Low-temperature Reservoir Research Articles

Experimental evaluation of self-generated heat-enhanced fracturing fluid for low-temperature and low-pressure shallow reservoirs

Experimental evaluation of self-generated heat-enhanced fracturing fluid for low-temperature and low-pressure shallow reservoirs

Assessment of carbon dioxide transcritical cycles for electrothermal energy storage with geological storage in salt cavities

Carbon capture, utilisation, and storage (CCUS) technologies are envisaged as critical actors in the energy transition and climate change mitigation framework. Despite the recent advances in CCUS implementation, there is still significant scope for their growth and improvement. On the other hand, developing new large-scale energy storage systems is a key factor for the massive deployment of renewable energy systems. Technologies such as the electrothermal energy storage system based on carbon dioxide transcritical cycles incorporating geological storage (CEEGS) can contribute to both fields. Preliminary studies have shown that the integrated storage system can operate with roundtrip efficiencies exceeding 50%, injecting over 1 million tons of captured carbon dioxide (CO2) annually. It is an early-stage technology with open challenges for successful development, such as an adequate balance between the high- and low-temperature thermal storage reservoirs or the operation definition between the electrothermal system and the carbon dioxide injection and recovery. Underground pressures will oscillate with the charge/discharge process, with operational implications and constraints. Advancing in the concept requires the definition of optimised operation. This work presents a novel analysis of the adaptation of CO2 transcritical cycles to include injection and production processes with the specific scenario of salt cavities. It considers new modifications to adapt the transcritical cycles in closed-mode operation to the conditions required by the salt cavities injection and production processes. Different case studies are evaluated, evaluating the impact of injection and geological storage, production and surface storage, and reinjection into the geological formation. The analyses show roundtrip efficiencies within the range of 49.1–73.0% when the injection, production, and reinjection processes are executed.

RHEOLOGICAL PROPERTIES OF LOW-TEMPERATURE GEL-FORMING COMPOSITIONS

In this work, the rheological properties of low-temperature versions of gel-forming compositions developed at the IPC SB RAS are studied. A composition on an inorganic basis and a composition comprising a polymer and inorganic components are intended to increase oil recovery from low temperature reservoirs. The measurements were carried using a Haake Viscotester iQ rheometer with a CC25 coaxial cylinder measuring system in oscillatory mode with controlled strain at a frequency of 1 Hz. During the oscillation test, the dependences of the elastic modulus G' and the viscosity modulus G'' on the strain amplitude were recorded, the ranges of linear viscoelasticity of the samples under study were established, and the strain value for kinetic experiments was chosen. At a given strain value (0.01), the kinetic dependences of G' were obtained and the dynamics of the rheological properties and the strength of the formed structure were evaluated. The time of gelation onset has been found. It was 2300 s at 38 °C, 3900 s at 30 °C, and 21000 s at 20 °C for the inorganic composition and 200 s at 70 °C, 570 s at 60 °C, and 1920 s at 50 °C for the polymer-inorganic composition. The time required to form a gel of maximum strength also was found to be increased with increasing temperature. It has been established that for all systems under study the time of gel formation was reduced with increasing temperature, while the strength of the formed structure also increased. A slight increase in the maximum value of the modulus G' (33490 and 32805 Pa) was observed for the composition on an inorganic basis at 38 and 30 °C respectively as compared with the maximum of the dependence obtained at 20 °C (24660 Pa). The major increase in the value of the modulus G' has been recorded for the composition on a polymer-inorganic basis with increase in temperature. In this case the value of the modulus G' increased from 8970 Pa at 50 °C to 11680 Pa at 60 °C and 14590 Pa at 70 °C, while the general form of the rheokinetic dependence for different compositions and temperatures remained the same. For citation: Kozhevnikov I.S., Bogoslovskii А.V. Rheological properties of low-temperature gel-forming compositions. ChemChemTech [Izv. Vyssh. Uchebn. Zaved. Khim. Khim. Tekhnol.]. 2024. V. 67. N 8. P. 22-28. DOI: 10.6060/ivkkt.20246708.1t.

