Full-scale Pore Size Distribution Research Articles

Nano-Scale Pore Structure Characterization and Its Controlling Factors in Wufeng and Longmaxi Shale in the Zigong Area, Southwest Sichuan Basin

The nano-scale pore systems in shale reservoirs control shale gas transportation and aggregation, which is of great significance for the resource evaluation of shale oil and gas and the selection of a “sweet spot”. Taking twelve marine shale samples from the Wufeng–Longmaxi Formation in the Zigong area, southwest Sichuan Basin, as the research target, we carried out a series of experiments, including total organic carbon (TOC) analysis, X-ray diffraction (XRD), gas adsorption (CO2 + N2), and mercury intrusion porosimetry (MIP), to study the full-scale pore structure characterization and controlling factors of pore volume and specific surface area. The results presented the following findings. (1) Marine shale samples from the target area are rich in organic matter, with an average TOC value of 3.86%; additionally, the mineral composition was dominated by quartz and clay minerals, with average contents of 44.1% and 31.4%, respectively. (2) The full-scale pore size distribution curves of pore volume developed multimodally, with the main peaks at 0.5 nm–2 nm, 3 nm–6 nm, and 700 nm–2.2 um; moreover, the full-scale pore size distribution curves of a specific surface area developed unimodally, with the main peak ranging from 0.5 nm to 1.2 nm. (3) Pore volume was mainly contributed by mesopores and macropores, with an average contribution of 46.66% and 42.42%, respectively, while the contribution of micropores was only 10.91%. The specific surface area was mainly contributed by micropores and mesopores, with an average contribution of 64.63% and 29.22%, respectively, whereas the contribution of micropores was only 6.15%. (4) The TOC content mainly controlled the pore volume and specific surface area of micropores and mesopores, while the clay and feldspar content generally controlled the pore volume and specific surface area of macropores. Additionally, the quartz content had an inhibitory effect on the development of all pore types. These results will help researchers understand the laws of gas accumulation and migration.

Experimental Investigation on Pore-Fracture Variations in Coal Affected by Carbon Disulfide.

Solvent treatment is an effective technique to stimulate pore and fracture growth in low-permeability coal seams and improve the efficiency of methane extraction. Adopting the nuclear magnetic resonance test, liquid nitrogen adsorption analysis, ultrasonic test, and CT scanning, pore variation and fracture development in lignite, bituminous coal, and anthracite after carbon disulfide treatment were analyzed. Full-scale pore size distribution characteristics were obtained. The Frenkel-Halsey-Hill model was adopted to analyze pore fractal properties. Experiment results show that carbon disulfide could increase coal porosity. Lignite showed the best pore alteration effect, with a porosity increase of 34.10%, followed by bituminous coal with a porosity increase of 14.55%, while anthracite had a slightly weaker change with only 0.91% porosity growth. The pore diameter distribution range of treated coal expanded from 0-450 to 0-1000 μm. The average pore diameter rose from 316 to 483 μm, with better connectivity between pores. After treatment, the proportions of micropore specific surface areas (SSA) in three coal samples decreased but the ratios of small pore and medium pore SSA increased. Fractal dimension D1 of lignite and bituminous coal decreased by 5.669 and 0.054%, while D1 of anthracite increased by 22.407%. D2 reduced by 0.599, 3.143, and 1.262%, respectively. Raw coal had the maximum porosity near both ends of the CT section. Porosity of lignite was the largest at the ends after treatment. Surface porosity inside coal samples also rose from about 0.1 in raw coal to approximately 0.4 after treatment. Ultrasonic velocity in lignite decreased by 50.16% due to solvent treatment. Increases in ultrasonic attenuation coefficient α and ultrasonic attenuation ratio β indicate good fracture development. Furthermore, development degrees of lignite and bituminous coal are higher than that of anthracite. Results of the above methods verify with each other, indicating the effectiveness of carbon disulfide treatment in improving pore and fracture structures. The outcomes of this research could offer a theoretical basis for chemical permeability-enhancement technology.

