Porous Reservoir Research Articles

The influence of pore throat heterogeneity and fractal characteristics on reservoir quality: A case study of chang 8 member tight sandstones, Ordos Basin

The Chang 8 member of the Yanchang Formation in the Ordos Basin exhibits extensive development of tight sandstone reservoirs. In comparison to conventional reservoirs, these tight sandstone reservoirs demonstrate smaller pore-throat systems and stronger heterogeneity due to interactions between inherent sedimentary components and various diagenetic processes. To further investigate the influence of microscopic pore throat structure on macroscopic physical properties and oil content within the reservoir, a comprehensive study was conducted utilizing high pressure mercury injection, nuclear magnetic resonance, X-CT scanning, and other pore throat testing methods. This study was complemented by observation techniques such as polarizing microscope, scanning electron microscopy, and laser confocal imaging, to study the pore throat system of reservoirs under the influence of different sedimentary components and diagenesis. By comparison, it is observed that the radius of the primary pore throat system in the tight sandstone reservoir ranges from 0.01 to 1 μm. The structural characteristics of the pore throat system significantly impact the macroscopic physical properties of the reservoir. Due to variations in testing methods, high pressure mercury injection, nuclear magnetic resonance (NMR), and X-ray computed tomography (X-CT) reveal different fractal dimensions of the reservoir's pore throat system. Therefore, it is better to respectively utilize fractal dimension Df2, Df2-NMR, Df2-CT, and pore throat parameters to characterize the microscopic pore throat system with a radius ranging from 0.01 to 1 μm. The decrease in the average pore throat radius and the increased irregularity of pore shape contribute to heightened heterogeneity in the micro-pore throat structure within the reservoir. This negatively impacts its physical properties and oil content. Furthermore, it is important to note that the minimum threshold of pore throat radius plays a crucial role as a primary factor determining the fluid seepage capacity within this reservoir. Moreover, when isolated pores exist, reduced fluid mobility ensues, which further worsens the seepage conditions of the reservoir. The chlorite rims development reservoir shows a low fractal dimension in its micro-pore throats, contributing to superior macroscopic petrophysical properties and oil content. However, compression, siliceous cementation, and calcite cementation negatively impact the average pore throat radius by increasing micropores, inaccessible pores, and narrow throat content. This results in a stronger heterogeneity of the pore throat structure, leading to poor seepage conditions and lower oil content.

Unlocking thin sand potential: a data-driven approach to reservoir characterization and pore pressure mapping

The gradual decline of production of the major fields of the Indus Basin has influenced the field pressure. Therefore, the prospects need to be assessed by the petro-elastic relationship. This study highlights the value-addition for identifying gas pockets within the E-Sand of the Lower Goru Formation through estimating and populating petro-elastic properties. A probabilistic neural network (PNN) was employed to develop the relationship of pore pressure to the inverted properties. The outcomes will help identify the high-pressure areas in accordance with the petro-elastic relationship for optimizing production strategy. In order to evaluate the petro-elastic relationship, stochastic seismic inversion was employed to holistically capture the reservoir’s variability. Pore pressure volumetric was estimated from inverted attributes using a PNN, a non-linear algorithm that was more suited to heterogeneous reservoirs. The main objective of the research is achieved via enhanced resolution of elastic properties attained through the integration of stochastic inversion and PNN processes. The high-resolution elastic properties including P-impedance, S-impedance, and Vp/Vs ratio can delineate the heterogeneities more profoundly. The petrophysical volumes obtained via enhanced inverted properties combined with pore-pressure through PNN illuminated the potential facies and the correlations in predicting the properties. The procedure provides a linkage of elastic, petrophysical, and geomechanical properties that is helpful for professionals covering a broad field of the petroleum sector. The developed workflow can be followed globally where problems occur regarding heterogeneities and early depletion.