Synthesis and Performance Study of Self-Degradable Gel Plugging Agents Suitable for Medium- and Low-Temperature Reservoirs.

Aiming at the problems of current similar hydrogel plugging agents, such as poor breaking performance, nonspontaneous degradation, and reservoir pollution which have been plaguing their application in temporary plugging operations, this study has synthesized a cross-linking agent for hydrogels with dimethylaminoethyl acrylate and dibromo-p-xylene as raw materials. With Fourier transform infrared, 1H nuclear magnetic resonance, and thermogravimetric analyses as representations of the structure and thermal stability of the cross-linking agent, a set of self-degrading hydrogel systems has been developed with the cross-linking agent as the core so as to make evaluations on the temperature resistance, plugging performance, and core damage performance of the hydrogel and conduct a study on its gelation kinetics. The research results show that the cross-linking agent shows good thermal stability. When applied in the hydrogel system, the hydrogel has shown high temperature resistance, maintaining gel strength for 5-10 days at 50-90 °C, with viscosity after complete degradation lower than 10 mPa·s. The excellent bearing strength of the hydrogel system has led to a core damage rate below 5%. The study on gelation kinetics of the hydrogel system shows that, with the increase in the concentration of the cross-linking agent, the gelation time of the hydrogel system is shortened, with the reaction order between the cross-linker concentration and the gelation time at about 0.6 under the condition of 50-90 °C.

DEVELOPMENT AND TESTING OF A MODULE FOR CALCULATING THE PARAMETERS OF SCALE INHIBITORS SQUEEZE TREATMENT

Inorganic scale (salt) deposition in the oil and gas industry is a serious and widespread problem that requires timely measures for effective control and management. The process of formation and deposition of mineral salts depends on a large number of changing factors, which creates additional difficulties for predicting and controlling scale formation processes. The fields of Eastern Siberia, the formation waters of which belong to the category of brines with a mineralization of 250 g/l and more (in some cases more than 600 g/l), are characterized by the scale formation of complex composition (sulfate, carbonate and chloride salts). Scale deposits can occur in the near-wellbore zone of the formation, which can lead to a significant decrease in the productivity of production wells. Many fields in Eastern Siberia have a number of features that complicate their operation. Among them are low reservoir temperature (10–14 °C), reservoir pressure close to the saturation pressure and salinity (halitization) of the reservoir. In the practice of the global oil and gas industry, it has been repeatedly proven that the implementation of technologies to prevent scale deposits is much more technologically and economically efficient than removing already formed sediments. In this regard, the use of scale inhibitors (SI) is one of the key methods to combat the formation of salts. When scale deposits lead to disruption of the operation of submersible well equipment, technologies for continuous or periodic dosing of SI into the annulus of the well can be effective. To protect the bottomhole zone of the formation from scale deposits, the priority technology should be the injection of scale inhibitors or squeeze treatment into the formation under pressure.In this work, based on a set of laboratory filtration experiments, a module has been developed that allows calculating the volumes of scale inhibitor and process fluids required for SI squeeze into the reservoir. The successful results of two operations of SI squeeze into the formation of horizontal wells for protection against deposits of sulfate salts are shown.

Surfactant–Polymer Flooding: Chemical Formula Design and Evaluation for High-Temperature and High-Salinity Qinghai Gasi Reservoir

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main developing enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10−2 mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir.