Pore throat structure heterogeneity and its effect on gas-phase seepage capacity in tight sandstone reservoirs: A case study from the Triassic Yanchang Formation, Ordos Basin

The microscopic heterogeneity of pore-throat structures in tight sandstone is a crucial parameter for understanding the transport mechanism of fluid flow. In this work, we firstly developed the new procedure to characterize the pore size distribution (PSD) and throat size distribution (TSD) by combining the nuclear magnetic resonance (NMR), cast thin section (CTS), and constant-rate mercury injection (CRMI) tests, and used the permeability estimated model to verify the full-scale PSD and TSD. Then, we respectively analyzed the fractal feature of the pore and throat, and characterized the heterogeneity of pores and throats. Finally, we elaborated the effect of the pore and throat heterogeneity on the gas-phase seepage capacity base on the analysis of the simple capillary tube model and gas-flooding experiment. The results showed that (1) The PSD and TSD of the tight sandstone sample ranged from 0.01 to 10 μm and from 0.1 to 57 μm, respectively, mainly contributed by the micropores and mesopores. Meanwhile, the permeability estimated by the PSD and TSD was consistent with the experimental permeability, and relative error was lower than 8%. (2) The PSD and TSD exhibited multifractal characteristics, and singularity strength range, Δα, could be used as the indicator for characterizing the heterogeneity of pore and throat. Furthermore, the throat of the sample showed stronger heterogeneity than that the pore. (3) The throats played an important role for the fluid transport in the tight sandstone, and the effect of the throat heterogeneity on the gas-phase seepage capacity was different under the lower and higher injection pressure. The macropores and micropores maybe respectively become the preferential migration pathways at the lower and higher injection pressure. In the end, the identification plate was established in our paper, and could be described the relationship among the throat heterogeneity, injection pressure, permeability and flow path of the gas phase in the tight sandstone.

Multi-scale Pore Structure Characterization of Lacustrine Fine-Grained Mixed Sedimentary Rocks and Its Controlling Factors: A Case Study of Lucaogou Formation in Jimusar Sag

The microscopic pore structure of fine-grained mixed sedimentary rocks (FMSRs) is of great significance for the occurrence mechanism and sweet spot optimization of mixed shale oil. At present, there is no clear understanding of the microscopic pore system of FMSRs and their coupling relationship with rock composition, which restricts the fine understanding of the reservoir forming mechanism of this type of reservoir. Taking the FMSR samples of the Permian Lucaogou Formation in the Jimusar Sag, the southeastern margin of the Junggar Basin, China, as an example, this paper quantitatively characterizes the full-scale pore structure of lacustrine FMSRs by casting thin sections, scanning electron microscopy, low-temperature nitrogen adsorption (LTNA), high-pressure mercury injection, and nuclear magnetic resonance (NMR); analyzes the coupling relationship between the full-scale pore structure and rock composition; and then summarizes the controlling factors. The results showed that the full-scale pore size distribution (PSD) can be revealed by combining the LTNA and NMR methods. The PSDs of FMSRs are evaluated, mostly corresponding to small pores (30–200 nm) and mesopores (200–1500 nm). The sediment grain size, mineral composition, sedimentary environment, and diagenesis jointly controlled the development of FMSR reservoirs. The development of coarser grain components (such as fine sand and arenaceous dolomite), high content of feldspar, low content of clay and calcite, and appropriate content of dolomite (less than 20%) were conducive to high-quality reservoirs. A near-provenance sedimentary pore throat is better. Siltstones, dolomitic siltstones, and dolarenites were mainly developed in shoreland sandy bar, distal sand bar, and dolomitic mud flat microfacies; type I pore throats with residual intergranular pores and dissolved pores are the most favorable for the Lucaogou Formation.

Fractal analysis of pore structures in transitional shale gas reservoirs in the Linxing area, Ordos Basin

Studying complex pore structures and fractal characteristics of gas shale provides significant guidance for clarifying the mechanism of shale gas accumulation and realizing its efficient development. In this paper, 12 samples of Taiyuan Formation shale are used as the research object, and the fractal theory is combined with mercury intrusion porosimetry and N2 adsorption technology to innovatively solve the problem of splicing point selection, which can reveal the full-scale pore size distribution of shale. The results demonstrate that the most common types of pores in the chosen samples are pores between or within clay minerals, micropores and mesopores inside organic matter, and microfractures, based on scanning electron microscopy imagery analyses. The pores of shale samples have fractal geometries. The fractal dimension DM1 values in the mercury intrusion porosimetry experiments range from 2.3060 to 2.6528. Two fractal dimensions, DN1 and DN2, may be obtained using the Frenkel-Halsey-Hill fractal method. DN1 values vary from 2.4780 to 2.6387, whereas DN2 values range from 2.5239 to 2.7388. Most macropores in shale samples have a size range of about 0.2 mm, with a wide pore size distribution, and the largest peak of the micro-mesopore volume is generally about 50 nm. The fractal dimension correlates positively with the corresponding pore volume, although the correlation between volume and composition is weak. The relatively strong correlation between fractals and the basic compositions of shale proves the fractal theory’s relevance in defining pore inhomogeneity. This study would contribute to the development of a fractal perspective-based method for pore splicing while also expanding our understanding of pore morphology and structure in transitional shale.

