Reservoir Pore Structure Research Articles

Pore‐Fracture Distribution Heterogeneity of Shale Reservoirs Determined by using HPMI and LPN2 GA Tests

AbstractThe compressibility of shale matrix reflects the effects of reservoir lithology, material composition, pore structure and tectonic deformation. It is important to understand the factors that influence shale matrix compressibility (SMC) and their effects on pore size distribution (PSD) heterogeneity in order to evaluate the properties of unconventional reservoirs. In this study, the volumes of pores whose diameters were in the range 6–100 nm were corrected for SMC for 17 shale samples from basins in China using high‐pressure mercury intrusion and low‐temperature nitrogen gas adsorption analyses, in order to investigate the factors influencing the SMC values. In addition, the variations in fractal dimensions before and after pore volume correction were determined, using single and multifractal models to explain the effects of SMC on PSD heterogeneity. In this process, the applicability of each fractal model for characterizing PSD heterogeneity was determined using statistical analyses. The Menger and Sierpinski single fractal models, the thermodynamic fractal model and a multi‐fractal model were all used in this study. The results showed the following. The matrix compression restricts the segmentation of the fractal dimension curves for the single fractal Menger and Sierpinski models, which leads to a uniformity of PSD heterogeneity for different pore diameters. However, matrix compression has only a weak influence on the results calculated using a thermodynamic model. The SMC clearly affects the multifractal value variations, showing that the fractal dimension values of shale samples under matrix compression are small. Overall PSD heterogeneity becomes small for pores with diameters below 100 nm and the SMC primarily affects the PSD heterogeneity of higher pore volume areas. The comparison of fractal curves before and after correction and the variance analysis indicate that the thermodynamic model is applicable to quantitatively characterize PSD heterogeneity of shale collected from this sampling area. The results show that PSD heterogeneity increases gradually as micro‐pore volumes increase.

Characterization and Evaluation of Carbonate Reservoir Pore Structure Based on Machine Learning

The carboniferous carbonate reservoirs in the North Truva Oilfield have undergone complex sedimentation, diagenesis and tectonic transformation. Various reservoir spaces of pores, caves and fractures, with strong reservoir heterogeneity and diverse pore structures, have been developed. As a result, a quantitative description of the pore structure is difficult, and the accuracy of logging identification and prediction is low. These pose a lot of challenges to reservoir classification and evaluation as well as efficient development of the reservoirs. This study is based on the analysis of core, thin section, scanning electron microscope, high-pressure mercury injection and other data. Six types of petrophysical facies, PG1, PG2, PG3, PG4, PG5, and PG6, were divided according to the displacement pressure, mercury removal efficiency, and median pore-throat radius isobaric mercury parameters, combined with the shape of the capillary pressure curve. The petrophysical facies of the wells with mercury injection data were divided accordingly, and then the machine learning method was applied. The petrophysical facies division results of two mercury injection wells were used as training samples. The artificial neural network (ANN) method was applied to establish a training model of petrophysical facies recognition. Subsequently, the prediction for the petrophysical facies of each well in the oilfield was carried out, and the petrophysical facies division results of other mercury injection wells were applied to verify the prediction. The results show that the overall coincidence rate for identifying petrophysical facies is as high as 89.3%, which can be used for high-precision identification and prediction of petrophysical facies in non-coring wells.

Experimental evaluation of microscopic pore structure and fluid migration characteristics of coal-measure sandstone reservoirs