Preparation and performance evaluation of microencapsulated acid used for gel breaking of fracturing fluid in low-temperature reservoirs

In low-temperature reservoirs, the generation of free radicals by oxidizing breakers is challenging, and the alkaline fracturing fluid generally inhibits enzyme’s activity, making it difficult to break down the fracturing fluid. Previous studies have demonstrated that acids can consume borate ions and disrupt crosslinking nodes even at low temperatures, thereby efficiently breaking gels. Thus, microencapsulated oxalic acid (OA) was prepared via a coacervation method, using ethyl cellulose (EC) or acrylonitrile–butadiene–styrene (ABS) as shell materials with varying initiator viscosities and core–shell ratios. An optimal microcapsule MC[OA/ABS-2000-1:2] was determined based on the coating effect, productivity, encapsulation rate, and release performance. The test results of FT-IR and TGA together proved that the optimal microcapsule was composed of 24.4 and 74.8 % of OA and ABS, respectively. Scanning electron microscopy and laser particle size analysis were employed to characterize the optimal microcapsule with an average particle size of 402.8 μm, which exhibited a high degree of sphericity. Because of their porous shells, these microcapsules exhibited sustained slow-release characteristics. Evaluations conducted at temperatures of 30 and 50 ℃, simulating the tight sandstone reservoir conditions in the Ordos basin, revealed that delayed gel breaking could be achieved within approximately 2.5 h at low temperatures by adding only 0.25 % of the optimal microcapsule. Furthermore, increasing the temperature and dosage of microcapsules resulted in shorter breaking times. Additionally, a synergistic breaking effect was observed between the enzymes and the prepared microencapsulated acid. Thus, by optimizing the microcapsule dosage based on the reservoir temperature and fracturing construction pumping time, employing the two breakers together can achieve delayed and complete gel breaking at the desired time. In conclusion, the microencapsulated acid prepared in this study has significant potential as a gel breaker for fracturing fluids in low-temperature reservoirs.

Molecular dynamics simulation and key performance study of VES self-diverting acid system for deep carbonate reservoirs

Viscoelastic Surfactant (VES) self-diverting acid technology is an ideal approach for enhanced recovery from heterogeneous reservoirs. Most VES self-diverting acid systems currently used in field operations are only suitable for low-temperature reservoirs, and research on self-diverting VES acid systems for deep carbonate rock formations is lacking. Additionally, studies on the molecular dynamics of the self-assembly of VES have mainly focused on cationic surfactants, with insufficient research on the self-assembly of betaines in the oil industry. This study investigated the effects of temperature, surfactant concentration, and metal ion concentration on the self-assembly of erucamide propyl hydroxysulfobetaine (EHSB) based on a self-assembly model through molecular simulation methods. Moreover, the viscosity of the EHSB was predicted under various conditions. The results indicated that the system viscosity was optimal at an EHSB concentration of 4 wt%. The EHSB system requires initiation by metal ions to enhance the viscosity, with Ca2+ having a more pronounced effect than Mg2+. This is attributed to the formation of a unique “octahedral” structure by Ca2+ in solution, which aids in the formation of large micelles. Furthermore, because of the smaller ionic radius of Mg2+ compared with that of Ca2+, Mg2+ is more likely to penetrate micelles and form salt bridges, promoting a tighter arrangement of surfactant molecules. Based on molecular simulation and laboratory experiments, under optimal concentrations of inorganic salts and EHSB, the system’s viscosity remained greater than 150 mPa·s at 140 °C, meeting the requirements for diversion in deep carbonate rock formations. Finally, the acidization capacity and diversion effects of the acidic system were demonstrated using single-core flood and dual-core diversion experiments. The results showed that the acid solution significantly etched the core, and the residual acid reduced the permeability contrast of the core from 3.54 to 2.35, indicating a good acidizing diversion performance. This study utilizes a combination of computer simulations and laboratory experiments to optimize a VES self-diverting acid system. The computer-predicted viscosity corresponds well with the actual measured viscosity, providing new technical insights for evaluating the performance of VES under complex formation conditions that are unattainable through laboratory tests. A self-diverting VES acid system suitable for deep carbonate rock reservoirs at 140 °C was developed, providing technical support for the efficient development of deep carbonate reservoirs.

