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The morphology of dodecane in a nanopore at temperatures typical in exploited or depleted oil reservoirs is investigated using molecular dynamics simulation. The dodecane morphology is found to be determined by interactions between interfacial crystallization and surface wetting of the simplified oil, while "evaporation" only plays a minor role. The morphology changes from an isolated, solidified dodecane droplet to a film with orderly lamellae structures remaining within, and finally to a film containing randomly distributed dodecane molecules, as the system temperature increases. In a nanoslit under the impact of water, since water wins against oil in surface wetting on the silica surface due to electrostatic interaction induced hydrogen bonding between water and the silanol group of silica, the spreading of dodecane molecules over the silica surface is impeded by this water confinement mechanism. Meanwhile, interfacial crystallization is enhanced, leading to always an isolated dodecane "droplet," with crystallization weakening as the temperature increases. Since dodecane is immiscible to water, there is no mechanism for dodecane to escape the silica surface, and the competition of surface wetting between water and oil determines the morphology of the crystallized dodecane droplet. For the CO2–dodecane system in a nanoslit, CO2 is an efficient solvent for dodecane at all temperatures. Therefore, interfacial crystallization rapidly disappears. The competition of surface adsorption between CO2 and dodecane is secondary for all cases. The dissolution mechanism is a clear clue for the fact that CO2 is more effective than water flooding in oil recovery for a depleted oil reservoir. [ABSTRACT FROM AUTHOR]

Subsurface natural hydrogen accumulations that can be economically and safely recovered are a major target of the present roadmap towards the use of hydrogen as an alternative and C-free energy resource. The existence of H 2 -rich reservoirs in ophiolites, where H 2 is produced via serpentinization, was theoretically predicted based on the intensity of gas seeps in Turkey and Albania. Here, we examine the geological bases supporting the potential existence of H 2 reservoirs within ophiolites in general, also considering available data on ophiolitic petroleum reservoirs, and we document a direct observation of a H 2 -rich accumulation within an ophiolite. We studied the case of a borehole, drilled in the 1970s for metal mining exploration purposes within the Tișovița–Iuți ophiolite, in Romania, which accidentally encountered pressurized gas with ∼29 vol% H 2 at a depth of about 800 m. We reconstructed the geometry of the ophiolite sequence in correspondence with the well and suggested that the reservoir is within cataclastic dunite near the tectonic contact between layered dunite and the harzburgite-dunite peridotites; the upper, non deformed portion of serpentinized layered dunite, likely with the contribution of tonalite veins, acted as a fluid trap. Although plugged, we detected H 2 leakage from this well and from a second well in the same area, with H 2 concentrations exceeding 100 ppmv in the air and 0.1 mg H 2 /L in the water within the wellhead open casing. We propose a broad conceptual model in which deformed, fractured, and non-deformed, impermeable sections of serpentinized peridotites can determine ophiolitic H 2 -rich reservoirs and traps, respectively, as factors that shall be considered in the guidelines for H 2 reservoir exploration. • Direct observation of pressurized H 2 -rich reservoir in ophiolite (Romania). • Potential reservoirs and cap rocks in ophiolites. • H 2 leakage observed in the abandoned wells. [ABSTRACT FROM AUTHOR]

Injecting CO 2 and foaming agents can effectively improve the recovery rate of high cycle steam huff and puff. In this paper, firstly, the influence of oil saturation and injection plug on recovery rate is analyzed using a sand filled pipe physical simulation device. Then, combined with reservoir parameters, the influence of reservoir thickness, interlayer thickness, and oil saturation on the economic limits of development is elucidated. Thirdly, reservoir engineering methods are used to analyze the appropriate timing for injecting foaming agents into the study area. Results show that (a) CO 2 dissolves in crude oil, increasing its internal elastic energy and forming a solution gas drive. (b) When the oil saturation is 40 %, the cyclic oil increase is 109 tons, and the oil to gas ratio is 1.09; when the oil saturation is 35 %, the cyclic oil increase rapidly decreases to 38 tons. (c) For the research area, foaming agents should be intervened as early as possible. Foaming agent concentration is 0.4%. • The influence of oil saturation and injection plug on recovery rate is analyzed. • The influence of reservoir parameters on development economic limits is elucidated. • eservoir engineering methods are used to analyze appropriate timing for injecting foaming agents. [ABSTRACT FROM AUTHOR]

Wax formation from paraffinic crude oil and deposition in reservoir pores; production and transportation lines are a foremost severe challenge to flow assurance. Chemical wax control has received huge acceptance and is mostly used in the petroleum industry. This work experimentally examined the Paraffin Inhibition tendencies of Jatropha oil (JTO), Jatropha oil-based Polyaminoamine (JPA), JTO dissolved in xylene (JTOX), and JPA dissolved in xylene (JPAX) in Niger Delta waxy crude-oils. Four performance indicators; Pour Point (PP), Weight of Wax Deposited (WWD), Wax Appearance Temperature (WAT), and Wax Crystal Morphology (WCM) were used to test the wax inhibition tendency of three crude oils. All experiments were performed on the blank and additives-treated crude-oils. The results obtained confirm that JTOX and JPAX act as PP depressants. Also, WWD decreases with increasing cold finger temperature correlating to the higher Wax Inhibition Efficiency (PIE) of the chemical additive. Below the WAT, the viscosity increased at a higher rate and the least wax amount was deposited, hence, the highest PIE (Crude-oil A:71%; Crude-oil B:72%; Crude-oil C:70%) was observed and close to the industrial control paraffin inhibitor (Crude-oil A:67%; Crude-oil B:65%; Crude-oil C:75%). JPAX has a significantly improved performance as a PP depressant than JTO alone. [ABSTRACT FROM AUTHOR]

The small hive beetle Aethina tumida (SHB) Murray,1867, is an invasive bee pest that is expanding its range across Latin America, parts of Australia and the Philippines, and is now established in two regions in Italy. However, despite multiple recent introductions, there is scant information about the dynamics of the initial stages of colonization of the SHB and this knowledge gap could impact management and quarantine strategies decisions for many countries. This note describes the monitoring strategies and the patterns of SHB establishment in a previously SHB‐free apiary on the island of Oahu, Hawaii in 2010–2011. The weekly hive inspections, conducted over a ten‐month period, showed that beetle prevalence increased slowly at the apiary level, and adult beetles were more commonly found (87.9%) inside the oil traps that were placed inside the hives between the outermost frames of the hive. There were relatively few "free roaming" beetles detected at this point and they were more often found on the side frames and underneath the cover of the hive, not on the floor of the hive. The results also suggest that in the early stages of colonization careful visual inspections of the frames of each colony had relatively low detection success when compared to oil traps. Our results support previous modelling studies that suggest the need to inspect a high proportion of colonies per apiary (>80%) to ensure a 5% detection rate during the initial stages of invasion. [ABSTRACT FROM AUTHOR]

To improve water solubility and salt tolerance of viscoelstic surfactants (VESs), modifying the spacer of Gemini VES was adopted and a novel Gemini VES nominated TC‐2OH, with tri‐cationic groups and double hydroxyls on the spacer, was developed. The basic surface activity properties of TC‐2OH and the molecular aggregate behavior stimulated by NaCl or NaSal were measured and analyzed to investigate the mechanism of viscoelastic fluid forming by TC‐2OH solution, and it proved that TC‐2OH is more sensitive to NaSal, compared with NaCl, due to the embedded structure of salicylate. The molecular structure of TC‐2OH imparts excellent solubility to itself, and with the assistance of ethanol, the dissolution time in water can be shortened to within 45 seconds. In addition, oscillation experiments, heat and shear resistant experiments, and drag reduction tests were conducted to study the advantage of NaSal for stimulating the formation of the slickwater compared with NaCl. The slickwater stimulated by NaSal indeed exhibit superior drag reduction and proppant carrying capacity. To effectively disassemble the wormlike micelles for gel breaking, ethylene glycol butyl ether performs better than the hydrocarbons because of its high polarity and water solubility. The gel breaking fluids of slickwater caused extremely low damage to the tight sandstone cores. The successful development of TC‐2OH enables instant preparation of slickwater and variable‐viscosity for fracturing in unconventional reservoirs, which also realizes convenient switching between the slickwater with different viscosity. [ABSTRACT FROM AUTHOR]

