Enhanced Oil Recovery Technologies, 2nd Volume

Fractured-vuggy reservoirs are known for containing substantial amounts of oil in high positions of reservoir, even after natural energy development and water injection development. However, due to their poor physical properties and fracture distribution, gas channeling becomes a common occurrence when injecting large amounts of gas, which hinders the formation of an effective gas cap, resulting in reduced oil displacement efficiency. This phenomenon results in a lengthy period of effective gas cap formation and reduces the oil displacement efficiency of an artificial gas cap. In this paper, according to the actual geological characteristics, logging data, and production data, the mechanism model and the numerical model of Oilfield A are established. The variation law of flow potential difference before and after gas injection channeling is studied by simulation, and the control method of artificial gas cap gas channeling in fractured-vuggy reservoir is put forward. The results show that the production gas–oil ratio method is the most convenient and practical in the oil field, and the flow potential difference can effectively predict the occurrence of gas channeling. It likely occurs when the ratio of flow potential difference between injection and production wells is less than 0.972. Gas channeling can be controlled effectively by altering the energy of position and pressure, as well as body measures including injection–production well pattern adjustment, injection–production parameter optimization. This technology provides a new approach for controlling gas channeling through gas cap drive in fractured-vuggy reservoirs. After the implementation of this technology, the effect is obvious, and can effectively improve the efficiency of gas top oil displacement and save costs. This gas channeling control technology is of great significance for the development of fractured-vuggy reservoirs. Full article

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. Full article

Currently, microbial enhanced oil recovery (MEOR) is of great interest because of its potential high efficiency and low environmental impact. Biosurfactants, in the purified form or contained in the bacterial cultural media, are one of the promising directions in MEOR because they are more stable in response to different environmental factors than life microorganisms are. However, the extraction and purification of biosurfactants, as well as their working concentrations and efficacy in real oilfield conditions remain a challenge. In the present work, cultural media of two novel bacterial isolates (Bacillus pumilus and Peribacillus simplex) were used in a model experiment with sand pack columns to enhance the recovery of heavy oil from Romashkino oilfield (Russia). Using FTIR and TLC methods, it was demonstrated that both cultural media contained lipopeptides. In the genome of both bacterial isolates, genes srfAA, fenD and bamC encoding synthesis of surfactin, fengycin, and bacillomycin, respectively, were revealed. The oil recovery efficacy of cell-free cultural media after 24 h of cultivation was 34% higher and 16% lower as compared with synthetic surfactant for B. pumilus and P. simplex, respectively. It can be concluded that the high-cost step of biosurfactants separation and purification may be excluded, and cell free cultural media of the isolates may be directly used in field conditions to enhance the recovery of heavy oils. Full article

Due to the high water saturation in high-water-cut tight sandstone gas reservoirs, factors such as threshold pressure gradient (TPG) and stress sensitivity (SS) cannot be overlooked in terms of their impact on seepage parameters. Therefore, this paper primarily investigates the seepage mechanisms in tight, high-water-cut sandstone gas reservoirs. While considering the influence of water saturation on various seepage mechanisms, it establishes a gas well productivity equation under stable seepage conditions and presents an analysis of the influencing factors. In a comparison of the unobstructed flow rates calculated using the productivity equation developed in this paper with those obtained from conventional gas well productivity equations and actual gas well productivity tests, the new equation demonstrates smaller errors. This provides a theoretical basis for evaluating productivity and making rational production allocation decisions in high-water-cut tight sandstone gas reservoirs. Full article

Steam-assisted gravity oil drainage (SAGD flooding) is a cutting-edge technology for the development of oils which is gradually replacing steam huff and puff and is being used more and more widely. Low-permeability interlayers are generally developed in oil reservoirs in China, which may shield the migration of steam, oil and gas. Targeted acidizing fracturing was proposed to break through the low-permeability interlayers, and hence, the problem that the hindrance to the expansion of the steam chamber led to heat loss and seriously affected the development effect could be solved. A typical kind of well with SAGD flooding actually applied in China, Shuyi District of Liaohe Oilfield, was taken as the example for studying the optimization of crack parameters. Based on the study of reservoir sensitivity characteristics in this well, the formulations of working fluids for targeted acidizing fracturing were developed by optimizing the weight percentages of main acid solution and additives. The formula of ‘4% hydrochloric acid + 2% polyphosphoric acid + 5% fluoroboric acid + 4% acetic acid’ could be used as the acidizing fracturing working fluid for typical blocks of the Shuyi District of Liaohe Oilfield, which can increase the permeability of the natural core by 40.19–57.06%. Studies on targeted acidizing fracturing are beneficial for enhancing the oil recovery of oil reservoirs. Full article

