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CO2 flooding technology is an effective technical means to enhance the recovery of low permeability reservoirs. After CO2 comes into contact with crude oil， the asphaltene in the system is deposited in a solid form， which causes a certain blockage to the reservoir， but the dissolution improves the flow capacity of the reservoir as a whole at the same time. The damage of CO2 flooding to low permeability reservoirs under different injection methods is different. The organic scale plugging mechanism， reservoir wettability， and CO2-water solution corrosion evaluation experiments were carried out after continuous CO2 injection and CO2-water alternating injection. The variation characteristics of relative permeability curve parameters were evaluated， and the damage of different injection methods of CO2 flooding to low permeability reservoirs was quantitatively characterized. The results show that the organic scale produced by CO2 flooding would block the pore throat of the rock， but on the whole， the dissolution caused by the reaction of CO2 and chlorite is stronger， which makes the recovery of the low permeability reservoirs effectively enhanced. Moreover， the organic scale blockage caused by CO2-water alternating injection is weaker than that caused by continuous CO2 injection， and the dissolution effect is better. The permeability loss rate is lower. It could achieve a better oil displacement effect in pores with a radius of more than 0.2 μm and increase the pore space and flow channel of the rock so that the recovery of low permeability reservoir could be effectively improved.

Alternating carbon dioxide and water flooding can not only seal greenhouse gases, but also combine the advantages of water flooding and carbon dioxide flooding, and can well control mobility and stabilize the displacement front, thereby greatly improving the macro-replacing efficiency. In order to further improve the development effect of water–carbon dioxide alternating flooding, this paper, based on sufficient collection of the literature, research, and analysis, pre-uses modified water instead of water, and deeply explores and studies the impact of modified water–carbon dioxide alternating flooding on the improvement of development effect and the mechanism of enhancing oil recovery in low-permeability reservoirs. The main work completed is as follows: (1) A comparative experiment of multiple groups of sand-filled tubes with different displacement media, modified water concentrations, and injection plug sizes was conducted under the conditions of simulating reservoir formation temperature of 70 °C and formation pressure of 18 MPa, and the optimal scheme and injection parameters of alternating modified water and carbon dioxide flooding were rationally selected. The results show that the alternating flooding of modified water and carbon dioxide in low-permeability reservoirs can significantly improve the development effect. The optimal injection parameters are a formulation concentration of 0.3% and an injection method of alternating a 0.1 PV slug injection of carbon dioxide and modified water. (2) Using Berea cores instead of sand-fill tubes, a comparative experiment of alternating oil displacement using carbon dioxide and modified water was carried out under the same experimental conditions. Nuclear magnetic resonance measurements were performed on five of the cores to analyze the microscopic oil displacement mechanisms of different displacement media. The results show the following: nuclear magnetic resonance testing shows that carbon dioxide displacement can greatly improve the oil recovery efficiency in tiny pores (about 47.43%); alternating injection can further improve the oil recovery efficiency in tiny pores (about 70.6%); and modified water can improve the oil recovery efficiency in larger pores (about 56.47%). [ABSTRACT FROM AUTHOR]

At present, there are relatively few studies on the exploitation of geothermal resources in depleted high-temperature gas reservoirs with carbon dioxide (CO2) as the heat-carrying medium. Taking the high-temperature gas reservoir of the Huangliu Formation in the Yingqiong Basin as the research object, we construct an ideal thermal and storage coupling model of a CO2 plume geothermal system using COMSOL6.2 software to conduct a sensitivity analysis of geological parameters in the operation of a CO2 plume geothermal system. The simulation results show that, compared with medium- and low-temperature reservoirs, a high-temperature reservoir exhibits higher fluid temperature in the production well and a higher heat extraction rate owing to a higher initial reservoir temperature but has a shorter system operational lifetime; the influence of the thermal conductivity of a thermal reservoir on the CO2 plume geothermal system is relatively minor, being basically negligible; and the thinner the thermal reservoir is, the faster the fluid temperature in the production well decreases and the shorter the thermal breakthrough time. These findings form a basis for selecting heat extraction areas for CO2 plume geothermal systems and also provide a theoretical reference for future practical CO2 plume geothermal system projects. [ABSTRACT FROM AUTHOR]

