High-pressure Mercury Injection Research Articles

Experimental investigation of porosity and permeability change caused by salting out in tight sandstone gas reservoirs

Salt precipitation and its induced problems are increasingly prominent with the development of deep and ultra-deep tight sandstone gas reservoirs with high salinity formation water. In this paper, the change of porosity and permeability of a series of tight sandstone was measured, and then the morphology and occurrence state of crystalloid salt within the pore was observed by SEM. Meanwhile, high-pressure mercury injection analyzed the changes of pore size distribution. Experimental results show that salt precipitation could affect the porosity and permeability, which decreases by 53% and 65% after salt precipitation, respectively. The occurrence state of the crystalloid salt can be divided into three models: superposition growth along with the intergranular pore-fractures/natural micro-fractures, lamellar growth attached to the surface of the hydrophilic mineral like I/S interstratified mineral and the individual particles located in the corner of the pore. When the size of crystalloid salt is closer to the pore size distribution of tight sandstone, it will cause cracks and pore throat blockage easily. It is suggested that salt wash pretreatment should be carried out before analysis of tight sandstone with porosity less than 5%.

Characterization of pore structure and its impact on methane adsorption capacity for semi-anthracite in Shizhuangnan Block, Qinshui Basin

To determine the pore structure characteristics and its effect on the adsorption capacity of semi-anthracite, high pressure mercury injection (HPMI), Low pressure nitrogen gas adsorption (LP-N2GA), Low pressure carbon dioxide gas adsorption (LP-CO2GA) and isotherm adsorption experiments were carried out on eight coal samples collected from the Shizhuangnan Block. The results show that the semi-anthracite reservoirs predominantly developed semi-open pores with poor connectivity and various pore morphology. The combined pore size distribution (PSD) from results of HPMI, LP-N2GA and LP-CO2GA indicated that the super-micropores in semi-anthracite reservoirs are most developed, providing the main storage space, accounting for 80.75% of the total TPV and 99.69% of the total SSA, followed by macropores. Additionally, the pore volume and SSA distributions of semi-anthracite reservoirs are unimodal with peak values present at 0.5–0.6 nm, indicating that pores with pore diameter between 0.5 and 0.6 nm are the largest contributors to TPV and SSA, accounting for 40.09% of the TPV and 56.95% of the total SSA. The super-micropores have a controlling factor on the adsorption capacity of semi-anthracite reservoirs. Vitrinite-rich coals developed stronger adsorption capacity as the vitrinite is rich in super-micropores whereas there are no obvious correlations between inertinite content with super-micropore SSA and VL. Additionally, mineral has a negative effect on the adsorption capacity of coals by inhibiting the development level of super-micropores. The combination application of HPMI, LP-N2GA and LP-CO2GA can more accurately reflect the pore structure of coal reservoir, especially for super-micropores.

Characteristics of microscopic pore structure and its influence on spontaneous imbibition of tight gas reservoir in the Ordos Basin, China

Spontaneous imbibition is an important mechanism governing the tight reservoir production performance, especially in the early stage of production after hydraulic fracturing. The microscopic pore structure of reservoirs is an important factor affecting imbibition. In this study, high-pressure mercury injection (HPMI), rate-controlled mercury injection, and low-temperature nitrogen adsorption (LP-N2GA) were preformed to study pore structure characteristics and fluid distribution in samples from the Ordos Basin, China. Nuclear magnetic resonance (NMR) and imbibition experiments were used to investigate the fluid distribution in porous media during imbibition. The porosity of samples ranges from 11.378% to 12.356%, with an average of 12.034%. The permeability of samples ranges from 0.034 mD to 0.056 mD, with an average of 0.048 mD. Results show that the recovery ranges from 68% to 94.81%, with an average of 81.09%. The reservoir is dominated by open flat slit micropores and mesopores. Sample pore volume ranges from 0.0155 ml/g to 0.0193 ml/g, with an average of 0.01687 ml/g. Micropores and mesopores less than 50 nm provide most of the pore volume. Pore radius and pore-throat ratio were obtained from experiments. Imbibition occurs primarily in pores ranging from 0.1 μm to 1 μm in radius, followed by pores ranging from 1 μm to 10 μm. The effects of porosity, permeability, average pore radius, average throat radius, average pore-throat ratio, specific surface area, and pore volume on imbibition recovery were statistically analyzed. Grey relational analysis was applied to sequence the imbibition influencing factors and determine the most influential factor. Results demonstrate that imbibition recovery is the most affected by average pore radius, followed by permeability, porosity, average pore-throat ratio, median radius, average throat radius, and specific surface area.