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m³ of the sands and 700 m³ of the fluids. This research provides a new model for offshore low-permeability oilfield development. Full article

In order to improve the recovery efficiency of the Jimusaer tight reservoir in Xinjiang, the nanometer oil displacement agent system suitable for the Jimusaer reservoir was used. In view of the low permeability, high formation temperature, and high salinity characteristics of the prepared water in the Jimusaer tight conglomerate reservoir in Xinjiang, the performance of the nanometer oil displacement agent affecting oil recovery was studied; the study considered interfacial tension, temperature resistance, wetting performance, static oil washing efficiency, and long-term stability. Nanometer oil displacement agent No. 4 had the lowest interfacial tension and could reach the order of 10⁻¹ mN∙m⁻¹; it had excellent temperature resistance and the best static oil washing efficiency and stability. Nano-oil displacement agent No. 2 had the best emulsification performance and wettability and also had good stability. By studying the performance and final oil displacement effect of the nano-oil displacement agent, it was found that the key factor affecting the oil displacement effect of this reservoir was the interfacial activity of the nano-oil displacement agent. When the interfacial tension was lower, it produced strong dialysis for oil displacement. The emulsification effect has a negative effect on low-permeability reservoirs, mainly because the fluid produces strong emulsification in low-permeability reservoirs; thus, it can easily block the formation and cause high pressure. An excessive or small contact angle is not conducive to oil displacement. An excessive contact angle means strong hydrophilicity, which can cause a strong Jamin effect in oil-friendly formations. If the contact angle is too small, it has strong lipophilicity and can lead to poor solubility in water. Nano-oil displacement agent No. 4 had the best oil displacement effect, with an oil recovery increase of 7.35%, followed by nanometer oil displacement agent No. 1, with an oil recovery increase of 5.70%. Based on all the performance results, nanometer oil displacement agent No. 4 was more suitable as the oil displacement agent and can be used to enhance oil recovery in the Jimusaer reservoir. This study has laid a foundation for the chemical flooding development of shale oil in the Xinjiang oilfield. Full article

Foam is a medium-stable system composed of gas and liquid phases, which has the advantages of low density at the gas phase and high viscosity at the liquid phase, and has a wide application in oil and gas field development and mineral flotation, but its special medium-stable system also brings many problems in industry applications. Scientists have carried out extensive analyses and research on the foam stability and bubble-bursting mechanism, which initially clarified the rules of bubble breakage caused by environmental factors such as temperature and pressure, but the mechanism of bubble bursting under the action of internal factors such as liquid mineralization and oil concentration of the films is still not clearly defined. In this paper, we propose a compound salt-resistant foaming agent, investigated the influence of the aggregation and adsorption behavior of oil droplets on the liquid films and boundaries, and established a relevant aggregation and adsorption model with the population balance equation. We put forward a liquid film drainage mechanism based on the distribution, aggregation, and transport of oil droplets in the liquid films, so as to explain the changes in foam stability under the action of oil droplets. On the other hand, the viscoelastic analysis of foam fluid is performed with a rheometer, and the results show that in comparison with conventional power-law fluid, foam fluid has a complex rheological behavior for low shear thickening, but high shear thinning. Full article

Chelating agents’ application for well stimulation is gaining more and more interest, as they can perform under harsh conditions. However, the mutual influence of surfactants and chelating agents on the wettability alteration of hydrophobic carbonate rock under conditions of high-temperature well stimulation is relatively unexplored. This paper aims to study interfacial processes on the surface of hydrophobic rock in the presence of the EDTA-based chelating agent and surfactants of different classes. Cationic (cetyltrimethylammonium bromide, CTAB, and cetylpyridinium bromide, CPB), anionic (sodium dodecyl sulfate, SDS), and amhoteric (alkyldimethyl aminooxide, AO) surfactants were studied. Wettability alteration of model hydrophobic rock was studied under conditions specific to well stimulation. It was shown that chelating agent (CA) alone and its mixture with SDS could not lead to sufficient wettability alteration. CTAB, CPB, and AO were able to change the wettability effectively. A synergistic effect between CA and these surfactants was observed and a possible mechanism was proposed. AO was selected as the most promising surfactant. The influence of surfactant on the CA’s dissolution capacity towards carbonate rock was investigated; dissolution capacity strongly depends on wettability alteration. Finally, the effect of CA, AO, and their mixture on the wettability of aged reservoir rock was studied and the absence of negative effects was proven. Full article