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%. [ABSTRACT FROM AUTHOR]

In view of the high salinity characteristics of reinjection oilfield wastewater in the Gasi Block of Qinghai Oilfield, with the polymer produced by Shandong Baomo as the research target, we systematically investigated the variations in the impact of six ions, Na+, K+, Ca2+, Mg2+, Fe2+, and Fe3+, in the produced water from polymer flooding on the viscosity and stability of the polymer solution. Additionally, we provided the primary research methods for complexation in reinjected wastewater. Experimental results indicate that the main factors leading to a decrease in polymer viscosity are high-valence cations, with the descending order of their influence being Fe2+ > Fe3+ > Mg2+ > Ca2+ > Na+ > K+. High-valent cations also effect the viscosity stability of polymer solutions, and their order from greatest to least impact is: Fe2+ > Ca2+(Mg2+) > Fe3+ > Na+(K+). This article is focused on investigating the influencing factors and extent of the impact of oilfield wastewater on the viscosity of polymer solutions. It illustrates the response mechanism of cations to the viscosity of polymer solutions in reinjection wastewater polymerization. Through this research, the goal is to provide reference control indicators and limits for the water quality of injected polymers at oilfield sites. This ensures the stability and controllability of polymers in field applications and offers theoretical guidance for polymer flooding technology. [ABSTRACT FROM AUTHOR]

During fracturing operations, special situations are often encountered. For example, the insufficient proppant-carrying capacity of fracturing fluid can cause quartz sand or ceramsite to settle near the wellbore and form a sand plug. Alternatively, excessive sand injection intensity can lead to severe accumulation of injected sand near the wellbore and also form a sand plug. These special situations are reflected in the fracturing operation curve as an abnormal increase in oil pressure over a short period of time. If not handled promptly, they can have unimaginable consequences. Sand plugs in fracturing operations, characterized by their speed and unpredictability, often form rapidly, within about 20 s. Conventional methods for on-site sand-plug warnings during fracturing include the oil pressure–time double logarithmic slope method and the net pressure–time double logarithmic slope method. Although these methods respond quickly, their warning results are unstable and vary significantly during actual operations. This is mainly because the fluctuations in the actual fracturing operation curve are often large, and there can be sudden pressure rises and drops even during stable periods, albeit less pronounced. To address the identification of anomalies in conventional fracturing operation monitoring and warning methods, a sand-plug warning index method has been proposed for sand-plug identification. This method combines the oil pressure–time double logarithmic slope with the oil pressure increment within 5 s, the rate of change in the oil pressure–time double logarithmic slope, and the fitted oil pressure intercept as indicators. The method has been validated using Well A in Fuling as an example. The validation results show that the dynamic analysis method can predict sand plugs while reducing warning fluctuations without affecting sensitivity. Compared to conventional methods, the warning time can be advanced by about 10 s. [ABSTRACT FROM AUTHOR]

CO2 flooding technology is an effective technical means for tertiary oil recovery in high water cut reservoirs. Using an existing well pattern to inject CO2 is an economical and feasible development method under low contemporary oil prices. Although the particle migration caused during the displacement process will block the pore throat of the rock, the injection of CO2 can effectively reduce the CO2 injection pressure, and the dissolution that occurs during the injection process improves the seepage capacity of the fluid as a whole. In this study, assessments of particle migration and plugging after CO2 flooding and evaluations of rock dissolution by CO2-aqueous solution were carried out, and the variation characteristics of the relative permeability curve before and after displacement were evaluated, further explaining the influence of CO2 flooding on reservoir seepage capacity. The results show that, in the process of CO2 injection, the injection pressure decreases under different injection rates. After CO2 flooding under oil conditions, the core permeability loss was 43.8%, and after cleaning with toluene and anhydrous ethanol, the core permeability recovery was 24.3%, indicating that the particles were bound by crude oil during the migration process and accumulated into clusters, resulting in blockages. Although there was a certain degree of blockage, the CO2-aqueous solution mainly reacted with chlorite and released Ca2+, Mg2+, and Fe2+ ions. The concentration of Ca2+ increased by 157.43%, the concentration of Mg2+ decreased by 43.33%, and the concentration of Fe2+ decreased by 50.47%, indicating that, although the generated MgCO3 and Fe2O3 blocked the pore throat of the rock, the overall dissolution effect of CO2 on CaCO3 was stronger, and the overall seepage capacity of the fluid was improved. To a certain extent, this technique can improve the water injection capacity and the effect of subsequent water flooding. [ABSTRACT FROM AUTHOR]