Analysis of heat and mass transfer rates in conducting Casson fluid flow over an expanding surface considering Ohmic heating and Darcy dissipation effects

In a recent scenario, the flow of Casson fluid via porous media has practical applications in various engineering processes, such, as the design of cooling systems for electronic devices, oil recovery in porous reservoirs, and polymer extrusion processes, etc. The proposed investigation illustrates the thermal and solutal transfer rates in a conducting Casson fluid flow over an expanding surface. However, the emphasis goes to the behavior of the Ohmic heating and Darcy dissipation when considering the transverse magnetic field and porous matrix. The governing flow phenomena with their dimensional form are altered into a non-dimensional set of equations with the help of suitable similarity rules. Further, an adequate numerical simulation is adopted to solve the transformed equations using the in-house bvp4c function in MATLAB. The physical parameters involved in the flow problem and their behavior on the governing flow phenomena are presented graphically and described briefly. Prior to this investigation, the conformity of the current numerical output obtained for the heat transfer rate was validated with the earlier work with a good correlation. Moreover, the major outcomes are; the non-Newtonian Casson parameter retards the axial and transverse velocity profile and the shear rate also decreases significantly. The Eckert number caused by the inclusion of the dissipative heat encourages the fluid temperature throughout.

Application of Raman spectroscopy for analyzing the behavior of gases in sandstone reservoirs

The behavior of gases within subsurface pores determines the oil and gas recovery and CO2 storage in the region. In this study, we report a novel method based on Raman spectroscopy for observing the distributions of CH4 and CO2 gases in the pores of sandstone reservoirs. First, we designed a pressure-cell to inject gases into a sample. Then, CH4 and CO2 gases were injected into the sample using the pressure-cell placed on the Raman spectroscopy system sample stage. Quartz and feldspar were the predominant minerals in the sample. The CH4-occupied pores exhibited a Raman peak at 2917 cm−1. Two-dimensional (2D) and three-dimensional (3D) mapping of the pores depicted the geometry of the CH4 gas-filled pores. After injecting CO2 gas, we observed an intensity peak at 1388 cm-1; we obtained 2D and 3D maps of the CO2 gas-filled pores based on this peak value. This study demonstrates the potential use of Raman spectroscopy as a visualization tool to reveal the pore geometry of sandstone reservoirs and determine the distribution of gases within such reservoirs. Our study can serve as a foundation for understanding the behavior of gases in subsurface reservoirs, improving oil and gas prospecting and exploration, and assessing CO2 storage..

Pore Characteristics of Hydrate-Bearing Sediments from Krishna-Godavari Basin, Offshore India

Pore-filling hydrates are the main occurrence forms of marine gas hydrates. Pore characteristics are a vital factor affecting the thermodynamic properties of hydrates and their distribution in sediments. Currently, the characterization of the pore system for hydrate-bearing reservoirs are little reported. Therefore, this paper focuses on the Krishna-Godavari Basin, via various methods to characterize the hydrate-bearing sediments in the region. The results showed that X-ray diffraction (XRD) combined with scanning electron microscopy (SEM) and cast thin section (CTS) can better characterize the mineral composition in the reservoir, high-pressure mercury injection (HPMI) focused on the contribution of pore size to permeability, constant-rate mercury injection (CRMI) had the advantage of distinguishing between the pore space and pore throat, and nuclear magnetic resonance cryoporometry (NMRC) technique can not only obtain the pore size distribution of nanopores with a characterization range greater than nitrogen gas adsorption (N2GA), but also quantitatively describe the trend of fluids in the pore system with temperature. In terms of the pore system, the KG Basin hydrate reservoir develops nanopores, with a relatively dispersed mineral distribution and high content of pyrite. Rich pyrite debris and foraminifera-rich paleontological shells are observed, which leads to the development of intergranular pores and provides more nanopores. The pore throat concentration and connectivity of the reservoir are high, and the permeability of sediments in the same layer varies greatly. The reason for this phenomenon is the significant difference in average pore radius and pore size contribution to pore permeability. This article provides a reference and guidance for exploring the thermodynamic stability of hydrates in sediments and the exploration and development of hydrates by characterizing the pores of hydrate reservoirs.

Factors Controlling Differences in Morphology and Fractal Characteristics of Organic Pores of Longmaxi Shale in Southern Sichuan Basin, China

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments.

