High-temperature Reservoirs Research Articles

Preparation and performance evaluation of the slickwater using novel polymeric drag reducing agent with high temperature and shear resistance ability

Slickwater fracturing fluids are widely used in the development of unconventional oil and gas resources due to the advantages of low cost, low formation damage and high drag reduction performance. However, their performance is severely affected at high temperatures. Drag reducing agent is the key to determine the drag reducing performance of slickwater. In this work, in order to further improve the temperature resistance of slickwater, a temperature-resistant polymeric drag reducing agent (PDRA) was synthesized and used as the basis for preparing the temperature-resistant slickwater. The slickwater system was prepared with the compositions of 0.2 wt% PDRA, 0.05 wt% drainage aid nonylphenol polyoxyethylene ether phosphate (NPEP) and 0.5 wt% anti-expansion agent polyepichlorohydrin-dimethylamine (PDM). The drag reduction ability, rheology properties, temperature and shear resistance ability, and core damage property of slickwater were systematically studied and evaluated. In contrast to on-site drag reducing agent (DRA) and HPAM, the temperature-resistant slickwater demonstrates enhanced drag reduction efficacy at 90 °C, exhibiting superior temperature and shear resistance ability. Notably, the drag reduction retention rate for the slickwater achieved an impressive 90.52% after a 30-min shearing period. Additionally, the core damage is only 5.53%. We expect that this study can broaden the application of slickwater in high-temperature reservoirs and provide a theoretical basis for field applications.

Evolution mechanism of permeability of hot dry rock under coupled effect of thermal fatigue and seawater interaction during coastal geothermal development

Using seawater as a heat transfer fluid for developing hot dry rock (HDR) geothermal energy in coastal areas is a frontier of engineering worth exploring; however, only a few studies have considered this research topic. During the development of HDR based on enhanced geothermal system (EGS) technology, the thermal shock fatigue effect of low-temperature seawater on high-temperature reservoirs leads to changes in the permeability of the HDR, notably impacting the reservoir reconstruction design and heat transfer efficiency. Accordingly, the changes in pore structure, pore distribution, porosity, and permeability of HDR in the Guangdong-Hong Kong-Macao Greater Bay Area were investigated based on nuclear magnetic resonance (NMR) techniques and fractal theory after treatment to different temperatures and numbers of thermal shocks due to seawater interaction. The experimental results showed that with an increase in temperature and the number of seawater interactions, the pore structure distribution of the HDR underwent significant changes, with the proportion of mesopores and macropores increasing by 24.29 % and 10.52 %, respectively. Moreover, the porosity and permeability increased with increasing temperature and number of thermal shock cycles, especially above 300 °C. When the temperature increased from 100 °C to 500 °C, the total porosity increased from 0.98 % to 3.85 %, an increase of 292.9 %, while the permeability increased from 10−4 mD to 0.1 mD, an increase of nearly 1000 times. Changes in the pore structure, pore distribution, porosity, and permeability of HDR are caused by multiple damage mechanisms related to high-temperature nonlinear expansion, thermal shock effects, chemical erosion, and fatigue. Additionally, the permeability of the HDR after seawater treatment at the same heat treatment temperature and number of thermal shocks was higher than that after freshwater treatment. At a temperature of approximately 500 °C and 20 thermal shocks, the permeability of HDR under the action of seawater was approximately seven times that of fresh water. Therefore, these results suggest that using seawater as a heat transfer fluid has more advantages in enhancing the permeability of reservoirs.

Molecular dynamics study on BS12/SDS stabilized CO2 foam: Evaluation of surfactant monolayer structure and interfacial properties