Low-permeability reservoirs have become an important field of oil and gas development in China. CO2 flooding technology is an effective technical means for tertiary oil recovery. Although the asphaltene in the system is deposited in the form of a solid after CO2 injection into the reservoir in contact with crude oil, which causes a certain blockage to the reservoir, the dissolution during the injection process improves the seepage capacity of the reservoir as a whole, and the damage degree of CO2 flooding to low-permeability reservoirs under different injection modes is different. In this paper, the damage degree of asphaltene precipitation to low-permeability reservoirs under different injection modes of CO2 flooding is quantitatively characterized. The mechanism experiment of organic scale plugging after continuous CO2 flooding and CO2–water alternate flooding, the wettability experiment of reservoirs, and the evaluation experiment of CO2–water solution on rock dissolution are carried out, and the variation characteristics of relative permeability curve parameters are evaluated. In this paper, the damage degree of asphaltene precipitation to low-permeability reservoirs under different injection modes of CO2 flooding is quantitatively characterized. The mechanism experiment of organic scale plugging after continuous CO2 flooding and CO2–water alternate flooding, the wettability experiment of reservoirs, and the evaluation experiment of CO2–water solution on rock dissolution are carried out. The variation characteristics of relative permeability curve parameters are evaluated. The results show that the organic scale produced by CO2 flooding will block the pore throat of the rock, but, on the whole, the dissolution caused by the reaction of CO2 and chlorite is stronger, which makes the recovery rate of low-permeability reservoirs effectively improved. The organic scale blockage caused by CO2–water alternating flooding is weaker than that caused by continuous CO2 flooding. The dissolution effect is better and the permeability is higher. It can achieve a better oil displacement effect in pores with a pore size greater than 0.2 μm. On the whole, it can increase the core pore space and seepage channel, so that the recovery rate of low-permeability reservoirs can be effectively improved. This study has important theoretical and practical significance for improving oil recovery in low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

The purpose of this study is to investigate the use of SiO2 nanoparticles in assisting with surfactants and polymers for tertiary oil recovery, with the aim of enhancing oil recovery. The article characterizes the performance of SiO2 nanoparticles, including particle size, dispersion stability, and zeta potential, evaluates the synergistic effects of nanoparticles with alpha-olefin sulfonate sodium (AOS) surfactants and hydrolyzed polyacrylamide (HPAM) on reducing interfacial tension and altering wettability, and conducts core flooding experiments in rock cores with varying permeabilities. The findings demonstrate that the particle size decreased from 191 nm to 125 nm upon the addition of SiO2 nanoparticles to AOS surfactant, but increased to 389 nm upon the addition of SiO2 nanoparticles to HPAM. The dispersibility experiment showed that the SiO2 nanoparticle solution did not precipitate over 10 days. After adding 0.05% SiO2 nanoparticles to AOS surfactant, the zeta potential was −40.2 mV, while adding 0.05% SiO2 nanoparticles to 0.1% HPAM resulted in a decrease in the zeta potential to −25.03. The addition of SiO2 nanoparticles to AOS surfactant further reduced the IFT value to 0.19 mN/m, altering the rock wettability from oil-wet to strongly water-wet, with the contact angle decreasing from 110° to 18°. In low-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for enhanced oil recovery increased the recovery rate by 24.5% over water flooding. The recovery rate increased by 21.6% over water flooding in low-permeability rock core experiments after SiO2 nanoparticles were added and surfactants and polymers were utilized for oil displacement. This is because the nanoparticles blocked small pore throats, resulting in increased resistance and hindered free fluid flow. The main causes of this plugging are mutual interference and mechanical entrapment, which cause the pressure differential to rise quickly. In high-permeability rock core oil displacement experiments, the use of AOS surfactants and HPAM for oil recovery increased the recovery rate by 34.6% over water flooding. Additionally, the recovery rate increased by 39.4% over water flooding with the addition of SiO2 nanoparticles and the use of AOS surfactants and HPAM for oil displacement. Because SiO2 nanoparticles create wedge-shaped structures inside highly permeable rock cores, they create structural separation pressure, which drives crude oil forward and aids in diffusion. This results in a comparatively small increase in pressure differential. Simultaneously, the nanoparticles change the rock surfaces' wettability, which lowers the amount of crude oil that adsorbs and improves oil recovery. [ABSTRACT FROM AUTHOR]

