High-pressure Mercury Intrusion Research Articles

Laminae characteristics of lacustrine shales from the Paleogene Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, China: Why do laminated shales have better reservoir physical properties?

Laminae are the most typical and representive sedimentary feature in organic-rich shales, and revealing their influences on the reservoir physical properties is vital to understand the oil enrichment mechanisms of lacustrine shale. This study investigated the laminae characteristics and their effects on the physical properties of the shales from the Second Member of the Kongdian Formation (Ek2). The research presented in this study is based on core and thin section observations, XRD analysis, low-pressure nitrogen physisorption (LNP), high-pressure mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM). The results show that the Ek2 shales developed massive and laminated sedimentary structures. The laminae can be categorized as siliceous laminae, dolomite laminae, clay-rich siliceous laminae, organic matter laminae, and calcite laminae. Analysis of SEM, LNP, MIP, and NMR show that macropores and micro-fractures contribute significantly to the total pore volume of laminated samples, while micropores and mesopores are the dominant pore types in massive samples. The pore structure and connectivity of the laminated samples are better than that of the massive samples. Comparison of laminar and massive mudstones in the Ek2 showed that the development of laminae physical properties that are more conducive for reservoir formation as a result of interlaminated fractures, optimized arrangement of minerals, and improved organic-inorganic interactions.

Fractal characteristics of the micropore throats in the shale oil reservoirs of the Chang 7 member of the Yanchang Formation, Ordos Basin

With the development of the global shale oil and gas revolution, shale oil has became an important replacement field to increase oil and gas reserves and production. The Chang 7 member of the Yanchang Formation in the Ordos Basin is an important shale oil exploration series in China. To study the micropore-throat structure characteristics of the Chang 7 member, we have conducted nuclear magnetic resonance (NMR) and high-pressure mercury intrusion (HPMI) experiments to analyze the pore-throat structure features of the Chang 7 reservoir, and we have considered fractal theory to study the fractal characteristics. The NMR results indicate that the [Formula: see text] spectral morphology of the Chang 7 reservoir can be characterized by three main patterns encompassing early and late peaks with different amplitudes: the type 1 reservoir contains mostly small pores and few large pores, and the porosities of the small and large pores range from 4.16% to 9.04% and 0.70% to 2.40%, respectively; the type 2 reservoir contains similar amounts of small and large pores; and the type 3 reservoir contains few small pores and mostly large pores, while the porosities of the small and large pores range from 1.81% to 2.74% and 3.32% to 5.64%, respectively. The pore-throat structure parameters are obviously affected by the pore size distribution, which in turn influences the reservoir seepage characteristics of the reservoir. The micropore-throat structure of the reservoir exhibits obvious piecewise fractal characteristics and mainly includes dichotomous and trilateral fractals. The type 1 reservoirs are dominated by dichotomous fractals, and these two fractal types are equally distributed in the type 2 and 3 reservoirs. The fractal dimension of the pore throats of different scales exhibits a negative correlation with the corresponding porosity, but no correlation is observed with the permeability, indicating that the size of the reservoir determined by pore throats imposes a strong controlling effect on their fractal characteristics.

Occurrence characteristics of the movable fluid in heterogeneous sandstone reservoir based on fractal analysis of NMR data: A case study of the Chang 7 Member of Ansai Block, Ordos Basin, China

