This study evaluated the effect of monovalent and divalent ions and the dosage of a SiO2-based nanocomposite on the thermochemical stability of HPAM polymeric solution. Chelating Amine–Functionalized NPs (AFNPs) were used to enhance the thermochemical stability of HPAM based on capturing monovalent/divalent ions after seven days at 70°C. Different polymer solutions prepared with calcium chloride dihydrate (CaCl2·2H2O) at 2000 mg/L and sodium chloride (NaCl) at 10000 mg/L, and two different dosages of HPAM (1000 and 2000 mg/L) were assessed in the presence and absence of AFNPs at dosages of 200, 500 and 1000 mg/L. The nanocomposite was characterized by N2 adsorption, Fourier-transformed infrared spectrophotometry (FTIR), thermogravimetric analysis (TGA), dynamic Light Scattering (DLS), and Zeta potential (ZP). Stability tests over time confirmed the positive effect of nanocomposite on increasing the thermochemical stability of polymer solutions. Results revealed that adding 0, 200, and 500 mg/L of nanocomposite to the polymeric solution at 1000 mg/L of HPAM, 10000 mg/L of NaCl, and 2000 mg/L of CaCl2·2H2O led to the viscosity reductions of 73.5%, 18%, and less than 1% after 7 days (70°C), respectively. Nanocomposite at 200 mg/L reduces the polymer degradation in the presence of the two salts evaluated separately, i.e., 20% for 10000 mg/L of NaCl and 15% for 2000 mg/L of CaCl2·2H2O. The adsorption tests on AFNPs and SiO2 NPs concluded that AFNPs had higher adsorption of cations in comparison to SiO2 NPs and that greater adsorption of cations is related to a reduction in polymer degradation.

Accurate characterization of crude oils by determining the composition of saturates, aromatics, resins and asphaltenes (SARA) has always been a challenging task in the petroleum industry. However, conventional experimental methods for determination of SARA composition are labour intensive, time-consuming and expensive. In the present study, artificial neural network (ANN) models were developed to predict the SARA composition from easily measurable parameters like density and viscosity. A dataset of 216 crude oil samples covering wide range of geographical locations was compiled from various literature sources. The ANN models with one hidden layer and six neurons are trained, tested and validated using MATLAB neural network toolbox. Results obtained on analysis revealed reasonably good accuracy of prediction of SARA components except for aromatics. The performance of developed ANN models was compared with various correlations reported in literature and found to be better in terms of mean squared error and coefficient of determination. The developed models hence provide a cost-effective and time-efficient alternative to the conventional SARA characterization techniques.

This review addresses the diverse applications of multiphase flows, focusing on drilling, completions, and injection activities in the oil and gas industry. Identifying contemporary challenges and suggesting future research directions, it comprehensively reviews evolving applications in these multidisciplinary topics. In drilling, challenges such as gas kicks, cutting transport, and hole cleaning are explored. The application of immersion cooling technology in surface facilities for gas fields utilized in integrated bitcoin mining is also discussed. Nanotechnology, particularly the use of nanoparticles and nanofluids, shows promise in mitigating particulate flow issues and controlling macroscopic fluid behavior. Nanofluids find applications in drilling for formation strengthening and mitigating formation damage in completions as highlighted in this work, as well as in subsurface injection for Enhanced Oil Recovery (EOR), waterflooding, reservoir mapping, and sequestration tracking. The review emphasizes the need for techno-economic analyses using multiphase flow models, particularly in scenarios involving fluid injection for energy storage. Addressing these multiphase flow challenges is crucial for the future of energy diversity and transition initiatives, offering benefits such as financial stability, resilience, sustainability, and reliable supply chains. The first part of this review presents the application of multiphase (typical gas, liquid, solid) flow models and technology for drilling, completion, and injection operations. While the second part reviews the applications of multiphase particulate (nanofluid) flow technology, the use of Computational Fluid Dynamics (CFD), Machine Learning (ML), and system modeling for multiphase flow models in drilling, completions, and injection operations.

The Upper Dalan and Kangan or Permian-Triassic carbonate formations in the central the Persian Gulf are considered as world’s giant gas reservoirs. The primary purpose of this research is to model and evaluate the relationship between hydraulic flow units (HFUs), electrofacies and microfacies with systems tracts of Permian-Triassic sequences. By integrating the results of core data, petrographic studies, and petrophysical logs of the studied formations, hydraulic flow units and electrofacies were identified. Based on the results of petrographic studies, twelve microfacies were identified in terms of textural and depositional characteristics. Based on depositional setting, sedimentary facies and INPEFA values obtained from gamma ray log and gamma deviation log (GDL) in the context of sequence stratigraphy, zonation of Dalan and Kangan reservoirs is carried out. The zonation boundaries correspond to the key stratal surfaces (sequence boundary and maximum flooding surface). Seven petrographic rock types (PRT) were identified for the upper Dalan-Kangan reservoirs based on sedimentary texture, diagenetic process and dominant pores. Using porosity and permeability data from the core analysis, five hydraulic flow units were identified based on the flow zone indicator (FZI) method. Using multi-resolution graph-based clustering (MRGC) four electrofacies were detected from petrophysical data (gamma, neutron, density and acoustic logs). Subsequently, the INPEFA, GDL and electrofacies were spatially modeled using the sequential indicator simulation (SIS) and sequential Gaussian simulation (SGS) geostatistical methods. Finally, a clear agreement was revealed between the reservoir zones and the stratigraphic sequence framework. It this regard, the microfacies belonging to the high-energy and grain-dominated settings (packstone, grainstone) of leeward shoal, shoal and seaward shoal belts have the best reservoir units due to the influence of dissolution and dolomitization. The best reservoir units in the Permian-Triassic deposits in the middle of the upper Dalan and lower Kangan are developed in UDS4, upper KS2 and middle KS1 units. On the other hand, mud-dominated facies (mudstone, wackestone) and anhydrite textures are mostly associated with the low-energy lagoonal environments, between tidal flat and Sabkha. Non-reservoir units have been formed in the upper Dalan/Kangan and in the transgressive systems tract of UDS3-a, KS2-a and the lower and upper part of KS1 transgressive-highstand systems tract.