СОСТАВ И УСЛОВИЯ ФОРМИРОВАНИЯ АЗОТНО-КРЕМНИСТЫХ ТЕРМ АМГИНСКОЙ ГРУППЫ (СЕВЕРО-ВОСТОК ПРИМОРСКОГО КРАЯ)

The article presents new data on the ionic, microcomponent and isotopic composition of thermal waters of the Amga group classified as sodium-bicarbonate waters characterized by low mineralization (up to 0.2 g/l), high contents of silica (up to 24 mg/l), lithium, tungsten and molybdenum, and pH = 8.5–9.7. The influence of neotectonics and Quaternary magmatism on the composition and conditions of formation of nitrogen-siliceous thermal waters is shown. Using δD and δ18O values in thermal and background waters, their atmogenic origin was proved, and the source area of mineral waters was identified. The calculated deep reservoir temperature of 77–81°С indicates the formation of resources in the crust at significant depths (as much as 2.5 km). The efficiency of using the multicomponent geothermometry method for low-temperature reservoirs is shown.

Efficiency estimation of super-viscous oil recovery by in-situ catalytic upgrading in cyclic steam stimulation: from laboratory screening to numerical simulation

The article provides an overview of ion-modified waterflooding technology, also known as low salinity, controlled salinity, or Smart water. This technology is currently considered one of the most promising approaches in the development of oil deposits in carbonate reservoirs due to its economic efficiency and environmental safety. The article discusses the main mechanisms and processes underlying ion-modified waterflooding and presents the results of laboratory studies conducted on core samples from foreign oil deposits. It includes an analysis of several studies, including contact angle measurements and core flooding experiments on core samples from oil deposits in carbonate reservoirs on the eastern side of the Melekess depression in the Republic of Tatarstan. It is important to note that the Vereyian deposits explored in this article are not a typical example of test objects for ion-modified water injection. This is because they are characterized by a low reservoir temperature of 23 °C, which suggests that the efficiency of the technology would likely be lower compared to studies conducted abroad, where reservoir temperatures were significantly higher. For example, Darvish Sarvestani et al. studied reservoir conditions at 90 °C, Yousef et al. – reservoir temperature of 100 °C, and Austad et al. examined the Ekofisk field at 130 °C and the Volhall field at 90 °C in Norway. However, as several studies have indicated, prolonged contact between rock samples and ion-modified water contributes to significant hydrophilization of the rock surface, as confirmed by contact angle measurements. The contact angle decreases from approximately 138.3° to 53.45° after exposure to ion-modified water. Additionally, the core flooding experiment demonstrated a slight increase in the oil displacement coefficient, reaching 9.2%. These findings suggest the potential for enhanced oil recovery by injecting Smart water into the Vereyian sediments, although further research is required to confirm the underlying mechanism.

Potential for improving the efficiency of carbonate oil deposits waterflooding with the use of controlled salinity technology (Smart water) at fields of Tatarstan Republic

The article provides an overview of ion-modified waterflooding technology, also known as low salinity, controlled salinity, or Smart water. This technology is currently considered one of the most promising approaches in the development of oil deposits in carbonate reservoirs due to its economic efficiency and environmental safety. The article discusses the main mechanisms and processes underlying ion-modified waterflooding and presents the results of laboratory studies conducted on core samples from foreign oil deposits. It includes an analysis of several studies, including contact angle measurements and core flooding experiments on core samples from oil deposits in carbonate reservoirs on the eastern side of the Melekess depression in the Republic of Tatarstan. It is important to note that the Vereyian deposits explored in this article are not a typical example of test objects for ion-modified water injection. This is because they are characterized by a low reservoir temperature of 23 °C, which suggests that the efficiency of the technology would likely be lower compared to studies conducted abroad, where reservoir temperatures were significantly higher. For example, Darvish Sarvestani et al. studied reservoir conditions at 90 °C, Yousef et al. – reservoir temperature of 100 °C, and Austad et al. examined the Ekofisk field at 130 °C and the Volhall field at 90 °C in Norway. However, as several studies have indicated, prolonged contact between rock samples and ion-modified water contributes to significant hydrophilization of the rock surface, as confirmed by contact angle measurements. The contact angle decreases from approximately 138.3° to 53.45° after exposure to ion-modified water. Additionally, the core flooding experiment demonstrated a slight increase in the oil displacement coefficient, reaching 9.2%. These findings suggest the potential for enhanced oil recovery by injecting Smart water into the Vereyian sediments, although further research is required to confirm the underlying mechanism.