In the Ordos Basin, Chang 7 sandstone is considered an essential tight sandstone reservoir. In this research, the occurrence characteristics of the movable fluid, fractal characteristics, and their relationship in Chang 7 reservoir of the Ansai Block, Ordos Basin, have been quantitatively evaluated through nuclear magnetic resonance (NMR) and fractal theory. Moreover, the factors influencing the fractal dimensions and movable fluid distribution have been determined through a series of experiments, i.e., conventional physical property, cast thin section, scanning electron microscope (SEM), high-pressure mercury intrusion (HPMI), and X-ray diffraction technique (XRD). It has been noticed the movable fluid distribution in the tight sandstone reservoirs is greatly affected by the pore structure heterogeneity. Results show the main pore types in Chang 7 are the intergranular dissolution pores, intragranular dissolution pores, residual intergranular pores, and inter-crystalline pores. The pore size chiefly ranges from 0.1 nm–5 μm, while the main fluids storage spaces are nanopores and submicron pores. The reservoir has been divided into three types (type Ⅰ, Ⅱ, and Ⅲ) based on the distribution of the T2 spectrum and petrophysical parameters. Moreover, these reservoirs have various movable fluid distributions and fractal structures. Multiple factors such as pore structure, pore size distribution, and mineral compositions are discussed, which influence the fractal dimension and movable fluid saturation. The reservoirs having more nanopores are often associated with strong heterogeneity and low movable fluid content. The fractal dimension is weakly affected by pore structure parameters and mineral compositions. The movable fluid saturation is significantly affected by pore structure while weakly affected by mineral compositions. The relationship between heterogeneity and movable fluid distribution varies with reservoir types. The inhibition of heterogeneity on the movable fluid of different reservoirs is mainly reflected in various pores. Movable fluids controlled by throats are primarily distributed in different pores, resulting in diverse effects of heterogeneity on controlling the effect of different throats in various reservoirs. The findings of this research can help better understand the occurrence characteristics of the movable fluid in tight sandstone reservoirs with different fractal features.

Study on Pore Structure and the Microscopic Mechanism of the Difference in Petrophysical Properties of Tight Sandstone: A Case Study of the Chang 3 Member of Weibei Oilfield, Ordos Basin

Tight sandstone reservoirs have complex pore throat structures and poor and large differences in petrophysical properties. In this study, taking the Chang 3 Member of Weibei Oilfield, Ordos Basin, China as an example, the microscopic mechanism of the differences in petrophysical properties of tight sandstone reservoirs was systematically studied by thin section observation, scanning electron microscope, whole-rock X-ray diffraction, and high-pressure mercury intrusion experiments. The research results show that the reservoir types of the Chang 3 Member are mainly feldspar lithic sandstone and lithic feldspar sandstone; the pore types include intergranular, intragranular dissolution pores, and a small amount of residual intergranular pores. Taking the permeability of 0.3 × 10−3 and 0.5 × 10−3 μm2 as the boundary, we divided the samples involved in high-pressure mercury intrusion into three categories according to the permeability from high to low: Type I, Type II, and Type III. Their proportions were 31.4, 20.0, and 48.6%, respectively. The study found that the smaller the sorting coefficient, the poorer the petrophysical properties of the samples; the pore throat distribution of different samples gradually changed to a uniform double peak–dominated type. The permeability of tight sandstone reservoirs is contributed by a small part of pore throats with a large radius, while the reservoir space is mainly contributed by a large number of pores connected with small throats. The porosity is negatively and positively correlated with the median pressure and mercury injection tortuosity, respectively. In addition, the pore throat radius corresponding to the maximum permeability contribution rate, maximum pore throat radius, and sorting coefficient are all positively correlated with the permeability. In general, the areas with larger pore throat radius, lower pore throat tortuosity, and larger pore throat sorting coefficient can be regarded as favorable areas for Chang 3 tight sandstone reservoirs.

Quantitative Comparison of Genesis and Pore Structure Characteristics of Siliceous Minerals in Marine Shale With Different TOC Contents–A Case Study on the Shale of Lower Silurian Longmaxi Formation in Sichuan Basin, Southern China