An integrated pore size distribution measurement method of small angle neutron scattering and mercury intrusion capillary pressure

Small-angle neutron scattering and high-pressure mercury intrusion capillary pressure testing are integrated to analyze the pore size distribution of the broad sense shale oil reservoir samples of the Permian Lucaogou Formation in the Jimsar Sag, Junggar Basin, China. The results show that, compared with the measurement method integrating gas adsorption and mercury intrusion, combination of small-angle neutron scattering and mercury intrusion can more accurately characterize full-scale pore size distribution. The full-scale pore size distribution curve of the rock samples in the study area includes two types: the declining type and submicron pore-dominated type. The declining type is mainly found with silty mudstone and dolomitic mudstone, and most of its pores are smaller than 80 nm. Silt-fine sandstones and dolarenite are mostly of the submicron pores-dominated type, with most pores smaller than 500 nm. They also present large specific pore volumes and average pore diameters of macropores and are the favorable lithogenous facies for development of high-quality reservoirs.

Full-scale pore size distribution features of uranium-bearing sandstone in the northwest of Xinjiang, China.

As an important nuclear fuel, uranium in sandstone uranium deposits is mainly extracted by in situ leaching. The porosity of sandstone is one of the important indexes determining in situ leaching efficiency. Moreover, the microscopic pore size distribution (PSD) of the uranium-bearing layer has an important effect on porosity. It is necessary to feature the pore structure by various techniques because of the different pore types and sizes in the uranium layer. In this paper, combined with nitrogen gas adsorption, nuclear magnetic resonance techniques and scanning electron microscopy, the full-scale PSD features of uranium-bearing sandstone in the northwest of Xinjiang are effectively characterized. The results show that pores structure of uranium-bearing sandstone include dissolution pores (d ≤ 50 nm), intergranular pores (50 nm < d ≤ 200 µm) and microfractures. Intergranular pores of 60 nm and 1 µm are the significant contributors to pore volume. The effects of the pore volume of two pore types (dissolution pores and intergranular pores) on the porosity of uranium-bearing sandstone are analysed. The results show that intergranular pores have the greater influence on the porosity and are positively correlated to the porosity. Dissolution pores have little effect on the porosity, but it is one of the key factors for improving uranium recovery. Moreover, the greater the difference of PSD between sandstones, the stronger the interlayer heterogeneity of uranium-bearing sandstone. This kind of interlayer heterogeneity leads to the change of permeability in the horizontal direction of strata. It provides a basis for a reasonable setting of well type and well spacing parameters.

Multiscale characterization of shale pore-fracture system: Geological controls on gas transport and pore size classification in shale reservoirs

A sound understanding of the pore-fracture system across all scales provides an in-depth look at the intricate gas transport mechanisms in shale reservoirs. We performed a comprehensive multiscale characterization analysis on the Longmaxi shale samples using five complementary techniques: low-temperature gas (N2) adsorption (LTGA), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), field emission scanning electron microscopy (FE-SEM), and X-ray computed tomography (CT) scanning. For pore size distribution (PSD) determination, LTGA (N2) analysis can detect small pores (2–300 nm sized), while MIP analysis is suitable for large pores or fractures (> 300 nm). NMR can reveal full-scale PSD characteristics of shale. Combining NMR with LTGA or MIP is recommended, since NMR alone would over- or under-estimate the pore size. The Longmaxi shale pores observed by FE-SEM imaging are of good connectivity and, by and large, are tens of nanometers sized. The scale-dependent analysis shows that the representative elementary volume (REV) for porosity of the Longmaxi shale based on FE-SEM imaging is almost 600 μm. As evident from the CT scanning, the connectivity of the entire shale pore-fracture system increased significantly after saturating the sample with water. The gas slippage (Klinkenberg) effect is significant at relatively low pressures. A second-order model would better estimate the intrinsic permeability compared with the traditional Klinkenberg equation. Microfractures manifest preferred orientation or alignment parallel to the shale bedding plane and are the dominant pathways for gas transport in shale. Finally, we proposed a new pore size classification of shale considering gas transport mechanisms: adsorption pores (pore size < 10 nm), slippage pores (10 nm < pore size < 1000 nm), and seepage pores or fracture-pores (pore size > 1000 nm). Although slippage pores dominate in terms of the total volumetric contribution of the Longmaxi shale, with a clear presence of adsorption pores, overall gas transport in shale is predominantly controlled by the seepage pores (fracture-pores), which constitute a very small portion of the total volume.