Pore types, origins and control on reservoir heterogeneity of carbonate rocks in Middle Cretaceous Mishrif Formation of the West Qurna oilfield, Iraq

Carbonates in Upper Cretaceous Mishrif Formation of the West Qurna oilfield in Iraq are characterized by complicated rocks and pores types, and strong heterogeneity. Based on the cores and cast thin sections of three wells, pore types were identified, and pore origins were analyzed from the perspective of sedimentary and diagenesis features. Porosity and permeability measurement, and high pressure mercury injection capillary pressure tests were conducted to determine the relationships between pores and reservoir heterogeneity. Six types of pores are identified, and they are intragranular pores, moldic pores, residual moldic pores, intergranular pores, micropores and intercrystal pores. The pore origins were controlled by the sedimentary environments and diagenesis. Pore types were controlled by lime mud contents, bioclastic textures, types and abundance that were controlled by sedimentary environments. Pore occurrence was determined by various diagenesis, while pore occurrence was mainly attributed to dissolution, which was influenced by the mineral composition of bioclastics. In addition, pores were altered by micritization, cementation and compaction. Results from the comparison of reservoir parameters show that the reservoir physical properties and pore structure of the each dominant pore type are similar. The study proves that reservoir characteristics are controlled by dominant pore types and reveals that pore type is a crucial cause for strong reservoir heterogeneity of carbonates.

Pore Connectivity Between Organic and Inorganic Matter in Shale: Network Modeling of Mercury Capillary Pressure

Each of the two major mineral components found in shale samples—organic matter (OM) and inorganic matter (iOM)—has a distinct pore system revealed by scanning electron microscope images, low-pressure nitrogen adsorption, and high-pressure mercury injection tests. Although a vast amount of research has been conducted to detect and measure pore sizes in OM and iOM separately, the connectivity of the pores in these two components remains unclear. In permeability models, pore connectivity between OM and iOM components plays an important role in studying and predicting fluid flow. We studied pore connectivity between OM and iOM by developing pore-network models to mimic the composite nature of distributed OM patches in shale. Input parameters to generate network models were porosity, pore- and throat-size distribution, and total organic content. Mercury injection and capillary-pressure curves were then simulated through generated network models using percolation theory. To study the effects of pore connectivity between OM and iOM, we changed the size and locale of OM patches in the generated network models. Simulation results showed that the locale of OM affects mercury saturation (location and numbers of invaded pores) at given applied pressures. To study the effect of pore-size overlap between OM and iOM pores, we simulated mercury injection for two groups of constructed pore networks: non-overlapping and overlapping. In non-overlapping cases, first all iOM pores were invaded with mercury; then, only OM pores at very high pressure were invaded. In overlapping cases, OM and iOM pores can be invaded simultaneously because some of the pores have similar sizes in both components. The simulated capillary-pressure curves show distinct behavior in the non-overlapping and overlapping cases. Non-overlapping capillary-pressure curves show a sudden increase when OM pores are invaded, whereas overlapping capillary-pressure curves are smoother. Results of this work increase understanding of the connectivity of pores from measured capillary-pressure curves for further implementation in permeability-predictive models.

Quantitative Analysis of Micron-Scale and Nano-Scale Pore Throat Characteristics of Tight Sandstone Using Matlab