In the waterflooding development of fractured ultra-low permeability reservoirs, the heterogeneity is becoming increasingly serious. The development of large fracture channels leads to serious water channelling and low recovery, and the effect of conventional profile control is not ideal. This paper proposed gel foam composite profile control and flooding technology to solve the above problems. Herein, the new intelligent gel and foaming agent systems were optimized through laboratory experiments, and their performance was evaluated. The new intelligent gel system has the characteristics of low viscosity, easy preparation, good injection, slow cross-linking, high strength, and long-term effectiveness. The injection parameters were optimized, and the indoor injection scheme was formulated, that is, the optimal injection volumes of gel and foam slugs were 0.3 and 0.6 PV, respectively. The injection sequence of composite slugs was to inject gel slugs first, then foam slugs. The injection mode of air foam slugs was multiple rounds of small slug injection. The final recovery rate in the indoor dual tube oil displacement experiment reached 35.01%, increasing by 23.69%. Furthermore, an oil output increase of 899 t and an average water cut decrease of 5% were acquired in the oil field test. It shows that the injection scheme can effectively improve oil recovery. The gel foam compound profile control and flooding technology herein has good adaptability in similar reservoirs and has good promotion prospects. Full article

Oil-in-water emulsions provide an essential contribution to enhanced oil recovery by acting as oil displacement and conformance control systems. However, the dominant factors affecting their emulsification and kinetics are unclear. The emulsification rate is usually defined in terms of changes in the torque, conductivity, or particle size over time, which results in inaccurately calculated emulsified oil amounts. Therefore, the effects of temperature, pH, and NaCl concentration on the emulsified mass and droplet sizes of aqueous emulsions of Jin8-7 and Chen373 oil with octadecyl amine ethoxylate ether as an emulsifier were investigated. The results showed that the formation of oil-in-water emulsions of Jin8-7 and Chen373 under different conditions occurred via a two-stage mechanism: rapid emulsification and emulsion maturation. The emulsified oil mass rapidly increased during the rapid emulsification period and plateaued during the emulsion maturation period. This indicates that the emulsified oil mass largely depended on the short rapid emulsification period. It was also found that increasing the temperature and pH were more conducive to the emulsification of Chen373 oil with a high viscosity and high asphaltene content. The optimal NaCl concentration was determined to be 2% and 4% for Chen373 and Jin8-7 oil, respectively, based on the emulsification mass during the rapid emulsification period. The droplet size decreased first and then increased during the emulsification process under most experimental conditions. A second-order kinetics model for emulsification was proposed, in which the evolution of emulsified oil mass calculated with time agreed with the experimentally measured values. This study can provide theoretical guidance for the implementation of chemical cold production of heavy oil in oilfields. Full article

With the increase in drilling fluid density requirements in low-pressure coefficient formations, traditional hollow bead drilling fluids and foam drilling fluids each have different degrees of deficiencies. Through extensive indoor experiments, an amphoteric surfactant (cocoamidopropyl betaine) with better foaming performance was selected to formulate an ultra-low-density drilling fluid that combines a foaming agent and hollow glass microbeads to reduce the density of the fluid, with the following specific formulation: 3% bentonite slurry + 0.3% xanthan gum + 0.5% carboxymethyl cellulose + 0.5% starch + 2% lignite resin + 2% blocking agent + 4% hollow glass microspheres + 0.5% foaming agent + 2% nano blocking agent. The performance of the system was evaluated, and the results showed that: the density of the ultra-low-density drilling fluid did not change much before and after aging at 80 °C and was relatively stable; the filter loss amount of the drilling fluid (tested by API) reached 4.6 mL, which meets the requirements for filter loss of drilling fluid; it can bear the pressure of 12 MPa under a 60–90-mesh sand bed and has better pressure sealing capability than hollow glass microbead drilling fluid. Full article

