In the mining industry, microseismic monitoring has emerged as a crucial instrument for reducing risks related to the stability of underground rock masses. The present research conducts an analysis of dynamic hazards specifically at the 8204-2 working face in Tashan Mine. A novel monitoring framework is introduced, which integrates a nonlinear threshold curve model with a wireless microseismic monitoring system. The results demonstrate the effectiveness of the microseismic monitoring system with high-frequency sampling, utilizing the nonlinear threshold model, in detecting and providing real-time early warnings for microseismic signals, even in challenging geological environments. Practical implementation and monitoring over the past six months revealed that the microseismic monitoring system, employing the threshold curve model, achieved a monitoring and early warning accuracy exceeding 95%. This model combines the construction of a nonlinear threshold curve with dynamic conversion of confidence factors, and implements multi-level graded early warning based on the matching degree between real-time data and the hazard model, making its accuracy superior to traditional monitoring and early warning systems. Consequently, this study holds great significance in enhancing precise identification and early warning capabilities for mine microseism, as well as improving safety assessments for deep rock mining and construction practices.

Surfactants and nanoparticles play a crucial role in regulating the properties of the oil-water interface. However, their influence on the initiation and migration patterns of residual oil in pores remains insufficiently characterized. In this study, nanocompounded systems were prepared by dispersing hydrophobic silica nanoparticles (SiO2-N) in solutions of linear and branched alkylbenzenesulfonate betaines (ASB and XSB), respectively. The effects of these compounded systems on the oil/water/solid interface properties were determined through interfacial tension measurements, emulsion observations, and oil-film stripping tests. The results showed that the addition of SiO2-N enabled the ASB- and XSB-compounded systems to exhibit low interfacial tension characteristics and strong oil film stripping capabilities. Meanwhile, the linear ASB-compounded system demonstrated stronger emulsion stability and further reduced the water separation rate of the emulsion. Additionally, in microscopic-scale oil displacement experiments, the oil displacement efficiencies of the ASB- and XSB-compounded systems increased by 14.9% and 6.5%, respectively. The analysis of remaining oil images indicated that the nanocompounded systems better stripped the aggregated columnar remaining oil, increasing the proportion of liquid and droplet remaining oil. That is to say, the ultralow interfacial tension of the nanocompounded system at the oil/water interface prompts the remaining oil in the pores to transform from columnar to film-like and droplet-like; the improvement in emulsion stability enabled the emulsified oil droplets to have better migration capabilities; the enhanced oil film stripping improved the initiation and migration capabilities of remaining oil, thereby increasing the oil displacement efficiency. Therefore, this paper investigates the initiation and migration characteristics of crude oil in porous media by changing the hydrophobic groups of zwitterionic surfactants of both genders and reveals the synergistic oil displacement mechanism of the compounded system of straight-chain and branched zwitterionic surfactants and nano-SiO2 particles.

The petroleum industry faces a serious problem of gas hydrate formation in pipelines and process equipment, particularly in low-temperature marine environments. It is necessary to understand the chemical thermodynamics of gas hydrate formation so that it can be conveniently avoided. Although research has been conducted to develop correlations or to use Artificial Intelligence (AI) to determine hydrate temperature, to the authors' knowledge, none have compared Machine Learning (ML) models' performance in hydrate formation temperature prediction, especially Web User Interface (WUI) development based on the best-performing model. To achieve precision, this work compares the performance of four ML models, such as Artificial Neural Networks (ANNs), Decision Tree Regressor (DTR), Support Vector Regressor (SVR) and Random Forest Regressor (RFR) in terms of hydrate formation temperature prediction using operating pressure and specific gravity as features. Python was employed for this work, as it supports open-source libraries such as Keras with TensorFlow and scikit-learn, among others. Results showed that the coefficient of determination (R-2), Root Mean Square Error (RMSE), and a20-index on the overall dataset are (0.9994, 0.3120, 1), (0.9992, 0.3716, 1), (0.9991, 0.3880, 1) and (0.9910, 1.2545, 0.9972) for DTR, ANNs, RFR, and SVR, respectively. Although all models delivered strong results, they differ sharply in the time required to train. ANNs required 974.9498 s, RFR needed 15.9753 s, and SVR took 294.4242 s. In contrast, DTR completed the task in only 0.2727 s. Based on performance and computational efficiency, the models rank as follows: DTR>RFR>SVR>ANNs. Eventually, Web User Interface (WUI) was developed based on the bestperforming model (DTR). The optimal activation function for the ANN is tanh, while the Support Vector Regressor model performs best with the Radial Basis Function (RBF) kernel. We are optimistic that this research will open novel avenues in natural gas engineering. It is recommended that the models' lower and upper bounds be broadened by training the model on additional experimental data across different operating conditions.