FEATURES OF THE LITHOLOGICAL STRUCTURE AND DEVELOPMENT OF RESERVOIR ROCKS AND HYDROCARBON RESERVOIRS IN THE MIDDLE DEVONIAN SEDIMENTS OF THE SOUTHERN PART OF THE TUZLIV DEPRESSION (DOBRUDJA FOREDEEP)

The aim of the work was to clarify the features of the lithological structure of the Middle Devonian sediments of the Zhovtoyarska-Tuzlivska and Biloliska-Zarichnenska prospective areas of the Dobrudja Foredeep and to determine its influence on the formation of reservoir rocks, traps and hydrocarbon reservoirs. The research was based on the results of geophysical research of wells (radioactive methods) in combination with fragmentary geological (lithological) data. As a result, 9 lithocycles of regressive nature were identified in the section for the first time (e-1 – e-5; g-1 – g-4). Each lithocycle is characterized by a two-membered structure and represents a separate productive horizon (PH). The lower parts of the latter are composed of porous and fractured reservoir rocks (limestones, dolomites, siltstones, sandstones), and the upper parts are composed of fluid-resistant packs (marls, anhydrites). It has been shown that cyclites are grouped into larger units (mesocyclites) of re- or progressive nature, which in different wells (in separate intervals) exhibit a certain similarity or difference in structure. Such spatial and age variability is caused, on the one hand, by the placement of wells in different facies zones of the sulfate-carbonate shelf, and on the other, by the processes of interaction of synsedimentary tectonic movements and paleoceanographic (sea level changes, etc.) factors. The consequence of this is the lateral lithological heterogeneity, which in the petrogeological aspect is manifested in the morphological features of the reservoirs and the character of the development of various types of reservoirs and ultimately determines, taking into account secondary rock changes, the prospects of specific productive horizons. Thus, for the Zhovtoyarska-Tuzlivska area, the vaulted trap is localized near borehole Zhovtoyarska-1 (e-1, e-2 productive horizons), according to other horizons it is fixed near borehole Zhovtoyarska-2. The development of lithological traps is predicted in e-1, e-3 and e-4 productive horizons, which is associated with the wedging of pore reservoirs in the direction from borehole Tuzlivska-2 to borehole Zhovtoyarska -2 and -1. For most productive horizons, the quality of reservoir rocks is expected to deteriorate in the same direction, which suggests the possibility of catagenetic screening of fluids. For the Biloliska-Zarichnenska area, along all productive horizons, trap vaults are localized near borehole Zarichnenska-1 or further south. The most capacious are the traps of horizons e-1, e-4 and e-5, composed mainly of pore-type collectors, the quality of which is low due to anhydritization. The best reservoir rocks are predicted in the Givetian sediments (g-2 – g-4 productive horizons) of borehole Zarichnenska -1.

Quantitative classification evaluation model for tight sandstone reservoirs based on machine learning

Tight sandstone reservoirs are a primary focus of research on the geological exploration of petroleum. However, many reservoir classification criteria are of limited applicability due to the inherent strong heterogeneity and complex micropore structure of tight sandstone reservoirs. This investigation focused on the Chang 8 tight reservoir situated in the Jiyuan region of the Ordos Basin. High-pressure mercury intrusion experiments, casting thin sections, and scanning electron microscopy experiments were conducted. Image recognition technology was used to extract the pore shape parameters of each sample. Based on the above, through grey relational analysis (GRA), analytic hierarchy process (AHP), entropy weight method (EWM) and comprehensive weight method, the relationship index Q1 between initial productivity and high pressure mercury injection parameters and the relationship index Q2 between initial productivity and pore shape parameters are obtained by fitting. Then a dual-coupled comprehensive quantitative classification prediction model for tight sandstone reservoirs was developed based on pore structure and shape parameters. A quantitative classification study was conducted on the target reservoir, analyzing the correlation between reservoir quality and pore structure and shape parameters, leading to the proposal of favourable exploration areas. The research results showed that when Q1 ≥ 0.5 and Q2 ≥ 0.5, the reservoir was classified as type I. When Q1 > 0.7 and Q2 > 0.57, it was classified as type I1, indicating a high-yield reservoir. When 0.32 < Q1 < 0.47 and 0.44 < Q2 < 0.56, was classified as type II. When 0.1 < Q1 < 0.32 and 0.3 < Q2 < 0.44, it was classified as type III. Type I reservoirs exhibit a zigzag pattern in the northwest part of the study area. Thus, the northwest should be prioritized in actual exploration and development. Additionally, the initial productivity of tight sandstone reservoirs showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. Conversely, it demonstrated a negative correlation with the median pressure and displacement pressure. The perimeters of pores, their circularity, and the length of the major axis showed a positive correlation with the porosity, permeability, sorting coefficient, coefficient of variation, and median radius. On the other hand, they exhibited a negative correlation with the median pressure and displacement pressure. This study quantitatively constructed a new classification and evaluation system for tight sandstone reservoirs from the perspective of microscopic pore structure, achieving an overall model accuracy of 93.3%. This model effectively predicts and evaluates tight sandstone reservoirs. It provides new guidance for identifying favorable areas in the study region and other tight sandstone reservoirs.