CO2 foam flooding holds great potential for enhanced oil recovery and geological storage. However, ensuring the stability of supercritical CO2 foam systems under high temperature and pressure reservoir conditions remains a challenge. Note that the term "supercritical CO2 foam" specifically denotes a foam system created by combining an aqueous solution containing chemical additives with CO2 in a supercritical state under high-temperature and high-pressure conditions. Surfactants can reduce the surface Gibbs free energy by adsorbing onto the CO2-water interface to form a monolayer structure, which hinders CO2 diffusion and improves foam stability. In this study, molecular dynamics simulations were employed to analyze the adsorption behavior and interfacial performance of betaine surfactant BS12 and the anionic surfactant SDS at the CO2-water interface. The results indicate that BS12 can reduce interfacial tension more effectively at near-saturated concentrations. Moreover, the monolayer formed by BS12 has a lower voidage and wider interfacial thickness. The carboxyl-nitrogen interaction among BS12 molecules impedes their further aggregation, thereby maintaining the mutually perpendicular "L" orientation of the headgroup and hydrophobic tail thus forming a rigid and stable monolayer structure. Additionally, the spatial distribution function, radial distribution function, and hydrogen bond statistics indicate that although BS12 exhibits slightly weaker hydrophobicity than SDS, its hydrophobicity is less affected by concentration. Specifically, the first hydration shell of the carboxyl group remains stable even at high concentrations. Besides, the steered simulations show that the rate-limiting step in the CO2 permeation process is the dense region of the surfactant headgroups. Besides, the permeation of CO2 molecules in the BS12 monolayer is characterized by a lower diffusion coefficient and higher energy barrier to overcome. In summary, BS12 forms a thicker and more uniform monolayer structure, effectively hindering the contact between CO2 and water molecules at the interface and further enhancing foam stability. Our findings further reveal the relationship between surfactant molecular architecture and interfacial properties, providing references for the screening and structural design of surfactants used in CO2 foam flooding.

SELECTION OF SURFACTANT COMPOSITIONS FOR EXTRACTION RESIDUAL OIL RESERVES IN THE CONDITIONS OF HIGH-TEMPERATURE RESERVOIRS OF THE NEOCOMIAN DEPOSITS OF THE BS GROUP FORMATIONS OF WESTERN SIBERIA

Maintaining stable production at fields in the final stage of development requires the use of enhanced oil recovery (EOR) methods that allow the mobilization of residual oil in the reservoir. The introduction of EOR based on surfactant compositions in our country is complicated by the shortage of effective thermostable reagents, which are both expensive and difficult to access. Accordingly, the issues of their import substitution are quite acute. In this work, on the basis of available anionic surfactants and nonionic surfactants, it was possible to compose two multicomponent surfactant compositions (high- and low-concentrated) for the mobilization of residual oil in the conditions of high-temperature reservoirs of the neocomian sediments of the BS group of Western Siberia. To substantiate the the components of the composition and the method of its injection, a set of experimental physico-chemical and filtration testing methods was used. In particular, the interfacial tension, the kinetics of oil film washing, the phase behavior in the oil-watersurfactant system, as well as the pre-displacement of oil after flooding using a linear composite core model of the reservoir were determined. The developed surfactant composition is a synergistic mixture that reduces the interfacial tension at the water/oil boundary to ultra-low values (5·10–3 mN/m at 0.5 % surfactant), which makes it possible to form a low-viscosity medium phase of a type III microemulsion according to the Winsor classification and effectively solubilize oil. A method of injection of surfactant compositions is proposed, according to which a rim of sulfonated polyacrylamide (PAA) with the addition of diethanolamine is injected into the oil reservoir after surfactant edging. Analysis of the dynamics of oil displacement from the linear model of the reservoir after flooding suggested that as a result of the action of a surfactant composition with subsequent injection of a polymer solution with diethanolamine, capillary-trapped oil is first mobilized, and then film oil.

Molecular insights into the synergistic mechanisms of hybrid CO2-surfactant thermal systems at heavy oil-water interfaces

A hybrid thermal recovery process is a promising EOR (Enhanced Oil Recovery) method and has been widely applied to post-steamed heavy oil reservoirs. Due to the complexity of High Temperature and High Pressure (HTHP) reservoir environments, Molecules Dynamics (MD) simulations are conducted to investigate the interfacial behavior between multiphase multicomponent fluids and heavy oil over a wide temperature range. We select CO2 and a cost-effective anionic surfactant, SDS (Sodium Dodecyl Sulfate), to build hybrid thermal systems. The interfacial behavior in different systems is characterized by the local density distribution, cluster analysis, hydrogen bond characters, solvent accessible surface area, and interaction energy. Systematic MD simulations reveal a two-step interfacial tension (IFT) reduction process stimulated by thermal migration. Both CO2 and SDS can achieve an IFT decrement with different mechanisms. Moreover, a co-addition of CO2 and SDS can further efficiently reduce the IFT. Average Reduced Density Gradient (aRDG) results reveal that a unique asphaltenes-SDS-CO2 structure improves the interfacial activities and mobility of the heavy oil phase through a bidirectional mass exchange mechanism, which ultimately realizes the most significant IFT decrement. Furthermore, an optimal concentration (10C–20S) in a hybrid thermal system is recommended because of its balanced performance. This work sheds insight into the synergistic effects of multiphase multicomponent thermal fluids on hybrid thermal systems, which will guide future field applications of hybrid thermal EOR processes.