Radial drilling-fracturing is an innovative fracturing technology that achieves superior stimulation effects. In order to study the permeability-increasing effect and main influencing factors of radial water jet drilling in the low physical section, this paper uses a fracking electrical simulation experiment, based on the principle of hydropower similarity, to simulate the reservoir conditions and well pattern in the low physical section and, at the same time, establishes the radial fracturing model of the low physical section reservoir, simulates the saturation field, pressure field, and production-change law under different drilling parameters, and studies different influencing factors. The experimental results show that when the number of drilling holes exceeds two, the effect of increasing production gradually becomes less significant as the number of drilling holes increases; Within the range of the angle between the two boreholes, the forward distance of the oil–water displacement front is the farthest and the sweep is relatively uniform. On both sides of the included angle, the forward distance of the oil–water displacement front edge is smaller than the forward distance of the displacement within the included angle range and it is clearly inclined towards the radial drilling with uneven spread. Radial drilling has an impact on the seepage field, causing changes in its streamline. The pressure inside the borehole is lower than the surrounding formation pressure and most of the flow lines change direction near the borehole location, causing deflection. As the borehole length increases, the oil-well production also increases. The optimal effect is for the borehole length to be 100 m. This study provides a reference for the on-site application of radial fracturing in low physical properties sections. Full article

Fluid wave code communication is used in layered water injection intelligent monitoring systems, but a model of fluid transient flow wave signal transmission is still unknown. Impedance and transfer coefficient in power transmission theory were used to describe transient flow waves in the transmission process of a tubular string in a water injection well and a transient flow wave model was built based on the transfer matrix method. The relationship between pressure and discharge was analyzed when the transient flow waves moved along the tubular string, and the influence of terminal impedance and dip angle of the tubular string on the wave transmission was studied. Simulations showed that the transient flow waves were with standing wave distribution when the transient flow wave signals transmitted in the tubular string. Moreover, the transmission volatility under different terminal impedances was analyzed. The communication frequency was selected according to the wave amplitude ratio between the two ends of the water injection tubular string. The relationship between the influence of tubular string parameters and fluid characteristics on the wave velocity and wave amplitude in the signal transmission process was obtained by simulation analysis. The wave velocity tended to decrease as the gas content increased. As the tube diameter–thickness ratio increased, the wave velocity decreased. Taking data from a water injection well in Daqing Oilfield as an example, a two-layer water injection test platform was built to study the fluctuation of discharge and pressure at monitoring points in the tubular string. The experiment condition was that the depth of the injection well was 1400 m. It was verified by the experiments that the pressure and flow changes in the downhole and wellhead had good consistency during the transmission of transient flow waves. Comparing the experimental results with the numerical results, the errors of the wave velocity and wave amplitude were 0.69% and 3.85%, respectively, indicating the verification of the simulation model. This study provides a theoretical support for the transmission of transient flow wave signals in a water injection tubular string. Full article

Recent research has highlighted wettability alteration as the main consequence of the different mechanisms involved in technologies such as adjusted brine composition water flooding (ABCW) and low-salinity water flooding (LSW). However, studies are still needed to give a phenomenological explanation, and the most influential components of the system (rock–oil–brine) must be clarified. This work focuses on determining the most relevant variables for the smart water effects to occur. Static (contact angles) and dynamic tests (coreflooding) were conducted. For the static tests, aged Berea slices, a specific crude oil (27° API, 10.5 cp at 60 °C), and mono and divalent inorganic salts (Na⁺, K⁺, Ca²⁺, and Mg²⁺/Cl⁻) were used in 3 different concentrations of 1000, 3000, and 5000 ppm (ionic strength variation between 0.015 and 0.06) to establish the wettability state by measuring the contact angles of the system. When salts containing chloride were evaluated, a decrease in oil wettability was observed at 5000 ppm. At 3000 and 1000 ppm, tendencies depended on the particular cation. Three brines were selected from the contact angle experiments to be used in coreflooding assays, considering a particular design to identify ion exchange from the rock–oil–brine system. The first assay was carried out in the absence of crude oil as a baseline to determine the ion exchange between the brine and the rock, and a second test considered crude oil to provide insight into ion exchange and its effect on displacement efficiency. Capillary electrophoresis was used in this research as a novel contribution to the systematic study of oil displacement tests, and it has proven to be a powerful tool for understanding the mechanisms involved. The results show that the variations in the concentrations detected in the displacement effluents were the product of the interactions between rock, oil, and brine since the concentrations measured in the absence of oil phase were comparable to those in the injection brine. Significant variations in the effluent ion concentrations were determined for the different brines used, and increases in the pressure differentials were observed for the KCl and CaCl₂ brines. These results suggest that the oil–brine ion exchange (salting in/out) represents a relevant mechanism to explain the observed displacement efficiencies and differential pressures. The ionic enrichment of the water phase due to the salting in/out effect needs to be better understood. Full article