Although low-permeability oil reservoirs boast abundant resources, oil recovery remains relatively low due to the limitations of current water flooding development technology in oilfields. To address the current challenges of low-permeability oil reservoirs, nano-SiO2 particle aqueous solutions, instead of conventional water injection, have been applied to these reservoirs, which can achieve promising results. Nevertheless, due to the simple surface structure of nano-SiO2 particles, the unsaturated hydroxyl groups on their surfaces tend to undergo electrostatic attraction with cations in formation water, leading to particle aggregation and flocculation, ultimately compromising their stability. Therefore, studying the interaction between nano-SiO2 particles and cations in saline solutions is of great significance for providing guidance on the application of nano-SiO2 particles in low-permeability oilfields. In light of this, this paper employs molecular dynamics simulations and quantum chemical methods to investigate the processes of interactions between nano-SiO2 particles and cations from a microscopic perspective. The results indicate that the interaction zone between monovalent cations and nanoparticles lies approximately 0.2 nm to 0.3 nm away from the particle surface. In comparison, the interaction zone between divalent cations and nanoparticles extends roughly from 0.3 nm to 0.4 nm from the particle surface. The range and depth of influence of divalent cations are more pronounced. No covalent or ionic bonds are formed between monovalent cations and nanoparticles. However, divalent cations can form ionic bonds with nanoparticles, thereby altering their structural configuration. Among these interactions, electrostatic forces represent the dominant interaction force responsible for changing the configuration of nano-SiO2 particles, whereas van der Waals forces and hydrogen bonding forces are merely weak interactions. Moreover, as the valence state of the cation increases from monovalent to divalent, the cation forms new ionic bonds with the nano-SiO2 particles, significantly modifying their structural configuration and further undermining their stability. The findings of this study can improve our understanding of the existing state of nano-SiO2 particles in formation water, which can help to improve the application effect of nano-SiO2 particles in low-permeability oil fields.

It is difficult to plug the fracture water channeling of a fractured low-permeability reservoir during water flooding by using the conventional acrylamide polymer gel due to its weak mechanical properties. For this problem, micron graphite powder is added to enhance the comprehensive properties of the acrylamide polymer gel, which can improve the plugging effect of fracture water channeling. The chemical principle of this process is that the hydroxyl and carboxyl groups of the layered micron graphite powder can undergo physicochemical interactions with the amide groups of the polyacrylamide molecule chain. As a rigid structure, the graphite powder can support the flexible skeleton of the original polyacrylamide molecule chain. Through the synergy of the rigid and flexible structures, the viscoelasticity, thermal stability, tensile performance, and plugging ability of the new-type gel can be significantly enhanced. Compared with a single acrylamide gel, after adding 3000 mg/L of micrometer-sized graphite powder, the elastic modulus, the viscous modulus, the phase transition temperature, the breakthrough pressure gradient, the elongation at break, and the tensile stress of the acrylamide gel are all greatly improved. After adding the graphite powder to the polyacrylamide gel, the fracture water channeling can be effectively plugged. The characteristics of the networked water flow channel are obvious during the injected water break through the gel in the fracture. The breakthrough pressure of water flooding is high. The experimental results are an attempt to develop a new gel material for the water plugging of a fractured low-permeability reservoir.

In order to improve the utilization of fracturing fluid and reduce the environmental pollution risk in large-scale fracturing of oil reservoirs in Ordos Basin, a type of reusable surfactant fracturing fluid is developed. Its formula composition is 15 x 10-3 g/mL of the synthesized surfactant and 6 x 10-3 g/mL of composite acid. The synthesized surfactant is formed by using 13-docosaenoic acid, 3-dimethylaminopropylamine, sodium chloroacetate, and other raw materials. The dissolution time of the fracturing fluid is less than 1 min. Due to the reversible entanglement interactions between the surfactant micelles, it is a viscosity-elastic fracturing fluid with good sand carrying capacity. It can remain basically unchanged after shearing. The surfactant fracturing fluid can be automatically broken to contact with the crude oil in the oil reservoir. The breaking time can be controlled within 100 min by adjusting the concentration of crude oil. After gel breaking, the viscosity is less than 2.9 mPa center dot s and the residue content is less than 1.25 mg/L. The interfacial tension of oil and the breaking liquid is below 0.1 mN/m. Subsequently, the field application of the fracturing fluid in N190 oil well has been carried out successfully. The backflow fluid of the surfactant fracturing fluid is successfully reused three times, and the performance of the fracturing fluid prepared in the field is basically consistent with the results of laboratory experiments. The fracturing construction by using the developed surfactant fracturing fluid can achieve a good fracturing stimulation effect and save a large amount of water resources.