Research on imbibition effect of surfactant fracturing fluid in offshore reservoirs with low permeability and high temperature

Surfactant imbibition can effectively improve the development effect of fracturing technique. In order to enhance oil recovery, a temperature resistant surfactant was selected using interfacial tension and contact angle testers based on the offshore reservoir conditions of high temperature and low permeability. Experiments on spontaneous and forced imbibition with artificial columnar cores were performed to optimize parameters of imbibition processes during fracturing in high temperature and low permeability reservoirs. Results show that among the three surfactants, amphoteric Gemini surfactant had a stable molecular structure with non-compressible hydrophobic groups which significantly reduced oil-water interfacial tension, enhanced rock wettability, and demonstrated good resistance to high temperatures The maximum recovery increase during amphoteric Gemini surfactant imbibition is 16.22%. The higher the core permeability, the higher the core inside pressure, and the longer the well shut-in time, the greater the forced imbibition effect. A proper well shut-in time and injection volume should be considered when using surfactant solution as fracturing liquid.

ИЗУЧЕНИЕ ВОЗМОЖНОСТИ ГИДРАТООБРАЗОВАНИЯ В ПЛАСТАХ СЕВЕРО-ЗАПАДНОЙ ЧАСТИ ИНДИГИРО-ЗЫРЯНСКОГО ПРОГИБА

The paper gives a brief description of geological section of the Indigirka-Zyryanka trough, promising for oil and gas, and the results of parametric drilling. Possibility study of hydrate formation in reservoir conditions of trough as one of the reasons for obtaining negative well test results was conducted. Performed calculations of the equilibrium conditions of hydrate formation have determined that the hydrate stability zone covers an insignificant interval of deposits 222 m thick below the bottom of permafrost rocks. It is concluded that the main reason for the insignificance of the hydrate formation zone is a relatively high geothermal gradient, which causes sufficiently high reservoir temperatures in the section. It is noted that favorable conditions for the formation of gas hydrates may arise in the presence of heavy differential pressure drawdown on the formation in the vicinity of borehole.

Characteristics and Research Significance of Micro-Nanoparticles in Geothermal Fluids in the Central Area of Shandong Province

The micro-nanoparticles found in geothermal fluids exhibit distinct characteristics that hold great potential for detecting deeply concealed geothermal resources. Utilizing a nanoparticle tracking analyzer (NTA), we conducted observations on karst geothermal fluids collected from the central region of Shandong Province, specifically Jinan and Zibo. Our investigation revealed the presence of a significant quantity of naturally occurring micro-nanoparticles within these geothermal fluids, with particle sizes typically falling in the range of 100 nm to 5 μm. To gain a comprehensive understanding of these micro-nanoparticles, we subjected them to a detailed analysis, encompassing their type, shape, crystal structure, and chemical composition. This in-depth examination was carried out using transmission electron microscopy (TEM). Our findings, supported by TEM images and energy dispersive spectroscopy, indicated that these micro-nanoparticles in the geothermal fluid samples predominantly exhibit amorphous characteristics and possess irregular or nearly spherical shapes, often accompanied by rough edges. Furthermore, it was evident that the composition of these micro-nanoparticles primarily consists of carbonates, sulfates, and chlorides, which contain elements such as Fe, Ca, and Na. The distinctive features of these micro-nanoparticles provide valuable insights into the properties of the high-temperature reservoirs and aquifers from which they originate. As a result, we firmly assert that natural micro-nanoparticles can significantly contribute to the detection and comprehensive study of concealed geothermal resources within the Earth. This novel approach offers a promising method for exploring and gaining a deeper understanding of these hidden geothermal resources.