Low-temperature gel breaking fracturing fluid for marine hydrate reservoir fracturing and its effect on phase equilibrium of methane hydrates

Hydraulic fracturing has been proven useful for improving the gas production efficiency of low-permeability hydrate reservoirs. However, no specific fracturing fluid system exists for marine hydrate reservoirs. Applying conventional water-based fracturing fluids in low-temperature (<293.2 K) marine hydrate reservoirs can lead to difficulties in gel-breaking and hydrate instability caused by external additives. In this study, we developed two water-based fracturing fluid systems that exhibited good gel-breaking performance at low temperatures (278.2–288.2 K), one comprising ammonium persulfate (APS), ferrous sulfate (FeSO4), and citric acid (CA), the other APS and triethanolamine (TEA). In addition, we investigated the influence of crosslinking and gel-breaking reactions of the fracturing fluids on the methane hydrate phase equilibrium. The breaking time of the APS-FeSO4-CA system at 278.2K, 283.2K, and 288.2K was 30 min, 75 min, and 120 min respectively. On the other hand, the APS-TEA system accomplished the same task in 3 h, 6 h, and 10 h respectively. Furthermore, methane hydrate phase-equilibrium data showed that the fracturing fluid's three states, base fluid (BF), fracturing fluid gel (FFG), and gel-breaking liquid (GBL), all exerted an inhibitory effect on the phase equilibrium, with the hydrate suppression temperature (ΔT) ranging from 0.4 to 1.0 K. The differences in their inhibitory effect were primarily related to the micromorphology of the hydroxypropyl guar gum (HPG) molecules and the number of active hydroxyl (-OH) groups in the solution. Cryo-scanning electron microscopy (SEM) measurements revealed that the micromorphology of HPG in BF, FFG, and GBL transformed from regular ribbon-like structures to 3-D network structures and then to hole-containing, short ribbon-like structures. FFG formed a regular 3-D network structure after adding crosslinking agents to the BF. The ΔT values reversed from FFG < BF to FFG > BF when the HPG concentration increased from 0.3 wt% to 0.5 wt%, possibly due to the difference in the HPG molecules' water adsorption capacity before and after crosslinking. The broken HPG molecules with OH− groups in the solution were transformed into residues after gel-breaking, decreasing the GBL's inhibitory effect. Therefore, our results indicated that micromorphology variations could cause differences in the HPG molecules' water adsorption capacity, ultimately leading to ΔT differences. Based on our findings, the gel-breaking fracturing fluid systems we developed demonstrated potential for optimizing hydraulic fracturing in marine hydrate reservoirs.

Injectivity Assessment of Radial-Lateral Wells for CO2 Storage in Marine Gas Hydrate Reservoirs