In recent years, with the deepening of exploration and development theories for tight oil reservoirs and the continuous breakthroughs in key engineering technologies, positive progress has been made in the development of onshore tight oil in China, it has become an important supplement to the growth of petroleum reserves and production. Therefore, identifying the main controlling factors of tight oil reservoir productivity and predicting this productivity are crucial for the development of petroleum resources. The article employs a comprehensive data preprocessing method to address field data, minimizing data errors to the greatest extent possible. In the study of controlling factors and prediction of productivity, various methods such as Pearson correlation coefficient, Random Forest, XGBoost, etc., are compared to enhance the reliability of the results. In addition, root mean square error, mean absolute error, and coefficient of determination are also introduced to evaluate the prediction results of each model, providing an overview of the overall framework of machine learning application in productivity. The study shows that compared with mutual information coefficient, the results of production capacity analysis using Random Forest are more consistent with Pearson correlation coefficient method. The fracturing engineering factors are dominant in the initial production capacity and first-year cumulative production; the initial production capacity is mainly controlled by the soaking time, the stable water cut, the volume of fracturing liquid volume and the formation thickness; the first-year cumulative oil production is mainly dependent on the stable water cut. The XGBoost method yielded the best performance across all three evaluation metrics, indicating that its prediction results are more reliable. In conclusion, machine learning methods can provide significant technical support for the exploration and development of tight oil reservoirs. • Utilize machine learning to discern geological and engineering factors impacting oil production. • Employ Random Forest and Pearson correlation coefficient for production analysis. • Achieve superior accuracy in oil production prediction with XGBoost. [ABSTRACT FROM AUTHOR]

Miscible gas injection in tight/shale oil reservoirs presents a complex problem due to various factors, including the presence of a large number of nanopores in the rock structure and asphaltene and heavy components in crude oil. This method performs best when the gas injection pressure exceeds the minimum miscibility pressure (MMP). Accordingly, accurate calculation of the MMP is of special importance. A critical issue that needs to be considered is that the phase behavior of the fluid in confined nanopores is substantially different from that of conventional reservoirs. The confinement effect may significantly affect fluid properties, flow, and transport phenomena characteristics in pore space, e.g., considerably changing the critical properties and enhancing fluid adsorption on the pore wall. In this study, we have investigated the MMP between an asphaltenic crude oil and enriched natural gas using Peng-Robinson (PR) and cubic-plus-association (CPA) equations of state (EoSs) by considering the effect of confinement, adsorption, the shift of critical properties, and the presence of asphaltene. According to the best of our knowledge, this is the first time a model has been developed considering all these factors for use in porous media. We used the vanishing interfacial tension (VIT) method and slim tube test data to calculate the MMP and examined the effects of pore radius, type/composition of injected gas, and asphaltene type on the computed MMP. The results showed that the MMP increased with an increasing radius of up to 100 nm and then remained almost constant. This is while the gas enrichment reduced the MMP. Asphaltene presence changed the trend of IFT reduction and delayed the miscibility achievement so that it was about 61% different from the model without the asphaltene precipitation effect. However, the type of asphaltene had little impact on the MMP, and the controlling factor was the amount of asphaltene in the oil. Moreover, although cubic EoSs are particularly popular for their simplicity and accuracy in predicting the behavior of hydrocarbon fluids, the CPA EoS is more accurate for asphaltenic oils, especially when the operating pressure is within the asphaltene precipitation range. [ABSTRACT FROM AUTHOR]

Solar energy is an attractive alternative to fossil fuels (electricity and coke) for petroleum products generation. A solar-integrated binary chemical cracking of heavy oil system integrates solar energy into oil processing for carbon neutrality，in which pyrolysis and electrolysis benefit heavy oil conversion and hydrogen storage. This system has been studied in terms of solar chemical engineering, electrolyte engineering and electrode engineering. The results show improved hydrogen yield and cracking rate of heavy oil and a significant reduction in the operating temperature compared to catalytic cracking. The performance of molten salt electrolytes is as follows: binary NaOH–KOH > ternary KCl–LiCl + NaOH > ternary KCl–LiCl + NaHCO 3. In electrode engineering, the electro-catalytic electrodes are in an order of Inconel 718> Ni > Incoloy 825 electrodes in the cracking rate, Ni > Inconel 718>Incoloy 825 electrodes in the hydrogen yield, and Incoloy 825>Inconel 718>Ni electrodes in the ability, for sustainable and stable efficient production. [Display omitted] • Solar binary chemical cracking can efficiently upgrade fuel and abundantly generate hydrogen. • Solar binary energy is integrated into oil processing to replace fossil energy. • The starting reaction temperature is 230 °C, lower than the catalytic cracking. [ABSTRACT FROM AUTHOR]

Hydrogen is considered a truly clean energy source with great potential for replacing fossil fuels. However, the special physical and chemical properties of this source make large-scale, safe, and efficient storage challenging, thus limiting its widespread use. Consequently, an underground hydrogen storage system inspired by underground methane storage and CO 2 geological sequestration has been proposed, and it is increasingly becoming a focus of research. Depleted oil reservoirs are ideal sites for such systems. Nevertheless, research on these types of underground hydrogen storage systems is limited to a few feasibility assessments, and the hydrogen seepage laws in reservoirs with residual oil are not well understood. In this paper, a study was conducted involving mathematical modeling and numerical simulation of underground hydrogen storage, which was converted from the SSZ low-permeability depleted oil reservoir in Bohaiwan Basin, eastern China, to reveal the seepage patterns between hydrogen and complicated in situ fluids (oil, gas, and water). First, a comprehensive analysis was conducted using numerous rock samples and experimental data to identify the composition, genesis, and distribution patterns of the sandstone reservoir, detailing its internal pore structure and fluid distribution postdepletion characteristics. Then, the hydrogen seepage properties in the presence of oil films in the three main throat types of low-permeability sandstone were analyzed, and corresponding mathematical models of the different throats were established. Finally, a numerical simulation of underground hydrogen storage was conducted to assess the impacts of various parameters, such as injection speed, reservoir heterogeneity, and residual oil saturation, on hydrogen seepage. The planar and vertical diffusion patterns of hydrogen were clarified, and the key factors affecting the efficiency of underground hydrogen storage were analyzed, offering suggestions for the establishment of stable and efficient underground hydrogen storage systems. • Selection and description of typical low-permeability reservoirs for UHS. • Mathematical model establishment for hydrogen percolation in porous rock. • Numerical simulation of the storage process of hydrogen. • Percolation laws of hydrogen in rock porous. [ABSTRACT FROM AUTHOR]