Very high viscosity significantly impacts the mobility of heavy crude oil representing difficulties in production and a decrease in the well’s efficiency. Downhole electric heating delivers a uniform injection of heat to the fluid and reservoir, resulting in a substantial decrease in dynamic viscosity due to its exponential relationship with temperature and a drop in frictional losses between the production zone and the pump intake. Therefore, this study predicts temperature and viscosity profiles in heavy oil-production wells implementing a downhole induction heater employing a simplified CFD model. For the development of the research, the geometry model was generated in CAD software based on the geometry provided by the BCPGroup and simulated in specialized CFD software. The model confirmed a 46.1% effective decrease of mean 12° API heavy-oil dynamic viscosity compared with simulation results without heating. The developed model was validated with experimental data provided by the BCPGroup, obtaining an excellent agreement with 0.8% and 15.69% mean error percentages for temperature and viscosity, respectively. Furthermore, CFD results confirmed that downhole electrical induction heating is an effective method for reducing heavy-oil dynamic viscosity; however, thermal effects in the reservoir due to heat penetration were insignificant. For this study, the well will remain stimulated. Full article

The reserves of heavy oil are enormous. However, its high viscosity and other characteristics make heavy oil extraction and transportation extremely difficult. Power ultrasonic (US) reforming technology on heavy oil has the advantages of environmental protection and fast results, so it is important to understand the mechanism of ultrasonic reforming. We examine the influence law of the electric power input of the US transducer on the viscosity of heavy oil. Fourier Transform Infrared Spectrometer (FTIR) and Gas Chromatography (GC) are applied to explain the changes in different functional groups, heavy components, and carbon chains before and after US irradiation. The cavitation noise method is also used to study the influences of variance in the intensity of cavitation on the viscosity of heavy oil. The results indicate that the viscosity of heavy oil first decreases, and next increases with an increase in electric power. The functional groups and chromatographic distillation also change in different forms, and with an increase in electric power, the cavitation effect is gradually enhanced. These findings suggest that it is not that the stronger the cavitation, the greater the influence on the viscosity of heavy oil. Full article

Most of the onshore water-flooding oilfield reservoirs have dominant seepage channels dominated by large pores and fractures, resulting in the oilfield being in a period of high water cut. The treatment of this problem needs to be solved by plugging. In the research process, the particle size and suspension of the water-swellable rubber particles were measured, and the effective time of the particles was evaluated; matching relationship. The results show that adding 2000 mg/L polymer to the water-swellable rubber particles can better improve the suspension performance; the performance of the polymer solution will not be affected during mixing and injection. In addition to strong swelling performance, it also has a certain strength and deformability, up to 10 MPa high via pressure and good thermal stability. Compared with the water and oil environment, the chemical degradation phenomenon is significant after soaking in alkaline conditions. Compared with the alkaline environment and the formation water environment, the final expansion ratio of the water-swellable rubber particles in the formation oil environment is as low as 2.5 times, which has the ability to block water. There was no oil blocking feature. When the crack width is too small, particles with excessively large particle sizes may accumulate at the injection end of the core, resulting in failure to inject into the core and fail to achieve the plugging effect. For the treatment of large, fractured pores, it is possible to first inject particles with a particle size of 0.250–0.420 mm to block areas with high permeability, and then inject particles with a particle size of 0.150–0.250 mm to block areas with low permeability. Full article

