Saline aquifers are considered as highly favored reservoirs for CO2 sequestration due to their favorable properties. Understanding the impact of saline aquifer properties on the migration and distribution of CO2 plume is crucial. This study focuses on four key parameters—permeability, porosity, formation pressure, and temperature—to characterize the reservoir and analyse the petrophysical and elastic response of CO2. First, we performed reservoir simulations to simulate CO2 saturation, using multiple sets of these four parameters to examine their significance on CO2 saturation and the plume migration speed. Subsequently, the effect of these parameters on the elastic properties is tested using rock physics theory. We established a relationship of compressional wave velocity (Vp) and quality factor (Qp) with the four key parameters, and conducted a sensitivity analysis to test their sensitivity to Vp and Qp. Finally, we utilized visco-acoustic wave equation simulated time-lapse seismic data based on the computed Vp and Qp models, and analysed the impact of CO2 saturation changes on seismic data. As for the above numerical simulations and analysis, we conducted sensitivity analysis using both homogeneous and heterogeneous models. Consistent results are found between homogeneous and heterogeneous models. The permeability is the most sensitive parameter to the CO2 saturation, while porosity emerges as the primary factor affecting both Qp and Vp. Both Qp and Vp increase with the porosity, which contradicts the observations in gas reservoirs. The seismic simulations highlight significant variations in the seismic response to different parameters. We provided analysis for these observations, which serves as a valuable reference for comprehensive CO2 integrity analysis, time-lapse monitoring, injection planning and site selection.

Aiming at the leakage problem in the compact sandstone drilling of the Keziluoyi Formation in Southwest Tarim, Nano-core-emulsion was prepared by coating modified nano-SiO2 with nano-emulsion, its particle size D50 is about 100 nm, with good dispersion stability. When 0.8% Nano-core-emulsion is added to 5% bentonite slurry, the fluid loss can be reduced by 40%, and the filter cake thickness can be reduced by 84%. Using a Nano-core-emulsion to optimize the plugging performance of potassium polysulfonate drilling fluid can reduce the fluid loss of the drilling fluid by 52%, the resulting filter cake is dense and tough, and the thickness is reduced by 40%. Using the pressure conduction method to evaluate the plugging rate, the plugging rate of the drilling fluid of the Nano-core-emulsion on the core of the Keziluoyi Formation is 63.4%, which is 20.9% higher than that of the field drilling fluid. According to microscopic examination and CT scanning analysis, the material has the plugging characteristics of "inner rigid support + outer soft deformation" and has demonstrated good field application results.

Internal multiple interference, affecting both seismic data processing and interpretation, has been observed for long time. Although great progress has been achieved in developing a variety of internal-multiple-elimination (IME) methods, how to increase accuracy and reduce cost of IME still poses a significant challenge. A new method is proposed to effectively and efficiently eliminate internal multiples, along with its application in internal-multiple-eliminated-migration (IMEM), addressing this issue. This method stems from two-way wave equation depth-extrapolation scheme and associated up/down wavefield separation, which can accomplish depth-extrapolation of both up-going and down-going wavefields simultaneously, and complete internal-multiple-elimination processing, adaptively and efficiently. The proposed method has several features: (1) input data is same as that for conventional migration: source signature (used for migration only), macro velocity model, and receiver data, without additional requirements for source/receiver sampling; (2) method is efficient, without need of iterative calculations (which are typically needed for most of IME algorithms); and (3) method is cost effective: IME is completed in the same depth-extrapolation scheme of IMEM, without need of a separate processing and additional cost. Several synthesized data models are used to test the proposed method: one-dimensional model, horizontal layered model, multi-layer model with one curved layer, and SEG/EAGE Salt model. Additionally, we perform a sensitivity analysis of velocity using smoothed models. This analysis reveals that although the accuracy of velocity measurements impacts our proposed method, it significantly reduces internal multiple false imaging compared to traditional RTM techniques. When applied to actual seismic data from a carbonate reservoir zone, our method demonstrates superior clarity in imaging results, even in the presence of high-velocity carbonate formations, outperforming conventional migration methods in deep strata.

