High-temperature Reservoirs Research Articles

Experimental study on critical sand production pressure gradient at different production stages of high temperature and high pressure tight sandstone gas reservoir

AbstractSand production is a common issue in sandstone gas reservoir development, severely impacting the productivity of sandstone gas wells. In order to thoroughly investigate the sand production characteristics of high‐temperature and high‐pressure tight sandstone gas reservoirs, this study focuses on six core samples from tight sandstone gas reservoirs(three samples with fractures), under reservoir conditions (185 MPa, 160°C), sand production experiments were conducted to thoroughly investigate the sand production patterns in sandstone reservoirs under the combined influence of different effective stresses and production pressure differentials. The results indicate: (1) under the simultaneous increase of effective pressure and production pressure differential, sand production near the wellbore (r = 0.1 m) becomes more likely in the reservoir; (2) in actual reservoirs without fractures near the wellbore (r = 0.1 m), sand production phenomena do not occur; (3) reservoirs with fractures near the wellbore (r = 0.1 m) are more prone to sand production, under an effective stress of 90 MPa, with specimens containing fractures exhibiting a 76.48% lower critical sand production pressure gradient compared to those without fractures; (4) when the pore fluid pressure is 95 MPa, the maximum gas production rate for Well X without sand production is 12.4 × 104 m3/d. The experimental results have guiding significance for the rational production of gas wells in this type of reservoir.

Preparation and Performance Evaluation of Temperature-Resistant and Salt-Resistant Gels.

In order to improve the plugging performance of high-temperature and high-salt oil reservoir plugging agents, this paper utilizes a copolymer composed of acrylamide and 2-acrylamide-2-methylpropanesulfonic acid (AM/AMPS) as the polymer, polyethyleneimine as the cross-linking agent, and nylon fiber as the stabilizer to develop a high-temperature- and high-salt-resistant gel system. This study analyzed and evaluated the temperature resistance, salt resistance and blocking performance of the gel system. The evaluation results show that the gel-forming strength of this gel system can reach an H level, and it has good thermal stability at the high temperature of 130 °C. At the high salinity of 240,720 mg/L, the syneresis rate remains below 2.5%, and the gel-forming time is greater than 15 h; the higher the temperature, the shorter the gelling time. The results of our sand-filled pipe-plugging experiment show that the gel system can adapt to sand-filled pipes with different levels of permeability, and reaching a plugging rate of 94%.

In-situ poly(hexahydrotriazine) gels temporary plugging agent suitable for high-temperature reservoirs: Regulation by inorganic chloride salts

A new acid-soluble in-situ temporary plugging agent suitable for high-temperature reservoirs was developed. By regulating the aldehyde-amine condensation reaction using inorganic chlorine salts, the poly(hexahydrotriazine) gels (PHT gels) exhibit good plugging performance and high-temperature resistance and can be degraded in weak acid solutions without residue. Results show that inorganic chlorine salts have a regulating effect on the gelling time of the gelant. Without the salt or the addition of monovalent chlorine salt, the gelant gels at room temperature but does not form a gel at high temperatures. After adding divalent or trivalent inorganic salts, PHT gels are formed at high temperatures, and their gelling time increases with the increase in salt content. Mechanical compression experiments show that the compression resistance of PHT gels is almost unchanged after exposure to high temperature (140 °C) and high salt (200 g/L NaCl and 10 g/L CaCl2). Displacement experiments show that PHT gels have excellent plugging performance with a plugging rate of more than 98.50% and a maximum plugging pressure of 5.34 MPa under the high temperature and high-salt conditions mentioned above. In addition, a hydrochloric acid solution with pH ≤ 5 can achieve residue-free breakage of PHT gels. The gel-breaking fluid has a high surface activity to facilitate flowback and a core unblocking rate of more than 100% after gel-breaking, making the reservoir permeability recoverable. The plugging and acidolysis ability of PHT gels make them excellent in-situ temporary plugging agents. This study aims to provide insights into the preparation of PHT gels and their use in high-temperature reservoirs.