CO2 storage in organic nanopores with varying widths: Molecular simulation and simplified local density model

Accurately characterizing CO2 adsorption behavior in organic nanopores is a prerequisite for estimating CO2 storage capacity in shale reservoirs with complex pore structures. This study employs grand canonical Monte Carlo (GCMC) molecular simulations to investigate the CO2 adsorption characteristics in organic nanopores with varying widths over a wide range of temperatures and pressures. Based on GCMC simulations, the pore width in the simplified Local-Density (SLD) adsorption model is related to key adsorption parameters, enabling the SLD model to evaluate CO2 storage density rapidly and accurately in organic nanopores under complex reservoir conditions. The research findings suggest that the features of CO2 excess adsorption curves are mainly influenced by temperature and the number of adsorption layers. Higher temperatures and increased adsorption layers result in higher pressure requirements to achieve the CO2 excess adsorption peak. Under high pressures, the number of adsorption layers plays a critical role in enhancing the adsorption capacity. Due to the constraints of pore size, there are fewer adsorption layers in micropores, leading to higher CO2 excess adsorption in mesopores than in micropores under high pressures. In the SLD model, the key parameter Λb decays exponentially with the increase of pore width. The average density of CO2 in the nanopores calculated by the modified SLD model is in good agreement with the simulation results. Finally, the research reveals that smaller organic nanopore widths result in higher CO2 densities, with limited sensitivity to temperature and pressure variations. Low pressure and high temperature reservoir conditions are unfavorable for CO2 storage, but adsorption significantly enhances CO2 storage density in nanopores, particularly in micropores.

Polyethylene Composite Particles as Novel Water Plugging Agent for High-Temperature and High-Salinity Reservoirs

Water channeling has always been one of the urgent problems during oilfield development. Especially for fractured reservoirs with high temperature, high salinity, and severe heterogeneity (e.g., deep carbonate reservoirs), it is difficult for the existing plugging agents to realize effective water plugging. In this paper, chemically stable polyethylene (PE) was selected as the main component to prepare multiscale PE composite particles that can be easily dispersed in water as a novel water plugging agent for fractured reservoir with high temperature and high salinity. The characteristics of the prepared PE composite particles, including thermal stability, salinity resistance, dispersibility, coalescence properties, and microscopic morphology, were systematically studied. Finally, the plugging performance of the particles was evaluated through visual physical simulation experiments. The prepared PE composite particles can be pulverized to a minimum of 6 μm, and the particle size is controllable within 6 μm to 3 mm by adjusting the pulverization parameters. The PE composite particles are easily dispersed in water by adding the dispersant, which is conducive to injectivity during the field application process. The particle size remains unchanged under the condition of salinity of 0–3.0 × 105 mg/L, which indicates that the prepared particles have good salt-resistant stability. After high-temperature aging, the particles adhere to each other, and the size of the agglomerations reach a size dozens of times larger than the initial size of the particle, which is conducive to effective plugging in fractures. Thermal degradation behavior analysis shows that the PE composite particles could theoretically withstand a temperature of 434.4 °C. It can be seen from the SEM images that after high-temperature melting and kneading with other components, the microstructure changes from a fibrous structure to a dense flake structure. Physical simulation experiments show that the PE composite particles accumulate in fracture after injection and form effective plugging through coalescence and adhesion of the particles, thereby realizing water flow diversion.

Experimental Evaluation of Authigenic Acid Suitable for Acidification of Deep Oil and Gas Reservoirs at High Temperatures

During the acid pressure conversion process in high-temperature, deep oil and gas reservoirs, a number of challenges are encountered that hinder the effectiveness of acid fracturing. These obstacles include significant corrosion of acidized pipe strings, rapid reaction rates of acid with rock, limited reach of acid liquids, and shallow penetration depth of active acids. Additionally, the transportation of highly corrosive acids presents safety risks, necessitating surface conditions that are free of acidity. However, underground conditions require strongly acidic liquids to meet enhanced ecological and environmental protection requirements. To address these limitations, experimental investigations have been conducted to examine the reaction rates of low-corrosive and low-acid rocks in alkaline systems involving halides and carbonyl compounds. Through meticulous assessments of reaction rates and dissociation effects in acid rocks, parameters have been successfully optimized to incorporate erythropoiesis and other compounding agents into acid-pressing designs. The experimental findings indicate that the concentration of released H⁺ ions after 60 min exceeded that of the conventional acid solution processed for 15 min. Enhanced dissolution was observed when erythropoietin content was increased to 20%. Furthermore, combining 10% acetic acid with 20% caustic acid resulted in a significant increase of 6.08% in the dissolution rate from 10 to 120 min, while exhibiting lower dissolution values compared with other types of acids. The development of naturally occurring acids with reduced rates of dissolution and acid–rock reaction holds significant potential for enhancing the efficacy of high-temperature, deep oil and gas reservoirs through acid fracturing stimulation.