To accurately investigate the evolution characteristics and generation mechanism of retained oil, the study analyzed organic-rich lacustrine shale samples from the Paleogene Kongdian Formation in Cangdong Sag, Bohai Bay Basin. This analysis involves Rock-Eval pyrolysis, pyrolysis simulation experiments, Gas Chromatograph Mass Spectrometer (GC–MS), and reactive molecular dynamics simulations (ReaxFF). The results revealed the retained oil primarily consisted of n-alkanes with carbon numbers ranging from C14 to C36. The generation of retained oil occurred through three stages. A slow growth stage of production rate was observed before reaching the peak of oil production in Stage I. Stage II involved a rapid increase in oil retention, with C12–C17 and C24–C32 serving as the primary components, increasing continuously during the pyrolysis process. The generation process involved the cleavage of weak bonds, including bridging bonds (hydroxyl, oxy, peroxy, imino, amino, and nitro), ether bonds, and acid amides in the first stage (Ro =0.50%–0.75%). The carbon chains in aromatic ring structures with heteroatomic functional groups breaks in the second stage (Ro =0.75%–1.20%). In the third stage (Ro =1.20%–2.50%), the ring structures underwent ring-opening reactions to synthesize iso-short-chain olefins and radicals, while further breakdown of aliphatic chains occurred. By coupling pyrolysis simulation experiments and molecular simulation technology, the evolution characteristics and bond breaking mechanism of retained oil in three stages were revealed, providing a reference for the formation and evolution mechanism of retained oil.

Internal multiples are commonly present in seismic data due to variations in velocity or density of subsurface media. They can reduce the signal-to-noise ratio of seismic data and degrade the quality of the image. With the development of seismic exploration into deep and ultradeep events, especially those from complex targets in the western region of China, the internal multiple eliminations become increasingly challenging. Currently, three-dimensional (3D) seismic data are primarily used for oil and gas target recognition and drilling. Effectively eliminating internal multiples in 3D seismic data of complex structures and mitigating their adverse effects is crucial for enhancing the success rate of drilling. In this study, we propose an internal multiples prediction algorithm for 3D seismic data in complex structures using the Marchenko autofocusing theory. This method can predict the accurate internal multiples of time difference without an accurate velocity model and the implementation process mainly consists of several steps. Firstly, simulating direct waves with a 3D macroscopic velocity model. Secondly, using direct waves and 3D full seismic acquisition records to obtain the upgoing and downgoing Green's functions between the virtual source point and surface. Thirdly, constructing internal multiples of the relevant layers by upgoing and downgoing Green's functions. Finally, utilizing the adaptive matching subtraction method to remove predicted internal multiples from the original data to obtain seismic records without multiples. Compared with the two-dimensional (2D) Marchenko algorithm, the performance of the 3D Marchenko algorithm for internal multiple predictions has been significantly enhanced, resulting in higher computational accuracy. Numerical simulation test results indicate that our proposed method can effectively eliminate internal multiples in 3D seismic data, thereby exhibiting important theoretical and industrial application value.