China has abundant shale gas resources with great exploration potential, and stage progress has been made in this aspect. The sedimentary environment and reservoir characteristics are important aspects of the study on shale gas accumulation. Previous studies have mostly been carried out from a “qualitative” perspective, but not from a “quantitative” one. There is a lack of comparative studies on “marine shales with different TOC contents”. This paper takes the marine shale of the first member of the Longmaxi Formation (Long 1 Fm) in southern Sichuan Basin, Southern China, as the research object. The core samples were taken to carry out analyses (mineral composition analysis, TOC content analysis, porosity analysis) and experiments (carbon dioxide and nitrogen adsorption experiments, high-pressure mercury intrusion, FIB-SEM, and FIB-HIM experiments). The element logging data were collected to conduct the quantitative comparison of genesis and pore structure characteristics of siliceous minerals in marine shale with different TOC contents in this area. The conclusions are as follows: first, a formula is used to calculate and determine whether there is excessive silicon; then the Al-Fe-Mn triangle diagram is used to analyze the genesis of excessive silicon, so as to quantitatively analyze the genesis of siliceous minerals in shale: the siliceous minerals of organic shale (1% < TOC <2%) in the member studied are almost terrigenous detrital genesis; most siliceous minerals in organic-rich shale (TOC >2%) are detrital genesis, and a small part (0–20%) are biogenic. Carbon dioxide and nitrogen adsorption experiments, as well as high-pressure mercury intrusion experiments are adopted to quantitatively characterize the whole-aperture pore structure characteristics. The pore development characteristics of different shale components are analyzed by combing FIB-SEM and FIB-HIM experiments. The organic-bearing shales in the target section of this study area mainly develop clay mineral pores (71%), and are dominated by macro-pores (57.3%) with a low number of pores, irregular-shaped pores, as well as poor storage capacity and connectivity; the organic-rich shales in the target section of this study area mainly develop organic pores (51%), and are dominated by micro-pores (32.1%) and mesopores (54%) that are large in number and elliptical-shaped, with good storage capacity and good connectivity. The results of this study help to improve the understanding of the pore size of marine shales, the origin of siliceous minerals in marine shales, and the pore structure characteristics of marine shales, which are of great theoretical and practical significance for improving the theory of shale gas formation and guiding the selection of shale gas sweet spot.

Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

Abstract The Chang 7 Member shale of the Upper Triassic Yanchang formation in the Ordos basin is a hot spot in petroleum geology research. In this study, considering the Chang 7 shale in the Yan’an area as an example, the full-scale pore size characterization of lacustrine shale was realized based on the scanning electron microscopy image gray correction method, nitrogen and carbon dioxide adsorptions, and high-pressure mercury intrusion tests. In addition, the pore structures and oil-bearing properties of the Chang 7 shale were systematically studied. The results show that the Chang 7 shale is rich in organic matter, with an average total organic carbon value of 4.69% and an average R 0 value of 0.9%. It is in the mature-wet gas (crude oil-associated gas) stage. There are certain differences in the development characteristics and pore size distribution of different types of pores in shale. The statistical results showed that the pore diameters of the intergranular pores and intragranular dissolved pores were significantly larger than the intercrystalline pores of clay minerals and the organic pores. The organic pores in solid bitumen are extremely developed, whereas the organic pores in kerogen are relatively underdeveloped. The lower limit of the effective pore size of shale is 20 nm. The network system composed of inorganic pores-microcracks-organic matter-organic pores and siltstone laminae provides important channels and retention spaces for the migration of shale oil and gas within the source. This study found that the proportion of movable oil in sandy layers is relatively high, followed by shale with sandy laminae, whereas pure shale has the lowest proportion of movable oil. Therefore, the degree of sandy laminar development, the abundance of organic matter, and the degree of thermal evolution are the key geological factors that control the porosity and oil-bearing properties of shale oil reservoirs.

Classifications of the Reservoir Space of Tight Sandstone Based on Pore Structure, Connectivity, and Fractal Character: A Case Study from the Chang 7 Member of the Triassic Yanchang Formation in the Ordos Basin, China.

Pore structure characteristics of tight sandstones, including pore types, connectivity, and morphological features, provides a basis for selecting the “sweet spot” in tight sandstone reservoirs. A variety of research methods, high-pressure mercury intrusion porosimetry, cast thin sections, scanning electron microscopy, and fractal theory were integrated to explore these parameters of tight sandstones from the Chang 7 member of the Triassic Yanchang Formation in the Ordos Basin, China. Results indicate that tight sandstones are defined by three pore types with distinct fractal dimensions and corresponding pore structure, which are combined pores, isolated grain pores, and clay-dominated pores. The pore spaces of the three types gradually evolve from the microscale to the nanoscale. Combined pores were formed by dissolution pores connected to the surrounding pores and have been distinguished by their irregular shape. Their connected paths are multidirectional, resulting in better connectivity. Isolated grain pores have a small number of poorly connected paths, which causes weak connectivity. Clay-dominated pores have narrow and complex connected paths, resulting in poor connectivity. From the combined pore to the clay-dominated pore, the fractal dimensions of pore spaces decrease, indicating that the heterogeneity of pore spaces is gradually weakened whereas the heterogeneity of the flow characteristics is gradually enhanced. On the basis of the proportions of the three pore types, the tight sandstones can be genetically classified into a combined pore type, an isolated grain pore type, and a clay-dominated pore type. The differences in pore space and heterogeneity affect the distribution of tight oil; therefore, sand bodies located near the source rock, characterized by strong dissolution and dominated by the combined pore type, are favorable zones for tight sandstone reservoirs.