Unraveling the Genesis of the Geothermal System at the Northeastern Edge of the Pamir Plateau

High-temperature geothermal systems hold promise for sustainable and environmentally friendly power generation. However, China’s geothermal power capacity significantly underutilizes its abundant resources. This study focuses on the geothermal potential of the Pamir Plateau, particularly its northeastern edge, where complex tectonic forces converge. We aim to unveil the mechanisms driving the emergence of high-temperature geothermal reservoirs in this unique geological setting. Hydrogeochemical analysis reveals diverse profiles in geothermal water, primarily derived from atmospheric precipitation. Estimation of reservoir temperatures and simulation of geotherms unveil distinct geothermal systems. Kongur exhibits a medium–low-temperature hydrothermal system and Tashkurgan demonstrates high-temperature hydrothermal system characteristics, while the Pamir’s northeastern edge hints at a potential high-temperature dry geothermal system where there might not be a fault. These findings have important implications for sustainable energy development and future geothermal exploration.

Strong thickening performance and mechanism of supramolecular system constructed by β-cyclodextrin polymer included adamantane polymer

Introducing supramolecular interactions into polymer systems to improve their properties has recently become a hot topic. However, the formation of supramolecular polymers through host–guest interactions using two types of polymers is rarely reported. In this paper, a novel supramolecular system (ABMN) is prepared by host–guest inclusion of β-cyclodextrin polymer (PAAB) and adamantane polymer (PAMN). Subsequently, the thickening ability and viscoelasticity of ABMN are investigated. The microstructure of ABMN is studied by dynamic light scattering (DLS), atomic force microscopy (AFM), and field emission scanning electron microscopy (FE-SEM). The results show that at the molar ratio of PAAB: PAMN = 1:1 the optimal inclusion is observed with the binding constant between β-cyclodextrin group and adamantane group of 575.33 L/mol. The thickening ability of ABMN is greatly improved when compared to the original polymers. At 90℃ and 32868 mg/L, the viscosity of the ABMN system at 2000 mg/L can reach 38.5 mPa s. The microstructure results evidence that a larger hydrodynamic radius and denser spatial network structures in the ABMN system are formed through the host–guest inclusion interactions. Therefore, the supramolecular system exhibits strong thickening properties and demonstrates exceptional resistance to both temperature and salt, rendering it an optimal candidate for employment in EOR in high-temperature and high-salinity reservoirs.

Enhancing Oil Recovery and Altering Wettability in Carbonate Reservoir Rocks through (3-Glycidoxypropyl)trimethoxysilane–SiO2 Nanofluid Injection

This study analyzes the impact of injection condition design factors of (3-glycidoxypropyl)trimethoxysilane (GPTMS)–SiO2 nanofluid on improving wettability and oil recovery through flotation and core flooding tests, respectively. Flotation tests were conducted to assess improvements in wettability that resulted from varying nanoparticle concentration, reaction time, and treatment temperature. The test results demonstrated that the hydrophilic sample ratio increased by up to 97.75% based on the nanoparticle reaction, confirming significant wettability improvement in all samples. Additionally, time-dependent fluid-flow experiments were conducted to validate oil recovery and rock–fluid interactions. In these experiments, for a 24-h reaction time, nanofluid injection caused a decrease in the maximum contact angle (43.4° from 166.5°) and a remarkable enhancement in the oil recovery rate by over 25%. Moreover, variations in contact angle and sample permeability were observed as the reaction time increased. Subsequently, the core flooding test revealed a critical reaction time of 24 h, maximizing oil recovery while minimizing permeability. Below this point in time, wettability improvement did not significantly enhance oil recovery. Conversely, beyond this threshold, additional adsorption due to particle aggregation decreased permeability, causing reduced oil recovery. Therefore, GPTMS–SiO2 nanofluid can be utilized as an injection fluid to enhance oil recovery in high-temperature and high-salinity carbonate reservoirs.