Modified ethylene-vinyl acetate copolymer (EVAM) and amino-functionalized nano-silica (NSiO2) particles were employed as the base materials for the synthesis of the nanocomposite pour point depressant designated as EVAM-g-NSiO2. This synthesis involved a chemical grafting process within a solution system, followed by a structural characterization. Moreover, combining macro-rheological performance with microscopic structure observation, the influence of the nanocomposite pour point depressant on the rheological properties of the model waxy oil system was investigated. The results indicate that when the mass ratio of NSiO2 to EVAM is 1:100, the prepared EVAM-g-NSiO2 nanocomposite pour point depressant exhibits excellent pour point reduction and viscosity reduction properties. Moreover, the nanocomposite pour point depressant obtained through a chemical grafting reaction demonstrates structural stability (the bonding between the polymer and nanoparticles is stable). The pour points of model waxy oils doped with 500 mg/kg ethylene-vinyl acetate copolymer (EVA), EVAM, and EVAM/SiO2 were reduced from 34°C to 23, 20, and 21°C, respectively. After adding the same dosage of EVAM-g-NSiO2 nanocomposite pour point depressant, the pour point of the model wax oil decreased to 12 °C and the viscosity at 32 °C decreased from 2399 to 2396.9 mPa·s, achieving an impressive viscosity reduction rate of 99.9%. Its performance surpassed that of EVA, EVAM, and EVAM/SiO2. The EVAM-g-NSiO2 dispersed in the oil phase acts as the crystallization nucleus for wax crystals, resulting in a dense structure of wax crystals. The compact wax crystal blocks are difficult to overlap with each other, preventing the formation of a three-dimensional network structure, thereby improving the low-temperature flowability of the model waxy oil.

The development of highly active functionalized ionic liquids (ILs) as both extractants and catalysts for use in achieving deep desulfurization continues to pose challenges. In this study, a highly efficient oxidative desulfurization system was constructed, composed of dual-acidic ionic liquids (DILs) and H2O2-AcOH. The investigation results of four DILs prepared from different metal chlorides ([HSO3C3NEt3]Cl-MnCln, MnCln = AlCl3, ZnCl2, CuCl2, FeCl3) in oxidative desulfurization showed that [HSO3C3NEt3]Cl-AlCl3 had an outstanding catalytic effect and significantly promoted the oxidation of sulfides. With a 0.2 g [HSO3C3NEt3]Cl-AlCl3, the removal rate of dibenzothiophene (DBT) reached 100% in 10 mL model oil under mild conditions at 55 °C for 20 min. The key is its ability to induce the dismutation of superoxide anions (•O2−), which facilitates the generation of singlet oxygen (1O2). The efficient oxidation of DBT is accomplished through a predominantly 1O2-mediated non-radical mechanism. [HSO3C3NEt3]Cl-AlCl3 serves as a favorable medium for contact to be made between 1O2 and sulfides, which indicates an efficient catalytic-adsorption synergy.

Amidst the rapid development of renewable energy, the intermittency and instability of energy supply pose severe challenges and impose higher requirements on energy storage systems. Among the various energy storage technologies, the coupled approach of power-to-hydrogen (H2) and underground H2 storage (UHS) offers advantages such as extended storage duration and large-scale capacity, making it highly promising for future development. However, during UHS, particularly in porous media, microbial metabolic processes such as methanogenesis, acetogenesis, and sulfate reduction may lead to H2 consumption and the production of byproducts. These microbial activities can impact the efficiency and safety of UHS both positively and negatively. Therefore, this paper provides a comprehensive review of experimental, numerical, and field studies on microbial interactions in UHS within porous media, aiming to capture research progress and elucidate microbial effects. It begins by outlining the primary types of UHS and the key microbial metabolic processes involved. Subsequently, the paper introduces the experimental approaches for investigating gas-water-rock-microbe interactions and interfacial properties, the models and simulators used in numerical studies, and the procedures implemented in field trials. Furthermore, it analyzes and discusses microbial interactions and their positive and negative impacts on UHS in porous media, focusing on aspects such as H2 consumption, H2 flow, and storage safety. Based on these insights, recommendations for site selection, engineering operations, and on-site monitoring of UHS, as well as potential future research directions, are provided.

