High-pressure Mercury Injection Research Articles

A Comparative Study on Microscopic Characteristics of Volcanic Reservoirs in the Carboniferous Kalagang and Haerjiawu Formations in the Santanghu Basin, China

Self-jetting high-yield oil flow was obtained from Ma 67 and Ma 36 wells drilled in the volcanic reservoirs of the Haerjiawu Formation in the Santanghu Basin, China. This has shifted the prospectors’ attention to the Haerjiawu Formation from the Kalagang Formation, which is generally considered to have favorable physical properties. To further explain the geological reasons why oil flow can jet itself from the volcanic rocks in the Haerjiawu Formation with poor physical properties, this study carries out a systematic comparison on the microscopic pore structures of volcanic rocks through unconventional tests such as low-temperature nitrogen adsorption, high-pressure mercury injection, and constant-rate mercury injection based on the analyses of physical properties and minerals. The results obtained are as follows. The volcanic rocks of the Kalagang Formation have relatively high pore permeability. However, their micropores have a wide distribution range of pore size and feature highly meandering structures and strong heterogeneity. Meanwhile, small pore throats connect large pores in the volcanic rocks, resulting in a relatively high pore/throat ratio. All these are conducive to the occurrence of tight oil and gas but unfavorable for the flow of oil and gas. The volcanic rocks in the Haerjiawu Formation have relatively low volcanic permeability. However, small pores connect large pore throats in the volcanic rocks; thus, leading to a relatively low pore/throat ratio. Meanwhile, the volcanic rocks feature low meandering structures, strong homogeneity, and high connectivity. All these are favorable for the formation of tight oil and gas reservoirs. These assessment results also indicate that the assessment indices of tight volcanic reservoirs should not only include porosity and permeability. Instead, more attention should be paid to the microscopic pore structures, and it is necessary to analyze the charging and flow of tight oil from the configuration of pores and pore throats. This study not only explains the geological factors of the wells with self-jetting high-yield oil flow in the Haerjiawu Formation from the perspective of microscopic pore structures but also provides a new idea and comparison method for the assessment of tight reservoirs in other areas.

Research on Characterization and Heterogeneity of Microscopic Pore Throat Structures in Tight Oil Reservoirs.

The key to the efficient development of a tight reservoir is its accurate evaluation. In this study, the pore throat structure characteristics of sandstone samples in the study block were analyzed by high-pressure mercury injection technology. According to the characteristics of the capillary pressure curve, the sandstone samples in the study block were divided into three types: the first type has a reservoir permeability greater than 0.7 mD and a core mercury injection saturation of 96% with a good reservoir quality; the second type has a reservoir permeability ranging from 0.4 to 0.7 mD and a core mercury injection saturation of 80% with a moderate reservoir quality; and the third type has a reservoir permeability between 0.1 and 0.4 mD and a core mercury injection saturation of 50% with a poor reservoir quality. Also, high-resolution synchrotron radiation imaging and scanning electron microscopy were used to observe the pore throat structure, connectivity, and microscopic heterogeneity of sandstone samples, showing an increasing level of pore disconnection, serious microscopic heterogeneity, and poor reservoir performance as reservoir permeability declines. As mineral composition tests show, the lithology of the tight sandstone in the target block is mainly medium-grained and fine-grained feldspar lithic sandstone and the longitudinal heterogeneity of lithology and mineral components of tight sandstone is relatively weak at above the centimeter level. Besides, based on the high-pressure mercury injection test data, fractal theory is applied to calculate the fractal dimensions of the three types of reservoirs. The result shows a gradual increase in fractal dimensions with the decrease of reservoir quality, in which the closer the fractal dimension is to 3, the more serious the microscopic heterogeneity is, and the stronger the roughness of the pore surface is. As a result, the more heterogeneous the tight reservoir gets, the more likely the injected fluid is to flow along the developed and connected pore regions.