Pore size distribution of high volatile bituminous coal of the southern Junggar Basin: a full-scale characterization applying multiple methods

Studying on the pore size distribution of coal is vital for determining reasonable coalbed methane development strategies. The coalbed methane project is in progress in the southern Junggar Basin of northwestern China, where high volatile bituminous coal is reserved. In this study, with the purpose of accurately characterizing the full-scale pore size distribution of the high volatile bituminous coal of the southern Junggar Basin, two grouped coal samples were applied for mercury intrusion porosimetry, low-temperature nitrogen adsorption, low-field nuclear magnetic resonance, rate-controlled mercury penetration, scanning electron microscopy, and nano-CT measurements. A comprehensive pore size distribution was proposed by combining the corrected mercury intrusion porosimetry data and low-temperature nitrogen adsorption data. The relationship between transverse relaxation time (T2, ms) and the pore diameter was determined by comparing the T2 spectrum with the comprehensive pore size distribution. The macro-pore and throat size distributions derived from nano-CT and rate-controlled mercury penetration were distinguishingly analyzed. The results showed that: 1) comprehensive pore size distribution analysis can be regarded as an accurate method to characterize the pore size distribution of high volatile bituminous coal; 2) for the high volatile bituminous coal of the southern Junggar Basin, the meso-pore volume was the greatest, followed by the transition pore volume or macro-pore volume, and the micro-pore volume was the lowest; 3) the relationship between T2 and the pore diameter varied for different samples, even for samples with close maturities; 4) the throat size distribution derived from nano-CT was close to that derived from rate-controlled mercury penetration, while the macro-pore size distributions derived from those two methods were very different. This work can deepen the knowledge of the pore size distribution characterization techniques of coal and provide new insight for accurate pore size distribution characterization of high volatile bituminous coal.

A novel pore size classification method of coals: Investigation based on NMR relaxation

Nuclear magnetic resonance (NMR) severs as a nondestructive and relative new technique that has been widely used in characterizing reservoir fluids and pore size distribution (PSD) of coals. Conventionally, pore fluids in coals are classified into movable fluid and irreducible fluid based on a single NMR T2 cutoff value (T2C). However, the single NMR T2 cutoffs model has some apparent defects in pore fluid/size classification, and few researches have reported the limitation of the single T2 cutoffs model. In contrast, the dual T2 cutoffs model may provide an accurate quantified model to classify different pore fluid types in coals. In this study, fifteen coal samples with different ranks were conducted in systematic NMR and centrifugal experiments to investigate the characteristics of pore fluid typing and PSD. Results show that when tried applying the single NMR T2 cutoffs model to classify the pore fluid typing, there are still some movable fluids when T2 < T2C. At the same time, when T2 > T2C, there is remaining some irreducible fluid in pores after high pressure centrifugal experiments. These results indicated the limited application of single NMR T2 cutoffs model in pore fluid classification. By introducing a novel pore fluid classification method (i.e. the dual T2 cutoffs model), a typical T2 spectrum under fully-saturated condition, the absolute irreducible fluid T2 cutoffs (T2C1) and absolute movable fluid T2 cutoff (T2C2) can re-divide the pore fluid typing of coal into three types: absolute irreducible fluid (T2 < T2C1), partial movable fluid (T2C1 < T2 < T2C2), and absolute movable fluid (T2 > T2C2). The results show that the T2C1 is in the range of 0.10–0.32 ms, while the T2C2 has a wider range from 36.12 ms to 89.07 ms. Finally, a conceptional model were proposed to clarify a full-scale PSD classification that includes the absolute irreducible fluid pores, partial movable fluid pores and absolute movable fluid pores. The model established in this study, can also be applicable for other rock types (e.g., sandstones, carbonates and shales).