Dracaena cambodiana Pierre ex Gagnep is an important plant resource for producing dragon's blood and one of most popular ornamental trees in China. For a better understanding of the physiological function of the stem, the structural characteristics and main substance histological location of the stems of D. cambodiana were studied. The structural characteristics of the different developmental stages of stems of D. cambodiana were observed and described detailly. And then a schematic diagram of the mature stem was created. Histochemical staining showed that two kinds of polysaccharides distributed in parenchymal cells. Saponins distributed mainly in ground tissue and phenolic compounds distributed mainly in the thick cell walls. An abundant of calcium oxalate raphide bundles were identified in cortex and primary tissue. Finally, the role of the above results in the taxonomy of Dracaena species and in their strong adaptability was discussed. [ABSTRACT FROM AUTHOR]

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO2 nanofluid alternating with the CO2 injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO2 nanofluid as a substitute medium and proposes a SiO2 nanofluid alternate CO2 flooding method to enhance oil recovery. Through the microcharacterization of SiO2 nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO2-I and SiO2-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO2 nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO2 flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO2, thereby enhancing the effectiveness of nanofluid alternate CO2 flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates. [ABSTRACT FROM AUTHOR]

This study focuses on the characteristics of fractured and vuggy high-temperature and high-salt reservoirs in the Tahe Oilfield. The Acrylamide/2-acrylamide-2-methylpropanesulfonic copolymer salt was selected as a polymer; the hydroquinone and hexamethylene tetramine was selected as the crosslinking agent with a ratio of 1:1; the nanoparticle SiO2 was selected, and its dosage was optimized to 0.3%; Additionally, a novel nanoparticle coupling polymer gel was independently synthesized. The surface of the gel was a three-dimensional network structure, with grids arranged in pieces and interlaced with each other, and the structure was very stable. The SiO2 nanoparticles were attached to the gel skeleton, forming effective coupling and enhancing the strength of the gel skeleton. To solve the problem of complex gel preparation and transportation, the novel gel is compressed, pelletized, and dried into expanded particles through industrial granulation, and the disadvantage of the rapid expansion of expanded particles is optimized through physical film coating treatment. Finally, a novel nanoparticle coupling expanded granule plugging agent was developed. Evaluation of the performance of the novel nanoparticle coupling expanded granule plugging agent. With an increase in temperature and mineralization, the expansion multiplier of granules decreases; aged under high-temperature and high-salt conditions for 30 days, the expansion multiplier of granules can still reach 3.5 times, the toughness index is 1.61, and the long-term stability of the granules can be good; the water plugging rate of granules is 97.84%, which is superior to other widely used particle-based plugging agents. [ABSTRACT FROM AUTHOR]