Research on the microscopic migration characteristics of fluids in coal measure sandstone has always been a hot spot in the evaluation of reservoir properties. In this study, taking the Yan’an Formation sandstone reservoirs in the Block A of the Ordos Basin as an example, the pore structures and fluid migration characteristics of coal-measure sandstones are systematically studied using a large number of thin sections, SEM (Scanning Electron Microscope), NMR (Nuclear Magnetic Resonance), relative permeability and water-flooding test results. The results show that the Jurassic sandstones in the target layer mainly develop lithic quartz sandstone, and the main pore types are intergranular and dissolution pores, followed by a small amount of intercrystalline pores. The surface porosity of the target sandstones mainly ranges from 7.90 to 10.79%, with an average value of 8.78%. The good correlation between porosity and permeability indicates that the target layer is a pore-type reservoir. The T2 relaxation time of the target layer is mainly distributed within 100 ms. Moreover, the reservoir of the Yan’an Formation has a high saturation of movable fluids, which is mainly distributed in 43.17–71.24%, with an average value of 56.90%. Meanwhile, samples with fractures have higher movable fluid saturations. In addition, the average irreducible water saturation of the Yan’an Formation sandstone reservoir is 35.14%, and the final oil displacement efficiency is 51.14% on average. There is a good positive correlation between the oil displacement efficiency and the co-permeability zone. As the co-permeability zone range increased from 15 to 55%, the oil displacement efficiency increased from 30 to 65%. When the cores develop fractures, they have characteristics of high permeability, high oil recovery rate, high oil displacement efficiency in the anhydrous period, low irreducible water saturation and low residual oil saturation.

Fractal Characteristics of Deep Shales in Southern China by Small-Angle Neutron Scattering and Low-Pressure Nitrogen Adsorption

The occurrence and flow of shale gas are substantially impacted by nanopore structures. The fractal dimension provides a new way to explore the pore structures of shale reservoirs. In this study, eight deep shale samples from Longmaxi Formation to Wufeng Formation in Southern Sichuan were selected to perform a series of analysis tests, which consisted of small-angle neutron scattering, low-pressure nitrogen adsorption, XRD diffraction, and large-scale scanning electron microscopy splicing. The elements that influence the shale fractal dimension were discussed from two levels of mineral composition and pore structures, and the relationship between the mass fractal dimension and surface fractal dimension was focused on during a comparative analysis. The results revealed that the deep shale samples both had mass fractal characteristics and surface fractal characteristics. The mass fractal dimension ranged from 2.499 to 2.991, whereas the surface fractal dimension ranged from 2.814 to 2.831. The mass fractal dimension was negatively correlated with the surface fractal dimension. The mass fractal dimension and the surface fractal dimension are controlled by organic matter pores, and their development degree significantly affects the fractal dimension. The mass fractal dimension increases with the decrease of a specific surface area and pore volume and increases with the increase of the average pore diameter. The permeability and surface fractal dimension are negatively correlated, but no significant correlation exists between the permeability and mass fractal dimension, and the internal reason is the dual control effect of organic matter on shale pores. This study comprehensively analyses the mass fractal characteristics and surface fractal characteristics, which helps in a better understanding of the pore structure and development characteristics of shale gas reservoirs.

NMRI online observation of coal fracture and pore structure evolution under confining pressure and axial compressive loads: A novel approach

Quantitative characterization of the spatial distribution, content and heterogeneity of fracture and pore structure (FPS) in coal reservoirs under confining pressures and axial compressive loads is significant for the engineering of coal bed methane. A novel online observation approach that combines nuclear magnetic resonance imaging with triaxial loading techniques is employed to achieve the visualization and full-scale quantitative characterization of the evolution of FPS in coals in the laboratory. The relationship between the stress states and FPS evolution was formulated. The results show that the spatial distribution of the FPS evolution process of coal samples can be divided into four stages: initial pore and fracture compaction closure, pore and fracture stable growth, pore and fracture unstable growth, and failure stages. As the deviatoric stress increases, the content of the adsorption pores, the heterogeneity of the adsorption space, and the gas adsorption capacity of coal samples gradually increase. In contrast, the seepage pore and fracture content as well as the permeability of coal samples decrease first and then increase. The heterogeneity of the seepage space of coal samples initially increases and then decreases. The maximum compression of seepage space and increase of adsorption space are 4.742% and 14.743%, respectively.

Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T2 Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

The classification of tight sandstone reservoirs is of significance for hydrocarbon exploration and production. Different from conventional reservoirs, tight sandstone reservoirs are characterized by a complex pore structure and strong heterogeneity. Tight sandstone reservoir classification may not be reliable with conventional reservoir classification methods. In this paper, a classification method of tight sandstone reservoirs was proposed on the basis of the nuclear magnetic resonance (NMR) transverse relaxation (T2) distribution, and it was employed for reservoir classification on the Shaximiao Formation in central Sichuan, China. As a result of the complex pore structure of a tight sandstone reservoir, the NMR T2 distribution is characterized by the presence of multiple peaks. Therefore, the three-peak Gaussian function was used to fit the T2 distribution and obtain the characteristic parameters. On the basis of high-pressure mercury intrusion (HPMI) experiments, the correlation between the characteristic parameters of the NMR T2 distribution and pore structure parameters and petrophysical properties was analyzed, and then the optimal characteristic parameters of the NMR T2 distribution were selected according to the results of correlation analysis and used to establish the pore structure index. In combination of petrophysical properties with the pore structure index, the model for classification of tight sandstone reservoirs was established by the naive Bayesian method based on hierarchical clustering, and the accuracy of the model was verified by k-fold cross-validation. Finally, the effectiveness of the proposed method was verified using the actual NMR logging data in conjunction with the oil test data. The results showed that the method for classification of tight sandstone reservoirs based on the NMR T2 distribution can provide effective guidance for production capacity evaluation.

Study of Fractal and Multifractal Features of Pore Structure in Tight Sandstone Reservoirs of the Permian Lucaogou Formation, Jimsar Sag, Junggar Basin, Northwest China.

The primary factor impacting the tight sandstone reservoirs and fluid flow capacity represents the pore-throat structure. On the basis of petrophysical characteristics test, scanning electron microscopy (SEM), and casting thin-section examination of tight sandstone reservoir specimens from the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin., the full-size pore-throat parameters and distribution characteristics were determined by constant-rate mercury injection (CRMI) analysis. Using fractal theory and multifractal theory, the pore architectures of sandstone pores are analyzed. Mercury intrusion capillary pressure (MICP) is used to compute the dimensions of fractals using various fractal models and multifractal characteristics. Analysis is done on the relationships between tight sandstone pore architectures and fractal and multifractal characteristics. According to the research, a network of tightly packed sandstone pores may be assessed using the dimensions of fractals computed from a 3D capillary model. When displacement pressure is increased, the dimensions of fractals rise; when permeability, pore-throat diameter, and variable coefficient are increased, it falls. Tight sandstone pores exhibit multifractal features, according to the multifractal analysis, and multifractal parameters may depict the size, concentration, and asymmetry of the pore size distribution (PSD). Sandstone’s PSD is comparable when its multifractal parameters (Δα, Δf, α0, α1, α2) are identical. Pore diameters of tight sandstone are positively connected with information dimensions D1 and correlation dimensions D2, and information dimensions D1 have a greater impact on PSD than correlation dimensions D2. Additionally, the 3D capillary model’s dimensions of fractals and D1 exhibit a substantial negative association. These findings play a significant guiding role in the quantitative characterization of unconventional reservoir pore structures. The multifractal technique is effective to define the heterogeneity of the sandstone pore system and to differentiate between distinct PSD in heterogeneity.

Understanding stress-sensitive behavior of pore structure in tight sandstone reservoirs under cyclic compression using mineral, morphology, and stress analyses

Tight sandstone reservoirs have excellent potential as oil and gas exploration fields. During exploitation, drilling upsets the stress balance of the reservoir. The top priority is studying the stress state in subsequent hydraulic fracturing and production operations. This study selected the samples of the Lower Shihezi Formation in Ordos Basin as research target, and investigated the stress sensitivity of tight sandstones based on casting thin sections (CTS), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and X-ray diffraction analysis (XRD). The results show that the fluctuation of permeability is larger than that of the porosity under the cyclic effective stress. Pore types can be divided into fracture-like, irregular oval, spherical arches, and triangle pores. Non-homogeneous deformation of microscopic structures and minerals eventually leads to permeability evolution. Overall, this study proposes novel pore models and throat types and provides insight into the stress sensitivity of tight sandstone reservoirs. A comprehensive analysis of stress sensitivity control factors for tight sandstones was then performed considering the combined effect of mineral components, microscopic morphology, and mechanical stability. However, we acknowledge that laboratory stress sensitivity evaluation generally does not completely represent the field-scale stress sensitivity. Therefore, the sample preparation and experimental conditions and process need to simulate in situ formation conditions as comprehensively as possible in future studies.