Inhibition effect of nano-silica synergistic corrosion inhibitor on 110SSsteel in ultra-high temperature organic acidic environment

ABSTRACT Compared to hydrochloric acid, organic acids can reduce the acid rock reaction rate in high-temperature reservoir acidification. Although corrosion inhibitors can reduce the corrosion of acid on the pipe string, the ultra-high temperature makes the effectiveness of corrosion inhibitors unsatisfactory. We found that the use of nano-silica can improve the effectiveness of corrosion inhibitors in organic acid systems. Some interesting findings are as follows. Firstly, the ultra-high temperature made the adsorption film of LD-H uneven or incomplete. Next, the high-temperature corrosion inhibition ability of corrosion inhibitors was enhanced by adding nano-silica to organic acids, with a corrosion inhibition rate of up to 99%. Furthermore, the addition of nano-silica made the adsorption membrane of LD-H more complete or uniform, which more effectively inhibited corrosion reactions. By enhancing the adsorption capacity of corrosion inhibitors and filling adsorption membranes, nano-silica enhanced the corrosion inhibition effect of LD-H in organic acid systems.

Lithology and Lithofacies Characteristics of Deeply Buried Clastic Reservoirs in Alternating Wet-arid Climate and its Hydrocarbon Significance

There have been series of HPHT (high temperature and high pressure) reservoirs with good quality and high productivity discovered in the Triassic Skagerrak Formation in the Central Graben of the UK North Sea. The bottlenecks for further E&P activity are the complicated depositional facies and high reservoir heterogeneity. The main reservoir space is a mixed porosity network composed of primary pores, micro-pores, secondary pores, secondary micro-pores and micro-fractures. Reservoirs of the Skagerrak Formation have greatly varied lateral connectivity as well as poor vertical connectivity. In the case of sufficiently high pressure differentials, hydrocarbon can be fed from high-potential area to low-potential area. There is no simple linear relationship between depth and reservoir quality. The primary depositional texture (grain size/sorting/clay content, etc.) linked to facies has a fundamental control on reservoir quality. Clean and well sorted cross laminated sandstone has the best reservoir quality, while the reservoir quality of planar laminated sandstone decreased due to increased degree of compaction caused by mica drapes. The reservoir quality of the fine-grained ripple cross laminated sandstone is even poorer than that of the planar laminated sandstone, due to abundant mica and clay drapes. Mottled bioturbated sandstone is fine grained with high clay content, which is more muddy because of containing burrows and insect larva. Pedoturbated sandstone has the poorest reservoir quality due to severe dolomite cementation. The dominant detrital material of the Skagerrak Formation is feldspar that provides abundant secondary porosity by alteration and dissolution. Chlorite coats are commonly developed and stained with residual oil or bitumen, which clearly inhibits quartz cementation and feldspar overgrowth. The presence of these clay coats contributes to the preservation of anomalously high porosity at depth in the cleaner and coarser grained fluvial channel facies. The Skagerrak formation facies is a dryland fluvial-lacustrine depositional system which is controlled by fluctuations of depositional base level due to salt mobilisation. The Skagerrak formation consists of several cycles that are vertically separated by lacustrine mudstone. The reservoir permeability system is composed of active fluvial channel sandstones, terminal splay sandstones, abandoned fluvial channel sandstones, minor channel sandstones connecting fluvial channel and terminal splay, as well as low-permeability faults, while the active fluvial channel sandstone is the “sweet spot”. The analysis of controls on deeply buried reservoir quality is significant to precisely predict “sweet spot” in the Skagerrak Formation.