Source/reservoir characteristics and shale gas “sweet spot” interval in Shahezi mudstone of Well SKII in Songliao Basin, NE China

Samples from the Shahezi mudstone of Well SongkeII (SKII) in the Songliao Basin were analyzed for mineral composition, source rock geochemistry, and reservoir pore structure. It is revealed that the Shahezi mudstone is a typical clay rock, with an average TOC of 2.12% (dominantly Type II–III organic matters) and a vitrinite reflectance Ro of 2.28–2.34%. The pore structure of the Shahezi mudstone reservoir mainly comprises intergranular pores and interlayer fractures in clay minerals, and also organic pores (including fractures at the particle-organic edges and also pores in some unstructured organic matters). The Shahezi mudstone has a specific pore volume of 0.01–0.04 cm3/g. Correlation analysis of specific pore volume and mineral composition reveals that the pore development of the Shahezi mudstone is mainly controlled by inorganic minerals. The nitrogen adsorption and high-pressure mercury intrusion tests were combined to obtain the full-scale pore size distribution and specific pore volume of the Shahezi mudstone, and the shale gas “sweet spot” interval is inferred to be 3,500–3,700 m. The study results can be referential for understanding the pore characteristics of highly-mature continental mudstone and locating the “sweet spot” of shale gas globally.

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.

Comprehensive characteristics of pore structure and factors influencing micropore development in the Laochang mining area, eastern Yunnan, China

Characterization of coal pore structure plays an important role in the exploration and development of coalbed methane. Results from corrected high-pressure mercury injection porosimetry, low-temperature liquid nitrogen adsorption, and low temperature carbon dioxide adsorption were used in combination with fractal theory. This study aims to gain insight into full-scale pore size distribution and to discuss factors influencing micropore development in relation to physical properties of coal samples. The results show that coal compressibility in the study area is between 0.79-1.27 × 10−10 m2/N, the maximum cumulative mercury intrusion volume was 75%–85% of that before correction. Pore shapes are mainly cone pores and parallel plate-shaped pores. The total pore volume (PV) ranges from 0.071–0.084 cm3/g. Micropores, especially those with diameters less than 1.5 nm, account for more than 90% of PV, providing storage space for most of the adsorbed gas. The effect of coalification on pore development is complex, there is no obvious relationship between micropore volume, specific surface area (SSA) and coal rank; however, a negative correlation exists between micropore volume, SSA and volatile yield. Moisture and fixed carbon content can increase micropore volume and SSA, while ash yield and minerals tend to reduce micropore volume and SSA.

Determination of full-scale pore size distribution of Gaomiaozi bentonite and its permeability prediction

Abstract Gaomiaozi (GMZ) bentonite is a potential buffer/backfill material for a deep geological disposal of high-level radioactive waste. It has a wide pore size distribution (PSD) with sizes ranging from several nanometers to more than one hundred microns. Thus, properly characterizing the pore structures of GMZ bentonite is a challenging issue. In this study, pressure-controlled porosimetry (PCP), rate-controlled porosimetry (RCP), and scanning electron microscopy (SEM) were used to investigate the PSD of GMZ bentonite. The results indicate that each method has its limitation, and a combined use of PCP and RCP is suitable to obtain the full-scale PSD of GMZ bentonite. Moreover, we also compared the full-scale PSD with nuclear magnetic resonance (NMR) result. It is found that there is no significant difference in the range of PSD characterization between NMR and mercury intrusion method (PCP and RCP). However, in a certain range, the detection accuracy of NMR is higher than that of mercury injection method. Finally, permeability prediction based on PCP and SEM data was conducted, and both of the two methods were found to be able to predict the permeability. The combined method is effective to obtain the full-scale PSD of GMZ bentonite, which is the key to estimation of the sealing ability of bentonite buffer.