Study on Micro-Nano Pore Characteristics and Classification of Tight Sandstone Reservoir Based on Q-Cluster

To realize the quantitative classification and comprehensive evaluation of the tight oil reservoir in the 4th of Quantou Formation in Songliao Basin, the pore structure of tight oil reservoir was quantitatively analyzed. In this study, experiments based on the constant-speed mercury injection, nuclear magnetic resonance, and micron CT are based on the observation of cast thin sections, and scanning electron microscope is conducted. The result shows that a tight oil reservoir space is mainly composed of the intergranular dissolved pore, residual intergranular pore, and intragranular dissolve pore. There are few intercrystalline pore and fracture at the same time. The average pore radius is 1.28~4.58 μm, and the average throat radius is 0.52~1.27 μm. Hence, there is a typical micro-nano throat combination with micropores. The pore throat composition and pore structure of reservoirs differ in reservoir with different physical properties. The reservoir quality depends on pore structure especially the throat radius. And the microthroat is a critical factor for permeability. Based on Q-cluster analysis, tight oil reservoirs are classified into three types. The analysis was based on the data such as max throat radius, average throat radius, displacement pressure, median pressure, and permeability. Finally, the reservoirs in the study area are mainly II and I types.

Rock thin-section analysis and identification based on artificial intelligent technique

Rock thin-section identification is an indispensable geological exploration tool for understanding and recognizing the composition of the earth. It is also an important evaluation method for oil and gas exploration and development. It can be used to identify the petrological characteristics of reservoirs, determine the type of diagenesis, and distinguish the characteristics of reservoir space and pore structure. It is necessary to understand the physical properties and sedimentary environment of the reservoir, obtain the relevant parameters of the reservoir, formulate the oil and gas development plan, and reserve calculation. The traditional thin-section identification method has a history of more than one hundred years, which mainly depends on the geological experts' visual observation with the optical microscope, and is bothered by the problems of strong subjectivity, high dependence on experience, heavy workload, long identification cycle, and incapability to achieve complete and accurate quantification. In this paper, the models of particle segmentation, mineralogy identification, and pore type intelligent identification are constructed by using deep learning, computer vision, and other technologies, and the intelligent thin-section identification is realized. This paper overcomes the problem of multi-target recognition in the image sequence, constructs a fine-grained classification network under the multi-mode and multi-light source, and proposes a modeling scheme of data annotation while building models, forming a scientific, quantitative and efficient slice identification method. The experimental results and practical application results show that the thin-section intelligent identification technology proposed in this paper does not only greatly improves the identification efficiency, but also realizes the intuitive, accurate and quantitative identification results, which is a subversive innovation and change to the traditional thin-section identification practice.

Experimental study on sand control gravel particle gradation optimization in mud hydrate reservoir

Sand production significantly influences the safety and stability of gas hydrate exploitation in reservoirs with high mud content. Gravel packing is an effective method for sand control. The median grain size ratio (D50/d50) values and fine particle content of gravel pack are important factors in sand control during natural gas hydrate exploitation. This paper focuses on the sand blocking effect and permeability characteristics of different grades of gravel. The sand retention test was carried out on four samples with different ratios. The optimal D50/d50 value and fine particle content for gas hydrate production were obtained. A laser particle size analyzer and geotechnical test found the reservoir and gravel layer pore structure change. The results show that the optimal GSR was 24.5, and the optimal fine particle content was about 38%. The permeability decline of the gravel layer occurs in the early stage of production, and the fine particles in the gravel will slow down the degree of seepage damage. For gravel with the same particle size range and different median particle sizes, it has little effect on sand control accuracy but mainly on permeability. The research in this paper can provide a reference for selecting sand control gravel for natural gas exploitation in marine areas.