Atrimonas thermophila gen. nov., sp. nov., a novel anaerobic thermophilic bacterium of the phylum Atribacterota isolated from deep subsurface gas field and proposal of Atrimonadaceae fam. nov. within the class Atribacteria in the phylum Atribacterota

A novel anaerobic, thermophilic bacterium of the class Atribacteria, strain M15T, was isolated from a high-temperature gas reservoir, Japan. Cells of strain M15T were gram-negative, short oval-shaped, and lacked flagella. Growth occurred at 45–75 °C (optimum 70–75 °C) and pH 6.5–8.5 (optimum pH 7.5–8.0) and was fast under optimal conditions (doubling time 11.4 h). Yeast extract was required for growth. Fermentative growth with glucose, arabinose, xylose, and cellobiose was observed. The major fermentative end products of glucose were acetate and hydrogen. The major cellular fatty acids were C16:0, iso-C15:0, and C18:0. The genomic G + C content was 46.0 mol%. Fluorescence and electron microscopy observations revealed the intracellular localization of genomic DNA surrounded by a membrane in the cells of strain M15T as reported in a sole validly described species of the class Atribacteria in the phylum Atribacterota, Atribacter laminatus strain RT761T, suggesting that the unique morphological traits are widely shared in this class. Phylogenetic analyses indicated that strain M15T belongs to a distinct family-level lineage in the class Atribacteria and shows low similarities to Atribacter laminatus strain RT761T (16S rRNA gene sequence identity of 90.1 %, average nucleotide identity [ANI] of 66.1 %, average amino acid identity [AAI] of 55.8 %). Phenotypic traits of strain M15T (thermophilic, fast-growing, relatively high G + C content, etc.) were clearly distinct from A. laminatus. Based on these phenotypic and genomic properties, we propose a novel genus and species, Atrimonas thermophila gen. nov., sp. nov. for strain M15T (=JCM39389T, =KCTC25731T) representing a novel family Atrimonadaceae fam., nov. in the class Atribacteria.

Synthesis and Characterization of a Temperature-Sensitive Microcapsule Gelling Agent for High-Temperature Acid Release.

Deep, high-temperature carbonate reservoirs, represented by the Chuanzhong-Gaomo Block and the Penglai Gas Field, have become important supports for increased storage and production in Sichuan Basin. However, acidization in high-temperature to ultrahigh-temperature reservoirs faces several technical challenges, such as fast acid-rock reaction rates, limited acid corrosion distances, and high risks of tubular corrosion. In this study, a novel high-temperature-resistant microencapsulated gelling agent GLE-3 was prepared using N-isopropylacrylamide (NIPAM) as the wall material, acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and N-vinylcaprolactam (NVCL) as the core materials, and N,N'-methylenebis(acrylamide) (MBA) as the cross-linking agent through inverse emulsion polymerization. GLE-3 was structurally characterized using infrared spectroscopy, transmission electron microscopy, and particle size analysis, and its properties were evaluated. The results showed that GLE-3 exhibited uniform particle size distribution ranging from 10 to 100 μm. Under high-temperature conditions of 180 °C and a shear rate of 170 s-1, the viscosity of the gel acid solution remained above 27.8 mPa·s, with a viscosity retention rate of 63.76%. Compared to GLE-1 (uncapsulated), GLE-3 demonstrated improved thermal stability and shear stability after microencapsulation. After 60 min of shearing at 180 °C and shear rate of 170 s-1, the viscosity retention rate was 88.99%. Furthermore, under 180 °C conditions, GLE-3 exhibited good high-temperature slow-release performance compared to GLE-1, which unencapsulated with the same raw materials. By increasing the viscosity of the gel acid, delaying the acid-rock reaction rate, and providing high-temperature slow-release effects, the high-temperature resistance of the acid system was enhanced, ultimately achieving deep acidization in high-temperature reservoirs.

Research on Optimization of CCUS Injection Production Parameters in High-Temperature Reservoirs Based on Intelligent Optimization Algorithms

Research on Optimization of CCUS Injection Production Parameters in High-Temperature Reservoirs Based on Intelligent Optimization Algorithms

Estimating the Influencing Factors of Gas–Water Relative Permeability in Condensate Gas Reservoirs under High-Temperature and High-Pressure Conditions

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.