Effects of boundary layer and stress sensitivity on the performance of low-velocity and one-phase flow in a shale oil reservoir: Experimental and numerical modeling approaches

Seepage flow is important because it is useful for production optimization and well spacing decisions. In this study, an enclosed high-precision seepage flow apparatus is used to determine the seepage flow characteristics of the Qianjiang shale reservoir in China under various pressures from 3 MPa to 24 MPa. The results revealed that the seepage flow curve has an inverse-spoon shape, which is completely different from the results for low-permeability and tight sandstone reservoirs, as reported in the literature. In addition, according to the full-scale pore size distribution technique, the modular automated processing system (MAPS), and the nuclear magnetic resonance (NMR) T2 spectrum before and after the seepage flow experiments, the seepage flow characteristics of the Qianjiang shale oil reservoir were not only caused by the boundary effect, but also dependent upon the stress sensitivity. It was also found that micro-fractures or macro-pore were compressed as the effective stress increased in the experiment. Moreover, a new non-Darcy model for a shale reservoir was derived, and the model was verified using experimental data. This model demonstrated it would be a good candidate for quantitative evaluation of affecting factors. It can also be applied to determine the main controlling factor. The calculated results showed that the shape of the nonlinear flow portion of the seepage flow curve for the Qianjiang shale oil reservoir was primarily dependent upon the effect of stress sensitivity. However, the linear flow portion of the seepage flow curve was dependent upon the combined effects of stress sensitivity and the boundary layer. Therefore, from the enhanced individual-well production point of view, the control of production pressure drops and selection of rational well spacing is important for the effective development of shale oil reservoirs.

Nuclear magnetic resonance surface relaxivity of coals

Nuclear magnetic resonance (NMR) transverse relaxation time (T2) measurements of fully water-saturated rock samples can provide a reference for pore size distribution (PSD). Commonly, surface relaxivity of the rock must be known before obtaining an absolute PSD sample using NMR data. There are many reports concerning the surface relaxivity of sandstones, shales, and carbonate rocks, however, little research has been performed on the surface relaxivity of coals, which limit the application of the NMR in PSD evaluation of coals. To obtain a standard surface relaxivity for PSD measurements of coals, we performed NMR, low-temperature N2 adsorption (LTNA), and mercury intrusion porosimetry (MIP) measurements for 15 bituminous and anthracite coals, whose Ro range from 0.52% to 3.07%. The results show that the values of surface relaxivity from LTNA (ρ2-SVR) are inconsistent with those from MIP (ρ2-MIP) for all samples. Moreover, the applications of ρ2-SVR and ρ2-MIP for PSD conversions are valid only for the smaller pores and larger pores, respectively. Evidently, both these two surface relaxivities cannot be used individually to calculate full-scale PSD. To obtain the actual surface relaxivity (ρ2) for full-scale PSD, we rebuilt a full-scale PSD by combining the pores smaller than 25 nm from LTNA and the pores larger than 25 nm from MIP. The results indicate that the calculated ρ2 provides excellent function for PSD transformation for all coal samples. Finally, the references of ρ2 for different coals are provided, i.e., values of 2.1 μm/s for sub-bituminous coal (low-rank coal), 3.0 μm/s for bituminous coal (medium-rank coal) and 1.6 μm/s for anthracite coal (high-rank coal). Using these referential surface relaxivities, a T2 distribution from NMR measurement can be converted to a PSD, which is applicable not only in the laboratory but also in field applications such as well logging.

Nuclear magnetic resonance T2 cutoffs of coals: A novel method by multifractal analysis theory

Nuclear magnetic resonance (NMR) has been widely used in petrophysical characterization of coals. For NMR experimental data analysis, transverse relaxation time (T2) cutoff value is a key parameter to identify the form of movable and irreducible fluids, and to evaluate permeability and full-scale pore size distribution (PSD). Conventionally, the T2 cutoff value is procured by a series of centrifugal experiments, which is much complicated and time consuming, and is also hard to be used in fields such as well logging. Thus, a convenient and practical method is needed for T2 cutoff value prediction. Based on series of centrifugal experiments, this study firstly determined an optimal centrifugal pressure of 1.38 MPa for T2 cutoff value calculation. The results from centrifugal experiments show that the T2 cutoff values of bituminous coals and anthracite coals in the range of 0.62–15.11 ms. Then, the multifractal analysis theory is introduced into the estimation of T2 cutoff values of coals. The results showed that the NMR T2 distribution of 100% water-saturated coal is multifractal, and the multifractal parameters of multifractal dimension (Dq) and singularity strength range (Δα) can be used to evaluate the T2 cutoff value of coals. Finally, a new multifractal-based NMR T2 cutoff calculation model was provided, and the model was verified by centrifugal experimental data of six coal samples. It is concluded that the provided multifractal analysis method is effective, convenient and independent of any other experiments. The model derived from the study of coal, is also applicable for researches of other rock types such as shales and so on.