Quasi-dry CO2 fracturing technology is a new CO2 fracturing technology that combines liquid CO2 fracturing (dry CO2 fracturing) and water-based fracturing. It uses a liquid CO2 system containing a small amount of water-based fracturing fluid to carry sand, and it is characterized by sand blending at normal pressure, convenient preparation, the integrated application of resistance reduction and sand carrying, and no dedicated closed sand blender requirement. We developed a self-crosslinking emulsion-type water-based fracturing fluid (ZJL-1), which contained ionic bonds, hydrogen bonds, van der Waals forces, and hydrophobic associations, for quasi-dry CO2 fracturing, and the comprehensive properties of the ZJL-1 fracturing fluid were evaluated. The results showed that the ZJL-1 fracturing fluid had obvious viscoelastic characteristics, a heat loss rate of less than 10% at 200 °C, a good thermal stability, sufficient rheology under high temperature and high shear conditions, and a good thermal stability. The resistance reduction rate reached 70%, which demonstrates a good resistance reduction performance. Compared with conventional guar fracturing fluid, ZJL-1 can carry more sand and has a lower core damage rate. The on-site use of quasi-dry fracturing showed that optimizing the mixing ratio of liquid CO2 fracturing fluid and ZJL-1 fracturing fluid effectively enhanced oil and gas recovery. This can be used to optimize quasi-dry fracturing and can be used as a reference. [ABSTRACT FROM AUTHOR]

Tahe oil field is a typical fissure cave carbonate reservoir with a temperature of up to 120~140 °C and a total salinity of formation water of (20~25) × 104 mg/L. In this paper, AM/AMPS was selected as the polymer, 1, 5-dihydroxy naphthol as the cross-linking agent, and polypropylene fiber as the system stabilizer to synthesize a novel gel plugging agent independently; the gel has good thermal stability at a high temperature of 130 °C and increased salinity of 20 × 104 mg/L, and has a dense and relatively stable three-dimensional network structure under a scanning electron microscope. The performance evaluation of the gel plugging agent indicated that: the gel dehydration rate increased gradually with the increase in temperature and salinity, making it suitable for reservoirs with temperatures below 140 °C and formation water salinity below 250,000 mg/L; the viscosity of the gel bulk was 125.3 mPa∙s, the post-gelatinizing viscosity was 42,800 mPa∙s, and the gelatinizing time at 120 °C, 130 °C and 140 °C was 10–20 h, 8–18 h, and 7–16 h, respectively. [ABSTRACT FROM AUTHOR]

Based on the characteristics of low-permeability oil and gas reservoirs and the requirements for profile control and water plugging and for water cut decrease and production increase in the high water cut stage of the middle and late exploitation periods, ultrafine temperature-resistant and salt-tolerant swellable particles DS-1 suitable for low permeability oilfields were prepared by introducing N,N-dimethylacrylamide(DMAA) monomers into the 2-acrylamido-2-methylpropanesulfonic acid (AMPS)/acrylamide(AM)/N,N-dimethylbisacrylamide ternary crosslinking system. The median of initial particle size was 22.00 μm, and is compatible with formation pore throats. A static water absorption experiment showed that the particles can still maintain a high swelling ratio after 15 days at a high temperature and high mineralization degree, so they have long-term stability. The physical and chemical properties of the particles were analyzed microscopically using the infrared spectrum method and the scanning electron microscope (SEM) method. A dynamic displacement experiment confirmed that the particles can effectively plug dominant channels of waterflooding, increase the injection pressure, and improve the interlayer and intralayer heterogeneity. In the field experiment, the swellable particles DS-1 were used as a main slug for water plugging operations, and a good water cut decrease and oil production increase effect was obtained. [ABSTRACT FROM AUTHOR]