The Influence of Reservoir Composition on the Pore Structure of Continental Shale: A Case Study from the Qingshankou Formation in the Sanzhao Sag of Northern Songliao Basin, NE China

Determining the pore structure characteristics and influencing factors of continental shale reservoir in the oil generation stage is of great significance for evaluating the shale oil reservoir space and analyzing shale oil enrichment mechanism. In this paper, shale from the first member of the Upper Cretaceous Qingshankou Formation (K2qn1) in the Songliao Basin was selected. X-ray diffraction (XRD), Rock-Eval pyrolysis, total organic carbon content (TOC), scanning electron microscopy (SEM), nitrogen gas adsorption (N2GA), and high-pressure mercury injection (HPMI) were used to clarify the composition characteristics of inorganic minerals and organic matter and determine the influencing factors of pore development in the K2qn1 shale. The results show that intergranular pores related to clay minerals and quartz, intragranular dissolution pores related to feldspar, and other mineral intragranular pores are developed. The organic matter pore is less developed, mainly composed of intragranular pores and crack pores of organic matter. Mesopores related to clay minerals are widely developed, rigid quartz particles can protect and support mesopores and macropores, and carbonate cementation can inhibit pore development. Although the TOC contents of shale are commonly less than 2.5%, it has a good positive correlation with porosity; TOC is greater than 2.5%, and the increase of residual oil fills part of the pores, leading to a decrease in porosity with the increase of TOC. Three types (types I, II, and III) of the reservoir space were classified by the combined pore size distribution diagram of N2GA and HPMI. By comparing the characteristics of pore structure parameters, it is found that Type I reservoir space is favorable for shale oil enrichment. It provides scientific guidance for shale oil exploration in the Songliao Basin.

Pore Structure and Movable Fluid Characteristics of Typical Sedimentary Lithofacies in a Tight Conglomerate Reservoir, Mahu Depression, Northwest China

The pore structure and movable fluid characteristics of tight conglomerate reservoirs are complex, which are greatly different from conventional reservoirs. The depositional mechanism is the fundamental factor controlling the physical properties of conglomerate reservoirs. However, there is a lack of systematic research on the pore structure and movable fluid characteristics of conglomerate reservoirs with typical sedimentary facies. This paper investigates the pore structure and movable fluid characteristics of conglomerate of different sedimentary facies based on various experiments. Casting thin sections, X-ray diffraction, scanning electron microscopy, high-pressure mercury injection, and nuclear magnetic resonance experiments were conducted on 32 conglomerates samples from the Mahu Sag, Junggar Basin, China. The quality classification method of tight conglomerate reservoirs is established. The results show that the conglomerate can be divided into three sedimentary facies; traction flow conglomerate (TFC) and pebbled sandstone (PSS) mainly develop intergranular pores and dissolved pores; and the pore diameter curves are mainly a double peak, single peak, and flat peak. Gravity flow conglomerate (GFC) mainly develops dissolved pores and interstitial micropores, and the pore diameter curve is mainly a single peak. PSS includes pebbled gritty sandstone (P(G)SS) and pebbled fine sandstone (P(F)SS). TFC and P(G)SS are favorable class I reservoirs, while GFC and P(F)SS are nonfavorable class II reservoirs. A new parameter, the ratio of the major axis to the minor axis of the pore outer ellipse (axial ratio), is proposed to quantitatively describe the compaction effect. The average axial ratios of the three lithofacies are 3.04, 3.98, and 8.78, respectively, indicating that the compaction is intensified and the pore structure becomes worse. By analyzing the correlation between pore structure parameters and permeability, it is found that the main controlling factors of permeability of GFC and TFC are sorting and connectivity, respectively, and the main flow radius is the most suitable parameter to describe permeability. A linear spectral decomposition method was used to establish a new quantitative calculation method of movable fluid saturation for different types of pores, and the results show that the movable fluid saturation of intergranular pores is the highest (average: 65.43%), and the movable fluid saturation of TFC and P(G)SS with more intergranular pores is the highest. Movable fluid saturation is inversely proportional to the content of I/S and the compaction rate and positively proportional to the content of quartz and feldspar and the cementation rate. The fluid mobility of water-wet samples is weaker. The research results provide theoretical support for the identification of favorable reservoirs and the cognition of a development mechanism.