In the process of oilfield development, the use of CO₂ can improve the degree of reservoir production. Usually, CO₂ is injected alternately with water to expand the spread range of CO₂, and CO₂ presents a supercritical state in the formation conditions. In the process of alternating CO₂ and water injection, wellbore freezing and plugging frequently occur. In order to determine the cause of freezing and plugging of injection wells, the supercritical CO₂ flooding test area of YSL Oilfield in China is taken as an example to analyze the situation of freezing and plugging wells in the test area. The reasons for hydrate freezing and plugging are obtained, the distribution characteristics and sources of hydrate near the well are clarified, and a coupling model is established to calculate the limit injection velocity and limit shut-in time of CO₂ and water alternate injection wells. The results show that the main reasons for freezing and plugging of supercritical CO₂ water alternate injection wells are long time shut down after alternate injection, improper operation when stopping injection and starting and stopping pumps, and slow injection speed during alternate injection. In the process of supercritical CO₂ water alternative injection, in the case of post-injection, the CO₂ in the formation will reverse diffuse to the injection well end. With the continuous increase of daily water injection, the initial diffusion position and the time of CO₂ diffusion to the perforated hole after well shut-in gradually increase. The time of CO₂ reverse diffusion to the bottom of the well is 1.6–32.3 d, and the diffusion time in the perforated hole is 1.0–4.5 d. Therefore, the limit shut-in time following injection is 2.6–36.8 d. Following gas injection, the limit shut-in time of a waterproof compound can be divided into three stages according to the change of wellbore pressure: the pressure stabilization stage, pressure-drop stage and formation fluid-return stage. The limit shut-in time of a waterproof compound following gas injection is mainly affected by permeability, cumulative gas injection rate and formation depth. The limit shut-in time of a waterproof compound is 20.0~30.0 days. The research results provide technical support for the wide application of CO₂ flooding. Full article

Accurate evaluation of shale oil reservoir fracability helps avoid blind fracturing and ensures efficient fracturing. However, the current evaluation of the fracability index rarely considers the impact of hydration caused by drilling fluid invasion during drilling. The results of a rock triaxial mechanical test conducted to evaluate the mechanical properties of shale oil reservoirs are reported in this paper. Based on the results, we developed a comprehensive evaluation method of shale oil reservoir fracability that considers hydration; the effects of the brittleness index, horizontal difference stress, and fracture toughness; and the law of water phase intrusion into shale oil reservoirs. The research results show that the average compressive strength decreased by 37.99%, the average elastic modulus decreased by 53.36%, and the average Poisson’s ratio increased by 68.75% after being soaked for 48.00 h at 80 °C and 30.00 MPa. The water saturation rate at the borehole wall was the highest; with the extension to the stratum, it gradually decreases to the original water saturation rate of the formation, while the fluctuation radius gradually increases with time. The Young’s modulus and fracture toughness decrease, the Poisson’s ratio increases, and the fracability index reaches a maximum value at the wellbore (i.e., the highest water saturation rate), indicating that the strength of the hydrated rock decreases and it can be easily fractured. The case analysis shows that the optimal fracturing position of the Da’anzhai Section of Well NC2H is around 2600 m deep. After the hydration occurs, the fracture initiation pressure of the formation is reduced from the original value of 72.31 MPa to 66.80 MPa. This indicates that when hydration decreases, the formation fracture pressure also increases. The research presented in this paper can be used to optimize fracture location and set a reasonable fracturing pressure. Full article

For the management of fractured large pores in high-water-bearing reservoirs, the general approach is to use transfer dissection and sealing. Conventional regulators have a limited regulating radius and can only produce blocking in the near-well zone, which is not ideal. Deep dissection technology can expand the radius of action and substantially improve the blocking effect. The existing deep-dissection agent system has problems such as high cost and poor effect, which affect its large-scale application. In this paper, to address these problems, a gel-type dissection modifier cross-linking agent was synthesized and optimized in the laboratory using low-concentration polymer, and the factors affecting the final gel formation effect were experimentally studied. The final polymer concentration was chosen to be 1500 mg/L~3000 mg/L, the poly-crossing ratio was 30:1, the pH was controlled at 7–9, and the temperature was controlled at 30–60 °C; the rubber was formed with good shear resistance and thermal stability, and had good adaptability to the high-mineralization environment. The optimal injection concentration of water-expanded rubber particles for this system was confirmed to be 3000 mg/L. Cryo-electron microscopy was used to observe the morphology of polymer gel formation and the adhesion of nucleated water-expanded particles to the gel, to clarify the mechanism of enhanced retention and sealing of nucleated water-expanded rubber particles by the multiple complex gel system, and finally to verify the sealing performance of the composite sealing system and determine the use effect by indoor simulation experiments with a two-dimensional flat plate model. This study is of great significance for the efficient development of high-water-bearing late reservoirs and further improvement of crude oil recovery. Full article