Pore Structure Characteristics, Genesis, and Its Controlling Effect on Gas Migration of Quaternary Mudstone Reservoir in Qaidam Basin

The Sanhu Depression in Qaidam Basin is the largest Quaternary biogenic gas exploration area with the shallowest burial depth in the world. The shallow high abundance of gas reservoirs and high-quality pure methane have become the main production areas. The development characteristics of loose mudstone reservoirs are restricted by extreme heterogeneity. Therefore, the Quaternary Qigequan Formation mudstone in Qaidam Basin is selected as the research object. Based on the study of the sedimentary background, petrological characteristics, and pore structure characteristics, by comparing the characteristics of different mudstone reservoirs, the controlling factors of the development of different mudstone reservoirs and the control of gas migration are clarified. Research shows the following: (1) The mudstone reservoirs of the Qigequan Formation mainly develop intergranular pores, clay mineral pores, and intragranular pores. The pore size distribution varies from nanometers to micrometers, and mesopores mainly contribute to the specific surface area. (2) Rigid minerals and clay minerals are the main controlling factors for the pore structure of mudstone reservoirs. The increase in the content of rigid minerals is conducive to the development of macropores or larger micropores, while the increase in the content of clay minerals is conducive to the development of mesopores and provides an important specific surface area for gas adsorption. (3) The gas migration form of pure mudstone is mainly dominated by Fick diffusion and slippage flow, which has the characteristics of self-sealing accumulation. The gas migration form of silty mudstone is the coexistence of Fick diffusion, slippage flow, and Darcy flow, which has the features of self-sealing and Darcy flow accumulation. The gas migration form of sandy mudstone is mainly Darcy flow, only with Darcy flow accumulation characteristics. The flow form of gas creates different accumulation modes of mudstone biogas. The Quaternary mudstone reservoir shows different particularity under different material components, and the exploration targets should be treated differently according to specific mudstone types.

Multi-Scale Pore Structure Characterization of Silurian Marine Shale and Its Coupling Relationship With Material Composition: A Case Study in the Northern Guizhou Area

Investigation of pore structure is vital for shale reservoir evaluation and also “sweet spot” prediction. As the strong heterogeneity in pore types, morphology, and size distributions of organic matter-rich shales, it is essential to combine different approaches to comprehensively characterize them.Field emission-scanning electron microscopy (FE-SEM), low-pressure gas (CO2 and N2) adsorption, and high-pressure mercury intrusion (HPMI) were employed to systematically investigate the pore structure of the lower Longmaxi shale reservoirs in the northern Guizhou area. The results show that the shales can be divided into four lithofacies based on mineral composition, namely, siliceous shale (SS), clay shale (CS), carbonate shale (CAS), and mixed shale (MS), among which siliceous shale is the primary lithofacies of the Longmaxi shale. Numerous organic matter (OM)-hosted pores, clay interlayer pores, interparticle pores, and intraparticle pores were identified within shale reservoirs. The specific surface area ranges from 11.3 to 27.4 m2/g, with an average of 18.1 m2/g. It exhibits a strong positive correlation with TOC contents, suggesting that organic matter is the major contributor to the specific surface areas. A wide range of pore size distribution was measured by integration of gas adsorption and HPMI. It is shown that the pore size is primarily distributed within ∼100 nm, corresponding to micropores, mesopores, and part of macropores. The total pore volume, which is mostly derived from the contribution of micropores and mesopores, remains within a range of 0.11 to 0.025 ml/g, with an average of 0.018 ml/g. Furthermore, the volume of micropores and mesopores is mainly controlled by organic matter contents. The dissolution pore contributes most to the macropore space within shale reservoirs, based on the positive correlation with macropore volume and easily dissolved minerals, including carbonate and feldspar. Also, the total pores volume is mainly dominated by organic matter and carbonate contents. This is possibly attributed to the easily dissolved and rigid features of carbonate, which can protect the primary interparticle pores due to its high compression resistance and is conducive to forming abundant dissolution pores. OM-rich carbonate-bearing mixed shale may be the most favorable lithofacies for gas storage in the northern Guizhou area.