Low dosage kinetic hydrate inhibitors (KHIs) are a kind of alternative chemical additives to prevent gas hydrate formation in oil & gas production wells and transportation pipelines. In this work, a series of KHIs were experimentally synthesized with N-vinyl caprolactam (N-VCap) and vinyl ether including vinyl ether, vinyl n-butyl ether, vinyl isobutyl ether, triethylene glycol divinyl ether, with the mole ratio ranging from 9:1 to 5:5. The inhibition performance of new-synthesized KHIs on the formation process of methane hydrate were examined and compared with that of commercial N-vinyl caprolactam PVCap. Several ethylenediamine reagents were used as synergists and tested to improve the inhibition capacity of new-synthesized KHIs. The experimental results demonstrate that the introduction of ether groups on PVCap improves the performance of hydrate inhibitors. PVCap-VNBE (N-VCap: vinyl n-butyl ether = 5:5) showed the best inhibition performance for methane hydrate, which could extend the TVO to 1251 min under 6 K subcooling. N,N'-dimethylethylenediamine shows the best synergistic effect for PVCap-VNBE (5:5), and extends the TVO by 2.75 times at 7 K subcooling. Additionally, the relationship between hydrate inhibition performance and interfacial tension of newly-synthesized KHIs under high pressure were studied. It shows that the lower interfacial tension of KHIs would result in longer onset time, exhibiting better inhibition performance.

The primary impediment to the recovery of heavy oil lies in its high viscosity, which necessitates a deeper understanding of the molecular mechanisms governing its dynamic behavior for enhanced oil recovery. However, there remains a dearth of understanding regarding the complex molecular composition inherent to heavy oil. In this study, we employed high-resolution mass spectrometry in conjunction with various chemical derivatization and ionization methods to obtain semi-quantitative results of molecular group compositions of 35 heavy oils. The gradient boosting (GB) model has been further used to acquire the feature importance rank (FIR). A feature is an independently observable property of the observed object. Feature importance can measure the contribution of each input feature to the model prediction result, indicate the degree of correlation between the feature and the target, unveil which features are indicative of certain predictions (Zien et al., 2009). We have developed a framework for utilizing physical insights into the impact of molecular group compositions on viscosity. The results of machine learning (ML) conducted by GB show that the viscosity of heavy oils is primarily influenced by light components, specifically small molecular hydrocarbons with low condensation degrees, as well as petroleum acids composed of acidic oxygen groups and neutral nitrogen groups. Additionally, large molecular aromatic hydrocarbons and sulfoxides also play significant roles in determine the viscosity.

Estimating gas enrichments is a key objective in exploring sweet spots within tight sandstone gas reservoirs. However, the low sensitivity of elastic parameters to gas saturations in such formations makes it a significant challenge to reliably estimate gas enrichments using seismic methods. Through rock physical modeling and reservoir parameter analyses conducted in this study, a more suitable indicator for estimating gas enrichment termed the gas content indicator, has been proposed. This indicator is formulated based on effective fluid bulk modulus and shear modulus and demonstrates a clear positive correlation with gas content in tight sandstones. Moreover, a new seismic amplitude variation versus offset (AVO) equation is derived to directly extract reservoir properties, such as the gas content indicator and porosity, from prestack seismic data. The accuracy of this proposed AVO equation is validated through comparison with the exact solutions provided by the Zoeppritz equation. To ensure reliable estimations of reservoir properties from partial angle-stacked seismic data, the proposed AVO equation is reformulated within the elastic impedance inversion framework. The estimated gas content indicator and porosity exhibit favorable agreement with logging data, suggesting that the obtained results are suitable for reliable predictions of tight sandstones with high gas enrichments. Furthermore, the proposed methods have the potential to stimulate the advancement of other suitable inversion techniques for directly estimating reservoir properties from seismic data across various petroleum resources.

Novel wet-phase modified expandable graphite (WMEG) particles were developed for in-depth profile control in carbonate reservoirs. The harsh environment of carbonate reservoirs (≥ 130 °C, ≥ 22 × 104 mg/L) brings significant challenges for existing profile control agents. WMEG particles were developed to address this problem. WMEG particles were synthesized via intercalation with ultrasound irradiation and chemical oxidation. The critical expansion temperature of WMEG particles is 130 °C, and these particles can effectively expand 3–8 times under high temperature and high salinity water. The core flow experiments show that WMEG particles exhibit a good plugging capacity, profile control capacity, and a better-enhanced oil recovery (EOR) capacity in deep carbonate reservoirs. WMEG particles can be expanded in the formation and form larger particles that bridge the upper and lower end faces of the fracture. Then the high-permeability zones are effectively plugged, and the heterogeneity is improved, resulting in an obvious increase in oil recovery. This research provides a novel insight into future applications of profile control agents for in-depth profile control treatment in carbonate reservoirs.