The pore-scale mechanisms of surfactant-assisted spontaneous and forced imbibition in water-wet tight oil reservoirs

The imbibition of water with surfactants, including spontaneous imbibition and forced imbibition, is of great significance for enhanced oil recovery (EOR) in tight sandstone reservoirs. Up to now, the migration behaviors of the water and the oil in pores of different sizes, as well as the mechanisms of both spontaneous imbibition and forced imbibition with different surfactants, have not been comprehensively addressed yet. This work first measured the oil-water interfacial tensions (IFTs) and the contact angles in oil-water-rock system with two types of surfactants, namely medium-IFT (0.1–10 mN/m) and low-IFT (0.001–0.1 mN/m) surfactants, at different concentrations to comprehend the functionalities of surfactants on oil recovery. Secondly, the pore size distributions of tight sandstones were determined by the high-pressure mercury intrusion (HPMI) and the nuclear magnetic resonance (NMR) technology to characterized the pores into three types (micropores, mesopores, and macropores) according to the pore sizes. Eventually, this work presented the oil recovery results in these three types of pores for spontaneous and forced imbibition using the two types of surfactants in water-wet tight core samples. Both spontaneous and forced imbibition results showed that the oil recoveries with surfactants were higher than those with brine, which was primarily attributed to the increased oil in the mesopores and the macropores. However, the addition of low-IFT surfactants apparently reduced the oil recovery in micropores, hence resulted in a lower oil recovery in comparison with the medium-IFT surfactants. It was also found that the oil in micropores contributed more than 50% of the oil recovery in the imbibition, except for the imbibition with low IFT, due to the high initial oil volume ratios in micropores; there could be a moderate IFT value (e.g., 0.1–1 mN/m) with the use of surfactants to obtain the highest oil recovery. Moreover, in comparison with the spontaneous imbibition, the forced imbibition could enhance the imbibition of water into the micropores but prevent the oil from being extracted from the mesopores and the macropores, which consequently led to a higher contribution of the micropores on oil recovery than that of the larger pores, especially the mesopores.

Semiquantitative microscopic pore characterizations of the metamorphic rock reservoir in the central paleo-uplift belt, Songliao Basin

Currently, metamorphic rock is a common target for natural gas exploration, and reservoirs are the key factors restricting natural gas exploration and development in metamorphic rocks. The deep metamorphic rock gas reservoir in the central paleo-uplift of the northern Songliao Basin has good exploration and development potential. In this study, we use a combination of qualitative descriptions and quantitative analysis to comprehensively analyze the pore characteristics of the reservoir and explore the factors controlling the pore characteristics of the metamorphic rock reservoir in the central paleo-uplift belt of the Songliao Basin. The metamorphic rock reservoir in the central paleo-uplift belt contains three types of lithologies: chlorite schist, mica schist and mylonite, each with different protoliths and metamorphic histories. The results of high-pressure mercury intrusion and nitrogen adsorption indicate that the pore size distributions of the schist and mylonite differ. Compared with the mylonite, the schist has larger reservoir space, more heterogeneity, smaller pore size, larger specific surface area and larger adsorbed gas storage capacity. This paper also studies the formation process of the reservoir and divides it into four stages. Finally, this article discusses in detail the factors controlling the microscopic pore characteristics of metamorphic rock reservoirs in the central paleo-uplift belt; the metamorphic rock protolith is the most important controlling factor.