The cast thin sections of tight oil reservoirs contain important parameters such as rock mineral composition and content, porosity, permeability and stratigraphic characteristics, which are of great significance for reservoir evaluation. The use of deep learning technology for intelligent identification of thin section images is a development trend of mineral identification. However, the difficulty of making cast thin sections, the complexity of the making process and the high cost of thin section annotation have led to a lack of cast thin section images, which cannot meet the training requirements of deep learning image recognition models. In order to increase the sample size and improve the training effect of deep learning model, we proposed a generation and annotation method of thin section images of tight oil reservoir based on deep learning, by taking Fuyu reservoir in Sanzhao Sag as the target area. Firstly, the Augmentor strategy space was used to preliminarily augment the original images while preserving the original image features to meet the requirements of the model. Secondly, the category attention mechanism was added to the original StyleGAN network to avoid the influence of the uneven number of components in thin sections on the quality of the generated images. Then, the SALM annotation module was designed to achieve semi-automatic annotation of the generated images. Finally, experiments on image sharpness, distortion, standard accuracy and annotation efficiency were designed to verify the advantages of the method in image quality and annotation efficiency. [ABSTRACT FROM AUTHOR]

Water huff-n-puff is considered to be an available method to exploit unconventional oil reservoirs, which can significantly promote the reservoir pressure and facilitate water–oil exchange under the imbibition effect. To explore the production characteristics and well performance during water huff-n-puff in the Huanjiang oil field that is a tight oil reservoir, field tests were carried out and production characteristics and well performances were investigated. Moreover, reservoir simulation works were conducted to study the various factors that influence the water huff-n-puff performance. Furthermore, sensitivity analysis for various factors was carried out with the tornado diagram method and the importance of different influencing factors was ranked quantitatively. The results demonstrate that water huff-n-puff has great significance to effectively replenish reservoir pressure as well as promote oil production. Field tests demonstrate that the average liquid rate as well as the oil rate of the horizontal wells increased by 5.94 and 1.18 m3/day , respectively. Considering the different oil production characteristics, the oil production process can be classified into three different stages. The levels importance of different influencing factors were ranked as rock wettability, water huff-n-puff cycles, water injection volume, hydraulic fracturing sections, well position, and soaking time. [ABSTRACT FROM AUTHOR]

The work is devoted to solving the problem of correctly determining capillary pressure functions during mathematical modeling of oil displacement processes during flooding of productive formations. It is shown that the use of these functions, determined in laboratory conditions using traditional methods using capillarimeters and high-speed centrifuges, when modeling processes of oil displacement from low-permeability productive reservoirs can lead to significant errors. The work notes that when conducting laboratory studies in rock samples, there is no formation of residual oil in a stationary form, while in real conditions of displacement of oil by water from productive formations, residual oil is formed in the rock, and in low-permeability formations the residual oil saturation can reach 50% or more of the pore volume. To obtain capillary pressure curves that more reliably reflect the real processes in productive formations during their flooding, it is proposed that when preparing rock samples for laboratory research, it is proposed to provide for the process of preliminary formation of residual oil saturation in these samples. This will make it possible to more reliably simulate the processes of oil displacement during waterflooding of productive formations in real conditions, especially when developing low-permeability oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

In unconventional oil and gas development, the hydraulic fracturing (HF) technique is adopted to inject high-pressure fluid into the reservoir and change its pore-fracture connection structure to enhance production. HF causes the rocks to crack and generates microseismic events (with moment magnitudes of M w ≤ 3 ). Studying the microseismic focal mechanisms (shear/tensile/compressive HF cracks) is helpful for characterizing fracture geometry, monitoring the in situ stress state, and evaluating the HF effects to optimize the reservoir reconstruction for increasing production. Due to fluid injection activity, there may be non-double-couple (non-DC) mechanisms associated with HF cracks, and the commonly used double-couple (DC) source model may not be suitable. For the moment tensor (MT) source model, which is commonly used to describe the non-DC mechanism, inversion is challenging in single-well monitoring. The shear-tensile general dislocation (GD) model includes a non-DC mechanism, and its inversion is more constrained than the full MT model by specifying the focal mechanism as shear-tensile (or compressive) faulting. This paper reports a focal mechanism inversion case study of HF shear/tensile/compressive cracks in a tight oil reservoir in the Ordos Basin, China. We perform inversions based on the DC, GD, and MT source models, respectively. The results indicate that, for the downhole monitoring geometry in this study, most of the DC inversions fail to obtain proper synthetic and observed waveform fitting results, and the MT inversion results of different microseismic events exhibit worse consistencies than the GD results. According to the GD results, almost all the HF cracks can be explained as strike-slip faulting and most cracks correspond to non-negligible tensile/compressive mechanisms. Our study suggests that the GD source model is preferred in downhole microseismic monitoring to obtain reliable shear/tensile/compressive HF cracks, and the inverted non-zero slope angle reduces the uncertainty in fracturing geometry characterization, which will help improve microseismic studies and HF evaluations for enhanced resource recovery. [ABSTRACT FROM AUTHOR]

The paper takes the Jidong Nanbu high temperature oil reservoir as the research object and establishes the comprehensive numerical model of CO2 storage and displacement based on the CO2 displacement mechanism, CO2 heat recovery mechanism, and CO2 geological storage mechanism. On this basis, the injection and production optimization model is established by combining the theory of multi-objective and single-objective optimization algorithm respectively. The objective function of the multi-objective injection and production optimization model is NPV and CO2 heat recovery. The model is solved using the NSGAII and MOPSO algorithm. The results show that the objective function value obtained by the MOPSO algorithm is better than the NSGAII algorithm. The optimal values of NPV and CO2 heat recovery were 4.781 × 108 CNY and 1.078 × 1016 J respectively. The objective function of the single objective injection and production optimization model is the NPV. GA and DE optimization algorithms are used to solve the model. The results show that the DE algorithm gets the better objective function value than the GA algorithm. The optimal value of NPV is 3.69 × 1010 CNY. [ABSTRACT FROM AUTHOR]

Waterflooding is a widely-used secondary oil recovery technique employed in the oil industry. In mature oil fields, waterflooding becomes increasingly essential in order to maximize oil recovery and extend field life, but optimizing its performance remains a complex and challenging task. In recent years, there has been growing interest in developing integrated approaches combining reservoir simulation, well modeling, and data-driven techniques to improve waterflood performance. The Capacitance–Resistance Model (CRM) has been proven to be a fast and effective tool for predicting waterflooding and reservoir characterization. Previous studies have successfully applied CRM to waterflood management to increase oil recovery. This paper develops a novel integrated and iterative workflow for waterflooding optimization in mature fields using the CRM for multilayer reservoirs equipped with Interval Control Valves (ICVs). The proposed approach, which integrates geological and well data with CRM results, was validated using a benchmark field model named the Olympus. This new workflow will help to put connected injection and production wells in different groups to reduce computational costs. In addition, this workflow can be used to determine the optimized number and proper location of the ICVs inside production wells. We determined the workover programs for existing wells, such as installing sensors and ICVs, deepening the wells, or plug-backs. Finally, it can be used for determining optimal water injection rates and well control strategies, such as valve openings in different production layers. As a result, the oil recovery factor increased, and the NPV was maximized, respecting the Olympus field's economic and operational constraints. [ABSTRACT FROM AUTHOR]