Few studies have systematically investigated the factors controlling organic matter enrichment in shales from the Qiongzhusi Formation, within and surrounding the Sichuan Basin, under different depositional environments. This has resulted in different academic understandings and limited clarity on the mechanisms of organic matter enrichment. On this premise, in this study, the basic geological characteristics and depositional paleoenvironments of shales along the passive continental margin, the western Hubei Trough, and the western Sichuan Trough were compared and analyzed using core, outcrop, and mineral testing. Furthermore, data from organic geochemical and elemental analyses were utilized to investigate the different enrichment mechanisms and formation modes of the organic matter in different periods. The results reveal that the organic matter enrichment in this region should be mainly influenced by the preservation conditions, paleo-productivity, and terrigenous input. However, there were clear differences in the main controlling factors in the different periods. In the Q1 phase, the region had a high sea level, had the strongest rifting, had the largest accommodation space, and exhibited characteristics of low terrestrial input and bottom water hypoxia. The changes in the paleo-productivity caused by upwelling currents were the main factors controlling the variations in the organic matter enrichment. In the Q2 phase, the weakened decreasing sea level co-occurred with a reduction in the accommodation space across the region. The organic matter enrichment was significantly controlled by the paleo-productivity, preservation conditions, and terrigenous inputs, and the organic matter enrichment conditions deteriorated from the passive continental margin to the western Hubei Trough and western Sichuan Trough. The total organic carbon (TOC) content of the shale decreased significantly. In the Q3 phase, the entire region entered an infilling stage, which was dominated by an oxygen-rich environment, and the preservation conditions were the decisive factor controlling the organic matter enrichment. The TOC content was low overall, and there were no evident differences across the different zones.

Compared with the transverse isotropic (TI) medium, the orthorhombic anisotropic medium has both horizontal and vertical symmetry axes and it can be approximated as a set of vertical fissures developed in a group of horizontal strata. Although the full-elastic orthorhombic anisotropic wave equation can accurately simulate seismic wave propagation in the underground media, a huge computational cost is required in seismic modeling, migration, and inversion. The conventional coupled pseudo-acoustic wave equations based on acoustic approximation can be used to significantly reduce the cost of calculation. However, these equations usually suffer from unwanted shear wave artifacts during wave propagation, and the presence of these artifacts can significantly degrade the imaging quality. To solve these problems, we derived a new pure P-wave equation for orthorhombic media that eliminates shear wave artifacts while compromising computational efficiency and accuracy. In addition, the derived equation involves pseudo-differential operators and it must be solved by 3D FFT algorithms. In order to reduce the number of 3D FFT, we utilized the finite difference and pseudo-spectral methods to conduct 3D forward modeling. Furthermore, we simplified the equation by using elliptic approximation and implemented 3D reverse-time migration (RTM). Forward modeling tests on several homogeneous and heterogeneous models confirm that the accuracy of the new equation is better than that of conventional methods. 3D RTM imaging tests on three-layer and SEG/EAGE 3D salt models confirm that the ORT media have better imaging quality.