Development of dual-crosslinked nanocomposite gel for water management in high-temperature reservoirs

Due to their controllable gelation time and high gel strength, polymer gels are widely used in the oil and natural gas industry for sealing operations. Aiming at the problems of fast gelation time and poor stability of polymer gel when the temperature exceeds 120 °C, a dual-crosslinked nanocomposite gel for high-temperature reservoir water management was developed. Polymers, crosslinking agents, nanomaterials, and retarders were studied for the effects of the concentration of each component on the initial viscosity, gelation time, stability, and viscoelastic properties of the gel. The long-term stability and water-plugging adaptability were evaluated. FTIR and viscoelastic performance analyses clarified the mechanism of action. The gel strength and thermal stability enhancement mechanism was analyzed based on SEM. At 170 °C,the gelation time is 5 ∼ 10h after adding retarder and aging in formation water for 30 days resulted in dehydration rates within 10%. The injection volume of the plugging agent is 0.3 PV, and the plugging rate of sand-filled pipes with different permeability is above 97%. The elastic modulus of the terpolymer SAV333/phenol-formaldehyde system was increased by 10 times by resorcinol and SiO2. The enhancement mechanism is mainly due to the gel’s strong dendritic dual-crosslinked network structure and the dual role of hydrogen bonding and electrostatic attraction of SiO2. Dual-crosslinked nanocomposite gel (DCNG) has shown promising performance as sealing material in high-temperature and ultra-high-temperature reservoirs.

Influence of viscosity ratio on enhanced oil recovery performance of anti-hydrolyzed polymer for high-temperature and high-salinity reservoir

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%.

Diagenetic Impact on High-Pressure High-Temperature Reservoirs in Deep-Water Submarine Fan Sandstone of Qiongdongnan Basin, South China Sea

The diagenetic evolution of sandstone is very complicated under the conditions of high temperatures and pressures in deep-water, deep-buried regimes, which have great influence on reservoir quality. This study investigates the typical reservoir target of Neogene deep-water, submarine-fan sandstones under high-temperature, high-pressure regimes in the Qiongdongnan Basin, South China Sea. Utilizing a thin section, scanning electron microscope (SEM), mineral geochemistry combined with burial history evolution, complex diagenetic events, and main controlling factors of the sandstone in the Neogene Meishan Formation were determined. The results show that the evolution of sandstone reservoirs is initially controlled by depositional framework compositions and subsequently modified by eogenetic and mesogenetic alterations during progressive burial. Eogenetic alterations mainly include the following: (1) mechanical compaction; (2) dissolution of feldspar; (3) low-Fe calcite cementation. Mesogenetic events were identified as the following: (1) dissolution of feldspar; (2) ferroan calcite and ankerite formation; (3) precipitation of quartz and clay mineral. Mechanical compaction is greatly influenced by the original depositional framework composition, and sandstone samples enriched in high contents of detrital clay matrix always experienced extensive mechanical compaction. Different phases of carbonate cement during different diagenetic regimes lead to continuous destruction on reservoir porosity. The dissolution of unstable feldspar minerals during eogenetic and mesogenetic environments leads to the development of secondary porosities and would enhance the quality of the reservoir. Overpressure formation is pervasively developed owing to early disequilibrium compaction and subsequent natural gas charging. Only well-sorted sandstones with low contents of detrital clay matrix could resist early mechanical compaction, lead to ample residual original porosities, and then undergo extensive mineral dissolution to generate sufficient secondary porosities. Subsequently, these porosities would be effectively protected by overpressure formation. Poor-sorted sandstones with high contents of detrital clay matrix would experience strong mechanical compaction and extensive destruction of original porosities. Thus, these sandstones are difficult to have significant dissolution and are unable to be effectively protected by overpressure formation. Therefore, the interplay between the original framework composition and the corresponding diagenetic pathways coupled with overpressure formation would result in strong reservoir heterogeneity for the deep-buried sandstones during progressive burial.

Laboratory Investigation and Empirical Modelling of Polymer Solution Viscosity

Polymer flooding, an improved oil recovery technique, is a well-established method for improving oil production. Although numerous polymers have been suggested in the literature, identifying suitable ones for applications in high-temperature and high-salinity carbonate reservoirs remains a challenging task. The viscosity of polymer solutions depends on various parameters, including polymer concentration, temperature, and shear rate. Therefore, screening polymers for these demanding conditions necessitates meticulous experimental work. In this experimental study, polymer solutions' physical property—viscosity—was measured as a function of polymer concentration, temperature, and shear rate. Subsequently, the generated rheological data were used to develop empirical models capable of predicting the viscosity of polymer solutions under various conditions. An acceptable match was achieved between the experimental and model-predicted data. Furthermore, a validation was conducted for the empirical models, yielding a root mean square error of 1.75. These models will significantly reduce the number of experiments required for the screening process and prove valuable for optimization procedures.