Based on micro-scale casting thin sections, nano-scale SEM images, and the pore distribution map identified through a binary image in Matlab, the pore size distribution and pore throat coordination number of the strata of Upper Paleozoic He8 section tight sandstone in the southeastern Ordos Basin were quantitatively analyzed with the above experimental data. In combination with a high-pressure mercury injection experiment, the pore throat distribution, the pore throat ratio, and the relationships between the characteristics, parameters, and pore permeability were investigated clearly. The results show that the tight sandstone pore space in the study area is dominated by micron-sized intergranular pores, dissolved pores, and intragranular pores. The nano-scale pore throat consisted of clay minerals, intercrystalline pores, and the flake intergranular pores of overgrowth quartz grains. Kaolinite and illite intercrystalline pores occupy the pore space below 600 nm, while the ones above 800 nm are mainly dominated by the intergranular pores of overgrowth quartz grains, and the 600–800 nm ones are transitional zones. The permeability of tight sandstone increases with the average pore throat radius, sorting coefficient, median pore throat radius, and average pore throat number. The porosity is positively correlated with the average pore radius and the average pore throat coordination number, and negatively correlated with the median pore throat radius.

Microscopic pore structure of Chang 63 reservoir in Huaqing oilfield, Ordos Basin, China and its effect on water flooding characteristics

Chang 63 reservoir in Huaqing oilfield, Ordos Basin, China is featured by strong pore structure heterogeneity, which leads to prominent Jamin effect in the water flooding, difficult development process, low productivity, and massive residual oil. Accordingly, this study aims to explore the microscopic pore structure of Chang 63 reservoir and investigate its influence on the water flooding efficiency, based on a series of comprehensive analyses, including physical property analysis, casting thin section observation, scanning electron microscopy measurement, high-pressure mercury injection, constant rate mercury injection, and microscopic real sandstone water flooding model. It is demonstrated that gray and gray-brown feldspathic sandstone are the main reservoir lithology in the study area, with dominant pore types of residual intergranular pores and feldspar dissolution pores. Pore throat radius is unevenly distributed, and small and micro pores take the majority. Based on the comparison of capillary pressure curve characteristics and comprehensive analysis of corresponding parameters, the pore structure of the Chang 63 reservoir is divided into four types, namely types I–IV. They have different reservoir spaces, and their reservoir and seepage capacities decrease in the order of types I–IV pore structures. Moreover, displacement patterns in them are also different, with the finger-like-reticular displacement as the primary. In addition, pore throat radius and distribution play a critical role in the water flooding. It is also demonstrated that the water flooding efficiency increases with permeability and porosity, pore structure quality, and pore throat distribution evenness.

Saturation Modeling Under a Complex Fluid-Fill History: Drainage and Imbibition

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188594, “Saturation Modeling Under Complex Fluid-Fill History—Drainage and Imbibition,” by H. Xian, SPE, L. Beugelsdijk, SPE, and A. Kohli, SPE, Shell; E. Fokkema, SPE, Nederlandse Aardolie Maatschappij; and A. Cense, Shell, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. This paper presents a saturation-modeling approach for fields and reservoirs with complex hydrocarbon-charging histories. The model resolves saturation-height functions for the primary-drainage, imbibition, and secondary-drainage equilibriums. As part of the approach, a method of evaluating the residual-hydrocarbon saturation below the initial free-water level (FWL) is proposed. The developed theory is based on the principle of capillary-pressure/saturation hysteresis on the drainage/imbibition process in a water-wet system. Introduction Many discovered oil and gas fields are found to have gone through complex fluid-fill histories where residual hydrocarbons are observed below the FWL. To add to the complexity, some of these are giant fields and are divided into compartments with varying contacts and FWLs. To model saturation-height dependencies for reservoirs in fields under imbibition equilibrium, one of the adopted practices is to use a drainage model built from core data or log data to compute the saturation starting from the original FWL contact but only calculate the hydrocarbon-in-place volumes above the initial FWL. Another common practice is to build log-based drainage models using the current FWL while ignoring the uncertainties in the transition zone from the imbibition effect. These approaches typically lead to an inappropriate estimation of the hydrocarbon saturation in the transition zone and normally require separate models for different segments of the field. In this paper, an approach is presented for modeling the core capillary-pressure imbibition and secondary drainage cycles, integrating with log-based saturation-height models, and designing a work flow for upscaling and implementation in 3D reservoir models. Imbibition and Secondary-Drainage-Model Theory Hysteresis of Saturation/Capillary Pressure and Analytical Imbibition Model Method. Modeling of saturation/capillary pressure of primary-drainage-imbibition hysteresis is more complicated than other types of hysteresis effects because its cycle is not a closed loop; the imbibition route does not end at the starting point of the primary drainage route. Fig. 1 shows the multi cycle drainage/imbibition scanning curves in mixed-wet or strongly water-wet rock systems. Saturation changes caused by the imbibition-hysteresis effect are larger at lower capillary pressures in the transition zone but become insignificant over the higher capillary pressures across the main nonwetting-phase column. The primary-drainage capillary pressure can be measured by high-pressure mercury injection, porous plate, and centrifuge. Spontaneous imbibition can be measured only by use of the porous-plate technique or by use of an Amott cell. The forced imbibition part of the imbibition capillary pressure can be measured by porous plate and centrifuge.