Natural fractures play a significant role in oil and gas reservoirs. Accurate predictions of fracture parameters are vital in reservoir prediction and oil and gas development. The birefringent phenomenon of shear waves in fractured media makes shear wave splitting (SWS) analysis an important tool in formulating fracture predictions. The traditional SWS analysis method is based on an orthogonal assumption of fast and slow shear waves. However, in an orthotropic medium composed of a background vertical transversely isotropic medium and a set of vertical fractures, fast and slow shear waves are not necessarily orthogonal. This causes the traditional SWS analysis method to fail. To solve this problem, we proposed an SWS analysis algorithm with a non-orthogonal assumption of fast and slow shear waves in this study. First, we introduced a parameter (difference angle) to characterize the angle between slow shear waves and the normal polarization directions of the fast shear waves. Subsequently, based on the traditional two-parameter scanning algorithm, a parameter was added to facilitate three-parameter scanning. In addition, we derived an expression for the two-parameter scanning objective function using the non-orthogonal assumption. Two-parameter scanning can accurately extract fast and slow wave time delay data, but it cannot determine an accurate fast shear wave polarization direction. Therefore, we optimized the three-parameter scanning algorithm as follows: first, we used two-parameter scanning to obtain the fast and slow wave time delays and then performed further scanning to determine the polarization direction of the fast shear wave and difference angle. The optimization algorithm significantly improved the computational efficiency. Subsequently, we tested the accuracy of this method using synthetic single-trace and three-component vertical seismic profile data. We demonstrated the implementation process of the three-parameter scanning method using actual data, separated fast and slow shear waves, and predicted fracture parameters. The final fracture parameters were verified. [ABSTRACT FROM AUTHOR]

Electrofracturing deeply buried shale formations could be used to increase reservoir permeability and improve reservoir production without requiring large volumes of freshwater. This paper describes a novel experimental system and initial test results to electrofracture shale under high confining pressures. Core-scale laboratory testing was performed on twelve rock samples recovered from a shale gas reservoir. Each sample was subjected to confining pressures of 20.7 MPa (3000 psi) or 58.6 MPa (8000 psi), representative of overburden pressures at depth. Samples were then subjected to application of high voltage until specimen fracture. The experiments produced deformed samples with multiple fracture types, both parallel and oblique to bedding planes. Electrofracturing increased permeabilities by up to nine orders of magnitude for extended time periods. Rock fracture and throughgoing fractures were demonstrated. Computed tomography images revealed the creation of fractures and tube/tunnel flow channels, which resisted closure under hydrostatic pressures up to 58.6 MPa. The breakdown energy and permeability changes in the sample were independent of applied confining pressure. The cumulative energy input required for fracture depended on applied confining pressure and sample length. The energy required to fracture samples up to 9 cm in length is generally more than 0.5 kJ/cm, but no greater than 1 kJ/cm. Our results show that electrofracture of shales under confining pressure is possible and could be a possible water-free mechanism for reservoir stimulation. [ABSTRACT FROM AUTHOR]

The formation of hydrogen sulfide (H2S) in petroleum reservoirs by anaerobic microbial activity (through sulfate-reducing microorganisms, SRMs) is called biogenic souring of reservoirs and poses a risk in the petroleum industry as the compound is extremely toxic, flammable, and corrosive, causing devastating damage to reservoirs and associated surface facilities. In this paper, we present a workflow and the tools to assess biogenic souring from a pragmatic engineering perspective. The retention of H2S in the reservoir due to the reactions with iron-bearing rock minerals (e.g., siderite) is shown in a theoretical approach here and supported with literature data. Cases are provided for two fields under secondary (waterflooding) and tertiary flooding with microbial enhanced oil recovery (MEOR). The use of the Monte Carlo method as a numerical modeling tool to incorporate uncertainties in the measured physical/chemical/biochemical data is demonstrated as well. A list of studies conducted with different chemicals alone or in combination with various biocides to mitigate biogenic souring provides an overview of potential inhibitors as well as possible applications. Furthermore, the results of static and dynamic inhibition tests using molybdate are presented in more detail due to its promising mitigation ability. Finally, a three-step workflow for the risk assessment of biogenic souring and its possible mitigation is presented and discussed. [ABSTRACT FROM AUTHOR]

The Shuguang area has great oil and gas potential in the Proterozoic and it is a major exploration target in the Western Depression. However, controlling factors and a reservoir-forming model of the Shuguang reservoir need further development. The characteristics of the reservoir formation in this area were discussed by means of a geochemical technique, and the controlling factors of the oil reservoir were summarized. The oil generation intensity of Es4 source rock was 25 × 106–500 × 106 t/km2, indicating that the source rocks could provide enough oil for the reservoir. The physical property of the quartz sandstone reservoir was improved by fractures and faults, which provided a good condition for the oil reservoir. Two periods of oil charging existed in the reservoir, with peaks of 38 Ma and 28 Ma, respectively. A continuous discharge of oil is favorable for oil accumulation. Oil could migrate through faults and fractures. In addition, the conditions of source–reservoir–cap assemblage in the Shuguang area well preserved the oil reservoir. The lower part of the Shuguang reservoir was source rock, the upper part was reservoir, and it was a structure-lithologic oil reservoir. These results are crucial for further oil exploration. [ABSTRACT FROM AUTHOR]

Utilizing the discrete fracture model (DFM), a transient flow model is established for fractured horizontal wells in tight oil reservoirs, accounting for threshold pressure gradient (TPG), stress sensitivity effect, hydraulic fracture parameters, and fracture distribution pattern. This model is solved using the finite-volume method (FVM), and an important sensitivity analysis is conducted. The findings reveal that the models incorporated by the threshold pressure gradient result in an upward trend in the pressure-derivative curve. As the threshold pressure gradient increases, this upward trend becomes more pronounced, rendering the distinction between flow regimes more challenging. The stress sensitivity effect predominantly impacts the pressure-derivative curve during the later flow period. Additionally, as the fracture half-length increases, the pressure performance of both fracture radial flow and formation radial flow becomes more difficult. Fracture conductivity has a significant influence during the early flow period, facilitating the identification of flow regimes with the trend of increasing fracture conductivity. [ABSTRACT FROM AUTHOR]

The technique of refracturing is an effective method to solve the rapid decline in oil well production caused by factors such as severe reservoir energy loss and fracture failure after the initial hydraulic fracturing of low-permeability reservoirs. The key to designing refracturing lies in establishing a model for evaluating the potential fracturing layers. Based on the geological characteristics of the low-permeability conglomerate reservoir in the Lower Wuerhe area of the Eig District of the Xinjiang Oilfield, this paper studies the influence of different development approaches on the distribution pattern of remaining oil in the reservoir. A coupled model of remaining oil distribution and the in situ stress field is established and discusses the characteristics of the four-dimensional in situ stress field under different development modes. This paper analyzes the influence of geological factors and well network factors on the distribution of residual oil, and analyzes the influence of various factors, such as reservoir properties and injection and extraction parameters, on ground stress. Based on the residual oil distribution and ground stress changes, an evaluation method for screening potential fractured layers in reservoirs with different development modes (water injection development and depletion development) is developed. [ABSTRACT FROM AUTHOR]