Characterizing the microscopic occurrence and distribution of in-situ pore water and oil is crucial for resource estimation and development method selection of shale oil. In this paper, a series of nuclear magnetic resonance (NMR) experiments were conducted on shales from the Gulong Sag, Songliao Basin, China, at AR, WR-AR, WOR-AR, Dry, SO, and WR states. In-situ pore water and oil were reconstructed after WOR-AR. An improved T1–T2 pattern for shale oil reservoirs comprising water and oil was proposed to classify and quantitatively detect pore fluids at different occurrence states. The total and free oil contents derived from NMR T1–T2 spectra at AR states were found to correlate well with those from multistage Rock-Eval. Moreover, the NMR-calculated total and free oil are generally larger than those measured from multistage Rock-Eval, whereas adsorbed oil is the opposite, which implies that adsorbed, bound, and movable oils in shale pores can be accurately and quantitatively detected via NMR, without absorbed hydrocarbons in kerogen. As per the NMR T2 and T1–T2 spectra at WOR-AR state, the microdistributions of in-situ pore water and oil were clearly demonstrated. Adsorbed, bound, and movable oils primarily occur in the micropores (1000 nm), respectively, whereas capillary-bound water is primarily correlated with micropores. Thus, the microscopic occurrence and distribution of adsorbed oil are remarkably affected by pore water, followed by bound oil, and movable oil is hardly affected. This study would be helpful in further understanding the microscopic occurrence characteristics of pore fluids in-situ shale oil reservoirs.

The application of perforating completion technology in oil and gas field development has gained widespread popularity. Enhancing the efficiency of oil and gas wells relies on increasing the penetration depth, which is influenced by the design of the perforation charge and the strength characteristics of the rock material. However, as a crucial objective function for optimizing perforating charge structures, jet velocity lacks a rapid and accurate calculating method. This article addresses this issue by proposing an improved collapse velocity model using the DP46RDX42-Y perforating charge as a case study. It presents a novel approach for calculating jet velocity based on the unsteady Pugh-Eichelberger-Rostoker (PER) theory. To validate the effectiveness of the proposed method and analyze the impact of different characteristic parameters on jet tip velocity, a series of numerical simulations were conducted using LS-DYNA software combined with Arbitrary Lagrange-Euler (ALE) techniques. Results indicate excellent agreement between the proposed method and the numerical results, demonstrating its superiority over the traditional Gurney formula with an impressive 34.15% increase in accuracy. Notably, this method is particularly suitable for perforating charges with low detonation velocity. Increasing the liner density and decreasing the liner thickness and cone angle is recommended to achieve higher jet tip velocity. Furthermore, the proposed method has the potential for broader application in other perforating charges with varying liner shapes. This study provides a comprehensive and efficient solution for calculating jet velocity, which facilitates optimizing perforating charge structures and calculating penetration depth.

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.

Based on the theory of superimposed deformation and the regional tectonic background, the multi-phase non-coaxial superimposed structures in Junggar Basin were systematically analyzed using seismic interpretation, field outcrop observation, and paleo-stress field recovery methods according to the characteristics of the current tectonic framework. Moreover, the tectonic evolution process of the basin was reconstructed using sandbox analogue modelling technology. The results showed that the study area has experienced five phases of non-coaxial deformation with superimposition: The first phase of deformation (D1) is characterized by NNE-SSW extension during late Carboniferous to early Permian, which formed large graben, half graben and other extensional structure style around the basin. The second phase of deformation (D2) is represented by NE-SW compression during the middle to late Permian, and it comprised numerous contraction structures that developed based on D1. The basic form of the entire basin is alternating uplift and depression. The third phase of deformation (D3) is the NW-SE transpressional strike-slip in the Triassic-Jurassic, which produced numerous strike-slip structural styles in the middle part of the basin. The fourth phase of deformation (D4) is the uniform sedimentation during Cretaceous, and the fifth phase (D5) is the compression along NNE-SSW due to the North Tianshan northward thrust, which produced three rows of fold thrust belts and tear faults in the front of the mountain in the southern margin of the basin. The newly established three-dimensional tectonic evolution model shows that, based on the large number of NW-trending grabens and half grabens in the Carboniferous basement of Junggar Basin, multiple level NE trending uplifts have formed with the joint superposition of the late structural inversion and multiple stress fields. This has resulted in the current tectonic units of alternating uplifts and depressions in different directions in the study area.