Study of the Imbibition Behavior of Hydrophilic Tight Sandstone Reservoirs Based on Nuclear Magnetic Resonance

Hydraulic fracturing is one of the key technologies to enhance the oil recovery from tight sandstone reservoirs. The study on the behavior of imbibition for tight sandstone reservoir is of great significance to increase oil production after fracturing. In this paper, nuclear magnetic resonance (NMR) and high-pressure mercury injection were implemented on the samples taken from the Yanchang Formation of the Ordos Basin. The NMR T2 curves of the core at the state of 100% water saturated were converted to pore-throat radius distribution curves. On this basis, the experiments of imbibition and displacement were conducted and the changes of fluid distribution, imbibition quantity, and imbibition rate with different scale pores and different imbibition times were analyzed. Moreover, the results of imbibition and displacement were compared to assess the distribution of the recoverable and remaining oil under two exploitation modes and the contribution of imbibition made to displacement in pores at different scales. The result shows that imbibition is a relatively slow process. The entire imbibition process is mainly affected by nanopores, which are widely distributed in cores, and the imbibition rate of total pores constantly decreases as the imbibition time increases. Moreover, the relative recovery in pores at different scales shows a huge difference under the two exploitation modes of imbibition and displacement. During imbibition, smaller pores produced higher degrees of oil, while during displacement, larger pores have higher relative recovery. The contribution of imbibition made to displacement in nanopores was the highest and decreased with the increase of the pore-throat size.

Pore Structure Characterization of the Tight Reservoir: Systematic Integration of Mercury Injection and Nuclear Magnetic Resonance

Pore structure is the most important factor affecting reservoir quality and petrophysical property of tight reservoir. The effective characterization of pore structures, including pore radius distribution (PRD), throat radius distribution (TRD), pore-throat radius distribution (PTRD), relevant pore structure parameters, etc., is of great importance for the oil exploration and exploitation. Taking the tight sandy conglomerate reservoir as research target of tight reservoir, this paper characterizes the pore structures by a combination of experiments on parallel core samples. These experiments include high-pressure mercury injection (HPMI), constant-rate mercury injection (CRMI), nuclear magnetic resonance (NMR), as well as microscopic analysis of casting thin sections and scanning electron microscopy (SEM). This paper systematically analyzes the advantages and shortcomings of these commonly used experimental techniques. And then, novel methods are proposed to characterize the pore structure (especially the full-range PRD, TRD, and PTRD) by utilizing the advantages of these techniques. In addition, an advanced pore classification scheme is proposed to reclassify the pore types. Finally, the controls of the pore structure on the flow characteristics are investigated, which in turn further demonstrates the correctness and importance of the proposed novel methods for characterizing pore structures. In summary, this study proposes novel methods to characterize the pore structure by integration of HPMI, CRMI, and NMR and provides insights into the pore structure characteristics of the tight sandy conglomerate reservoir.

Evaluation of the pore structure of tight sandstone reservoirs based on multifractal analysis: a case study from the Kepingtage Formation in the Shuntuoguole uplift, Tarim Basin, NW China