Research on Micro-Pore Structure and 3D Visual Characterization of Inter-Salt Shale Based on X-CT Imaging Digital Core Technology

Pore structure is the key factor affecting reservoir accumulation and enrichment behavior. Due to the complex mineral components and pore structure of shale oil reservoirs and strong heterogeneity, it is necessary to explore the micro-pore structure characteristics of inter-salt shale. In this study, in order to qualitatively and quantitatively analyze the pore structure of inter-salt shale reservoirs, as well as evaluate the mineral composition and its spatial distribution characteristics, three shale samples from the 10th cyclothem of the Eq3 (Eq34–10 cyclothem) inter-salt shale were selected to acquire 2D and 3D grayscale images by modular automated processing system (MAPS) and X-ray micro-computed tomography (Micro-CT), respectively. The color map of the inlaid characteristics of mineral aggregates was established by Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN), and different mineral types in the grayscale image were determined. After that, the digital core technology was used to reconstruct the core in 3D, and the maximum sphere method was used to extract the pore network model, so as to realize the quantification of micron pore throats and the 3D visualization of inter-shale samples. Meanwhile, in order to compare the fractal characteristics of the pores of the samples, the two-dimensional and three-dimensional fractal dimensions of the three cores were calculated by combining the digital core technique with fractal theory. The study yielded several notable results: the pore structure of inter-salt shale reservoirs is complex and multi-scale, and the CT scanning digital core technology can effectively realize 3D visualization of rock microstructure without damage. The pore types of rock samples are mainly intergranular pores, interparticle pores, and dissolved pores, and the minerals are mainly dolomite, calcite, and glauberite. The micron pore throat radius of the rock sample is 0.5–13.9 μm, the distribution of coordination number is mainly in the range of 1–4, and the shape of the pore throat is mainly triangular and square. The pore space of inter-salt shale has suitable fractal characteristics, and the three-dimensional fractal dimension of the three cores is in the range of 2.41–2.49. In sum, this work used digital core technology to study the microscopic pore structure of inter-salt shale oil, establishing a basis for further understanding of the seepage characteristics and exploration and development of shale oil.

Fluid space reformation law of liquid nitrogen fracturing coal based on NMR T1–T2 spectra and inspiration for coalbed methane production

The low porosity and permeability characteristics of coal seams have become the main bottleneck restricting high-efficiency extraction of coalbed methane. At present, enhanced fracturing and permeability enhancement technologies are often used to transform the pore structure of coal reservoirs, aiming to improve the permeability of coal bodies. In order to study the evolution law of coal pore and pore fluid occurrence space under the action of liquid nitrogen (LN2) cold shock, this paper takes lignite in saturated and centrifugal state as the research object. After freezing and thawing of LN2, the coal samples were tested by nuclear magnetic resonance. Through the T1-T2 spectrum and 3D peak map, the change process of coal pore fluid occurrence space was quantitatively characterized, and the change of T2 distribution and T2 spectrum area was used to reflect the coal pore evolution process. The results shows that after the same coal sample is frozen for 5, 50, and 150 min, the free water storage space expands by 86.7%, 101.4%, and 120.1%, respectively, the effective porosity ratios are 62.5%, 66.7%, and 80.4%, respectively, 5, 15, and 25 cycles after freeze–thaw cycles, the free water storage space was expanded by 146.9%, 170.6%, and 220.1%, respectively, the effective porosity ratios were 71.5%, 75.4%, and 83.3%, respectively. Further analysis shows that with the increase of LN2 freezing time and the number of freeze–thaw cycles, the occurrence space of free water in the pores increases significantly, and the occurrence space of irreducible water gradually decreases. This study can provide some basic support for the quantitative evaluation of the pore structure of LN2 fracturing coal in field applications.

Wettability of Tight Sandstone Reservoir and Its Impacts on the Oil Migration and Accumulation: A Case Study of Shahejie Formation in Dongying Depression, Bohai Bay Basin