The carbon dioxide (CO2) leak from conventional underground carbon storage reservoirs is an increasing concern. It is highly desirable to inject CO2 into low-temperature reservoirs so that CO2 can be locked inside the reservoir in a solid state as CO2 hydrates. Marine gas hydrate reservoirs and surrounding water aquifers are attractive candidates for this purpose. However, the nature of the low permeability of these marine sediments hinders the injection of CO2 on a commercial scale due to the low injectivity of wells with conventional completions. This study investigates the injection of CO2 into low-permeability marine reservoirs through a new type of well, namely a radial-lateral well (RLW). A mathematical model was developed in this study to predict the CO2 injectivity of the RLW. The model comparison shows that the use of RLW to replace vertical wells can improve CO2 injectivity by over 30 times, and the use of RLW to replace frac-packed wells can increase CO2 injectivity by over 10 times. A case study and sensitivity analysis were performed with field data from the South China Sea. The result of the analysis reveals that the injectivity of the RLW is nearly proportional to reservoir permeability, lateral wellbore length, and the number of laterals. The CO2 injection rate is predicted to be 19 tons/day to 250 tons/day, which is 3 to 15 times higher than the injectivity of frac-packed wells. It is feasible to inject CO2 into the low-permeability, low-temperature marine reservoirs at commercial flow rates. This work provides an analytical tool to predict the CO2 injectivity of RLW in low-temperature marine reservoirs for leak-free CO2 storage.

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.

Occurrence of deep liquid oil reservoirs in the Sichuan and Tarim basins as constrained by geological evidences and molecular simulation

The hydrocarbon phase state of deep to ultra-deep reservoirs in the Tarim and Sichuan basins has been of great interest in oil and gas exploration. Based on a combination of molecular dynamics simulation, gold-tube pyrolysis experiments, and geological-geochemical theory, this study discusses the mechanisms governing the stability of oils in deep reservoirs from the perspectives of their reservoir accumulation histories and chemical reactions. Generally, the reason for the existence of liquid oil in the Tarim Basin is widely considered to be only controlled by external geological conditions, mainly including low geothermal gradient, absence of thermal events, low maximum reservoir temperatures, and late hydrocarbon generation process. However, this study firstly proposed that the chemical composition of oil is an internal factor for its thermal stability. The simulation results reveal that the polycondensation reactions of asphaltene will release hydrogen atoms, which can provide a necessary hydrogen source for cracking of liquid chain hydrocarbons. It means that the presence of asphaltene components can promote the cracking of chain hydrocarbons and generate methane. The normal mature oil in the Sichuan Basin generally has higher contents of asphaltenes than that of the high-mature light oil of the Tarim Basin, so more hydrogen has historically been available for the cracking of oil to gas. By looking at the accumulation histories and chemical compositions of the crude oils, this study first explains the stable long-term storage of liquid hydrocarbons in the Tarim Basin, providing important guidance for future deep to ultra-deep oil and gas exploration.

Validation of Play Fairway Analysis of the geothermal potential of Camas Prairie, south-central Idaho, by an exploration well

Play Fairway Analysis (PFA) methodology was adapted for geothermal exploration at Camas Prairie, Idaho. Geophysical data, structural and geologic mapping, volcanic rock ages and vent locations, and the distribution of thermal springs and wells all indicated a relatively high geothermal potential along the southern margin of the Prairie. An exploration well (USU Camas-1) was drilled to a depth of 618.3 m to validate the PFA. A permeable zone was encountered at ~ 357.5 m with a maximum measured temperature of ~ 80 °C, which was suppressed following the injection of cold water. A moderate transmissivity of ~ 0.25–1 cm2/s estimated from an injection test as well a seasonal artesian flow at ~ 0.7 L/s corroborate the presence of a permeable zone. The existence of a lacustrine clay seal was confirmed near the bottom of the basin-fill sediment occupying the upper 314 m of the well. Geothermometers suggest the USU Camas-1 well water equilibrated at a reservoir temperature of ~ 120 °C. Based on the locations of both thermal and cold wells, geothermal fluids appear to be flowing upward along one or both of two fault systems. The presence of young basalts and elevated helium isotope ratios suggest that the heat source of Camas Prairie is magmatic. However, the faults may be acting as a conduit for geothermal fluids to rise from great depth without a shallow magmatic source being present. Camas Prairie is a promising area for geothermal development, but the relatively low reservoir temperatures indicate this resource may not be suitable for electric generation. Perhaps the best use would be for heating.

