Es3l), samples with different features were selected and analyzed using N2 adsorption, high‐pressure mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), high‐speed centrifugation, and displacement image techniques. The results show that shale pore structure characteristics control shale oil movability directly. Movable oil saturation has a positive relationship with pore volume for radius > 2 μm, as larger pores often have higher movable oil saturation, indicating that movable oil is present in relatively larger pores. The main reasons for this are as follows. The relatively smaller pores often have oil‐wetting properties because of organic matter, which has an unfavorable effect on the flow of oil, while the relatively larger pores are often wetted by water, which is helpful to shale oil movability. The rich surface provided by the relatively smaller pores is beneficial to the adsorption of immovable oil. Meanwhile, the relatively larger pores create significant pore volume for movable oil. Moreover, the larger pores often have good pore connectivity. Pores and fractures are interconnected to form a complex fracture network, which provides a good permeability channel for shale oil flow. The smaller pores are mostly distributed separately; thus, they are not conducive to the flow of shale oil. The mineral composition and fabric macroscopically affect the movability of shale oil. Calcite plays an active role in shale oil movability by increasing the brittleness of shale and is more likely to form micro‐cracks under the same stress background. Clay does not utilize shale oil flow because of its large specific surface area and its block effect. The bedding structure increases the large‐scale storage space and improves the connectivity of pores at different scales, which is conducive to the movability of shale oil.