The lateral sealing of a fault plays a pivotal role in the efficacy of a fault trap and its degree of hydrocarbon filling. Nevertheless, the evaluation of this phenomenon remains a challenging task, with evaluation methods either unable to accurately reflect subsurface reality or obtaining the necessary parameters difficult. In light of these considerations, a porosity-based fault laterality evaluation method was proposed, with the F1 Fault of the Nanpu No. 5 structure in the Nanpu Sag serving as the research object. First, the relationship between porosity and the product of burial depth and shale content was established using measured porosity, burial depth, and shale content data of the surrounding rocks in the study area. Subsequently, the reservoir rock porosity was obtained by employing logging data or core samples or by calculating the reservoir rock shale content from natural gamma logging data. Concurrently, the shale content of fault rock was calculated using three-dimensional (3D) seismic data, mud logging data, and natural gamma logging data, thereby enabling its porosity to be determined. Finally, the porosity difference between the two was employed to assess the lateral closure of faults. The results indicate that the porosity difference is less than 0 at lines L1~L3 of the F1 Fault, which suggests that the fault is not laterally closed at this site. Conversely, the F1 Fault is laterally sealed at this location, as indicated by the porosity difference being greater than 0 at lines L4~L10. The findings of this evaluation were found to be in close alignment with the actual distribution of oil and water, indicating that the proposed method can accurately evaluate the lateral closure of faults with developed fault rocks and provide valuable guidance for the exploration of faulted oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Oil sand reservoirs and caprock undergo deformations triggered by pore pressure increases and thermal induced stresses during the steam-assisted-gravity-drainage (SAGD) processes. Geomechanical assessments are mandated by energy regulators to evaluate the caprock integrity and ensure the safe SAGD operations. Commercial reservoir simulation packages started to incorporate geomechanical effects when predicting flow response; however, these geomechanical modules are not able to correctly model the plastic deformations caused by thermal-hydraulic-mechanical (THM) interactions, which has a first order effect on predicting steam chamber propagation and evaluating caprock integrity. An integrated coupled THM modeling methodology is proposed here to improve the modeling of reservoir deformations and caprock integrity in a heterogeneous oil sand reservoir with interbedded shale barriers. The pressure and temperature front are found to propagate at different speed and that dominate the elastic and plastic deformations caused by changes of shear and mean effective stress. Therefore, four stages are divided in the SAGD process that can be interpretations of changes in stress paths including buildup of pore pressure, generation and dissipation of thermal induced stresses. The response surfaces of minimum factor of safety are introduced and computed to provide a conservative estimate for caprock integrity during SAGD of a heterogeneous reservoir with multiple layers of caprocks in Athabasca oil sands. [ABSTRACT FROM AUTHOR]

The wettability of shale reservoirs has an important influence on the flow of external fluids. In this paper, the effect of wettability on the self-absorption of hydraulic fracturing fluid under different pore size conditions is first analyzed. Then, the mechanism of the influence of wettability pore size on the flow coefficient is elucidated. The results show that (a) as the pore size decreases, the importance of various forces acting on the fluid during the flow process changes, and the solid-liquid interaction will greatly affect the fluid flow in the nanopore. (b) When the radius is 5, the flow enhancement increases from 0.6331 to 0.998 as the radius increases from 0 to 3.141594.(c) The shale inorganic material contains a variety of minerals, and the interaction forces between different mineral surfaces and water molecules are different, resulting in different apparent viscosities. • The influence of wettability on hydraulic fracturing fluid imbibition is analyzed. • The effect of different pore size conditions is considered. • The wettability pore size influence mechanism of flow coefficient is clarified. [ABSTRACT FROM AUTHOR]

Geochemical reactions are crucial for in situ CO2 mineralization underground associated with CO2‐enhanced oil recovery (CO2‐EOR) in a hydrocarbon reservoir. However, the presence of formation water and adsorbed oil on rocks generates physical barriers to CO2's access to mineral surfaces, which may yield impedance to CO2 mineral trapping that has yet to be accounted for. In this study, we mimic the dynamic oil detachment process using molecular dynamic (MD) simulation and analyze the influence of an adsorbed oil film on supercritical CO2 (scCO2) diffusion toward the mineral surface in the presence and absence of a water phase. Our results demonstrated a negative impact of water on oil film detachment by scCO2, which may weaken mineral reactions and is unfavorable for mineralized CO2 storage underground. Plain Language Summary: Carbon dioxide emission has been identified as one of the primary factors influencing global climate change. Storing CO2 underground while enhancing oil recovery is a promising technology that can effectively reduce costs for carbon capture, utilization, and storage (CCUS). Mineral trapping, that is, converting CO2 to carbonate minerals through CO2‐water‐mineral surface reactions, is one of the major mechanisms for CO2 storage. However, residual oil adsorbed on rock surfaces after CO2 injection into an oil reservoir yields a physical barrier for CO2 approaching mineral surfaces. CO2‐water‐oil‐mineral interactions have yet to be thoroughly understood. Therefore, we conducted a series of molecular dynamics simulations to mimic the dynamic oil detachment process and unveil the impact of water on oil film detachment by supercritical CO2. We found that the presence of water strengthens the interactions between the oil and rock surface, which may give rise to a substantial delay in oil film detachment and weaken mineral reactions. Our results provide significant implications for the mineralized storage of CO2 in a depleted oil reservoir and CO2‐enhanced oil recovery and its consequent sequestration. Key Points: CO2‐water‐oil‐rock interactions are investigated using molecular dynamics simulationsscCO2 can collapse the oil film and channel out a path for CO2 diffusionWater exhibits a negative impact on oil film detachment by scCO2 [ABSTRACT FROM AUTHOR]

In this paper, firstly, the tectonic features, sedimentary features, reservoir formation features and oil and gas drainage system of the P5-QS2 well are systematically analyzed. Then, the main controlling factors of reservoir aggregation in this area with seismic data is studied to achieve the purpose of optimizing favorable targets. Finally, a new model of dense, thin sandstone reservoir aggregation with dual control of lithology and tectonics is proposed, and the potential zone of P5-QS2 well area is clarified. Results show that: (a) Tectonics and lithology are the main controlling factors for the formation of oil and gas reservoirs. (b) The QS 2 and QS 4 wells deployed at the high point of the P5-QS2 well zone are currently producing a cumulative total of more than 15 million cubic meters of gas. (c) The deployment of the MZ 15 well is expected to achieve an industrial oil flow rate of 100,000 tons per day, further realizing a new breakthrough in the exploration of the Jurassic Badawan Formation in the hinterland of the P5-QS2 well zone. [ABSTRACT FROM AUTHOR]

During hydraulic fracturing of waxy shale oil reservoirs, the presence of fracturing fluid can influence the phase behavior of the fluid within the reservoir, and heat exchange between the fluids causes wax precipitation that impacts reservoir development. To investigate multiscale fluid phase transition and microscale flow impacted by fracturing fluid injection, this study conducted no-water phase behavior experiments, water injection wax precipitation experiments, and water-condition phase behavior experiments using a nanofluidic chip model. The results show that in the no-water phase experiment, the gasification occurred first in the large cracks, while the matrix throat was the last, and the bubble point pressure difference between the two was 12.1 MPa. The wax precipitation phenomena during fracturing fluid injection can be divided into granular wax in cracks, flake wax in cracks, and wax precipitation in the matrix throat, and the wax mainly accumulated in the microcracks and remained in the form of particles. Compared with the no-water conditions, the large cracks and matrix throat bubble point in the water conditions decreased by 6.1 MPa and 3.5 MPa, respectively, and the presence of the water phase reduced the material occupancy ratio at each pore scale. For the smallest matrix throat, the final gas occupancy ratio under the water conditions decreased from 32% to 24% in the experiment without water. This study provides valuable insight into reservoir fracture modification and guidance for the efficient development of similar reservoirs. [ABSTRACT FROM AUTHOR]

This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2. [ABSTRACT FROM AUTHOR]