Difference of Microfeatures among Diagenetic Facies in Tight Sandstone Reservoirs of the Triassic Yanchang Formation in the Midwestern Region, Ordos Basin

Based on the background of sedimentary characteristics, a large amount of core and thin section analysis, taking Chang 6 reservoir of Yanchang Formation in the central and western Ordos Basin as an example, through the application of scanning electron microscopy, high-pressure mercury injection, nuclear magnetic resonance and microscopic water drive oil model, and other experimental test methods, the diagenetic facies types and microscopic pore structure characteristics of tight sandstone reservoirs are discussed and analyzed in depth. The results show that the average porosity loss rate caused by early diagenesis compaction in the study area is 50.62%, which is the main reason for reservoir compactness. The cementation further causes porosity loss, and the later dissolution increases the reservoir space in the study area to a certain extent. Different diagenetic facies reservoirs not only have obvious differences in porosity evolution characteristics but also have significant differences in pore throat radius distribution characteristics, movable fluid occurrence characteristics, and water drive oil characteristics. The pore throat distribution with radius greater than R50∼R60 determines the permeability. The difference in movable fluid saturation mainly depends on the connectivity of the relative large pore space corresponding to the relaxation time greater than the cut-off value of T2. The size of pore throat radius has a good control effect on water flooding efficiency.

Pore Structure Differentiation between Deltaic and Epicontinental Tight Sandstones of the Upper Paleozoic in the Eastern Linxing Area, Ordos Basin, China

Research on tight gas reservoirs in the eastern margin of the Ordos Basin, China, has recently become a hot spot. This paper mainly studies the reservoir characteristics of tight sandstone in the north-central area close to the provenance in eastern Linxing. Cast thin section, scanning electron microscopy, high-pressure mercury injection, and X-ray diffraction (XRD) were applied to discriminate the tight sandstone reservoir differences between the Permian Taiyuan and Shanxi formations in the study area. The results show that the deltaic tight sandstones in the Shanxi Formation are dominated by lithic quartz sandstone and lithic sandstone with an average porosity of 2.3% and permeability of 0.083 mD. The epicontinental tight sandstones in the Taiyuan Formation are mainly lithic sandstone and lithic quartz sandstone, with average porosities and permeabilities of 6.9% and 0.12 mD, respectively. The pore type is dominated by secondary dissolution pores, containing a small number of primary pores, and fractures are not developed. The capillary pressure curves of the Taiyuan Formation sandstone are mainly of low displacement pressure, high mercury saturation, and mercury withdrawal efficiency, while the Shanxi Formation sandstone is mainly of high displacement pressure, low mercury saturation, and withdrawal efficiency. The diagenetic evolution of sandstone in the Shanxi Formation is in meso-diagenesis stage A, and the Taiyuan Formation has entered meso-diagenesis stage B. The siliceous cement in the Taiyuan Formation sandstone enhanced the sandstone resistance to compaction and retained some residual intergranular pores. The pore types in the Shanxi Formation sandstone are all secondary pores, while secondary pores in the Taiyuan Formation sandstone account for approximately 90%. The results can be beneficial for tight gas production in the study area and similar basins.

Quantitative Characterization of Heterogeneity in Different Reservoir Spaces of Low-Permeability Sandstone Reservoirs and Its Influence on Physical Properties

The complex pore structure of low-permeability sandstone reservoir makes it difficult to characterize the heterogeneity of pore throat. Taking the reservoir of Sanjianfang formation in QL oilfield as an example, the fractal dimension of different storage spaces is calculated by using fractal theory based on casting thin section, scanning electron microscope, and high-pressure mercury injection, and the correlation between porosity, permeability, and contribution of different storage space permeabilities is analyzed. The results show that the reservoir of Sanjianfang formation in QL oilfield mainly develops small pores, fine pores, and micropores, and the fractal dimension of micropore structure is between 2.6044 and 2.9982, with an average value of 2.8316. The more complex the pore structure is, the stronger the microheterogeneity is. The higher the fractal dimension, the more complex the pore structure and the smaller the porosity and permeability. The fractal dimensions of small pores, fine pores, and micropores increase successively with the decrease in pore radius, and the microstructure heterogeneity of large pores is weaker than that of small pores. It provides a theoretical basis for the exploration and development of low-permeability sandstone reservoirs.

Micropore Structures and Percolation Characteristics of Carboniferous Carbonate Reservoirs in the Zanarol Area.