The Lamadian oilfield has entered the stage of strong water cut after natural energy development and conventional water flooding development. The use of asphalt binder for profile control can not only adjust the contradiction between layers, expand the swept volume, but also improve the oil displacement efficiency. The field test has achieved certain results. The main oil layer in the Lamadian oilfield has a strong oil layer thickness and serious vertical and plane heterogeneity. After years of water injection development and polymer injection development, most oilfields have entered a period of strong water cut. In the test, it is found that the effect of different well layers is very different, the effect is unstable, and the reason is unclear. Therefore, it is necessary to carry out research on the adaptability and parameter optimization of profile control of asphalt binder through laboratory experiments. In this paper, the asphalt binder provided on site are modified and the dispersion effect of modified asphalt binder is studied, and the concentration of suspending agent is optimized. The artificial cemented core structure and injection method are improved to solve the problem of aggregated asphalt binder on the end face during injection. The displacement profile control experiment was carried out with artificial cores, and the matching relationship between the injected particle size of the asphalt binder and the permeability was determined, and the optimal injection amount was optimized for cores with different permeabilities. The research results show that adding a KCl (potassium chloride solution) solution with a concentration of 2% as a dispersant can exert a better dispersing effect on the asphalt binder. Through the plugging rate experiments of three types of asphalt binder, the profile control effect is determined as the best when the particle size of the asphalt binder is 0.06–0.1 mm. According to the experimental results, the experimental research on the injection concentration and profile control radius of the profile control agent system was carried out. Finally, it was determined that the injection concentration of 3500 mg/L and the profile control radius of 1/3–1/2 of the well spacing were the optimal injection parameters. The field application of a profile control agent provides experimental basis. Full article

The failure of thickeners at high temperature results in gelled acid acidification fracturing. To solve the problem, 8 kinds of polymers were synthesized by free radical polymerization of aqueous solution using AM, AMPS, NaAMPS, MAPTAC, DTAB and NVP as raw materials. The polymer was characterized by infrared spectroscopy and viscosity-average molecular weight, and the temperature resistance, rheology, salt resistance and shear resistance of the polymer solution were compared, and the mechanism was analyzed. The results show that the viscosity of GTY−2 is 181.52 mPa·s, and the viscosity loss rate is 56.89% at 180 °C and 100 s⁻¹, and its temperature resistance is the best. Meanwhile, the viscosity retention rate of GTY−2 is 84.58% after 160 min shear, showing the strongest shear resistance. The viscosity loss rate of GTY−1 in 20% hydrochloric acid solution is 80.88%, and its acid resistance is stronger than that of GTY−2. Moreover, due to the amphiphilicity of DTAB, the molecular hydration film becomes thicker, and the salt resistance of GTY−2 is lower than that of GTY−1. The experimental results show that GTY−1 and GTY−2 have good temperature resistance, salt resistance, acid resistance and shear resistance, and can be used as thickeners for acid fracturing with thickened acid to improve the effect of acid fracturing under high temperature conditions. Full article

After long-term polymer flooding, water channeling, and ineffective water circulation occur in oil wells, which seriously affect polymer flooding efficiency and oilfield recovery. The weak gel system has the property of delaying cross-linking. After the weak gel system enters the deep formation, the cross-linking reaction is carried out, which can achieve the purpose of deep regulation and flooding. In this paper, according to the formation characteristics of high temperature, high permeability, and large pores in Y1 block (a block in the Daqing Yushulin Oilfield), the formulation of weak gel system was developed. The optimal formulation was determined by parameters such as gel-forming properties, stability, viscoelasticity, and rheology. Finally, the best formulation for the Y1 block is that containing 0.22% of polyacrylamide (HPAM) and 0.15% of chromium (III) acetate system. The gel-forming time of the formulation is 8 h, and the viscosity can be maintained at 15,000–24,000 mPa·s. Next, this paper studied the factors that affect the gelation of formulations, mainly including dissolved oxygen content, bacterial content, insoluble suspended solids content, and metal ions in the formulation water. The results show that the critical point of the worst effect is the oxygen content close to 1.5 mg/L, and the optimal critical point of oxygen content of the gel system is 7 mg/L. The bacteria in the prepared water degrade the weak gel solution. The more bacteria, the more serious the degradation of the weak gel. A small amount of insoluble suspended solids will greatly increase the viscosity of the weak gel solution, but will accelerate the gel-breaking time. When the content of insoluble suspended solids is high, more than 1000 mg/L, a precipitate will be formed at the bottom of the solution, and the difference in the content of insoluble suspended solids in this interval has little effect on weak gels. The metal ion that mainly affects the gelation effect is Fe²⁺. With the increase of Fe²⁺ mass concentration, the viscosity of weak gel decreases sharply. Full article