Water injection for oil displacement is one of the most effective ways to develop fractured-vuggy carbonate reservoirs. With the increase in the number of rounds of water injection, the development effect gradually fails. The emergence of high-pressure capacity expansion and water injection technology allows increased production from old wells. Although high-pressure capacity expansion and water injection technology has been implemented in practice for nearly 10 years in fractured-vuggy reservoirs, its mechanism remains unclear, and the water injection curve is not apparent. In the past, evaluating its effect could only be done by measuring the injection-production volume. In this study, we analyze the mechanism of high-pressure capacity expansion and water injection. We propose a fluid exchange index for high-pressure capacity expansion and water injection and establish a discrete model suitable for high-pressure capacity expansion and water injection curves in fractured-vuggy reservoirs. We propose the following mechanisms: replenishing energy, increasing energy, replacing energy, and releasing energy. The above mechanisms can be identified by the high-pressure capacity expansion and water injection curve of the well HA6X in the Halahatang Oilfield in the Tarim Basin. By solving the basic model, the relative errors of Reservoirs I and II are found to be 1.9% and 1.5%, respectively, and the application of field examples demonstrates that our proposed high-pressure capacity expansion and water injection indicator curve is reasonable and reliable. This research can provide theoretical support for high-pressure capacity expansion and water injection technology in fracture-vuggy carbonate reservoirs.

This paper comprehensively reviews the application and research progress of CO2 fracturing fluids in China, highlights the existing issues and puts forward suggestions for future development. Three types of fracturing fluid systems containing CO2, namely, CO2 dry fracturing fluid, CO2 energized fracturing fluid, and CO2 foam fracturing fluid, are categorized based on the mass ratio and process difference between CO2, water, and treatment agents. Field applications in China reveal several problem to be resolved: (1) The application scope of CO2 fracturing fluids is restricted to depleted reservoirs, re-fracturing of old wells, and medium-deep reservoirs with low formation pressure coefficients; (2) different types of CO2 fracturing fluids require different processes and ground supporting equipment; (3) optimization of CO2 compatibility, functionality, temperature and salt tolerance, as well as the cost of treatment agents is necessitated; (4) existing CO2 fracturing fluid system fail to perform well with low friction, low filtration, and high sand-carrying capacity. (5) there lacks a targeted industry standard for evaluation of performance of CO2 fracturing fluid system and treatment agents. Therefore, in order to meet the goals of CCUS-EOR, CCUS-EGR, or integration of fracturing, displacement and burial by CO2, efforts should be made in the aspects that followed, including in-depth investigation of the mechanism of CO2 fracturing fluids, the adaptability and compatibility between existing equipment, different CO2 fracturing fluid systems and processes, and construction of treatment agents, low-density proppants and high-performance systems of recyclability and industrial-grade. In addition, optimization of CO2 fracturing fluid system based fracturing design is also crucial taking such related factors such as overall reservoir geological conditions, petrophysical properties, CO2 transportation, and well site layout into consideration.

Sand production along with the oil/gas detrimentally affects the oil production rate, downhole & subsurface facilities. Mechanical equipment and various chemicals like epoxy resin, furan resin, phenolic resin, etc. are used in the industry to reduce or eliminate this problem. In the present study, a blend of organic and inorganic silicates are used to consolidate loose sand in the presence and absence of crude oil using a core flooding apparatus. The effects of chemical concentration, pH, curing temperature and time, and the presence of residual oil on the consolidation treatment results such as compressive strength and permeability retention, were investigated and optimized. FT-IR and FE-SEM characterization techniques were employed to investigate the interaction between the chemical molecules and the sand grains. The current binding agent exhibited a viscosity of less than 6 cP at room temperature, which facilitates efficient pumping of binding agent into the desired formation through the well bore. The developed mixture demonstrated consolidation properties across all pH conditions. Furthermore, during the experimental investigation, the curing time and temperature was carefully optimized at 12 h and 423.15 K, respectively to achieve the highest compressive strength of 2021 psi while achieving the permeability retention of 64%. The current chemical system exhibited improved consolidation capacity and can be effectively utilized for sand consolidation treatment in high-temperature formations.