In this paper, experimental and numerical studies were conducted to differentiate solvent exsolution and liberation processes from different heavy oil–solvent systems in bulk phases and porous media. Experimentally, two series of constant-composition-expansion (CCE) tests in a PVT cell and differential fluid production (DFP) tests in a sandpacked model were performed and compared in the heavy oil–CO2, heavy oil–CH4, and heavy oil–C3H8 systems. The experimental results showed that the solvent exsolution from each heavy oil–solvent system in the porous media occurred at a higher pressure. The measured bubble-nucleation pressures (Pn) of the heavy oil–CO2 system, heavy oil–CH4 system, and heavy oil–C3H8 system in the porous media were 0.24 MPa, 0.90 MPa, and 0.02 MPa higher than those in the bulk phases, respectively. In addition, the nucleation of CH4 bubbles was found to be more instantaneous than that of CO2 or C3H8 bubbles. Numerically, a robust kinetic reaction model in the commercial CMG-STARS module was utilized to simulate the gas exsolution and liberation processes of the CCE and DFP tests. The respective reaction frequency factors for gas exsolution (rffe) and liberation (rffl) were obtained in the numerical simulations. Higher values of rffe were found for the tests in the porous media in comparison with those in the bulk phases, suggesting that the presence of the porous media facilitated the gas exsolution. The magnitudes of rffe for the three different heavy oil–solvent systems followed the order of CO2 > CH4 > C3H8 in the bulk phases and CH4 > CO2 > C3H8 in the porous media. Hence, CO2 was exsolved from the heavy oil most readily in the bulk phases, whereas CH4 was exsolved from the heavy oil most easily in the porous media. Among the three solvents, CH4 was also found most difficult to be liberated from the heavy oil in the DFP test with the lowest rffl of 0.00019 min−1. This study indicates that foamy-oil evolution processes in the heavy oil reservoirs are rather different from those observed from the bulk-phase tests, such as the PVT tests. [ABSTRACT FROM AUTHOR]

The present article highlights a few fundamental aspects that need to be considered while characterizing fluid flow through a petroleum reservoir. Darcy’s law, as applied in describing fluid flow through pipes or saturated groundwater aquifers, cannot be directly applied under all circumstances. Darcy’s original version of Darcy’s law carries a simple algebraic equation relating linear Darcy flux with the hydraulic gradient. Steady-state Darcy’s law is being applied with lots of assumptions, even when describing saturated groundwater fluid flow. However, fluid flow through a petroleum reservoir involves multi-dimensional, multi-phase and multi-component, compressible fluid flow with inertial effects under non-isothermal conditions. This article highlights first why already established Navier–Stokes Equation cannot be applied to characterize fluid flow through a petroleum reservoir; and then shows why the fundamental principle associated, even with fluid flow through a saturated groundwater aquifer, cannot be applied directly to characterize the flow through a petroleum reservoir. Finally, the article presents critical limitations associated with mass conservation equation, momentum conservation equation and fluid flow equation used to characterize flow through petroleum reservoirs. [ABSTRACT FROM AUTHOR]

During the development of oil reservoirs, a rapid increase in water cut following reservoir flooding leads to inefficient or ineffective circulation of injected water, rendering a significant portion of the remaining oil in the reservoir inaccessible. The displacement method using polymer particle dispersion systems effectively solves the issue of rapid water breakthrough in oil reservoirs. Owing to the particle phase separation phenomenon, polymer particles can selectively penetrate into the larger pores where water circulation is inefficient, enhance their flow resistance, and thereby achieve equilibrium displacement along with an increased swept volume. This paper investigates the heterogeneous distribution of polymer particles within a porous medium, incorporates the red blood cell dendrite concentration distribution theory from biological fluid mechanics, and develops a mathematical model to delineate the viscosity characteristics of polymer particle dispersion systems, taking into account the phase separation phenomenon. Building on this foundation, it formulates a capillary bundle model for the polymer particle dispersion system specifically designed for oil displacement and proceeds to determine its relative permeability curve. Simulation outcomes reveal that at a water saturation level of 0.063, the concentration of polymer particles in fractured large pore capillaries is markedly elevated, yet capillaries with a pore size under 26 µm remain devoid of polymer particles. With the increase of water saturation, the concentration of polymer particles in large pore capillaries reduces, whereas it progressively augments in medium pore capillaries. Upon reaching a peak water saturation of 0.751, capillaries smaller than 18 µm are entirely free of polymer particles. These findings suggest that the heterogeneous distribution of polymer particles markedly inhibits the percolation capabilities of the dispersed system following a water phase breakthrough, facilitating the entry of more dispersion into oil-laden capillaries and thus enhancing the flow capacity of the oil phase. [ABSTRACT FROM AUTHOR]

The development of oil and gas resources in low-permeability reservoirs is being paid more and more attention. Moreover, oil and gas resources in low-permeability reservoirs are affluent, and the water cut of the medium permeability layer is so high that the injection capacity has decreased significantly. Therefore, it is of great importance to address the issues of injectability and enhance oil recovery in low-permeability reservoirs. Given the existing conditions of low permeability and high water cut in Daqing Oilfield, the synthesis of an in situ emulsified associative polymer (ISEPAM) is the focus of the research. The polymer was prepared by micellar polymerization, ensuring a molecular weight of 5 × 106 Dalton. A series of experiments were conducted to investigate its dissolution filtration property, viscosifying, emulsification, anti-adsorption, conductivity, and oil displacement capacity. The experimental results show that ISEPAM has more significant properties than the polymeric surfactant (HB) used in Daqing Oilfield. The ISEPAM solution has significant filterability (filter factor is 1.1), viscosifying (38.66 mPa·s), emulsification (the water evolution rate of ISEPAM was only 4.4% for 60 min at 90% water cut), and good anti-adsorption property (after five adsorptions, still has a viscosity retention rate of 65%) in a specific concentration (1000 mg/L) and the field water in Daqing Oilfield (salinity is 4996.3 mg/L). The reason for this is due to the presence of dynamic reversible networks in the ISEPAM solution, and there are no cationic functional groups on the polymer chain. The conductivity of ISEPAM was tested using a homogeneous square core with 48.1 mD permeability, and the results show that the viscosity retention rate of the effluent can reach 90% and excellent injection property can be achieved. In the oil displacement test, ISEPAM presents excellent sweep efficiency and enhanced oil recovery by about 25% under 50 mD permeability. Under low permeability conditions, the ISEPAM exhibits better injectability and excellent oil displacement capacity. The related findings can provide an important idea and reference for the design and development of EOR polymers in the reservoirs with low permeability or high water cut. [ABSTRACT FROM AUTHOR]

The shale reservoir consists mainly of mud shale, characterized by its unique physical and chemical properties, extensive bedding, and micro-cracks. As a result, it is susceptible to hydration and dispersion, leading to the instability of the wellbore during drilling. To address this issue, chemical or physical methods are necessary to enhance the wellbore integrity and ensure stability during the drilling process. This paper focuses on simulating the biomimetic mineralization process to study the composite membrane structure formed by the deposition of montmorillonite and polyelectrolyte. The study investigates the reinforcement effect of the composite membrane on the wellbore wall. By examining the morphology and structure of montmorillonite and BPEI deposition films, the influence of deposition times and polyelectrolyte variations on the deposition film is analyzed. Additionally, the mechanical properties of the montmorillonite and BPEI deposition film are evaluated. The investigation also employs simulated drilling fluid circulation deposition to assess the reinforcement effect of the deposition film on the well wall. Experimental results indicate that the deposition film formed by montmorillonite and BPEI demonstrates a certain level of effectiveness in improving wellbore stability. These findings provide a solid basis for further research on process technology and offer new insights for ensuring the safety of shale oil reservoir drilling. [ABSTRACT FROM AUTHOR]

In recent years, with the continuous development of exploration technology, great achievements have been made in shale oil exploration in the ST Basin in my country. However, in practice, due to insufficient understanding of the formation mechanism, evaluation standards and resource potential of shale oil, this has brought certain constraints and limitations to the exploration and evaluation of shale oil. This article conducts a comprehensive analysis of the main controlling factors of shale oil resource potential in Area A of the ST Basin. Based on the "three-thirds" relationship between TOC and oil content, the shale oil and gas resource classification evaluation method is determined. Using the shale oil reservoir evaluation method, the shale oil in Area A of the ST Basin was evaluated. The study found that Block A not only has good reservoir performance, but also has excellent oil and gas quality, and the brittle minerals have good compressibility. The shale oil resources in area A were calculated based on relevant parameters, and it was found that the potential shale oil resources in this block reached 9.66·109 t. The research provides certain technical support for the exploration and development of shale oil in China. [ABSTRACT FROM AUTHOR]