Thermoplastic fracture characteristics of granite suffering thermal shocks

Thermal-shock-dependent thermoplastic fracturing is a prominent characteristic of hydraulic fracturing in high-temperature reservoirs, such as hot-dry-rock geothermal and deep oil–gas reservoirs. When cold water is injected, the rock surrounding the hydraulic fracture tip experiences sudden temperature changes, affecting the cohesive crack's tension-open in the fracture process zone (FPZ), i.e., the temperature-dependent plastic softening behavior. Based on our previously established thermoplastic cohesive fracture model, a description model of rock thermoplastic fracture properties related to thermal shock was proposed. Then, we performed mode-I fracture tests on high-temperature granite subjected to different thermal shock treatments and used digital image correlation (DIC) to characterize the fracture process (especially FPZ development). By comprehensively analyzing loading curves and DIC-based surface deformations, we quantificationally delineated seven thermoplastic fracture characteristics of thermal-shock-treated granite based on the proposed description model. We find that (1) cohesive tensile strength linearly decreases with increased thermal shock. (2) Critical COD and completely developed FPZ length linearly decrease only for temperature differences above 140 °C while they vary slightly for temperature differences from 0 °C to 140 °C (3) Plastic modulus, fracture energy, and accumulated dissipated energy change nonlinearly with the intensification of thermal shock. These three properties slightly vary for temperature differences from 0 °C to 140 °C but significantly reduce once the temperature difference exceeds 140 °C. (4) The temperature sensitivity modulus is mainly positive but follows different evolution laws with the temperature difference (≤140 °C: decreasing; >140 °C: increasing). For temperature differences of 0 °C and 140 °C, the temperature sensitivity modulus shifts from positive to negative only when COD is approximately at 0.5 times the critical value. The positive temperature sensitivity modulus implies that the yield surface of the cohesive crack contracts with enhanced thermal shocks. (5) We compared the linear elastic fracture parameter, energy release rate, with the thermoplastic fracture parameter, fracture energy. Our analysis reveals that the fracture energy is 3.34 ∼ 1.58 times larger than the energy release rate as the thermal shock intensifies, with a significantly different trend in the variability. This highlights the importance of considering thermoplastic fracture characteristics in hydraulic fracturing applications for high-temperature reservoirs. Furthermore, we put forward optimization recommendations based on our findings.

Dynamic modelling of reservoir fines retention by mesoporous silica nanofluid to improve oil recovery during low salinity water flooding of a consolidated sandstone

Mesoporous silica (SiO2) nanoparticles (MSNP) was used to stabilize formation fines for increased oil recovery during low salinity water flooding. Likewise, the effect of porous media length on dynamic retention of fines at high temperature reservoir condition was investigated. Breakthrough curves of reservoir fines adsorption by mesoporous SiO2 nanofluid (MSNF) were described using Thomas and Yoon-Nelson models. Similarly, effect of concentration, flow rate, porous media length and temperature on the retention capacity of reservoir fines was modelled using Box Behnken design of experiments. Subsequently, effect of reservoir fines stabilization on oil recovery was evaluated. Formation damage remediation propensity of MSNF was investigated. Finally, the oil recovery mechanisms were determined using the sessile drop contact angle and Wilhelmy plate methods. Experimental results of the dynamic adsorption with coefficient of determination (R2) values between 0.967 and 0.999 signifies that the reservoir fines adsorption by MSNF were well predicted by Thomas and Yoon-Nelson models. Consequently, MSNF stabilized the reservoir fines by attaching onto their surface rather than on the porous media thereby changing the wettability to water-wet, decreasing the contact angle to 16.1°, 17.1° and 20.7° for kaolinite, illite and montmorillonite, respectively. Thus, increasing oil recovery by 22–23% original oil in place.

Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates

Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10–20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4–5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8–10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery.

Consistency Checks for Pressure-Volume-Temperature Experiment of Formation Oil and Gas at High Temperature

The oil and gas phase behavior of high temperature is complex and changeable, which is usually obtained by PVT experiments. The accuracy of the experiment data plays a crucial role in the reserve evaluation and development plan of oil and gas reservoirs. However, the current PVT experiment consistency checks are not suitable for high-temperature reservoir conditions. This paper proposes a systematic check method for the PVT experiment data consistency at high temperature. These checks revise the material balance method, Hoffman method, and equilibrium constant method by using the equilibrium constant calculation method at high temperature. The consistency check of component data and constant volume depletion experiment data is carried out by combining the three improved methods with the component check method, so as to judge the experiment data accurately. In this paper, two high-temperature reservoir fluids—gas condensate sample fluid X and volatile oil sample fluid Y—are selected to carry out consistency checks with component data and constant volume depletion data. This check method is of great significance to study the phase behavior of formation oil and gas at high temperature, especially for volatile oil and gas condensate fluid.