Interfacial Behaviors and Oil Detachment Mechanisms by Modified Silica Nanoparticles: Insights from Molecular Simulations.

Surfactant flooding has been considered as a promising approach for chemically enhanced oil recovery (EOR). However, this technique encounters several limitations, such as high costs, environmental concerns, and reduced efficiency under high-temperature and high-salinity reservoir conditions. Recently, nanoparticles have also been proposed as an alternative for EOR due to their superior properties compared with surfactants. This research employs molecular dynamics simulations to explore the impact of modified SiO2 nanoparticles on oil-water interfacial behaviors and the detachment of oil droplets from an oil-wet surface. The simulation results reveal that modified nanoparticles, featuring hydrophilic and hydrophobic functional groups, have slight impacts on interfacial tension reduction of the oil-water interface. Nanoparticles with varying degrees of modification exhibit distinct positions within the interface, consequently influencing the thickness of the interfacial layer. Notably, the interactions among the nanoparticles, oil molecules, and surface facilitate the formation of a water channel, thereby enhancing the process of oil detachment. Comparative analysis indicates that in terms of oil displacement efficiency, the thickness of the interfacial layer has a more significant impact than interfacial tension reduction. Furthermore, to elucidate the mechanisms of modified nanoparticles enhancing the oil recovery rate, the interaction energies among the oil droplet, nanoparticles, water, and surface are analyzed. The molecular-level insights derived from this investigation could provide valuable guidance for the design of modified nanoparticles tailored to EOR applications.

Development, evaluation and stability mechanism of high-strength gels in high-temperature and high-salinity reservoirs

The high-temperature and high-salinity environment of the reservoir present a challenge for developing high-strength gels. In this study, a combination of acrylamide/2-acrylamido-2-methylpropanesulfonic acid (AM/AMPS) and partially hydrolyzed polyacrylamide (HPAM) was crosslinked with hydroquinone (HQ) and hexamethylenetetramine (HMTA) to prepare high-strength gels suitable for high-temperature and high-salinity reservoirs. The evaluation demonstrated that the gels exhibited exceptional strength, with a storage modulus exceeding 40 Pa. Gels containing more than 0.2 % crosslinker remained stable for over 120 days in brine with a salinity of 22 × 104 mg/L at 130 °C. Core flooding experimental evaluation revealed that the gel exhibited excellent plugging ability in fractures. Mechanisms of gel hardening and long-term stability in high-temperature and high-salinity environments were investigated by rheological testing, cryo-scanning electron microscopy (cryo-SEM) and Fourier transform infrared spectroscopy (FTIR) analysis. Results suggest that chelation between carboxylate groups in the gel and bivalent cations like calcium or magnesium increases mesh density, leading to hardening of the gel; aging also contributes to maintaining its strength while limiting syneresis due to AMPS presence and high mesh density, thus ensuring stability in extreme environments. The findings, although limited to laboratory-scale conditions and subject to potential variations in real time applications, still serve as a proof of concept for guiding the formulation of high-strength gels in reservoirs under extreme conditions.

Cracking process and microstructural characteristics of granite under heating–cooling alternations

Studying the damage correlation mechanism of rocks subjected to heating–cooling alternations is of important significance for deeply understanding the permeability increase mechanism of reservoirs during heat extraction from hot dry rocks and assessing the reservoir stability. By carrying out the uniaxial compression test, Brazilian splitting test, nuclear magnetic resonance test, and scanning electron microscopy test on granite after heating–cooling alternations, the evolution laws of physical and mechanical properties as well as the microstructures of granite were studied. In addition, the multi-scale response characteristics and the damage correlation mechanism of granite after heating–cooling alternations were analyzed. Research results show that, when the heat treatment temperature rises to 600 °C, the physical and mechanical parameters, including the wave velocity, strength, and elastic modulus, reduce abruptly. The heat treatment temperature exerts more significant influences on the physical and mechanical properties of the granite than the heating–cooling alternation cycles. Both the temperature and alternation cycles are beneficial to the microcrack development and propagation, while the temperature more significantly affects the development degree of microcracks. Under the external load, the microscopic defects in the granite after heating–cooling alternations guide the propagation of macrocracks and cause more serious damage to the microstructures in the granite, exhibiting more complex failure modes. The results provide a theoretical basis for fracturing technology and stability evaluation of high-temperature reservoirs.