Proven oil and gas reserves in carbonate rocks comprise a high proportion of oil and gas fields, but these reservoirs have high heterogeneity. It is of great importance to study the micropore structures and percolation characteristics of carbonate rocks for the development of oilfields. In this paper, reservoirs are studied by means of casting sections, high-pressure mercury injection, and water and gas flooding oil phase permeability experiments. Reservoirs are classified into three categories, I, II, and III, by the k-means cluster analysis method. The results show that class I reservoirs are mainly composed of biolimestone with strong dissolution, displacement pressure of 0.016 MPa, median pressure of 0.135 MPa, mercury removal efficiency of 17.15%, well-developed pore throats, and good connectivity. They have the highest reservoir quality index and strong percolation ability. Class II reservoirs are mainly biogenic limestone and granular limestone with intergranular pores, a displacement pressure of 0.098 MPa, a median pressure of 6.026 MPa, and a mercury removal efficiency of 25.82%. The pore throat class is complex, and the sorting is poor. Class III reservoirs are mainly clastic limestone with residual intergranular pores, poor connectivity, displacement pressure of 0.403 MPa, median pressure of 3.77 MPa, mercury removal efficiency of 14.01%, small median radii, and good sorting performance. Relative permeability experiments show that water drive permeability at the isopermeability point is (0.049 10–3 μm2) higher than that of gas drive (0.041 10–3 μm2). The permeability of oil and water phases in class I reservoirs is obviously higher than those of class II and III reservoirs. When gas flooding is used, the phase permeability characteristics of class I and II reservoirs are no different than when water flooding is used. The permeability of gas flooding is slightly lower than that of water flooding. Because of the high proportion of micropores in class III reservoirs, gas can easily enter the pores, so the relative permeability of the gas phase increases rapidly. With increases in injection volume, the ultimate oil displacement efficiency of class I reservoirs can reach 53.2%, while those of class II and III reservoirs are 50.7 and 46.1%, respectively. This study provides important guidance for formulating oilfield development plans.

Micro-occurrence of formation water in tight sandstone gas reservoirs of low hydrocarbon generating intensity: Case study of northern Tianhuan Depression in the Ordos Basin, NW China

A series of experimental techniques which contain casting thin slice observation, field emission scanning electron microscopy, high-pressure mercury injection, constant-velocity mercury injection, and NMR(nuclear magnetic resonance) were used to study the throat microstructure and microscopic occurrence of formation water in the Upper Paleozoic tight sandstone gas reservoir in northern Tianhuan Depression, Ordos Basin. The results show that intragranular dissolution pores, intercrystalline pores, and residual intergranular pores represent 33 %, 31 %, and 16 % of the pore types in the reservoir of the He8-Shan1 members in the northern Tianhuan Depression, respectively. Pore radii range from 80 μm to 300 μm, with an average of 154.18 μm, while throat radii range from 0.01 μm to 1.60 μm, with an average of 0.55 μm. Micron pores and nano throats control the seepage ability of the reservoirs, and the throat radius serves as the controlling factor. Formation water has four microscopic occurrences: bound water, capillary water, free water, and adsorbed water. At low charging pressure, a mixture of gas and water was found in the intergranular pores and dissolution pores controlled by macro throats, with a high gas content and existent free water; a small amount of membrane adsorption water was observed at high charging pressure. However, in the intergranular pores and dissolution pores controlled by medium-small throats, the mixture of gas and water at low charging pressure presents a low gas content and a large amount of capillary water, while at high charging pressure, the mixture of gas and water or pure gas presents a high gas content and a small amount of capillary water. Pure water controlled by tiny throats, on the other hand, was found at low charging pressure in the intergranular pores, whereas gas and water mixture was found at high charging pressure, but the gas content is low and bound water appears. In the intergranular micropores, pure water, which is bound water, is the primary composition at both low and high charging pressure. The throat radius cut-offs of the four kinds of formation water are 0.10 μm, 0.26 μm, and 0.28 μm, the permeability cutoffs are 0.21 × 10−3 μm2, 0.51 × 10−3 μm2, and 0.55 × 10−3 μm2, and the porosity cutoffs are 5.86 %, 7.99 %, and 8.18 %, respectively. The starting pressure gradient and throats less than 0.10 μm are controlling factors on the micro-occurrence and residual water saturation of formation water. As the amount of gas driving water increases in the natural gas accumulation process, the percentage of formation water controlled by large throats gradually decreases. Free water makes up 50 % of the research area, capillary water makes up 18 %, bound water compensates 30 %, adsorbed water is 2 %, and residual water saturation is about 32 %.