Pore structure is the key factor affecting reservoir accumulation and enrichment behavior. Due to the complex mineral components and pore structure of shale oil reservoirs and strong heterogeneity, it is necessary to explore the micro-pore structure characteristics of inter-salt shale. In this study, in order to qualitatively and quantitatively analyze the pore structure of inter-salt shale reservoirs, as well as evaluate the mineral composition and its spatial distribution characteristics, three shale samples from the 10th cyclothem of the Eq3 (Eq3⁴–10 cyclothem) inter-salt shale were selected to acquire 2D and 3D grayscale images by modular automated processing system (MAPS) and X-ray micro-computed tomography (Micro-CT), respectively. The color map of the inlaid characteristics of mineral aggregates was established by Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN), and different mineral types in the grayscale image were determined. After that, the digital core technology was used to reconstruct the core in 3D, and the maximum sphere method was used to extract the pore network model, so as to realize the quantification of micron pore throats and the 3D visualization of inter-shale samples. Meanwhile, in order to compare the fractal characteristics of the pores of the samples, the two-dimensional and three-dimensional fractal dimensions of the three cores were calculated by combining the digital core technique with fractal theory. The study yielded several notable results: the pore structure of inter-salt shale reservoirs is complex and multi-scale, and the CT scanning digital core technology can effectively realize 3D visualization of rock microstructure without damage. The pore types of rock samples are mainly intergranular pores, interparticle pores, and dissolved pores, and the minerals are mainly dolomite, calcite, and glauberite. The micron pore throat radius of the rock sample is 0.5–13.9 μm, the distribution of coordination number is mainly in the range of 1–4, and the shape of the pore throat is mainly triangular and square. The pore space of inter-salt shale has suitable fractal characteristics, and the three-dimensional fractal dimension of the three cores is in the range of 2.41–2.49. In sum, this work used digital core technology to study the microscopic pore structure of inter-salt shale oil, establishing a basis for further understanding of the seepage characteristics and exploration and development of shale oil. Full article

Tight sandstone gas is a significant unconventional natural gas resource, and has been exploited economically mostly through the application of hydraulic fracturing technology in recent decades. However, formation damage occurs when fracturing fluid percolates into the pores inside sandstones through imbibition driven by capillary pressure during fracturing operations. In this work, the formation damage resulting from the whole operation process composed of fracturing, well shut-in and flowback, and the degree of damage at different moments were investigated through core flow experiments and the low-field Nuclear Magnetic Resonance (NMR) technique. The results show that imbibition damage occurs starting from the contact surface between the formation and the fracturing fluid, which penetrates into an increasingly deep position with time down to a certain depth. The T2 spectra of NMR at different moments indicates that fracturing fluid initially enters the small pores, followed by the large pores due to the larger capillary pressure in the former. Thus, the sandstone cores with low permeability incur a higher degree of damage due to their stronger capability of retaining fracturing fluid compared to high-permeability cores. The front position of the fracturing fluid imbibition at different moments, along with the degree of damage, were characterized through the one-dimensional encoding processing of the NMR signal. These results underlie the effective strategy to relieve formation damage resulting from imbibition during hydraulic fracturing operations. Full article

This paper presents a low-cost, high-temperature-resistant and high-strength polyacrylamide gel system formed by secondary cross-linking. The gel system (named JM186) used phenolic resin and organic zirconium as cross-linking agents, and the performance of the gel system was systematically evaluated under high temperature. The gel properties studied include: gel formation time, gel strength, thermal stability, sand-filled pipe sealing efficiency, and its microstructure. The concentration of polyacrylamide in JM186 gel system was as low as 0.3%, which can control the gelling time in a range of 1–9 h by adjusting the ratio of two cross-linking agents. It can resist temperature up to 120 °C without dehydration, and its highest gel strength can reach H grade. The modulus of elasticity (G’) and viscosity (G”) can reach 32.33 Pa and 3.25 Pa, respectively. DSC (differential scanning calorimetry) test indicated that the temperature of structural failure for this composite gel is 310.5 °C. The average sealing efficiency of the gel is 96.03% in sand-filled pipes. Finally, the gel microstructure was observed by cryo-scanning electron microscopy (Cryo-SEM). It was found that the gel system by secondary cross-linking has a dense and thickened network structure compared with the single cross-linker gel system. The gel is cross-linked by both the coordination bond and covalent bond, and the two cross-linking agents have a synergistic effect. This is the reason why the secondary cross-link gel system is better than the single-cross-linker gel system. Full article