Characterization of the Full-Sized Pore Structure and Controlling Factors of the Coal-Bearing Shale in the Wuxiang Block, South-Central Qinshui Basin, China

The characterization of the full-sized pore structure is important for the evaluation and prediction of the reservoir of shale gas with strong heterogeneity. It is of great scientific significance to explore the pore structure characteristics of overmature coal-bearing shale. Core descriptions, X-ray diffraction (XRD), vitrinite reflectance (Ro), field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion porosimetry (MIP), and low-pressure N2/CO2 gas adsorption (N2-/CO2-GA) experiments were performed on overmature coal-bearing shale samples from the Wuxiang block, south-central Qinshui Basin, China. The results show that the total organic carbon (TOC) ranged from 0.29 to 8.36%, with an average of 3.84%, and the organic matter (OM) is dominated by type III kerogen. The minerals in the shale primarily consist of clay (43–85.5%, averaging 52.1%) and quartz (12.6–61.2%, averaging 43.5%). The major clay minerals are illite-smectite (I/S) and illite, ranging from 22.5 to 55.6% (mean 41.4%) and 8.7–52.7% (mean 32%), respectively. FE-SEM images reveal that intraparticle pores (IntraP pores) and interparticle pores (InterP pores) are widely developed in clay minerals, and organic pores are occasionally present. Mesopores make the greatest contribution to the total pore volume (PV), and micropores are the major contributors to the specific surface area (SSA). Clays are the main controllers of micropore development. Mesopores developed in the clay mineral layers are promoted by I/S but inhibited by illite. Macropores and microfractures are mainly developed in clays and quartz and do not correlate significantly with the TOC, or mineral composition, due to the influence of compaction and cementation. The TOC and minerals affect pore structure characteristics mainly by influencing micropores.

Pore-fracture network alteration during forced and spontaneous imbibition processes in shale formation

Imbibition controls mass transfer in the complex pore-fracture network in shale, which may change the pore-fracture network and lead to a low efficient flowback of fracturing fluid. Thus, it is necessary to accurately characterize the pore-fracture network alteration during the imbibition process. In this study, forced and spontaneous imbibition tests were conducted under the confining pressure on selected shale core samples with induced fractures, collected from Longmaxi Formation, Sichuan Basin, China. The low-field nuclear magnetic resonance (NMR) spectrometer was employed to monitor the variation of pores and micro-fractures in the shale core samples during the dynamic imbibition process. In addition, optimal surface relaxivities, ranging from 0.019 to 0.033 μm/ms, were determined by comparing the NMR T2 distributions with the pore size distributions (PSDs) measured via high-pressure mercury intrusion (HPMI) tests. Then, the measured dynamic T2 spectra with three distinct peaks were converted into the corresponding PSDs to quantitatively analyze the number, size, and connectivity changes of small pores, large pores, and micro-fractures in shale. Results show that the total porosities of the four shale core samples are increased by 3.5%, 10.2%, 32.9%, and 36.3% after the imbibition tests. The forced imbibition leads to more remarkable improvements in the pore volume of large pores with radius between 0.2 and 3.6 μm. In contrast, the spontaneous imbibition results in more significant increases in the number and size of small pores with radius between 0.0004 and 0.36 μm. It is also found that the total porosity increment is primarily an outcome of small pore alteration during the imbibition. Moreover, the enlarged pores and micro-fractures are mainly categorized as the capillary bounded fluid pores and movable fluid pores, which significantly affect the efficiency of oil and gas transfer in shale. The findings of our study demonstrate the comprehensive effects of capillary force, clay hydration, osmotic potential, confining and pore pressures, and creep deformation and failure on the pore-fracture network alteration in shale and advance the understanding of the mechanisms behind the forced and spontaneous imbibition processes.

Pore throat characterization of bioturbated heterogeneous sandstone, Bhuj Formation, Kachchh India: An integrated analysis using NMR and HPMI studies

Nuclear magnetic resonance (NMR) relaxometry and high-pressure mercury intrusion (HPMI) are substantially utilized techniques to characterize the inherent heterogeneity of reservoirs. Bioturbation is one such type of microscale heterogeneity that provides challenges to optimal recovery planning and volumetric estimation of hydrocarbon reserves. A comprehensive approach is determined by acknowledging the applicability and limitation of each method. Due to the wide variation in petrophysical properties resulting from the effect of bioturbation, the sample size ranges from mm to cm; hence, a proper methodology needs to be formulated. The present study extends the available method of generating pseudo Pc curves from NMR studies to analyze the effect of multiscale bioturbation heterogeneity. The samples were chosen from two different classes on a bioturbation scale referred to as the bioturbation index (BI) ranging from 0 to 6, 0 being 0% bioturbation and 6 meaning 100% bioturbation. The results indicate that lower BI samples had unimodal behavior, while the higher BI sample had bimodal characteristics in pore network distribution. Increased anisotropy was evident in the higher BI samples, and the HPMI study revealed a contrasting nature of pore throat connectivity with a lower threshold and displacement pressure and an increased median throat diameter in the bioturbated part compared with the nonbioturbated. The bioturbated volume essentially had better and less tortuous pore throat connectivity. The effects of bioturbation were identifiable in a core-scale study using NMR. The bimodal characteristic behavior with two distinct pore throat classes with the larger throat class as dominant claims the bioturbation-assisted pore throat connectivity established in them. The purpose of the paper is to investigate pore throat distribution in bioturbated or heterogeneous reservoirs by integrating NMR and HPMI methods. This study proposes a method that can correlate NMR responses from logging into pore throat distribution in bioturbated zones of the reservoir.