Pore Structure Characteristics and Evolution Law of Different-Rank Coal Samples

In this study, the full-size pore structure characteristics of six different-rank coal samples were investigated and analyzed from three perspectives, namely, pore shape, pore volume, and pore specific surface area, by performing a high-pressure mercury injection experiment and a low-temperature nitrogen adsorption experiment. Next, the full-size pore volumes and pore specific surface areas of the six coal samples were accurately characterized through a combination of the two experiments. Furthermore, the relationships between volatile matter content and pore volume and between volatile matter content and pore specific surface area were fitted and analyzed. Finally, the influences of metamorphic degree on pore structure were discussed. The following conclusions were obtained. The pore shapes of different-rank coal samples differ significantly. With the increase of metamorphic degree, the full-size pore volume and pore specific surface area both decrease first and then increase. Among the pores with various sizes, micropores are the largest contributor to the full-size pore volume and pore specific surface area. The fitting curves between volatile matter content and pore volume and between volatile matter content and pore specific surface area can well reflect the influence and control of metamorphic degree on pore volume and pore specific surface area, respectively. With the increase of volatile matter content, the pore volume and the pore specific surface area both vary in a trend resembling a reverse parabola.

Mechanisms of shale hydration and water block removal

Shale samples of Silurian Longmaxi Formation in the Changning area of the Sichuan Basin, SW China, were selected to carry out scanning electron microscopy, CT imaging, high-pressure mercury injection, low-temperature nitrogen adsorption and imbibition experiments to compare the hydration characteristics of montmorillonite and illite, analyze the main factors affecting the water block removal of shale, and reveal the mechanisms of pore structure evolution during shale hydration. The hydration characteristics of shale are closely related to the composition of clay minerals, the shale with high illite content is not susceptible to hydration and thus has limited room for pore structure improvement; the shale with high montmorillonite is susceptible to hydration expansion and thus has higher potential of pore structure improvement by stimulation; the shale with high illite content has stronger imbibition in the initial stage, but insufficient diffusion ability, and thus is likely to have water block; the shale with high montmorillonite content has weaker imbibition in the initial stage but better water diffusion, so water blocking in this kind of shale can be removed to some degree; the shale reservoir has an optimal hydration time, when it is best in physical properties, but hydration time too long would cause damage to the reservoir, and the shale with high illite content has a shorter optimal hydration time; inorganic cations can inhibit the hydration of clay minerals and have stronger inhibition to illite expansion, especially K + ; for the reservoir with high content of montmorillonite, the cation content of fracturing fluid can be lowered to promote the shale hydration; fracturing fluid with high K + content can be injected into reservoirs with high illite content to suppress hydration.

Research on the Oil-Bearing Difference of Bedding Fractures: A Case Study of Lucaogou Formation in Jimsar Sag

Lucaogou formation in Jimsar sag is host to large quantities of bedding fractures which are known to play a critical role in the enrichment, accumulation, and efficient development of tight oil. In this paper, we examine and finely characterize the development of the bedding fractures found in the upper and lower sweet spots of Lucaogou formation of tight oil reservoir through field outcrop and core observation, cast thin section analysis, and imaging log recognition and investigate the factors affecting their differentiated oil-bearing by means of inclusion temperature measurement, TOC testing, physical property testing, high-pressure mercury injection, and physical simulation experiment. By comparison with the linear density, bedding fractures are more developed in the lower sweet spot. These fractures occur in parallel to the formation boundary and have small aperture. Most of bedding fractures are unfilled fractures. Among the few types of fractures found there, bedding fractures have the best oil-bearing property, but the oil-bearing can differ from one bedding fracture to another. The factors affecting the differentiated oil-bearing of bedding fractures include the temporal coupling of the formation of these fractures with the hydrocarbon generation of the source rocks and the spatial coupling of the bedding fractures with the source rocks. In terms of temporal coupling, mass hydrocarbon generation in Jimsar sag began in Late Jurassic. Inclusion temperature measurement indicates that the bedding fractures there formed in or after Early Cretaceous. Hence, by matching the mass hydrocarbon generation period of the source rocks with the formation period of the bedding fractures, we discovered that the bedding fractures formed within the mass hydrocarbon generation period, which favored the oil-bearing of these fractures. The spatial coupling is manifested in TOC, porosity, permeability, and pore throat, with TOC being the main controlling factor. For TOC, the higher the formation TOC, the better the oil-bearing property of the bedding fractures. For porosity, subject to the TOC level, if the TOC is adequate, the larger the porosity, the larger the chloroform asphalt “A,” accordingly the higher the oil content of the formation, and the better the oil-bearing property of the bedding fractures developed therein. In this sense, in terms of spatial coupling, TOC constitutes the main controlling factor of the oil-bearing property of bedding fractures.