After volumetric fracturing, the conventional recovery methods for tight oil reservoirs rely on natural energy depletion. However, the production rate rapidly declines due to their intricate characteristics, such as threshold pressure gradient (TPG), stress sensitivity, and multi-scale porous media. This study plotted permeability loss charts based on stress sensitivity experiments. A pressure distribution equation incorporating TPG and flow in different regions was developed, and production prediction methods for tight oil reservoirs were established. The results revealed the effects of TPG and multi-region flow on pressure distribution, demonstrating the need to control bottom hole pressure (BHP) in tight oil reservoirs. Accordingly, methods to improve tight oil reservoir development were proposed by controlling BHP. Reducing BHP, increasing the imbibition displacement, and improving oil-phase mobility proved conducive to enhanced oil recovery. The development model featuring BHP control for 1000 days with initially rapid and subsequently slower BHP declines demonstrated the highest recovery rate, surpassing depletion development by 7.404%. This research helps us to optimize tight oil reservoir development plans while offering significant practical guidance for developing similar oil reservoirs, which is of the reference value for the industry. [ABSTRACT FROM AUTHOR]

Molecular diffusion is critical for enhanced oil recovery (EOR) in shale oil reservoirs with complex fracture networks. Understanding the influence of fractures on diffusive mass transfer is crucial for predicting oil recovery and remaining oil distribution. Diffusive mass transfer between fractures and matrix is critical in comprehensively and effectively simulating molecular diffusion. Resolution of matrix cells significantly affects diffusion accuracy at the fracture–matrix interface. Low resolution results in multiple fractures in the same matrix cell, leading to decreased precision in calculating mass transfer by conventional methods. To address this, a novel multiphase and multicomponent model is proposed. The new model integrating the consideration of fracture spacing modifies molecular diffusion transmissibility between fracture and matrix in an embedded discrete fracture model. The discretization employs the two-point flux approximation in the finite-volume method. Validation compares the coarser mesh to the finest grid as a reliable reference. Results show the proposed model accurately captures diffusive mass transfer in a coarser mesh. Modified models study molecular diffusion's effects on EOR in shale oil reservoirs with complex fracture networks by CO2 huff and puff. Results indicate that increasing injection rates cannot improve oil recovery under extremely low porosity and permeability. Molecular diffusion facilitates CO2 penetration into the formation. This expands the swept CO2 volume and increases both volume expansion and formation energy. In addition, the light and heavy components of the crude oil are diffused into the fractures and eventually produced, which reduces gas production in the case of diffusion. [ABSTRACT FROM AUTHOR]

Due to damage caused by fracturing fluid invasion, tight oil reservoirs exhibit slow post-hydraulic fracturing production recovery and low productivity. This study investigates the impact of a nanoclay-based active agent system on oil–water two-phase flow during and after fracturing fluid invasion, emphasizing its potential for enhancing recovery in tight oil reservoirs. Laboratory experiments using crude oil and natural core samples analyze the mechanism of how nanofluids affect oil–water distribution and flow characteristics during fracturing fluid invasion and oil recovery stages. Results show that nanofluids rapidly disrupt the emulsified state of "water-in-oil" emulsions, reducing emulsion viscosity by 84.19% and oil–water interfacial tension by two orders of magnitude, facilitating oil droplet dispersion and deformation and altering the wettability of oil-wet rock surfaces to aid crude oil detachment. Nanofluids increase the accessible volume of the water phase in pores and throats, enlarging flow paths for fracturing fluid flowback and oil recovery. The oil recovery process post-fracturing fluid invasion is delineated into three stages: substantial fracturing fluid flowback in the first stage, with nanofluids reducing the fluid return rate by 11.08% upon crude oil breakthrough; emulsion droplets occupying pores and throats in the second stage, with nanofluids reducing additional resistance during emulsion flow; and continuous oil production in the third stage, with nanofluids consistently and stably altering rock surface wettability to reduce invaded rock matrix resistance to oil flow. The findings of this study hold potential value in mitigating damage from fracturing fluid invasion in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

Nowadays, there has been a recognition of the remarkable potential of nanofluids and microorganisms as eco-friendly agents for enhanced oil recovery. on the other hand, one of the unique strategies for boosting hydrocarbon recovery is altering the wettability of the rock surface of oil and gas reservoirs. Herein, a nanohybrid that combines graphene oxide (GO) and silica (SiO2) was synthesized using a low-temperature, facile, and eco-friendly approach (sol-gel). GO-SiO2 nanocomposite was characterized with the aid of XRD, SEM, and FTIR analyses. Afterward, Nanofluids with different concentrations (0.005, 0.01, 0.015, and 0.02 wt%) of GO-SiO2 nanocomposite at various ratios (1:1, 1:2, and 2:1) were prepared using a surfactant-free and pH-neutral approach with a salinity of 30,000 ppm. The results of the Zeta potential measurement reveal that the manufactured nanofluids have great stability and the ratio of 1:1 was the most effective ratio for improving the reservoir wettability change from oil-wet to water-wet. At a higher temperature of 80 °C compared to the ambient condition of 25 °C, a more significant change in wettability was observed (23° to 161°). At the optimal concentration of nanofluid (0.015 wt%), the contact angle increased from 23° (on a non-treated surface) to 161°. These findings suggest that GO-SiO2 has great potential as an affordable, flexible, and environmentally friendly natural nanofluid, particularly under harsh conditions for the EOR process. [ABSTRACT FROM AUTHOR]

The identification of lithology is a crucial step in determining the characteristics of petroleum reservoirs, and many studies have investigated the application of deep neural networks in lithology identification. However, incorrect lithology labels as a result of manual interpretation can seriously affect network training when deep learning is used to identify lithology from well logging data. To address this problem, a method of learning with noisy labels (probabilistic end-to-end noise correction in labels, PENCIL) is applied to the network training process. Experiments are conducted on two real well logging datasets, and two types of label noise, random and pattern, are added to the lithology labels of the training data to simulate the lithology label noise that may exist in the actual data. To demonstrate the effect of this method, this study trains four network models, namely residual network (ResNet), bidirectional gated recurrent unit (Bi-GRU), ResNet-PENCIL, and Bi-GRU-PENCIL. The results of the experiments show that pattern label noise has a more serious effect on network training than random label noise, and network models that use the PENCIL framework effectively mitigate the effect of incorrect lithology labels on lithology identification results. [ABSTRACT FROM AUTHOR]

In order to further clarify the shale oil accumulation period of the Chang 7 member of the Mesozoic Triassic Yanchang Formation in the Zhijing-Ansai area of the central Ordos Basin, Using fluid inclusion petrography analysis, microscopic temperature measurement, salinity analysis and fluorescence spectrum analysis methods, combined with the burial history-thermal history recovery in the area, the oil and gas accumulation period of the Chang 7 member of the Yanchang Formation in the Zhijing-Ansai area was comprehensively analyzed. Sixteen shale oil reservoir samples of the Mesozoic Triassic Yanchang Formation in seven typical wells in the study area were selected.The results show that the fluid inclusions in the Chang 7 member of Yanchang Formation can be divided into two stages. The first stage inclusions mainly develop liquid hydrocarbon inclusions and a large number of associated brine inclusions, which are mainly beaded in fracture-filled quartz and fracture-filled calcite. The fluorescence color is blue and blue-green, and the homogenization temperature of the associated brine inclusions is between 90–110°C. The second stage inclusions are mainly gas-liquid two-phase hydrocarbon inclusions, gas inclusions and asphalt inclusions. Most of them are distributed in the fracture-filled quartz, and the temperature of the associated brine inclusions is between 120–130°C. Fluid inclusions in Chang 7 member of the Yanchang Formation can be divided into two stages. The CO2 inclusions and high temperature inclusions in the Chang 7 member of the Yanchang Formation are mainly derived from deep volcanic activity in the crust. [ABSTRACT FROM AUTHOR]