Fractal research on pores in oil and gas reservoirs - Inspirations from over 700 high pressure mercury injection experiments

Pore fractal has now become an important research method to study reservoir pore heterogeneity and complexity, and is widely used in unconventional reservoir research. However, its guiding significance for reservoir research and the relationship between fractal dimension and reservoir pore structure parameters are not yet clear. This undoubtedly hinders the further development of fractal in reservoir research. This time, comprehensive research, including pore fractals, was conducted on over 700 high-pressure mercury injection experiments, providing guidance for reservoir pore fractal research. The research results indicate that there are significant differences in the application of fractals in different oil fields. Generally, the curves of high-pressure mercury injection experiments present 1–4 segment fractals, among which the 2 and 3 segment fractals are the most common, and the 4 segment fractals are the least common. There is a correlation between the number of the fractal segments with permeability and pore throat sorting coefficient. The lower the permeability, the more obvious the multi-segment fractal features. The more fractal segments, the greater the fractal dimension corresponding to each segment. The number of fractal segments can characterize the distribution of reservoir pore size. The fractal dimension of large pore-throats is greater than that of small pore-throats. On the whole, there is a negative correlation between fractal dimension and permeability, porosity, and pore throat radius. But this correlation is unstable in different oilfields. And the average value of the overall correlation coefficient is only about 0.5. Different fractal segments in a multi-segment fractal represent different types of pores. The application of pore fractal dimension needs to be combined with pore types.

An analytical solution model of oil–water dynamic imbibition considering dynamic contact angle effect and osmotic pressure at micro-nano scale

Spontaneous imbibition is one of the important mechanisms to enhance oil recovery during hydraulic fracturing process of shale reservoirs. The dynamic contact angle effect in imbibition kinetics of liquid–liquid system is complicated due to the large number of micro-nano pores in shale reservoir. Moreover, the content of clay minerals is high, the chemical osmosis effect is significant, and the impact of osmotic pressure on imbibition is not clear. In order to clarify the dynamic contact angle effect in imbibition kinetics and correctly understand the role of osmotic pressure in imbibition process. In this paper, based on the molecular kinetic theory (MKT), the dynamic contact angle effect is successfully coupled with imbibition kinetic equation, and a capillary pressure equation is developed. On the basis, considering the effects of osmotic pressure, external displacement pressure and boundary layer effect on imbibition, An analytical solution model of oil–water dynamic imbibition model is developed. The results shows that under the respective effects of capillary pressure and osmotic pressure, the imbibition velocity initially stabilizes before increasing over time; under the action of displacement pressure, the imbibition velocity increases with time. Imbibition velocity is directly proportional to interfacial tension and capillary radius, but inversely proportional to contact angle and oil viscosity. With the salt concentration difference increasing from 80 mol/m3 to 4710 mol/m3, the imbibition velocity increased by about 54 times. Compared with the membrane efficiency of 30 % and 5 %, the imbibition velocity is increased by 4.95 times. In this work, the dynamic contact angle effect in the imbibition kinetics of liquid–liquid system was accurately characterized, clarified the action mechanism of osmotic pressure, and provided theoretical support for enhancing oil recovery of shale reservoirs.