The mechanism of SC-CO2–brine–rock interaction (SCBRI) and its effect on the mechanical properties of shale are crucial for shale oil development and CO2 sequestration. To clarify the influence of SCBRI on the micromechanics of shale, the lamina and matrix of shale were saturated with SC-CO2–brine for 2, 4, 6, and 8 days, respectively. The micro-scratch technique was then used to measure the localized fracture toughness before and after SC-CO2–brine saturation. Combining the micro-scratch results with SEM-QEMSCAN-EDS analysis, the differences in mineral composition and mechanical properties of lamina (primarily composed of carbonate minerals) and matrix (primarily composed of clay minerals) were studied. The QEMSCAN analysis and micro-scratch results indicate distinct mineralogical compositions and mechanical properties between the lamina and the matrix. The results showed that: (1) SCBRI leads to the decrease in carbonate mineral content and the significant increase in matrix porosity and laminar cracks. In addition, the damage degree increased at saturation for 6 days. (2) SCBRI weakens the mechanical properties of shale. The scratch depth of laminar and matrix increased by 34.38% and 1.02%, and the fracture toughness decreased by 34.38% and 13.11%. It showed a trend of first increasing and then decreasing. (3) SCBRI enhances the plastic deformation behavior of shale, and the plastic index of lamina and matrix increases by 18.75% and 21.58%, respectively. These results are of great significance for evaluating the mechanical properties of shale oil and gas extraction by CO2.

For a better understanding of the strong heterogeneities of the Mishrif Formation in the H Oilfield of southeast Iraq, the characterization of the carbonate architectures has become one of the key research departments of carbonate rocks. This study aims to reveal the architecture and controlling factors of the carbonate tidal channels in the MB1-2B sub-layer of the Mishrif Formation in response to the delineation of the tidal channels that have hydrocarbon potential. Three architectural elements and three architectural boundaries of the tidal channels were identified by interpreting the cores, well-logging, seismic, and analytical data. The results show that: (1) the architecture characteristics of tidal channels are mainly migrating type in the downstream zone, the side of concave bank of the tidal channels is usually filled with relatively coarse-grained grainstone; (2) the architecture characteristics of tidal channels are mainly swinging type in the upstream zone, showing the high porosity and permeability; (3) the architecture characteristics of tidal channels are mainly vertical-accretion type in the mid-regions, indicating the instantaneous current reversals and high geographical position. This analysis demonstrates that the best reservoir quality within the tidal channels is located in the bend of the tidal channel near the inner lagoon and open sea, it provides the geological models for later exploration and development in the Mishrif Formation.

Huge numbers of induced unpropped (IU) fractures are generated near propped fractures during hydraulic fracturing in shale gas reservoirs. But it is still unclear how their fracture space and conductivity evolve under in-situ conditions. This paper prepares three types of samples, namely, manually split vertical/parallel to beddings (MSV, MSP) and parallel natural fractures (NFP), to represent the varied IU fractures as well as their surface morphology. Laser scan and reconstruction demonstrate that the initial fracture spaces of MSVs and MSPs are limited as the asperities of newly created surfaces are well-matched, and the NFPs have bigger space due to inhomogeneous geological corrosion. Surface slippage and consequent asperity mismatch increase the fracture width by several times, and the increase is proportional to surface roughness. Under stressful conditions, the slipped MSVs retain the smallest residual space and conductivity due to the newly sharp asperities. Controlled by the bedding structures and clay mineral hydrations, the conductivity of MSPs decreases most after treated with a fracturing fluid. The NFPs remain the highest conductivity, benefitting from their dispersive, gentle, and strong asperities. The results reveal the diverse evolution trends of IU fractures and can provide reliable parameters for fracturing design, post-fracturing evaluation, and productivity forecasting.