The migration and accumulation of oil in tight sandstone reservoirs are mainly controlled by capillary force. Due to the small pore radius and complex pore structure of tight sandstone reservoirs, the capillary force is very sensitive to wettability, so wettability significantly affects oil migration and accumulation. However, the study of oil migration and accumulation in tight sandstone reservoirs often needs to combine multiple methods, the process is complex, and the research methods of wettability are not uniform, so the mechanism of wettability affecting oil migration and accumulation is not clear. Taking the tight sandstone of the Shahejie Formation in the Dongying sag, Bohai Bay Basin, as the research object, the wettability characteristics of a tight sandstone reservoir and their influence on oil migration and accumulation were analyzed by means of a pore permeability test, XRD analysis, micro-CT experiment, contact angle tests, spontaneous imbibition experiments, and physical simulation experiments on oil migration and accumulation. The results show that the reservoir is of the water-wet type, and its wettability is affected by the mineral composition. Wettability in turn affects the spontaneous imbibition characteristics by controlling the capillary force. Oil migration in tight sandstone reservoirs is characterized by non-Darcy flow, the oil is in the non-wetting phase and subject to capillary resistance. The key parameters to describe the oil migration and accumulation characteristics include the kickoff pressure gradient, the critical pressure gradient, and ultimate oil saturation. Wettability affects oil migration characteristics by controlling the capillary force. The more oil-wet the reservoir is, the more favourable it is to oil migration and oil accumulation and therefore the higher the reservoir’s ultimate oil saturation is.

New insight to experimental study on pore structure of different type reservoirs during alkaline‐surfactant‐polymer flooding

AbstractRecently, as the demand for fossil and renewable energy continuously increases, enhancing oil recovery has become one of the key methods to meet the increased requirement. However, most of the oilfields are facing serious problems, including formation heterogeneity and low recovery factor. Therefore, further analysis is required to study the distribution of remaining oil and how to enhance oil recovery effectively. In this study, the core samples of different reservoir types were employed and characteristics of pore structure were measured by a high‐pressure mercury porosimeter. The recovery factor and distribution of remaining oil with different reservoir types were determined by core flooding experiments and nuclear magnetic resonance tests. According to the results, the heterogeneity of pore structure becomes weaker as the permeability of the reservoir increases. The recovery during different periods improved as the core permeability increased. The distribution of remaining oil in different pore sizes has an obvious difference. The contribution of the recovery factor is highest in smallpores and mesopores for type II reservoir while is greatest in mesopores and macropores for type III reservoir. These results can provide theoretical and technical support for further enhancing oil recovery.

Micro-pore structure and fractal characteristics of deep shale from Wufeng Formation to Longmaxi Formation in Jingmen exploration area, Hubei Province, China

To explore the pore structure and fractal characteristics of shale reservoirs in the Jingmen exploration area and quantitatively evaluate the heterogeneity and complexity of pores, taking Wufeng-Longmaxi formations of Well YT3 as the research object, the pore structure characteristics of shale reservoirs are analyzed by low-pressure nitrogen adsorption experiments, total organic carbon (TOC) content testing, X-ray diffraction analysis, etc., and the FHH fractal model is established based on the low-temperature nitrogen adsorption fractal geometry method. The relationship between fractal dimension and shale composition, pore structure, physical property, gas-bearing property, and burial depth is discussed. The results show that (1) The lower section of Longmaxi Formation and Wufeng Formation have significantly higher TOC concentrations than the upper section of Longmaxi Formation. With the increase of burial depth, the silicate minerals increase gradually, while clay minerals decrease. (2) The on-site desorption gas content of shale shows that the gas content of the upper section of Longmaxi Formation with low TOC abundance is lower than the lower section of Longmaxi Formation and Wufeng Formation. In terms of shale gas composition, nitrogen dominates the upper section of Longmaxi Formation, whereas methane dominates the Wufeng Formation and lower section of Longmaxi Formation. (3) The isothermal curve of shale under low-pressure nitrogen is identical to IUPAC type IV, while the adsorption hysteresis loop is similar to types H3 and H4. The pores are mainly micro medium pores distributed below 50 nm, and they are flat and slit. The lower section of Longmaxi Formation and Wufeng Formation have significantly larger adsorption volumes than the upper section of Longmaxi Formation, and the abundance of organic matter provides a large amount of organic pore storage space. (4) The BET specific surface area and BJH total pore volume in the lower section of Longmaxi Formation and Wufeng Formation with rich organic matter are significantly larger than in the upper section of Longmaxi Formation with low organic matter, whereas the average pore size is significantly smaller. (5) Shale pores have obvious fractal characteristics, with D2 being higher than D1, indicating that the pore structure is more complicated than that of the pore surface. Fractal dimension has a significant positive correlation with TOC content, BET-specific surface area, and burial depth, a weak positive correlation with quartz content and BJH total pore volume, a significant negative correlation with clay mineral content and average pore diameter, and almost no correlation with porosity and permeability. Many factors that affect the fractal dimension. Correlation analysis reveals that the mass fraction of TOC and clay mineral, specific surface area, average pore diameter, and burial depth are the main controlling factors. The fractal dimension can be utilized to quantify the complexity and heterogeneity of pore structure, which provides a concept for studying the distribution characteristics of shale pore structure and reservoir evaluation.