TECHNOLOGICAL COMPLICATIONS (FORMATION DAMAGE) DURING CO2 INJECTION FOR ENHANCED OIL RECOVERY. Part 2. INTERACTION OF CO2 WITH FORMATION OIL: WETTABILITY CHANGE, ASPHALTENE PRECIPITATION AND DEPOSITION IN THE FORMATION

In the second part of the review (the first part was published in [1]) the processes of formation damage at CO2 injection due to the oil phase stability disturbance are considered. Changes in reservoir temperature, pressure or fluid composition due to CO2 dissolution can provoke asphaltene precipitation and deposition. Their adsorption on the reservoir pore surface leads to a change in decrease in rock permeability. The currently ac wettability and a cepted numerical models describe well the experimental results on colmatation of pore media by asphaltenes in the presence of CO2, with different equations for asphaltene adsorption and kinetics of their occurrence being used in the models. Asphaltenes precipitated in pore volumes migrate with formation fluids to production wells and can form deposits that complicate oil production.

CO2-Induced In-Situ Targeted Precipitation of Asphaltene in Heavy Oil Reservoirs: Balancing Formation Gas Channeling Regulation and Wellbore Asphaltene Blockage Prevention

Summary To investigate the mechanisms of the asphaltene precipitation in oil caused by CO2, the sandstone core oil displacement experiments and asphaltene structure observation experiments are designed in this work. The oil displacement experiments create CO2 flooding conditions under different pressures in heavy oil reservoirs and analyze the produced oil components and precipitated asphaltene proportions. Meanwhile, nuclear magnetic resonance (NMR) analysis is conducted on the sandstone cores to discuss the precipitation characteristics of asphaltene in the reservoir pores. The observation experiments analyze the microstructure of precipitated asphaltene after interactions between oil and CO2. The results show that the increasing pressure promotes the precipitation of asphaltene from oil by enhancing the dissolution and component extraction of CO2 in oil, which reduces oil viscosity and promotes reservoir development efficiency. This process also leads to an increase in CO2 sequestration in the reservoir. However, the precipitated asphaltene reduces reservoir permeability, hindering the optimization of the oil recovery rate. During the process of increasing pressure, the rate of increase in oil recovery decreases. In reservoirs containing oil with high asphaltene proportion, the oil recovery rate even decreases under high pressure. Additionally, in-situ targeted precipitation and retention of asphaltenes in large pores can reduce the distribution differences of pores with different sizes in the reservoir, weakening the above negative effects and enhancing oil recovery by regulating gas channeling. Moreover, the ratio of resin in oil affects the asphaltene precipitation form, and CO2 can promote the association of asphaltenes by weakening the steric stabilization effect of resin on asphaltene in oil, which makes the microstructure of precipitated asphaltenes dense and regular and promotes asphaltene precipitation and oil recovery increasing. This work aims to verify the advantages of CO2-induced asphaltene precipitation in improving the efficient and environmentally friendly development of heavy oil reservoirs, while exploring the significance of CO2 flooding in promoting carbon sequestration.

An efficient reduced order model for nonlinear transient porous media flow with time-varying injection rates

An intrusive Reduced Order Model (ROM) is developed for nonlinear porous media flow problems with transient and time-discontinuous fluid injection rates. The proposed ROM is significantly more computationally efficient than the Full Order Model (FOM). The training regime is generated using the FOM with constant injection rates during the offline stage. The trained ROM exhibits high accuracy for complex pumping schedules (rate vs time) simulated online. The proposed ROM uses the combination of Proper Orthogonal Decomposition and Discrete Empirical Interpolation Method (POD-DEIM), which is compared with the classical POD-Galerkin. The use of an approximated column-reduced Jacobian is shown to be vital to achieving a substantial speedup of ROM vs FOM run-times. An analysis of the trade-off between accuracy and run-time is conducted for ROMs of different sizes and hyper-parameters. The impact of the training regime on the performance of the presented ROM is assessed. The performance of the ROM is studied in the context of a two-dimensional analysis of time-varying injection into a two-well system in a layered porous media reservoir. The accuracy and efficiency of POD-DEIM motivate its potential use as a surrogate model in the real-time control and monitoring of fluid injection processes.