Long-Term Thermal Stability of Ionic Surfactants for Improving Oil Production at High-Salinity High-Temperature Conditions.

Surfactants with stable chemical structures and robust ability are required to lower interfacial tension and stabilize emulsions for successful chemical injection applications. This work selected six surfactants, dodecyl carboxylic sodium (LAS), dodecyl sulfonate dodecyl sodium (SLS), dodecyl sulfate sodium (SDS), dodecyltrimethylammonium bromide (DTAB), 3-(N,N-dimethylmyristylammonio) propanesulfonate (SB3-14) and a sulfobetaine formulation (PCT-10), and systematically investigated the ionic-type effects on thermal stability at 95 °C for 150 days in high-salinity water (total dissolved solids (TDS) = 57,600 ppm). With characterizations of aged samples performed through a spinning drop tensiometer, high-performance liquid chromatography, and infrared spectroscopy, it can be seen that the long-term stability sequence of ionic surfactants in solutions is sulfobetaine ≈ quaternary ammonium > sulfonate > sulfate > carboxylate. The carboxylate possibly precipitates out from the solution in the acid form, and the sulfonate and sulfate decompositions are due to the hydrolysis of the anionic head, forming alcohol and NaHSO3/NaHSO4. Obvious decomposition of sulfobetaine and quaternary ammonium was not observed, but these molecules might suffer the elimination of the ionic head, forming the corresponding alkene and amine. The results also show that the dissolved oxygen in the solution preparation significantly sped up the degradation of sulfonates. At last, the emulsion stability tests of crude oil in surfactant solutions showed that sulfobetaine surfactants retained the highest emulsifying ability after thermal aging and thus are promising candidates for long-term chemical injection in high-temperature high-salinity reservoirs.

Fracture behavior and fracture surface roughness of high-temperature granite subjected to liquid nitrogen and water cooling

The thermal damage mechanism of water and liquid nitrogen on granite is a key scientific concern in reservoir fracturing. This study conducted fracture tests on high-temperature granite specimens subjected to water and liquid nitrogen cooling. The fracturing process was monitored and the fracture surface roughness was evaluated. The results indicated that the P-wave velocity, peak load, and fracture toughness exhibited a decreasing trend with increasing heating temperature. Specifically, at 150 °C, liquid nitrogen cooling samples exhibited higher fracture toughness than untreated ones. Acoustic emission events at peak load were more prominent in liquid nitrogen cooling samples, indicating higher brittleness and concentrated energy release. Conversely, water cooling samples displayed prolonged post-peak stages, suggesting greater ductility. The size of fracture process zones (FPZ) generally increased with temperature, with water cooling samples consistently exhibiting larger FPZ dimensions compared to liquid nitrogen cooling samples. Despite this, liquid nitrogen cooling resulted in significantly rougher fracture surfaces and numerous small cracks, while water cooling formed more extended through-going fractures. This suggests that high-temperature granite reservoirs by liquid nitrogen fracturing can enhance heat exchange areas more effectively. Additionally, different types of granite exhibit varying responses to temperature changes and cooling treatments, contingent on their unique mineral composition and structure.

Microfluidic devices, materials, and recent progress for petroleum applications: A review

AbstractMicrofluidic devices are miniaturized systems that manipulate fluids on a small scale, typically at microlitre or nanolitre volumes. They have received significant attention in various industries, including petroleum applications. The recent advancements in microfluidic devices for petroleum applications have the potential to improve oil recovery efficiency, reduce costs, and provide valuable insights into fluid behaviour and reservoir characterization. This paper aims to provide a comprehensive overview of microfluidic devices, their materials, and their applications in the petroleum industry. The first section of the paper focuses on describing the materials used in microfluidic devices specifically tailored for energy sector applications. In the second section, the paper highlights relevant applications and discoveries in petroleum research, showcasing the innovative techniques and special features enabled by microfluidic devices. These applications include but are not limited to asphaltenes characterization, enhanced oil recovery (EOR), and water treatment. The versatility and customization of microfluidic devices have allowed researchers to accurately represent fractures, ensure chemical conformance, simulate high pressure–high temperature conditions and reservoir heterogeneity, and study geochemical interaction. Additionally, molecular tagging and machine learning techniques have been employed for image analysis, further enhancing the capabilities of microfluidic devices. Throughout the paper, the advantages and disadvantages of implementing microfluidic devices and utilizing specific materials are thoroughly discussed. This analysis provides valuable insights into the challenges and potential limitations associated with this technology. To conclude, the paper offers suggestions, ideas, and highlights for future research paths, pointing toward promising directions for further exploration in this field.