Both the microscopic pores and the pore structure of a reservoir affect its properties, including permeability and the distribution of oil and gas. Due to the stronger pore structure heterogeneity in tight sandstone reservoirs, it is difficult to characterize the pore structure of tight sandstone with traditional Euclidean geometry. In this study, based on the comprehensive utilization of reservoir data, such as petrophysical property data, mercury injection capillary pressure data and thin sections images, image processing and multifractal analyses are used to classify and describe the pore structure of tight sandstone in the Kepingtage Formation in the Shuntuoguole low uplift, Tarim Basin. The relationships among pore structure parameters, physical properties, and multifractal feature parameters are discussed in detail. Finally, a pore structure classification method using multifractal parameters based on K-means clustering analysis is proposed and applied to tight sandstone. The results show that the pore structure of the Kepingtage Formation can be divided into four types with distinct multifractal characteristics. The multifractal parameters correlate well with the porosity and permeability. The multifractal parameters αmin, αmax, Dmin, and Dmax are positively correlated with the average pore throat radius (rt) but are negatively correlated with displacement pressure (Pd). The parameters αmin, αmax, Dmin, and Dmax are the most sensitive indicators of pore structure and can serve as good indicators of the pore structure type. This pore structure classification method based on multifractal analysis and K-means clustering can be effectively used to classify the pore structure of tight sandstones. This study provides an effective means of pore structure classification and heterogeneity characterization based on thin sections, which is especially valuable in regions without high-pressure mercury injection data.

Temperature effect on gas adsorption capacity in different sized pores of coal: Experiment and numerical modeling

Accurate methane gas adsorption capacity estimation is key for the coalbed methane (CBM) reservoir gas-in-place assessment. As in situ, the reservoir pressure and temperature vary from one location to another. The temperature induced gas sorption capacity evaluation is important for the CBM and mining industry. In this study, grand canonical Monte Carlo (GCMC) simulation was used to investigate temperature effect on methane adsorption capacity and adsorbed methane density for different sized pores. Methane adsorption experiments were performed to show realistic temperature effect on methane adsorption capacity and the experimental data were used directly to validate the numerical model. The pore structure of coal was characterized by high-pressure mercury injection, low-pressure N2 gas adsorption, low-pressure CO2 gas adsorption. The simulation results revealed that, first, temperature influence on methane adsorption was more obvious in smaller pores than that in larger pores. Based on the characteristics of the temperature influence on methane adsorption, pores can be divided into three categories: 0.7–0.9 nm pores, 1.0–1.3 nm pores and pores larger than 1.4 nm. In the 0.7–0.9 nm group, methane adsorption capacity decreased by approximately 19% at 3 MPa from 20 °C to 100 °C. In contrast, in the 1.0–1.3 nm pores and pores larger than 1.4 nm, methane adsorption capacity decreased by approximately 32% and 45%. Second, in 0.7 nm and 1.0 nm pores, methane adsorption capacity decreased linearly with an increase in temperature. In 4.0 nm pores methane adsorption capacity exhibited a negative exponential decrease with increasing temperature at low pressure (<3 MPa). Third, when the pore size was the same, the temperature effect was more obvious at a lower pressure than that at a higher pressure. The experimental results indicated that methane adsorption capacity in the coal sample decreased linearly with temperature increasing, and temperature effect on reducing methane adsorption capacity was greater at low pressure. These experimental results were consistent with the simulation results. Based on simulation and experimental data, it was obvious that temperature-induced gas adsorption capacity variation was both pore size dependent and pressure dependent.

Pore throat characteristics of tight sandstone of Yanchang Formation in eastern Gansu, Ordos Basin

An important factor to evaluate reservoir quality is the pore-throat size. However, the strong heterogeneity makes it difficult to characterize the pore-throat distribution in tight reservoirs. The field emission scanning electron microscope (FESEM), high pressure mercury injection and rate-controlled mercury injection are used to investigate the pore-throat size distribution in tight sandstone reservoirs of Member 7 of the Yanchang Formation in eastern Gansu, Ordos Basin, and studies of the pore throat size controlling on physical property of the tight sandstone reservoirs are also carried out. The result shows that the pore type is mainly dominated by the residual intergranular pore, dissolution pore, micropore and a few micro-fractures; the high-pressure mercury injection experiment indicates that the pore-throat size ranges from 0.0148 μm to 40 μm, the pore throat more than 1 μm is less; the rate-controlled mercury injection experiment reveals that for samples with different physical properties, the pore radius mainly varies from 80 μm to 350 μm; the throat radius exhibits the strong heterogeneity, and is from 0.12 μm to 30 μm; the pore-throat size can be effectively characterized by combination of high-pressure and rate-controlled mercury injections, and it varies from 0.0148 μm to 350 μm. The permeability is mainly controlled by the large pore throat (>R50) which accounts for a small proportion; in the tight sandstone with the permeability greater than 0.1 mD, the permeability is mainly controlled by the micropore and mesopore; in the tight sandstone with the permeability smaller than 0.1 mD, the permeability is mainly controlled by the nanopore and micropore; the proportion of small pore throat increases with reduction of permeability, it is important that the small pore throat influences the reservoir storage property though its effect on permeability are small.