Pore Water and Its Influences on the Nanopore Structures of Deep Longmaxi Shales in the Luzhou Block of the Southern Sichuan Basin, China

In the Luzhou Block of the southern Sichuan Basin, the deep Longmaxi shales have become important exploration targets in recent years. However, the water-bearing properties of these shales are still unclear, which significantly limits evaluations of reservoir pore structures and gas-in-place (GIP) contents. In this study, twelve fresh shale core samples were collected at the well site, and the pore water (CPW) and equilibrium water (CEW) contents, as well as the pore structures of the shales, were analyzed under both as-received and dried conditions. The results indicate that the deep shales have low water-bearing extents with a pore water content (CPW) of 3.82–16.67 mg/g, and that both the organic matter (OM) and inorganic matter (IM) pores can be used for pore water storage. The extent of influence of pore water on nonmicropores and IM pore structures is more significant than that on micropores and OM pore structures. Meanwhile, the pore water obviously reduces the retention effects of nanopores and may block nanopores with pore widths < 0.5 nm. An average of 40% of pore spaces were taken up by pore water in the studied deep shales in the Luzhou Block, and the residual pore surface area and pore volume of the shales were mainly contributed from micropores and nonmicropores, respectively.

Investigation on pore structure, fluid mobility and water huff-n-puff oil recovery of tight volcanic oil reservoir

The pore structure of tight volcanic oil reservoirs is very complex and the permeability is extremely low. The oil recovery effect of traditional water-driven and gas-driven development is not ideal. In this paper, we first analyzed the pore structure characteristics and fluid movability characteristics of tight volcanic rocks. Then, the feasibility of water huff-n-puff in tight volcanic rocks was analyzed. Finally, we investigated the oil recovery characteristics, pore motility characteristics, and ORM of water huff-n-puff in tight volcanic rocks by using a high temperature and ultra-high pressure water huff-n-puff physical simulation experimental device under NMR monitoring. The study shows that the mineral composition of tight volcanic rocks is relatively simple, but the pore structure is very complex. The pores are mainly amygdule pores, and contain some vesicular pores and matrix pores. The fractures include structural fractures, dissolution fractures, and shrinkage fractures. Fractures are of great significance for communicating relatively independent pores and improving the seepage ability of fluids in tight volcanic rocks. The fluid movable saturation of tight volcanic rocks is 32.93%–83.75%, and the minimum movable pore radius is 0.0178 μm. The seepage capacity of large pores (r > 0.1 μm) is 2.19–7.75 times that of middle pores (0.001 μm < r < 0.1 μm). The oil recovery efficiency (the ratio of the volume of recovered oil to the volume of injected water) of the first two cycles of water huff-n-puff of tight volcanic rocks exceeds 20%, which is high-efficiency oil recovery period. However, with the increasing huff and puff cycles, the recovery factor and oil change rate both decrease rapidly. After five cycles of water huff-n-puff, the recovery factor of tight volcanic rocks increases by 29.13%. For the selected experimental core, middle pores are the main oil-producing pores, and their contribution rates in natural energy depletion and five cycles of water huff-n-puff are 59.665% and 78.173%. In five cycles of water huff-n-puff, the contribution rates of elastic displacement are 96.491%, 93.846%, 86.667%, 64.706%, and 55.556%, and the effect of imbibition displacement is relatively small. Increasing the water injection pressure is beneficial to water huff-n-puff oil recovery of tight volcanic rocks. The research can provide a good theoretical basis for the efficient development of tight volcanic oil reservoirs.