The upper and lower limits and grading evaluation of the Shahezi tight gas reservoirs in the Xujiaweizi Rift, northern Songliao Basin: Implications from microscopic pore structures

The upper and lower limits and grading evaluation scheme of tight gas reservoirs (TGRs) at a microscopic pore structure level were explored by conducting high-pressure mercury intrusion porosimetry (HMIP), rate-controlled mercury intrusion porosimetry, nuclear magnetic resonance (NMR), and wettability experiments on tight rock samples from the Lower Cretaceous Shahezi (SHZ) Formation in the Xujiaweizi Rift, northern Songliao Basin. The results showed that the upper throat radius limit of the SHZ TGRs corresponds to 1.86 μm, derived from the microscopic equilibrium state of buoyance and capillary forces. The above value is closely related to several geological factors, including a pore-to-throat radius ratio, the density difference between formation water and gas, formation dip angle, gas–water interfacial tension, and wettability. The SHZ Formation enters a tight reservoir stage when the burial depth is deeper than 3460 m. A new method integrating HMIP and NMR experiments was proposed to estimate the thickness of the adsorbed water film with a value of ∼21.56 nm. The theoretical lower throat radius limit of the SHZ TGRs was determined as ∼22 nm, considering the individual methane dimension. Natural gas can be scarcely injected into tight reservoirs below the theoretical lower limit, serving as theoretically invalid tight reservoirs in the study area. From the configuration relationship between pores and throats, two TGR types were identified in the SHZ Formation (types I and II). Type-I TGRs are characterized by relatively excellent seepage capacity, with the maximum connected throat radius and permeability of 0.4 μm–1.86 μm and (0.015–0.27) × 10−3 μm2, respectively, and their storage space mainly comprises abundant dissolution and residual intergranular pores. Furthermore, an adequate storage space (3.6% to more than 12%) and an appropriate burial depth (<5000 m) promote type-I TGRs to be the most favorable targets for current SHZ tight gas accumulation development in the Xujiaweizi Rift.

Investigation on pore structure characteristics of ultra-tight sandstone reservoirs in the upper Triassic Xujiahe Formation of the northern Sichuan Basin, China

Pore structure is the key factor to control the quality and fluid flow of ultra-tight reservoir. The relationship between rock types, pore types, and pore sizes of ultra-tight sandstone reservoirs was identified by observing microscopic characteristics under a polarizing microscope and scanning electron microscope (SEM) and quantitively assessed using high-pressure mercury intrusion (HPMI) and fractal theory. By a comparative analysis of lithic sandstone and feldspar lithic sandstone reservoirs of Upper Triassic Xujiahe Formation of the Northern Sichuan Basin, we found that the pore type of the ultra-tight sandstone reservoir was linked to the rock type. Argillaceous lithic sandstone minly generates fracture pores, while fine-grained lithic sandstone and feldspar lithic sandstone formed dissolved pores by dissolution of carbonate cement, rock debris, and feldspar particles. Meanwhile, clay minerals such as kaolinite and chlorite in the reservoir possess pores between clay platelets and intraplatelet pores within clay aggregates, which are important pore types for ultra–tight sandstone reservoirs. A method to divided intervals of pore size distribution was proposed using high-pressure mercury intrusion (HPMI), and three intervals of pore diameter distribution were observed: 10–40 nm, 40 nm–1 μm, and 1–100 μm, which is largely controlled by pore type. The reservoir with only fracture pores is a one–interval reservoir with pore diameter in the range of 1–100 μm, while the reservoirs with dissolved pores and clay mineral-related pores have the above three intervals. Meanwhile, the fractal of pores in different scale range is different, and the larger the pore size, the stronger is the reservoir heterogeneity. A treelike pore structure model can be utilized to define pore development features in ultra–tight sandstone reservoirs. Micron–scale pores with diameters of 1–100 μm is mostly made up of fractures, cement and particle dissolution pores. However, nano–scale pores in the range of 40 nm–1 μm and 10–40 nm are predominantly pores formed between clay platelets and intraplatelet pores within clay aggregates, respectively.