Whole-aperture characteristics and controlling factors of pore structure in the Chang 7th continental shale of the Upper Triassic Yanchang Formation in the southeastern Ordos Basin, China

Quantitative assessment is still lacking on the pore-sizes distribution of micropores and mesopores, and the major controlling factors remain enigmatic for the continental Chang 7th shale reservoirs in southeastern Ordos Basin. In this study, scanning electron microscopy, organic geochemical analysis, low-temperature gas adsorption, high-pressure mercury injection, and X-ray diffraction analysis were conducted on 29 core samples from representative eight wells in the Xiasiwan-Yanchang area, yielding a particular investigation on characteristics and controlling factors of the structure in the Chang 7th shale. The Chang 7th shale is mainly characterized by organic and secondary micropore and mesopore, respectively, ranging the peaks of pore size from 0.35 to 0.65 nm, 0.75 to 1.00 nm, 1.10 to 1.35 nm, and from 4 to 13 nm. Whole-aperture characterization of the pore structure shows that meso- and macropores demonstrate a major contribution to total pore volume (PV), and the surface area is mainly provided by micro- and mesopores with pore radii less than 20 nm. A weak positive variation was identified between the PV of micromesopores and total organic carbon content, implying that micropores are currently in the process of developing. The micromesopore specific surface area and volume, respectively, yield a significant positive and weak variation with the quartz and clay mineral content, suggesting that siliceous minerals are favorable for micromesopore development. The infusion of siliceous biogenic debris and silica-replaced carbonate biogenic debris from the northeastern and southwestern source areas, respectively, is likely responsible for development of biogenic siliceous minerals in the Chang 7th shale. Furthermore, the hollow cavities in siliceous organisms have considerably contributed to the preservation of primary pores owing to their characteristic skeleton-supported framework.

Characterization of Microscopic Pore Structures of Rock Salt through Mercury Injection and Nitrogen Absorption Tests

Microscopic pore structure of rock salt plays a dominant role in its permeability. In this paper, microscopic pore structure of a set of rock salt samples collected from Yunying salt mine of Hubei province in China is investigated by high pressure mercury injection, rate-controlled mercury penetration, and nitrogen absorption tests. The pore size distribution is further evaluated based on fractal analysis. The results show that pore size of rock salt varies from 0.01 to 300 μm with major concentration of pore size smaller than 1.00 μm. The pore’s radiuses are mainly distributed within a range between 15 and 50 nm. The research further reveals that the pore channel size of rock salt is randomly distributed, but the distribution of pore throat radius fits very well with fractal law. By analysis of permeability, it is found that the maximum and medium radius of the pore throat have significant impacts on permeability. Porosity is not apparently related to the permeability of rock salt. The higher the fractal dimension is, the higher the impacts on permeability of the small throat are detected and the lower the influence on permeability of the big throat is exhibited. It indicates that the small throat determines majorly the permeability of rock salt. The findings obtained from this study provide an insight into understanding the characteristics of microscopic pore structure of rock salt.

Advancing CO2 enhanced oil recovery and storage in unconventional oil play—Experimental studies on Bakken shales