Establishing reservoir numerical simulation and profile control optimization methods considering the mechanism of profile control has always been a difficult research problem at home and abroad. In this paper, firstly, a physics-based data-driven model was established on daily production data of injection and production wells following the principle of material balance. Key parameters including transmissibility, control pore volume, water injection allocation factors, and injection efficiency are derived directly from history matched model, and the dominated flow channels could be quantitatively identified. Then, combined with the evaluation results of the plugging ability of the plugging agent, imaginary well nodes are added to the existing interwell relationship to characterize the heterogeneity of interwell-specific parameters. This process performs flow processing along the interwell control units, forming a new and rapid method for simulation and prediction. Lastly, based on the calculated interwell transmissibility, water injection efficiency, and allocation factors, injection wells with low water injection efficiency can be preferentially selected as profile control wells. In addition, taking the production rates, injection rates, and the amount of plugging agent as optimization variables, we established an optimal control mathematical model and realized the parameter optimization method of the profile control. We demonstrated the results of one conceptual model and two indoor experiments to verify the feasibility of the proposed method and completed two actual field applications. Model validation and actual field application show that the proposed method successfully eliminates the complicated geological modeling procedure and the tedious calculation process associated with the profile control treatment in traditional numerical simulation methods. The calculation speed improves tens or hundreds of times, and water channeling paths are accurately identified. Most importantly, this method realizes the overall decision-making of profile control well selection, dynamic production prediction, and parameter optimization of profile control measures quickly and accurately by mainly using the daily production data of wells. The findings of this study can help for better understanding of the optimization design and application of on-site profile control schemes in large-scale oilfields. [ABSTRACT FROM AUTHOR]

Nowadays, there are a wide variety of thickeners developed for dry CO2 fracturing worldwide, but numerous problems remain during in situ testing. To address problems in CO2 fracturing fluid operation (high frictional drag, low viscosity, low proppant-carrying capacity, narrow reservoir fractures, etc.), the authors have synthesized the novel hydrophobic long-chain ester thickener, studied viscosity, frictional drag, and proppant-carrying capacity of CO2 fracturing fluid and core damage by CO2 fracturing fluid by varying the temperature, pressure, and level of injection of the novel thickener and explored the thickening mechanism for this thickener in CO2. Based on the study results, as the temperature, pressure, and amount of injected thickener increased, fracturing fluid viscosity increased steadily. In the case of shearing for 125 min under conditions of 170 S−1, 40°C, and 20 MPa, when the thickener level increased from 1% to 2%, fracturing fluid viscosity increased and then decreased, varying within 50–150 mPa·s, and the viscosity-enhancing effect was evident; under conditions of 20°C and 12 MPa, as the flow rate increased, drag reduction efficiency reached 78.3% and the minimal proppant settling speed was 0.09 m/s; under conditions of 40°C and 20 MPa, drag reduction efficiency reached 77.4% and the proppant settling speed was 0.08 m/s; with the increases in temperature, pressure, and injection amount, core damage rates of the thickener varied within 1.77%–2.88%, indicating that basically no damage occurred. This study is of significant importance to the development of CO2 viscosity enhancers and CO2 fracturing operation. [ABSTRACT FROM AUTHOR]

In order to address the serious problem of steam channeling in the reservoir development bv steam flooding, a high-temperature channeling blocking system based on multi-group cross linked gel was developed. An evaluation was made on its temperature resistance, steam plugging capability, and erosion resistance. It was found in the study that the high-temperature channeling blocking system based on multi-group cross linked gel could stably generate gel under high temperature of 130°C, and the gel had a good stability after 120 d at 250°C, and excellent plugging performance; the plugging rate of the gel-based channeling blocking system was as high as 99. 63% at high temperature when the injection speed was 1 mL/min and the plugging agent volume injected was 0. 8 time the pore volume, and the breakthrough pressure gradient was 7. 35 MPa/m; at 250 °C, the channeling blocking system was completely gelling in the sand-filled pipe, and the plugging rate was maintained above 98% after high-temperature steam flushing (30 times the pore volume), with good flushing resistance. The channeling blocking system has proven to be highly effective in plugging with steam by on-site application, effectively solving the problem of steam channeling in the development with steam flooding of heavy oil reservoir, and it can provide a technical support for the efficient development of heavy oil reservoir. [ABSTRACT FROM AUTHOR]