Tight sandstone reservoir sensitivity and damage mechanism analysis: A case study from Ordos Basin, China and implications for reservoir damage prevention

Analysis of reservoir sensitivity to velocity, water, salt, acid, alkali and stress is critical for reservoir protection. To study the tight sandstone reservoir sensitivity at different formation depths (effective stress) and formation water conditions (pH, salinity, and fluid velocity), a series of dynamic core flow tests under different pH, salinity, acid, and effective stress conditions were performed on samples from tight sandstone reservoirs of the Upper Triassic Yanchang 8 (T3y8) Member and conventional reservoirs of the Middle-Lower Jurassic Yan'an 9 (J1-2y9) Member in the Ordos Basin. The results indicate that, compared with the conventional reservoirs, the tight sandstone reservoirs are more sensitive to velocity and stress, less sensitive to water, alkali and salinity, and respond better to acid fracturing. In addition, the critical conditions (salinity, velocity, pH, and stress) for pumping drilling, completion, and fracturing fluids into tight sandstone reservoirs were investigated. A combination of scanning electron microscopy coupled with energy-dispersive spectrometry (SEM-EDS), cathodoluminescence (CL), casting thin section (CTS) and nuclear magnetic resonance (NMR) images, high-pressure mercury injection capillary pressure (MICP) measurements as well as X-ray fluorescence spectral (XRF) analyses were employed to analyze the damage mechanisms of the conventional reservoirs (J1-2y9) and tight sandstone reservoirs (T3y8) caused by fluid invasion. The results suggest that reservoir sensitivity is primarily conditioned by the composition of detrital components and interstitial fillings, petrophysical properties, pore-throat structure, and diagenetic facies. All these factors control the sensitivity types and extent of the reservoirs. Our results indicate that the poorer the reservoir physical properties, the stronger the reservoir heterogeneity and sensitivity, implying that tight sandstone reservoirs are more susceptible to changes in fluids than conventional reservoirs. This study offers insights into the reservoir damage types and helps to improve the design and implementation of protection measures for tight sandstone reservoir exploration.

Classification Evaluation of Gas Shales Based on High-Pressure Mercury Injection: A Case Study on Wufeng and Longmaxi Formations in Southeast Sichuan, China

Classification Evaluation of Gas Shales Based on High-Pressure Mercury Injection: A Case Study on Wufeng and Longmaxi Formations in Southeast Sichuan, China

Characteristics of Hydration Damage and Its Influence on Permeability of Lamellar Shale Oil Reservoirs in Ordos Basin

The continental shale oil reservoir has low permeability, high clay content, rich lamellar structure, and strong heterogeneity, which makes the reservoir vulnerable to hydration damage. In order to study characteristics of hydration damage and its influence on permeability of lamellar shale oil reservoirs, a series of experiments such as high-pressure mercury injection, steady gas permeability, rock thin section identification, and scanning electron microscope were carried out with the downhole core in Ordos Basin as the experimental object. The effects of water and water-based drilling fluid on pore size distribution, permeability, and rock microstructure were analyzed. Results show that the pore size of the reservoir is mainly nanoscale, and the pore size of shale changes most dramatically in the stage of hydration for 12-24 hours, while that of tuff changes most dramatically in 24-48 hours. The permeability increases rapidly with hydration time and then tends to be stable, among which the permeability of samples with lamellar structure in the direction parallel to the lamellar structure is most easily affected by hydration and changes fastest. Hydration leads to the formation of new pores, new fractures, and the expansion of existing fractures in rocks, especially in the strata containing large amounts of terrigenous clastic, lamellar structure, and pyrite. The new seepage channel increases the permeability of rock, and the soil powder and plugging particles in drilling fluid are easy to form protective mud cake in these places. These protective mud cakes not only change the microstructure of rock but also inhibit the influence of hydration on the pore space and permeability of rock, which play an effective role in preventing the mineral shedding on the rock surface, reducing the increase of micropores and delaying hydration.