Although well logs and core data show that there is significant oil content in Bakken shales, the oil transport behavior in these source rocks is still not well understood. This lack of understanding impedes the drilling and production operations in the shale members. A series of experiments were conducted to investigate the rock properties of the Bakken shales and how to extract oil from the shales using supercritical CO2. High-pressure mercury injection tests showed that pore throat radii are less than 10nm for most pores in both the upper and lower Bakken samples. Such small pore sizes yield high capillary pressure in the rock and make fluid flow difficult. Total organic carbon content was measured using 180 shale samples, and kerogen was characterized by Rock-Eval pyrolysis, which indicated considerable organic carbon present (10–15wt%) in the shales. However, oil and gas are difficult to mobilize from organic matter using conventional methods. A systematic experimental procedure was carried out to reveal the potential for extracting hydrocarbons from the shale samples using supercritical CO2 under typical Bakken reservoir conditions (e.g., 34.5MPa and 110°C). Results showed that supercritical CO2 enables extraction of a considerable portion (15–65%) of hydrocarbons from the Bakken shales within 24 h. Measurement of CO2 adsorption isotherm showed that Bakken shale has a considerable capability to trap CO2 (up to 17mg/g) under a wide range of pressures. The experimental results suggest the possibility of using supercritical CO2 injection to increase the ultimate oil recovery and store a considerable quantity of CO2 in the Bakken Formation.

Evolution of the deeply buried Jurassic reservoirs in the southern Junggar Basin, NW China: Evidences from the Well DS-1

The southern Junggar Basin has enormous hydrocarbon mainly from the Jurassic and Permian source rocks, which indicated the importance of exploration of the deeply buried Jurassic reservoirs, therefore, the study of the deeply buried Upper Jurassic Qigu Formation (J3q) reservoirs in Well DS-1 in the Dushanzi anticline was carried out through microscopic observation and measurement, nuclear magnetic resonance (NMR), scanning electron microscopy (SEM) and high pressure mercury injection. Results showed that the main reservoir storage spaces in the deeply buried Upper Jurassic Qigu Formation reservoirs were fractures and dissolved pores. The J3q reservoirs with low porosity and permeability values of 0–12% and (0–5) × 10−3μm2 respectively, were generally tight. According to the mercury injection data, heterogeneity existed in the deeply buried Qigu Formation reservoirs with inhomogeneous pores and changeable sizes of pores throats. Pores and pore throats in the silt-fine sandstones of the lower Qigu Formation (J3q1) were more big and wide respectively than that in the argillaceous siltstones of the upper Qigu Formation (J3q3). Reservoirs in J3q1 had more mobile fluid and better conductivities than reservoirs in J3q3. The strong compaction and multistage diagenesis resulted in the tight J3q reservoirs. Anhydrite and quartz cementation, and various authigenetic minerals (e.g. hematite, kaolinite, illite/smectite formation, illite, chlorite and zeolite) filled in the pores. The homogenization temperature of brine inclusions (63.1–161.7 °C) in quartz overgrowth indicated the quartz had grown since the late Eocene. Due to the Tian Shan reactivity in the Late Cenozoic, the structure fractures were developed and promoted dissolution by oil and formation water in the reservoirs of J3q1.

Characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag

Zhanhua Sag is a widely accepted target zone with huge exploration and development potential for shale oil and shale gas resources. Many detailed studies have been undertaken around the geochemistry of the lower section of the third member of the Shahejie Formation (Es3x), while few studies have focused on the reservoir. In this study, based on the mineralogical features and geochemical characteristics, and by using statistical methods, the characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag are explored through field-emission scanning electron microscopy (FE-SEM), high pressure mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) techniques. Three major findings were obtained. ① There are micropores and microfractures in the reservoir space, which include intergranular pores, clay intercrystal pores, pyrite intercrystal pores, dissolved pores, structural microfractures, and bedding microfractures. ② According to the features of pore size distribution (PSD), the pore distribution can be divided into the following three categories: 0–50 nm, 50 nm–2 μm, and >2 μm; the average volumes of these components are 0.01079 mL g−1, 0.00361 mL g−1, and 0.00355 mL g−1, respectively, thus showing that the pores whose radii are distributed at 0–50 nm form the most important reservoir space (though those with the 50 nm–2 μm and >2 μm radii are also important and cannot be ignored). ③ There are different controlling factors when it comes to different scale pores. Based on statistics and FE-SEM results, the dissolved pores in calcite were determined to be the controlling factor for the 0–50 nm portion, the intercrystalline pores in clay and pyrite, and intergranular pores between authigenic minerals (calcite, dolomite, and pyrite) and clastic minerals (calcite and dolomite) were determined to be the controlling factors for the 50 nm–2 μm portion, and the structural microfractures and bedding microfractures were determined to be the main factors for the >2 μm portion. Furthermore, it is the brittle minerals content and bedded structure that control the microfractures. This study thus clarifies the types and characteristics of reservoir space and identifies pore structure controlling factors of mudstone and shale in Es3x in the Zhanhua Sag; this information has important significance for future reservoir evaluations.