Characterization of pore size distributions of shale oil reservoirs: A case study from Dongying sag, Bohai Bay basin, China

Abstract Shale oil reservoirs characterized by complex pore structures typically contain a wide pore size range from nanometers to millimeters. The pore size distribution (PSD) is one of the most critical parameters affecting fluid storage and transport properties in shale oil reservoirs. Quantitatively and accurately determining PSD is of great importance for evaluating the shale oil occurrence state and movable fluid volume. In this study, four major techniques, including nitrogen adsorption (NA), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR), were adopted to determine pore sizes in ten shale oil reservoir samples from Dongying sag, Bohai Bay basin, China. NMR T2 spectra were converted to PSDs by using a new subsection calibration method based on the NA and SEM measurements; using the linear and power exponent conversion models, these two models are compared. The results show that the subsection calibration is an effective method for shale NMR T2 spectrum conversion. Shale oil reservoir T2 spectra can be converted to full-scale PSDs by combining NA micropore ( 1000 nm) in shale oil reservoirs; however, they are mainly connected by small-scale throats. Therefore, the comprehensive characterization of shale oil reservoir pore structures may be efficiently and accurately determined by a combination of NMR and MICP.

Characterizations of full-scale pore size distribution, porosity and permeability of coals: A novel methodology by nuclear magnetic resonance and fractal analysis theory

Nuclear magnetic resonance (NMR) has been widely used to evaluate the pore size distribution (PSD) properties of coals. However, the NMR signal itself only provides a relative distribution of pore size. To calculate an absolute pore size distribution from the NMR data, the T2 cutoff value needs to be known. Meanwhile, the T2 cutoff value is an indicator to divide the irreducible fluid and movable fluid in porous rock and a key factor for permeability prediction. Conventionally, the T2 cutoff value is obtained by centrifugal experiments, the process of which is complicated and time consuming, and some T2 cutoff value prediction models are not suitable for coals with complex pore structures. Hence, a new method is needed for T2 cutoff value prediction. In this study, we performed scanning electron microscopy (SEM), low-temperature nitrogen adsorption/desorption (LTNA) and NMR experiments on 12 coal samples. The results of SEM and LTNA reveal the complex pore structures of the coals. According to the results from centrifugal experiments, the T2 cutoff value is in the range from 0.5–2.8 ms for subbituminous coals, whereas it is 15–32 ms for anthracite coals. We present a fractal theory based method for T2 cutoff value prediction. Using the estimated T2 cutoff values, we calculated the movable porosities, PSD and permeability for the selected coals. The results show that the proposed permeability model provides significantly better permeability estimation than classic (Coates and SDR) models. These methods are applicable not only for coals, but also for other unconventional gas reservoir rocks such as gas shales.

Shale pore size classification: An NMR fluid typing method

Abstract Shale reservoir is characterized by complex pore networks, within which there are various pore fluids including unrecoverable fluid, capillary bound fluid and movable fluid. Although considerable literature has investigated the pore structure of gas shale using different laboratory testing techniques, few papers have provided a quantified model to distinguish different types of fluids (corresponding to different pore types) in shale. In this study, seven shale core plugs from the Sichuan Basin were measured in a series of NMR experiments under full brine-saturated, centrifugal and heat-treated conditions to analyze the pore structure information and pore fluid transport during the processes of centrifuging and heating. For a typical T2 spectrum of 100% brine-saturated shale, the movable fluid T2 cutoff (T2C1) and unrecoverable fluid cutoff (T2C2) were derived from NMR centrifugal and heat-treated experiments to distinguish the unrecoverable fluid (T2 T2C1). Our results show that for the investigated shales, the T2C2 ranges from 0.09 ms to 0.36 ms, and T2C1 has a wide range from 0.45 ms to 2.98 ms. The surface relaxivities range from 0.00426 μm/ms to 0.02822 μm/ms, and the shales having high silicate mineral contents commonly have low surface relaxivities. A conceptional model based on the dual T2 cutoff method was constructed to illustrate the full-scale pore size distribution: unrecoverable fluid pores, capillary bound fluid pores and movable fluid pores. This study provides a new method of pore fluid typing and full-scale pore size distribution classification for shales.