Experimental Methods for the Quantitative Assessment of the Volume Fraction of Movable Shale Oil: A Case Study in the Jimsar Sag, Junggar Basin, China

Deep insights into the movability of the retained shale oil are of great significance to shale oil. Rock and crude oil samples were collected from well J174 in the Jimsar Sag, Junggar Basin. Rock samples were subjected to different extraction followed by analysis of the component in the extracts, and measurement of porosity in conjunction with nuclear magnetic resonance and high-pressure mercury injection analysis. The results of these analyses were used to establish an experimental method for quantitative assessment of movable shale oil. The extract content of the component varied among different extraction and between mud shale and non-mud shale samples. The saturated hydrocarbon in the extracts of the mud shale was similar to those of the non-mud shale after extraction with CHCl3 alone or after sequential extraction with nC6 + CHCl3. The aromatic hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC6, but the opposite was observed after sequential extraction with nC6 + CHCl3. The contents of the non-hydrocarbon in the extract were significantly lower for the mud shale than for the non-mud shale after extraction with nC6, but the opposite was observed after extraction with CHCl3 or nC6 + CHCl3. The contents of the asphaltene in the extract were not significantly different for the mud shale and non-mud shale after extraction with nC6, but the contents were higher for the mud shale than for the non-mud shale after extraction with nC6 + CHCl3 or CHCl3. The viscosity of the crude oil was negatively correlated with the saturated hydrocarbon, was positively correlated with the aromatic hydrocarbon and non-hydrocarbon, and was not correlated with the asphaltene. For the mud shale and non-mud shale, their porosity after extraction with nC6 or CHCl3 was higher than their original porosity. Moreover, their porosity after extraction with CHCl3 was higher than after extraction with nC6. The movable oil was significantly correlated with the lithology, with sandstone allowing for a higher fluid movability than mud shale and dolomite allowing for a higher fluid movability than siliceous rocks.

Challenges in the Petrophysical and Dynamic Characterization of Deepwater Turbidite Deposits of the Colombian Caribbean Offshore–A Case Study

The Colombian Caribbean region has become an important exploratory target, and recent discoveries confirm its potential as a gas province to overcome the expected near-future gas deficit. A petrophysical and dynamic characterization workflow was implemented for this challenging deepwater play, where the depositional environment is the result of turbidity current processes. The reservoirs consist mostly of thin to very thin sand layers, corresponding mainly to the Ta, Tb, and Tc divisions of the Bouma sequence as observed in the cored intervals. Bouma divisions Td and Te are related with the lowest rock quality and represent the nonreservoir intervals. The greatest challenge in the characterization of this particular reservoir is the vertical resolution, given the very low thickness of the layers, which becomes very difficult to detect using standard resolution logs. Thus, tomography images, resultant CT-scan curves, and their integration with routine and special core analyses were used to reveal the true nature of this complex reservoir. The proposed methodology focuses on the integration of routine and special core analysis for the petrophysical and dynamic characterization of the reservoir, where the pore-throat-radius distribution from high-pressure mercury injection becomes the basis of the differentiation between what is considered reservoir and what is not. Pore-throat radius estimated from high-pressure mercury injection (R35) correlates extremely well with textural features and clay content in the rock; therefore, this parameter (R35) was used to define the different classes for rock typing. The approach taken was to develop a multilinear regression model of R35 as a function of very high-resolution tomography outputs in the cored zones and then see how it may be extrapolated to the uncored zones using available high-resolution logs. Special petrophysical analyses, such as NMR low field, porous-plate capillary pressure, electrical properties, and relative permeability curves (steady state), showed correlation with the defined rock types and, in turn, allowed for a determination of the gas accumulation potential of the area. Finally, rock and fluid (dry-gas) properties have been used to build a single-well radial model to design initial well tests (DST) and predict production performance from each interval (selective tests). The simulation model represents the lateral and vertical heterogeneity related to the geological environment (turbidites). The final results have defined the flow and shut-in times during tests to optimize the budget.