Multi-scale fractal characterizations of lignite, subbituminous and high-volatile bituminous coals pores by mercury intrusion porosimetry

Pore fractal models, including thermodynamics and classic geometry models, can help quantify pore structure. To evaluate the effect of the pore structure on coal permeability, we calculated the multi-scale fractal dimensions and discussed factors influencing pore fractals, including coal petrology and coal reservoir parameters. We investigated pore physical properties, including of the pore size/volume distribution, pore structure and pore heterogeneity for lignite, subbituminous and high-volatile bituminous coals (LSBC) in the Southern Junggar Basin, NW China. The multi-scale fractal dimensions of coal pores according to classic geometry models (Dc1, Dc2, Dc3 and Dc4) are in the range of 3.15–4.26, 2.42 to 3.92, 2.30 to 3.60 and 2.35 to 5.41, respectively. The abnormal fractal dimensions (D > 3) can be attributed to high pore heterogeneity, fractures that existed in coals and pore compressibility during a high-pressure mercury injection. The fractal dimension (Dc) and Ro, m generally presented an inverted ‘U-shaped’ tendency with maxima occurring at 0.6% Ro, m, which was mainly caused by variations in the macropore volume by the first coalification jump. It was found that the multi-scale fractal dimensions of classic geometry model is more appropriate for describing pore heterogeneity in LSBC. The micropore/macropore volumes and the fractal dimension (Dc3 and Dc4) were predominant indices of pores connectivity (IMS and EMW). A ‘U-shaped’ trend was obtained between the permeability contribution and macropore fractal dimension (2.6–2.7 for Dc4), similar to EMW/IMS vs. the macropore fractal dimension. These conclusions coincided with that of good pore connectivity representing high permeability and can have high feasible applications in CBM exploration and exploitation. High heterogeneity coals with developed macropores may contribute significantly to coal permeability in LSBC reservoirs.

Characteristics and controlling factors of shale gas reservoir in the Fuling area, Sichuan Basin

Statistical analysis of massive laboratory analytical data shows that for intervals in the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation in the Fuling area, Sichuan Basin, the total organic carbon content is 0.55%–5.89% with an average of 2.54%, presenting a gradual increase trend from top to bottom. Based on whole-rock X-ray diffraction data, the content of clay minerals of the shale is 16.6%–62.8% with an average of 40.9%, gradually decreasing from top to bottom. The content of brittle minerals gradually increases from top to bottom, ranging from 37.2% to 83.4% with an average of 59.1%. Porosity is 1.17%–7.98% with an average of 4.61% through the helium injection method. The horizontal permeability is 0.002–335.209 mD with an average of 23.785 mD by the steady-state method. Massive analytical data from the high-pressure mercury injection method show the micropores are well developed in the shale, and mainly provide the primary specific surface area of pores, while the micropores, transitional pores and mesopores primarily contribute to permeability. The pore types were observed using SEM in combination with argon ion polishing technology. From top to bottom of the shale interval, the organic pores increase and the inorganic pores decrease. Gas desorption data show that the total gas content is 0.44–5.19 m3/t with an average of 1.97 m3/t, and gradually increase from top to bottom of the shale interval. The development of marine shale gas reservoir in Well A is controlled by mineral compositions, the development characteristics of organic matter. TOC is not only a major intrinsic factor controlling the lower reservoir interval, but also an important material to provide the reservoir space for the shale gas. In the late diagenetic stage, the clay mineral assemblages changed from montmorillonite to illite, forming new micropores and leading to an increase of the porosity and great influences on the upper reservoir interval. The content of brittle minerals is more than 50%, facilitating formation of fractures, and the permeability performance can be enhanced significantly. In general, the Wufeng Formation and the bottom interval of the Longmaxi Formation are both high-quality reservoirs and primary pay intervals.