The volcanic rocks in the deep depth of Nanpu sag is the main formation of oil and gas enrichment. It has huge resource potential and prospects for exploration and development. Accurate characterization of lithology and pore space is the basis of reservoir quality prediction. Through petrography studies of cores and thin sections, explosive and sedimentary facies represent the dominant oil and gas-bearing reservoirs, and intergranular pores and fractures are major pore and seepage space. In order to predict favorable reservoirs and improve the efficiency of fracturing, according to composite well loggings and electrical images, logging response features of different lithofacies are characterized and five types of pore structure facies are classified. Further, five types of petrophysical facies are proposed. Among them, Type I and Type II are the most favorable petrophysical facies in the study area. The petrophysical facies typing approach show consistency with oil test data, which verifies that this approach can well predict reservoir quality and provide technical support for the exploration and development of the oil and gas-bearing volcanic rocks. [ABSTRACT FROM AUTHOR]

Radial borehole fracturing is a production method that combines ultrashort radius radial boreholes with hydraulic fracturing, which is expected to effectively improve the drainage and transformation effect of tight oil and gas reservoirs. In view of the problem that radial boreholes cannot be fully fractured when high-pressure liquids are injected into them simultaneously, this paper proposes a new method of fracturing the radial boreholes step by step, and this method is verified by the laboratory fracturing experiments. It designed and processed wellbores with both internal and external pipes, conducted 24 sets of radial boreholes step-by-step experiments of double-layer radial boreholes, analyzed the reproducibility of the experimental results, and compared the results of fracturing radial boreholes simultaneously and fracturing radial boreholes step-by-step experiments. The results show that this method can fracture two sets of radial boreholes distributed in different vertical planes. The results demonstrate that this method is feasible and can solve the problem that not all the radial boreholes are fractured when fracturing fluids are simultaneously injected into them. Besides, the azimuth is the key factor affecting fracture geometries. When the azimuths are 0° and 30°, the fractures can cut through radial boreholes in different layers within the rock samples. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. Fracturing radial boreholes with smaller azimuths first and then radial boreholes with larger azimuths should be selected. This study provides a theoretical basis for the field application of radial borehole fracturing technology. Highlights: A new method of fracturing the radial boreholes step by step is proposed. The azimuth is the key factor affecting fracture geometries. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. [ABSTRACT FROM AUTHOR]

To address the issue of low viscosity and poor high-temperature shear resistance of suspension liquid type fracturing fluids commonly used in continuous fracturing operations for high-temperature unconventional oil reservoirs with large displacement mineralized water, A novel titanium crosslinking agent has been prepared, which can significantly enhances the temperature resistance and shear resistance of the gel. In addition, a novel dialysis purification method is proposed, which allows the titanium crosslinker to be pre-mixed with anhydrous suspension, and overcomes the defect of uneven mixing due to high viscosity fluid when add crosslinker, which can't be solved by boron or zirconium crosslinker. Here, the crosslinking agent was prepared by mixing butyl titanate, lactic acid, triethanolamine and water according to a certain molar ratio. Then, the resulting gel was obtained by pre-mixing with suspension fracturing fluid liquid, and can maintain the viscosity of 63.1mPa·s at a shear rate of 170 s−1 and 150 °C, which is nearly twice that of the gel to bring with added externally crosslinking agents. The fracturing fluid can effectively increase fracturing efficiency, and has excellent application prospects in the context of High temperature deep well and large displacement fracturing. [ABSTRACT FROM AUTHOR]

The precise determination of minimum miscible pressure is of great importance for CO2 enhanced oil recovery and storage as it directly influences the efficiency of pore-scale oil displacement and CO2 trapping. In this study, an interpretable machine learning framework is developed, enabling the reliable evaluation of nano-confined minimum miscible pressure. Four machine learning algorithms (Random Forest, Multi-layer Perceptron, Support Vector Regression, and eXtreme Gradient Boosting) are employed to accurately predict the nanoconfined minimum miscible pressure of a CO2-oil system. The results demonstrate that, excluding support vector regression, the determination coefficients for all models surpass 94%, signifying the robust predictive performance of our model. Subsequently, Shapley Additive exPlanations is used to analyze the feature importance ranking and the impact of each input feature on minimum miscible pressure in these models. Based on the interpretation results, our multi-layer perceptron model is superior in mining the inputoutput relationship and reflecting the petrophysical laws, rendering it highly suitable for predicting the minimum miscible pressure while considering nano-confinement. In addition, it is found that pore size significantly influences minimum miscible pressure prediction and that minimum miscible pressure decreases with decreasing pore size when the pore size is =75 nm. Single-factor sensitivity analysis is applied to validate the trend patterns between input features and minimum miscible pressure in the multi-layer perceptron model. [ABSTRACT FROM AUTHOR]

Gas injection displacement is a widely used technique to enhance the recovery of coal methane (CH4) or oil reservoirs. Additionally, this method plays a crucial role in effectively developing CH4 resources in a closed goaf. In the present study, the distribution characteristics of fissures in a closed goaf were determined using a physical simulation test, and the connected fissure network was extracted and modeled. Further, CH4 extraction numerical simulation tests were conducted on the connected fissure network under gas injection conditions. The migration and distribution characteristics of CH4 were analyzed in the connected fissure network under different gas injection conditions, including gas injection position, gas injection rate, and gas injection type. The research also evaluated the impact of different gas injection conditions on CH4 production in vertical wells. Finally, a model was developed to determine characteristic parameters for CH4 production in vertical production wells, which were calculated and compared across different gas injection conditions. Results revealed a negative correlation between CH4 volume fraction and gas injection time in vertical wells under different gas injection conditions, contrary to the S-type growth curve. Gas injection positions significantly influenced the migration and distribution of gas within the connected fissure network, with higher CH4 productivity and production efficiency in the gas injection position P2 compared to P1. The increase in the gas injection rate enhanced CH4 production efficiency, albeit having little effect on CH4 productivity. Gas injection types yielded no significant influence on CH4 production efficiency, although CH4 productivity was lower with 100% CO2 injection compared to 100% N2 and mixed gas. This investigation provides the foothold for enhancing the recovery of CH4 in closed goafs and contributes to the progress of carbon emission reduction technology in coal mining areas. [ABSTRACT FROM AUTHOR]

Turbidite deposits are of great importance because of their correlation with the existence of oil reservoirs. Therefore, the spatial distribution of these deposits is frequently studied, considering the turbidite probability maps. The uncertainty of the original turbidite data, captured indirectly by sonars, is quantified by generation of possible scenarios of the probability map. This research aims, from the use of statistical characteristics and the creation of groups, through unsupervised machine learning algorithms, to identify the possible scenarios, generated by geostatistical methods, that are more similar to the original data considered in the study. Through the results, in addition to quantifying the uncertainties generating possible scenarios, it is verified that the methodology developed is capable of creating differentiated groups and identifying the group that has similar characteristics to the reference data, helping in the generation and identification of possible scenarios of turbiditic basins. The main novelty of this work is to combine geostatistical and machine learning methods, in addition to creating groups of images that have similar statistical characteristics. [ABSTRACT FROM AUTHOR]