A novel TLFD-GA algorithm for multi-objectives optimization of ORC power plants with the effect of pressure drop considered

This research introduces a novel TLFD-GA algorithm for the three-level criteria optimization of organic Rankine cycle (ORC) power plants. It replaces the non-dominated sorting of NSGA-II with three-level fuzzy decision to simultaneously optimize environmental, thermodynamic, and techno-economic criteria. The algorithm provides direct optimization results without needing additional decision-making methods. Furthermore, the impact of pressure drop in plate heat exchangers is investigated, revealing a proportional relationship between pressure drop and the increment of evaporation pressure. A parametric study on 24 basic and recuperative trans-critical geothermal ORC systems indicates that compensating for pressure drop leads to a 5% decrease in thermodynamic performance, a 20% decrease in techno-economic performance, and a 20–60% increase in heat transfer area per net output power. After TLFD-GA optimization, the saving to investment ratio improves by an average of 4.5% across scenarios. R1270 stands out with a remarkable ratio of 3.13 and 4.32 in medium and high-temperature geothermal reservoirs. Moreover, the proposed TLFD-GA optimization algorithm has demonstrated its superiority in terms of superb convergence and stability when compared to NSGA-II, which suggests its prospective application in the low-carbon and green energy fields.

Research on EOR for ultralow interfacial tension foam in high-temperature and high-salinity reservoirs: flooding simulation and application in Shengli Oilfield

For high temperature and high salinity reservoirs, the foam formulation system is required to have better foaming capacity and foam stability under formation conditions in tertiary EOR. In order to obtain a new foam agent suitable for this type of oil reservoir, through the compounding and testing of 7 common oilfield foam chemical agents, 15 formulated foam agents are tested and screened. Then the foam displacement experiment of the dual sand packs model was established to simulate the new foam flooding process. The production dynamic of the high-permeability sand pack and the low-permeability sand pack was captured and analyzed, and EOR mechanism of the foam system in the heterogeneous reservoir was clarified. The experimental results show that the formulation of B4(anionic & nonionic combined surfactant) & FSN100(fluorinated surfactant) with a mass proportion of 2:3 (BF23) has the best performance in terms of foaming properties, low interfacial tension reduction, and oil washing efficiency. Furthermore, BF23 foam injection greatly increased the recovery factor from 36.7% to 61.6%, clearly displacing the remaining oil in the low-permeability pack. Finally, the new foam agent solution used in Shenger block of Shengli Oilfield shows its good value for enhanced oil recovery.

Geothermal Resource Exploration in Reshi Town by Integrated Geophysical Methods

Geothermal resources are a sustainable and valuable source of energy that offers considerable economic and social advantages. The present investigation centers on the accessibility of geothermal reservoirs in Reshi Town, Taoyuan County, Changde City, located in the Hunan Province of China. Geophysical exploration techniques are of paramount importance in the identification and exploration of geothermal resources. The present investigation utilized an integrated geophysical approach that incorporates induced polarization (IP), magnetotelluric (MT), and joint profile techniques. The primary objective of this study was to examine the distribution of formation lithology, subsurface electrical structures, karst fracture development zones, and the location and occurrence of deep and large thermal reservoirs in Reshi Town, Changde City. The research encompassed a comprehensive process that included the collection of data, its subsequent interpretation, inversion, and validation through drilling. The joint profile approach provided comprehensive data on fault structures within the study region. Using magnetotelluric sounding, areas with lower electrical resistance were found along lines L2, L3, and L4. This showed that thermal water reservoirs were underground. The induced polarization sounding method exhibited a distinct response to geothermal water, including minerals, suggesting the presence of a high-temperature geothermal reservoir, along line 1. Drilling operations carried out at two different locations, ZK01 on line L3 and ZK02 on line L4, confirmed the existence of underground hot water. The drilling findings have verified the existence of faults F3 and F4, which act as important channels for geothermal fluids. The present research offers a dependable geophysical foundation for the forthcoming development of geothermal resources in Reshi Town, and areas with similar geological conditions.