During heavy oil recovery in the Bohai Oilfield, substantial emulsification of oil and water occurred, primarily forming water-in-oil (W/O) emulsions. This phenomenon could alter fluid dynamics within the subsurface porous media, potentially impacting well production performance. To elucidate the properties of water-in-oil emulsions and their associated liquid resistance effects, this study conducted a series of rheological tests, microscopic examinations, and injection experiments. The results show that the droplet size and distribution of water-in-oil emulsions were primarily influenced by shear rate and water content, which in turn modified emulsion viscosity. The stability of water-in-oil emulsions was reduced when they flowed through porous media. The increase in emulsion viscosity and the liquid resistance effect collectively enhanced the seepage resistance of water-in-oil emulsions flowing through porous media. Notably, when the emulsion droplet size exceeded the pore throat size, over 90% of the total seepage resistance was attributable to the liquid resistance effect. Conversely, when the majority of the emulsion droplets were smaller than the pore throat, the viscosity accounted for more than 60% of the seepage resistance. Water-in-oil emulsions flowed through cores with permeabilities ranging from 50 to 100 mD, exhibiting threshold pressure gradients between 35 and 43 MPa/m. At a core permeability of 300 mD, the threshold pressure gradient was significantly reduced to 1 MPa/m. The presence of a water-in-oil emulsion in the reservoir could result in a production pressure differential falling below the threshold pressure, thereby reducing reservoir productivity.

Inadequate strength and stability of active crude oil emulsions stabilized by conventional surfactants always lead to a limited plugging rate of plugging agents. Thus, to address this issue, the synthesis of amphiphilic Janus nanosheets was effectively carried out for enhancing the system performances and subsequently characterized. Based on the outcomes of orthogonal tests, an assessment was conducted on the nanosheet and surfactant formulations to optimize the enhancement of emulsion properties. The experimental demonstration of the complex system has revealed its remarkable emulsifying capability, ability to decrease interfacial tension and improve rheological behavior at high temperature (80 °C) and high salinity (35,000 ppm) conditions. Involving probable mechanism of the system performance enhancement is elucidated by considering the synergistic effect between surfactants and nanosheets. Furthermore, variables including water-to-oil ratio, salinity, temperature and stirring intensity during operation, which affect the properties of prepared emulsions, were investigated in detail. The efficacy and stability of the complex system in obstructing medium and high permeability cores were demonstrated. Notably, the core with a high permeability of 913.58 mD exhibited a plugging rate of 98.55%. This study establishes the foundations of medium and high permeability reservoirs plugging with novel active crude oil plugging agents in severe environments.

The oxygen initiation process, one of the key processes in the early stage of the autothermic pyrolysis in-situ conversion technology, has not been deeply investigated, which seriously limits its development. In this study, the reaction behaviors, kinetic parameters, heat and product release characteristics during the isothermal oxygen initiation process of Huadian oil shale in O2/N2 mixtures with different oxygen concentrations and initiation temperatures were investigated via TG/DSC-FTIR. The results show that the samples exhibit three different reaction behaviors during the initiation stage, consisting of two main parts, i.e., the oxidative weight-gain and the oxidative reaction phases. The former phase is mainly characterized by the oxygen addition reaction that produces oxidizing groups which increase the sample mass. And the latter stage consists of two main subreactions. The first subreaction involves the oxidative cracking and pyrolysis of oxidizing groups and kerogen to produce fuel deposits such as residual carbon, while the second subreaction focuses on the oxidation of the resulting fuels. Furthermore, increasing the oxygen concentration significantly promotes the above reactions, leading to an increase in the reaction intensity and reaction rate. Owing to the combined effect of oxygen concentration and residual organic matter content, the total heat release increases with the increasing initiation temperature and reaches its maximum at 330–370 °C. In addition, the preheating stage primarily produces hydrocarbon gases, while the initiation stage predominantly generates CO2. As the preheating temperature increases, the CO2 output intensifies, the required reaction time shortens, and the release becomes more concentrated. Based on these findings, a reaction mechanism for the oxygen initiation process of Huadian oil shale was proposed, and recommendations were provided for optimizing the construction process.