The investigation of low-temperature oxidation (LTO) of crude oil within tight shale holds significant importance due to its implications for subsequent oxidation reactions and enhanced oil recovery in the process of air injection. In this study, the tight shale sample underwent oxidation at various LTO temperatures, followed by an analysis of the resulting gas composition. Furthermore, the oxidized oil was separated from the tight shale and subjected to characterization using electron paramagnetic resonance, nuclear magnetic resonance, and negative ion electrospray Fourier transform-ion cyclotron resonance mass spectrometry techniques. The primary focus was on examining the distinct LTO reaction pathways observable across different temperature ranges. The findings demonstrated a correlation between LTO temperature and the concentration of free radicals, which predominantly resided on aromatic hydrocarbons, alkanes, and oxygen atoms. Additionally, the proton count of polycyclic aromatic hydrocarbons exhibited a continuous increase from 83 to 350 °C, suggesting intensified aromatization and condensation reactions involving aliphatic and aromatic compounds. With rising LTO temperature, the molecular structure of O2 compounds underwent significant transformations, characterized by increased condensation degree and a decrease in low carbon number molecular structures, while higher equivalent double bonds and carbon number molecular structures became more prevalent. The influence of cycle path 1 diminished at temperatures ranging from 83 to 150 °C and 250 to 350 °C, whereas the significance of cycle paths 2 and 3 increased, resulting in an overall escalation of the oxidation rate with temperature elevation. It was observed that the shale oil LTO process exhibited a negative temperature coefficient within the temperature range of 150-250 °C, emphasizing the criticality of overcoming the energy barrier in this region to achieve stable combustion. This comprehensive investigation provides valuable insights into the mechanisms underlying LTO in crude oil confined within tight shale.

The sedimentary environment of the Upper Triassic in the southeastern Sichuan Basin is obviously controlled by Luzhou paleo-uplift (LPU). However, the influence of paleo-uplift on the sedimentary patterns of the initial stages of this period in the southeastern Sichuan Basin has not yet been clear, which has plagued oil and gas exploration and development. This study shows that there is a marine sedimentary sequence, which is considered to be the first member of Xujiahe Formation (T3X1) in the southeastern Sichuan Basin. The development of LPU resulted in the sedimentary differences between the eastern and western Sichuan Basin recording T3X1 and controlled the regional sedimentary pattern. The western part is dominated by marine sediments, but the eastern paleo-uplift area is dominated by continental sedimentation in the early stage of T3X1, and it begins to transform into a marine sedimentary environment consistent with the whole basin in the late stage of the period recorded by the Xujiahe Formation. The evidences are as follows: (1) time series: based on the cyclostratigraphy analysis of Xindianzi section and Well D2, in the southeastern Sichuan Basin, the period of sedimentation of the Xujiahe Formation is about 5.9 Ma, which is basically consistent with the Qilixia section, eastern Sichuan basin, where the Xujiahe Formation is widely considered to be relatively complete; (2) distribution and evolution of palaeobiology: based on analysis of abundance evolution of major spore-pollen, many land plant fossils are preserved in the lower part of T3X1, indicates the sedimentary environment of continental facies. In the upper part of T3X1, the fossil of terrestrial plants decreased, while the fossil of marine and tidal environment appeared, this means that it was affected by the sea water in the late stages of T3X1; (3) geochemistry: calculate the salinity of water from element indicates that the uplift area is continental sedimentary environment in the early stage of T3X1, while the central and western areas of the basin are marine sedimentary environment. Until the late stage of T3X1, the southeast of the basin gradually turns into marine sedimentary environment, consisting with the whole basin; (4) types of kerogen: type Ⅲ kerogen representing continental facies was developed in the early stage of T3X1 in the uplift area, and type Ⅱ kerogen, representing marine facies, was developed in the late stage; while type Ⅱ kerogen was developed in the central and western regions of the basin as a whole in T3X1. This study is of great significance for understanding of both stratigraphic division and sedimentary evolution providing theoretical support for the exploration and development of oil and gas.

Graphene is a single atom thick crystal composed of carbon atoms. It is the lightest, thinnest, strongest material that conducts heat and electricity well heretofore. In terms of application, by introducing oxygen-containing groups, graphene can be well dispersed in solvents, can be chemically modified and functionalized, or connected with other electroactive substances through covalent bond or non-covalent bond to form composite materials, which is conducive to further processing and promotion. The application of graphene in oilfield chemistry started late, but developed rapidly. Graphene has played an active role in drilling fluid, cementing fluid, fracturing fluid, displacement fluid and other oilfield working fluids. It can enhance the temperature and salt resistance of working fluid and improve the effect of working fluid. In this paper, several directions of graphene applications in oilfield chemistry, such as modified graphene, graphene copolymers and graphene nanoparticles, are reviewed in detail from the synthesis methods, action mechanisms and effects of graphene and its derivatives, and the frontier cases at this stage are given. On the basis of the existing research, suggestions for the development direction of graphene materials in oilfield chemistry are given for a variety of graphene materials, aiming to provide guidance for the application of graphene in oilfield chemistry.