Thermal-gas-chemical method for oil production intensification in low-temperature reservoirs

A method is proposed for developing an oil deposit based on low-temperature oil oxidation as a result of initiating an exothermic reaction and subsequent injection of oxygen-containing gas into the reservoir. In the proposed method, which includes successive injection of aqueous solutions of potassium salt and sulfuric acid into the well, light oil or gas condensate is injected into the deposit before injection of the aqueous acid solution. Further, after injection of an aqueous solution of sulfuric acid into the formation, air is pumped with further pushing with water. In the method, a 16% aqueous solution of potassium dichromate is used as an aqueous solution of potassium salt. The application of the proposed technology led to an increase in the temperature in the reservoir above 200 °C and an increase in the displacement efficiency up to 19.7%. Keywords: thermal chemical treatment; production stimulation; low-temperature reservoir; enhanced oil recovery; low temperature oxidation; oil displacement.

WATER PRODUCTION ISOLATION TECHNIQUES FOR OIL-WELLS WITH HIGH RESERVOIR TEMPERATURE

Advanced drilling technology makes it possible to penetrate oil and gas sites with deep bedding of oil reservoir, a complex multi-layer structure and a high reservoir temperature at the well bottom, reaching 150°C. The difficult geology of oil strata leads to the fact that the productive layers of a well are flooded unevenly. In this work the causes for water cut in reservoirs are given, repair and insulation work and technologies for isolation of water-bearing intervals in the oil-producing wells considered. Grouting composites for water inflow limitation in reservoirs with low temperature (up to 100°C) and high-temperature reservoirs are studied. For water flood control in the oil and gas wells with high temperature viscoelastic composites with extended gel-time and high stable strength and adhesive properties has been proposed. The advantage of polymer-based composites is their kinetic behavior in dynamic mode, when filtering in a porous medium, which makes it possible to isolate effectively intake formations with different channel openings with a small flow rate of the mixture.

Simulation investigation of room-temperature reciprocating packed bed magnetic refrigerator cycle: Comparison of magnetocaloric effect evaluated methods

Built-in method and straightforward adiabatic temperature change method have been widely used in the simulation investigation of Active Magnetic Regeneration Refrigeration (AMRR) cycle. Nevertheless, the difference between the abovementioned two approaches has rarely been discussed. In this regard, a simulation study on the reciprocating packed bed magnetic refrigeration cycle is presented with the special emphasis on the influence of the different magnetocaloric effect evaluated methods, where Gd and water working as magnetic material and heat transfer fluid. With the help of Finite Element Method (FEM), the numerical solutions of the thermodynamic equations of Gd and water can be obtained. Utilizing the FEM, the two methods can lead to same results when the time interval approaches zero. For a comparatively large time interval, the accurate heat expelled to the high-temperature reservoir can be achieved via the straightforward adiabatic temperature change method while the accurate heat absorbing from the low-temperature reservoir can be obtained via the built-in method. Moreover, calculated Coefficient of Performance (COP) via the straightforward adiabatic temperature change method is larger than that via the built-in method.

Investigation of air-cooled condenser’s operating parameters in modern thermal power plant

Air-cooled condensers in thermal power plants have recently become increasingly popular. Besides all the advantages they have, like no demands for water supply on the plant site and no need for taking care of environmental regulations, they also have some serious disadvantages. One of the biggest disadvantages air-cooled condensers do have is precisely the nature of the Earth?s atmosphere being their low temperature reservoir. Low density and low heat capacity of the air as the cooling medium combined with extremely stochastic behavior of the atmosphere itself put some serious challenges in front of the air-cooled condenser?s proper and steady functioning. In this paper, the operating parameters of the air-cooled condenser in the chosen thermal power plant were investigated to gain a clearer insight into the influence of the atmospheric changes on its entropy generation and consequently on its efficiency. Also, the acquired results were further proposed as a starting point for potential optimization of the process inside the device.