Comparative analysis of the pore structure of fusain in lignite and high-volatile bituminous coal

Fusain samples from lignite and high-volatile bituminous coal were obtained by stripping. The morphological characteristics of the fusain samples and raw coal samples were observed under an optical microscope and scanning electron microscope. The pore structure characteristics of the samples were quantitatively characterized through high-pressure mercury injection and low-temperature liquid N2 adsorption experiments. The results showed that the pore volume and pore specific surface area of the fusain samples from lignite were significantly larger than those of the fusain samples from high-volatile bituminous coal. The main pore types of fusain were macropores and mesopores. Compared with the raw coal samples, fusain from lignite was found to be more conducive to the occurrence of free gas, while that from high-volatile bituminous coal was more conducive to the occurrence of adsorbed gas and free gas. The types of macropores in both sets of fusain samples were similar, and mainly exhibited a tubular structure and multi-side opening similar to a tubular structure.The connectivity between the mesopores, part of the macropores and part of the transition pores were poor. Mechanical compaction causes the cell wall of fusain to break and fill the pores, and the mineral filling causes the pores narrow, which affects the pore structure to a certain extent. The results imply that the first coalification jump has little effect on the pore structure of fusain, whereas it has an obvious effect on the pore structure of raw coal.

A reservoir quality evaluation approach for tight sandstone reservoirs based on the gray correlation algorithm: A case study of the Chang 6 layer in the W area of the as oilfield, Ordos Basin

As an important type of unconventional hydrocarbon, tight sandstone oil has great present and future resource potential. Reservoir quality evaluation is the basis of tight sandstone oil development. A comprehensive evaluation approach based on the gray correlation algorithm is established to effectively assess tight sandstone reservoir quality. Seven tight sandstone samples from the Chang 6 reservoir in the W area of the AS oilfield in the Ordos Basin are employed. First, the petrological and physical characteristics of the study area reservoir are briefly discussed through thin section observations, electron microscopy analysis, core physical property tests, and whole-rock and clay mineral content experiments. Second, the pore type, throat type and pore and throat combination characteristics are described from casting thin sections and scanning electron microscopy. Third, high-pressure mercury injection and nitrogen adsorption experiments are optimized to evaluate the characteristic parameters of pore throat distribution, micro- and nanopore throat frequency, permeability contribution and volume continuous distribution characteristics to quantitatively characterize the reservoir micro- and nanopores and throats. Then, the effective pore throat frequency specific gravity parameter of movable oil and the irreducible oil pore throat volume specific gravity parameter are introduced and combined with the reservoir physical properties, multipoint Brunauer-Emmett-Teller (BET) specific surface area, displacement pressure, maximum mercury saturation and mercury withdrawal efficiency parameters as the basic parameters for evaluation of tight sandstone reservoir quality. Finally, the weight coefficient of each parameter is calculated by the gray correlation method, and a reservoir comprehensive evaluation indicator (RCEI) is designed. The results show that the study area is dominated by types II and III tight sandstone reservoirs. In addition, the research method in this paper can be further extended to the evaluation of shale gas and other unconventional reservoirs after appropriate modification.

Determinations of the multifractal characteristics of the pore structures of low-, middle-, and high-rank coal using high-pressure mercury injection

The multifractal characteristics of pore structures of low-, middle-, and high-rank coals were analyzed in this study based on the results of high-pressure mercury injection analysis and multifractal theories. The results showed that coal pore structures exhibit multifractal behavior, and were much affected by coalification degrees. For example, it was observed that the Hurst Index (H), information dimension D1, and correlation dimension D2 decreased with increases in the coalification degree. Also, the spectrum width increased, indicating greater local fluctuations of the pore size distributions (PSDs), narrower distribution intervals, enhanced heterogeneity, and reduced pore connectivity. Micropores and mesopores have opposing effects on the multifractal characteristics of pore structures. It has been found that increases in the percentage of mesopores lead to better pore connectivity and more homogeneous pore structures. In addition, increases in mineral content and Mad lead to better connectivity and more uniform pore structures. However, increases in vitrinite content results in decreased pore connectivity, and the complexity of pore structures tends to increase. Also, increases in inertinite content reduce the heterogeneity of the low value regions of the pore volumes, resulting in decreases in the complexity of the overall pore structures.