Logging Evaluation of Irreducible Water Saturation: Fractal Theory and Data-Driven Approach—Case Study of Complex Porous Carbonate Reservoirs in Mishrif Formation

Evaluating irreducible water saturation is crucial for estimating reservoir capacity and developing effective extraction strategies. Traditional methods for predicting irreducible water saturation are limited by their reliance on specific logging data, which affects accuracy and applicability. This study introduces a predictive method based on fractal theory and deep learning for assessing irreducible water saturation in complex carbonate reservoirs. Utilizing the Mishrif Formation of the Halfaya oilfield as a case study, a new evaluation model was developed using the nuclear magnetic resonance (NMR) fractal permeability model and validated with surface NMR and mercury injection capillary pressure (MICP) data. The relationship between the logarithm mean of the transverse relaxation time (T2lm) and physical properties was explored through fractal theory and the Thomeer Function. This relationship was integrated with conventional logging curves and an advanced deep learning algorithm to construct a T2lm prediction model, offering a robust data foundation for irreducible water saturation evaluation. The results show that the new method is applicable to wells with and without specialized NMR logging data. For the Mishrif Formation, the predicted irreducible water saturation achieved a coefficient of determination of 0.943 compared to core results, with a mean absolute error of 2.37% and a mean relative error of 8.46%. Despite introducing additional errors with inverted T2lm curves, it remains within acceptable limits. Compared to traditional methods, this approach provides enhanced predictive accuracy and broader applicability.

Formation mechanism of deep to ultra-deep carbonate reservoir: a case study of the Ediacaran Dengying Formation, Penglai area, Sichuan Basin

The formation of high-quality deep to ultra-deep carbonate reservoirs presents a topic worthy of thorough exploration. Focusing on the Ediacaran (Sinian) Dengying Formation in the Penglai area of the Sichuan Basin, we analysed genesis mechanisms of deep to ultra-deep marine carbonate reservoirs through drilling/logging, seismic data and analytical tests, which showed the dolomite reservoir primarily consists of secondary solution pores and cavities, exhibiting characteristics of vertical overlap and horizontal continuous distribution. The microbial mound beach, which represents the main dominant facies type within the reservoir, can be categorised into three types: high-quality reservoir, medium-quality reservoir and poor reservoir. The reservoir has undergone five stages: syngenetic to quasi-syngenetic, shallow burial, supergene, burial and deep burial adjustment stages. It is postulated that the development of deep to ultra-deep carbonate reservoirs is governed by sedimentary facies, with the type and structure of carbonate influencing the development and evolution of reservoir pores. Multiphase diagenetic fluids further modify and enhanced the properties of the reservoirs. Deep and ultra-deep carbonate reservoirs exhibit strong heterogeneity, and high-quality reservoirs are characterised by multi-factor joint control and multi-stage composite genesis. The lithological and structural–lithological traps associated with them commonly cluster in large areas so effective identification of favourable sedimentary facies and reservoirs is crucial for predicting deep to ultra-deep carbonate reservoirs, characterising traps and improving the success rate of drilling.

Soret effect on the mixing of H2 and CO2 cushion gas: Implication for underground hydrogen storage

For underground hydrogen storage (UHS), hydrogen (H2) injection and withdrawal will create a temperature difference between the wellbore and the reservoir. The thermal diffusion driven by the temperature gradient (Soret effect) may enhance the mixing between H2 and cushion gas and affects the purity of the produced H2. In this work, the thermal diffusion process of H2 and CO2 under reservoir conditions is quantitatively observed for the first time. Results show that the Soret effect drives H2 accumulation in the high-temperature region, and is influenced by temperature, pressure, and concentration. There is significant concentration difference between the high- and low-temperature sections when minor quantities of gas are injected. From experimental observations, we obtain the Soret coefficients across different physical conditions and propose a correlation for their prediction. Additionally, while thermal diffusion slows down in porous reservoirs, the concentration difference established along the temperature gradient remains unchanged at steady state.

Research on the molecular dynamics of coalbed methane diffusion and adsorption in reservoir pores under different factors

Research on the molecular dynamics of coalbed methane diffusion and adsorption in reservoir pores under different factors

Application of the EBSD Technique in the Study of Porosity and Permeability in Deformation Bands in Sandstone.