FRACTAL ANALYSIS OF HYDRATE SEDIMENT USING HIGH-PRESSURE MERCURY INTRUSION AND LOW-TEMPERATURE NITROGEN ADSORPTION

FRACTAL ANALYSIS OF HYDRATE SEDIMENT USING HIGH-PRESSURE MERCURY INTRUSION AND LOW-TEMPERATURE NITROGEN ADSORPTION

Multiscale pore structure characterization of an ultra-deep carbonate gas reservoir

The pore structures of shallow and mid-deep carbonate gas reservoirs have been well explored. Totally different from these reservoirs, however, the pore structure of a target ultra-deep carbonate gas reservoir, the Qixia Reservoir in the Shuangyushi play is still unknown. Affected by tectonic movement and deep hydrothermal transformation, the lithology of this target reservoir has significantly changed and it has developed different scales of pores and fractures. Thus, a multiscale micro-CT (computed tomography) method is needed to combine different scales of its pore space to evaluate carbonate samples more realistically. In this study, the multiscale micro-CT method and other traditional methods including X-ray diffraction (XRD), casting thin section, scanning electron microscope (SEM), routine petrophysical measurements (RPM), and high-pressure mercury intrusion (HPMI) are first combined to quantitatively describe a distribution of multi-scale pores, throats, and fractures in the target ultra-deep carbonate gas reservoir. The results showed that micro pores (70%–90%), micro throats (>90%), and micro fractures (>90%) dominated in this reservoir. Dolomite accounted for more than 90% of the rock mineral composition in the Qixia reservoir with few clay minerals. Intercrystalline pores and micro fractures were the main pore types and the mean reservoir porosity was less than 2%. Micro fractures play a great role in improving reservoir permeability. The HPMI method presented with errors in the classification of ultra-deep carbonate reservoir types owing to the development of vugs, large pores, and fractures. In this study, a new classification method was proposed to classify this type of reservoirs based on porosity, permeability, and the studied parameters from the multiscale micro-CT method such as throat number and connected porosity proportion. The target reservoir was divided into the following four categories according to the new classification method: fracture macropore type (FMA), macropore type (MA), fracture micropore type (FMI), and micropore type (MI). According to the results of multiscale CT scanning, a strong linear relationship was observed between the number of throats, the connected porosity, and the permeability of the ultra-deep carbonate rock samples studied. Fractures improved the permeability of rock samples by aiding the connection of isolated pores and the expansion of the number of throats. Therefore, the MA and MI types of reservoirs should be properly fractured to increase their productivity.

Comparative Study of Pore Structure Characteristics between Mudstone and Coal under Different Particle Size Conditions

In order to investigate the difference of pore structure characteristics between mudstone and coal under different particle size conditions, samples acquired from Henan province were smashed and screened into three different particle sizes (20–40, 80–100, and &gt;200 mesh) to conduct the experiments, using the high-pressure mercury intrusion porosimetry (MIP) and low-temperature N2 adsorption (LT-N2A) techniques. The results demonstrated that the proportion of open pores or semi-enclosed pores increased, and the pores became preferable contacted each other for both mudstone and coal during the crushing process. These variations of pore structure characteristics in the coal were beneficial to methane storage and migration. The total specific surface areas and pore volumes all showed a tendency of increasing continually for both mudstone and coal, as the particle sizes decreased from the LT-N2A test. The mudstone and coal were non-rigid aggregates with micropores, plate-shaped pores, and slit-shaped pores developed inside. The effect of the crushing process on the pore shape for the mudstone and coal was inappreciable. Moreover, the influence of the particle sizes on the mesopore was the most significant, followed by the macropore; and on the micropore, the influence was negligible for both mudstone and coal. The crushing process only had a significant impact on the pore structure of mudstone with a particle size of less than 100 mesh, while it could still alter the pore structure of coal with a particle size of larger than 100 mesh. It is believed that this work has a significant meaning to explore the diffusion and migration rules of coal-bed methane in coal.