To address the issues of reservoir blockage and sharp decline in fluid output of production wells in the polymer injection zone of the Henan oilfield, physical modeling has been used to study the blockage mechanism and blockage locations of the polymer-flooded reservoir based on oil reservoir characteristics and blockage knowledge. The results show that all the constant pressures in the low, moderate, and high permeability cores subjected to polymer injection and subsequent waterflooding were higher than the constant pressure during primary waterflooding; hence, polymer retention and blockage phenomena were obvious in the cores; in the high permeability core, the pore surface adsorbed more polymer molecules though pore throat radii were still much greater than the size of the polymer molecule, suggesting that polymer blockage is mainly caused by adsorption and retention. For the low permeability core, the specific surface area of the inlet end was much larger than that in the high permeability core, leading to more serious capture of polymer molecules at the small pores, indicating that blockage under polymer injection is mainly caused by capture and retention; for the lower permeability (91.81 mD) core, as compared with the case prior to polymer injection, the polymer-injected core had fewer large pores and throats, the mean pore throat radius decreased from 42.2 μm to 39.9 μm, and the mean throat-to-pore coordination number decreased from 3.36 to 3.19; thus, polymer capture and retention led to core blockage; the leftward shift of the curve corresponding to the porosity component, high porosity peak weakening after polymer injection, moderate and low porosity peaks appearing after polymer injection, and enhancement of lower porosity peaks indicate that, after polymer injection and subsequent waterflooding, polymer adsorption and capture led to blockage of some large pores; the highest pressure gradient, i.e., 6.3 MPa/m, was achieved at the P2-P3 segment; thus, the worst blockage occurred at the P2-P3 stage, or 1/8-1/4 of the sandpack length. In this paper, Nanbaxian oil and gas field, China, was taken as an example to investigate the interpretation method of gas saturation in a complex pore structure. The "four properties" relationship of the formation reservoir in the Nanbaxian oil and gas field was studied in depth according to the conventional logging data and core analysis data. The neural network algorithm was used to reconstruct the resistivity curve of the water layer to eliminate the influence of lithology, shale content, and pore structure on the resistivity. The difference between the reconstructed curve and the measured resistivity curve was used to identify the gas and water, and the ratio of the two was used to calculate the gas saturation, and good results were achieved. It was found that the sedimentary types of the Nanbaxian oil and gas field cause the reservoir to be thin, numerous, and dispersed; the lateral correlation is difficult. In addition, the structural features lead to the reservoir types being various in the vertical direction, which makes the identification of reservoir fluid more difficult. The results revealed that the rock compaction, poor physical properties, complex pore structure, high resistivity of surrounding rocks, and low formation water salinity make the water layer with high resistivity and difficult to identify gas and water. [ABSTRACT FROM AUTHOR]

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 104 mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, we selected XN-T from 27 kinds of swelling retarding particles by testing their swelling capacity, and coated a thin film to improve its retarding swelling capacity. The mechanisms of strong water absorption and water-holding abilities of particles were analyzed by infrared spectrometry and SEM. In the core flow experiment, the plugging rate was found to be 98.42%. Finally, the injection parameters of the coated particles were optimized to maximize the water plugging and profile control ability, resulting in an optimal particle size of 0.4–0.6 mm and a mass fraction of 10%. [ABSTRACT FROM AUTHOR]

The synthesis and performance of a novel temperature‐tolerant foamed resin for enhanced oil recovery were investigated using various methods, including infrared, NMR, scanning electron microscopy (SEM), and displacement experiments. Polycondensation of furfuryl alcohol prepolymers was confirmed by the infrared and NMR results. The poor temperature tolerance of furfuryl alcohol prepolymers after gelation at high temperatures is mainly due to the fracture of furan rings. The addition of ester additives is an effective method of increasing the temperature tolerance of the prepared foamed resins and can effectively reduce the weight‐loss rate of the polycondensation products. The SEM results show that the skeleton structure of the foamed resin remains intact after high‐temperature treatment. Thus, the novel plugging agent system has excellent thermal stability and still has a high strength (>0.8 MPa) after high‐temperature aging treatment for 40 days, giving the prepared foamed resin a good plugging performance (plugging rate > 91%) at 250 °C. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019, 136, 47161. [ABSTRACT FROM AUTHOR]