Deformation bands are common constituents of porous clastic fluid reservoirs. Various techniques have been used to study deformation band structure and the associated changes in porosity and permeability. However, the use of electron backscatter diffraction technique is limited. Thus, more information is needed regarding the crystallographic relationships between detrital crystals, which can significantly impact reservoir rock quality. We employ microscopic and microstructural investigation techniques to analyze the influence of cataclastic deformation bands on pore space. Porosity measurements of the Cretaceous Ilhas Group sandstone in NE Brazil, obtained through computerized microtomography, indicate that the undeformed domains exhibit a total porosity of up to 13%. In contrast, this porosity is slightly over 1% in the deformation bands. Scanning electron microscopy analyses revealed the presence of grain fragmentation and dissolution microstructures, along with cement-filling pre-existing pores. The electron backscatter diffraction analyses indicated extensive grain fragmentation and minimal contribution from intracrystalline plasticity as a deformation mechanism. However, the c axes of quartz crystals roughly align parallel to the orientation of the deformation band. In summary, we have confirmed and quantified the internal changes in a deformation band cluster, with grain size reduction and associated compaction as the main mechanism supported by quartz cementation.

Research on the influence of dynamic contact angle of mercury meniscus on the interpretation of rock pore throat radius in mercury intrusion experiments

Addressing the lack of measurement methods for dynamic contact angles of mercury meniscus in mercury intrusion porosimetry experiments and the unclear understanding of the impact of dynamic contact angles on the interpretation of pore throat radius in rocks, a new type of closed mercury intrusion characteristic curve (O-R curve) is constructed utilizing the withdrawal curve O and the secondary injection curve R obtained from the experiments. Based on the excellent wetting and de-wetting correlation characteristics at the equal mercury saturation points on this curve, a method for measuring the dynamic contact angles of mercury meniscus (O-R loop method) is established. Taking the Chang 63 tight oil reservoir samples from the Nanliang Oilfield in the Ordos Basin of China as an example, this method is applied to investigate the dynamic contact angles of mercury meniscus in mercury intrusion porosimetry experiments and the impact on the interpretation of pore throat radius in rocks. The results indicate that the dynamic contact angles of mercury meniscus changes significantly during the experiments, which cannot be ignored. And the smaller pore throats lead to more severe deformation of mercury meniscus, resulting in higher wetting resistance coefficients and hysteresis angles. Calculations reveal that the pore throat radius interpreted using the modified Washburn equation (which adopts dynamic contact angles) are generally larger than those interpreted using the conventional Washburn equation (which adopts static contact angles), with relative errors ranging from 12.2% to 54.7%. The smaller the pore throats, the larger the relative errors. The analysis shows that the conventional Washburn equation significantly underestimates the reservoir pore throat radius due to the neglect of the dynamic contact angle, while the modified Washburn equation provides more accurate interpretation. Overall, this research provides a method for calculating the dynamic contact angle in mercury intrusion porosimetry experiments and has important reference significance for the accurate interpretation of rock pore throat radius.

Multifractal characteristics on pore structure of Longmaxi shale using nuclear magnetic resonance (NMR)

The efficient exploration and extraction of shale gas is essential for China's energy structure as a replacement for natural gas. In this research, shale samples from the Longmaxi Formation in Changning, Sichuan Province were investigated for their pore structure. To achieve this, X-ray diffraction (XRD) and nuclear magnetic resonance (NMR) experiments were performed on the samples. Fractal theory was employed to characterize the pore structure and fractal features of the shale reservoirs. The fractal characteristics of reservoir rocks were correlated with physical parameters and mineral components to identify the controlling factors for the multifractal dimension. The results indicate the following: ① Quartz predominates in the mineral composition of shale in the study area, while clay minerals are the least abundant. ② The primary pore types observed in the samples are bound fluid pores, primarily controlled by mesopores (2 nm ≤ r ≤ 50 nm). ③ The calculated multifractal parameters show that the heterogeneous pore structure exhibits multifractal characteristics. ④ The low probability multifractal parameters Dmin-D0 and αmax-α0 were found to be negatively correlated with reservoir porosity, permeability, and clay mineral content, while the high probability multifractal parameters D0-Dmax and α0-αmin were found to be positively correlated with them. The comprehensive fractal characterization of reservoir rocks demonstrates the applicability of multifractal dimensions in characterizing the heterogeneity of shale reservoir pore structures, which holds potential promise for coal methane exploration.