The occurrence of tight oil in the Chang 8 lacustrine sandstone of the Huaqing area, Ordos Basin, China: Insights into the content of adsorbed oil and its controlling factors

Tight oil is a great potential resource for unconventional oil exploration and development. Determining the content of adsorbed tight oil in sandstone reservoirs and the factors controlling its content is crucial for the evaluation and development of tight oil resources. Using fluorescence petrography, environmental scanning electron microscopy, porosity as well as permeability analyses, high-pressure mercury intrusion, and nuclear magnetic resonance imaging, the present study analyzed the occurrence form, location, and relative content of free and adsorbed tight oils and effect of controlling factors on the content of adsorbed tight oil in sandstone reservoirs of the Chang 8 member in the Huaqing area of the Ordos Basin. The free tight oil mainly exists in residual intergranular, intergranular dissolved, intragranular dissolved, and dissolution-enlarged pores as well as some throats in the form of flakes with various areas and slender strips. The adsorbed tight oil mainly occurs on the surfaces of the mineral particles and mica fragments as well as in fractures, some throats or the intragranular as well as intergranular dissolved pores in the form of films with variable thicknesses and long strips. The lower limit of the pore radius at which free tight oil occurs in sandstone is approximately 0.1 μm and the adsorbed tight oil occurs on the surface of mineral particles and in spaces with pore radii of 0.02–0.3 μm. The contribution of free tight oil to total tight oil in the present study has highest and lowest content of 60.95% and 32.48%, respectively, with an average content of 50.14%. The contribution of adsorbed tight oil to total tight oil has highest and lowest content of 67.52% and 39.05%, respectively, with an average content of 49.86%. The content of adsorbed tight oil is generally proportional to the median pressure and inversely proportional to the porosity as well as permeability of the reservoir; particularly, porosity is relevant. The content of adsorbed tight oil is inversely proportional to the quartz content and directly proportional to the feldspar, carbonate cement, and clay mineral content of the sandstone.

Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs

Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), high-pressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (Sapex), the ratio of the maximum pore-throat radius and the medium pore-throat radius (Rmax/R50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.

Favorable lithofacies types and genesis of marine-continental transitional black shale: A case study of Permian Shanxi Formation in the eastern margin of Ordos Basin, NW China

Based on core description, thin section identification, X-ray diffraction analysis, scanning electron microscopy, low-temperature gas adsorption and high-pressure mercury intrusion porosimetry, the shale lithofacies of Shan23 sub-member of Permian Shanxi Formation in the east margin of Ordos Basin was systematically analyzed in this study. The Shan23 sub-member has six lithofacies, namely, low TOC clay shale (C-L), low TOC siliceous shale (S-L), medium TOC siliceous shale (S-M), medium TOC hybrid shale (M-M), high TOC siliceous shale (S-H), and high TOC clay shale (C-H). Among them, S-H is the best lithofacies, S-M and M-M are the second best. The C-L and C-H lithofacies, mainly found in the upper part of Shan23 sub-member, generally developed in tide-dominated delta facies; the S-L, S-M, S-H and M-M shales occurring in the lower part of Shan23 sub-member developed in tide-dominated estuarine bay facies. The S-H, S-M and M-M shales have good pore structure and largely organic matter pores and mineral interparticle pores, including interlayer pore in clay minerals, pyrite intercrystalline pore, and mineral dissolution pore. C-L and S-L shales have mainly mineral interparticle pores and clay mineral interlayer pores, and a small amount of organic matter pores, showing poorer pore structure. The C-H shale has organic micro-pores and a small number of interlayer fissures of clay minerals, showing good micro-pore structure, and poor meso-pore and macro-pore structure. The formation of favorable lithofacies is jointly controlled by depositional environment and diagenesis. Shallow bay-lagoon depositional environment is conducive to the formation of type II2 kerogen which can produce a large number of organic cellular pores. Besides, the rich biogenic silica is conducive to the preservation of primary pores and enhances the fracability of the shale reservoir.