Although nano SiO2 exhibits excellent application potential in the field of oil and gas exploration and development, such as drilling fluid, enhanced oil/gas recovery, etc., it is prone to agglomeration and loses its effectiveness due to the action of cations in saline environments of oil and gas reservoirs. Therefore, it is crucial to study the mechanism of the change in energy between nano SiO2 and cations for its industrial application. In this paper, the effect of cations (Na+, K+, Ca2+, and Mg2+) on the surface energy of nano SiO2 particles is investigated from the perspective of molecular motion and electronic change by density functional theory. The results are as follows: Due to the electrostatic interactions, cations can migrate towards the surface of nano SiO2 particles. During the migration process, monovalent cations are almost unaffected by water molecules, and they can be directly adsorbed on the surface by nano SiO2 particles. However, when divalent cations migrate from a distance to the surface of nano SiO2 particles, they can combine with water molecules to create an energy barrier, which can prevent them from moving forward. When divalent cations break through the energy barrier, the electronic kinetic energy between them and nano SiO2 particles changes more strongly, and the electrons carried by them are more likely to break through the edge of the atomic nucleus and undergo charge exchange with nano SiO2 particles. The change in interaction energy is more intense, which can further disrupt the configuration stability of nano SiO2. The interaction energy between cations and nano SiO2 particles mainly comes from electrostatic energy, followed by Van der Waals energy. From the degree of influence of four cations on nano SiO2 particles, the order from small to large is as follows: K+ < Na+ < Mg2+ < Ca2+. The research results can provide a theoretical understanding of the interaction between nano SiO2 particles and cations during the application of nano SiO2 in the field of oil and gas exploration and development.

Nano-SiO2 solution has great potential for application in the field of oil and gas exploration and development. However, its application is restricted due to the aggregation of nano-SiO2 in stratum water. This paper studies the process of interaction between nano-SiO2 particles and salt solutions by using the molecular dynamics simulation experiments, including the characteristics of transportation and diffusion of cations around the nano SiO2, the effect of cations on the recombination and destruction of hydrogen bonds, the interaction energy between cations and nano SiO2. The main results are as follows. During the transportation and diffusion of cations in the solution, the hydrogen bonds of water molecules are broken, so that the hydrogen bonds can be rearranged, and a stable solvated layer can be formed. In the solvated layer, the repulsive force of solvation can prevent the charge exchange between cation and the charged surface of nano SiO2 particle. Compared with the monovalent salt solution, more divalent cations can break through the solvation layer to generate the charge exchange on the surface of nano-SiO2 particle. More divalent cations can conduct small amplitude oscillation movement near the surface of nano-SiO2 particle due to the strong electrostatic effect. When the concentration of salt solution is increased (3000 mg/L -> 7000 mg/L) and the valence of cations is increased (monovalent -> bivalent), the hydrogen bond is easier to break through the solvation layer to gather on the surface of nano SiO2 particles, which is unfavorable to the stability of nano SiO2 particles. When the cations transport to the position of 7 & Aring; away from the surface of nano-SiO2 particles, the short-range force (including hydrogen bond force, van der Waals force, and electrostatic force) begins to affect the movement of cations. When the cations transport to the position of 2 similar to 3 & Aring; away from the surface of nano-SiO2 particles, the charge exchange occurs between cations and the surface of nano SiO2 particle, so that the local energy is increased and the cation continues to oscillate. In summary, with the increasing of concentration of salt solution and the valence state, more cations can break through the solvation layer to be adsorbed on the surface of nano SiO2 particle, showing that the ability of transportation and diffusion of cations is weakened, the interaction energy between nano SiO2 particle and salt solution molecules is enhanced. The electrostatic force is the main force to destroy the stability of nano SiO2 particle. The conclusions can provide a certain theoretical basis for the efficient application of nano-SiO2 materials in the field of oil and gas exploration and development and other interrelated industry.

Summary To promote the effect of waterflooding of a heterogeneous low-permeability reservoir in the Ordos Basin, a microbial plugging agent is developed to plug the multiscale water channeling. Based on the characteristics of the growth of bacteria, the microbial plugging agent can plug both porous media and microfractures with different scales. The microbial plugging agent is prepared by activating the native bacteria present in low-permeability reservoirs by using the fermentation nutrients. After growing in the fermentation nutrient solution for 4 days in a beaker, the growth of microbial strains begins to stabilize. After that, the main particle size of the prepared microbial plugging agent is between 40 μm and 160 μm and the median particle size (D50) is near 90 μm. The microbial plugging agent has good shear resistance, salt resistance, and stability. At the initial state, due to good injectivity, the microbial plugging agent can smoothly enter into a low-permeability core, a heterogeneous core, and a fractured core, respectively. Thus, it can grow and reproduce in the cores. Based on the characteristics of growth, it can match with the spatial scale of pore or fracture in the cores, so that it cannot only plug the porous media water channeling with different scales but also plug the microfracture water channeling with different scales. This phenomenon has been confirmed by microscopic visualization flow experiments and core flow experiments. The developed microbial plugging agent can be applied to plug the multiscale water channeling to enhance oil recovery of low-permeability heterogeneous reservoirs.

Abstract Natural gas production in the Sichuan Basin has been increasing in recent years with double-digit growth. Exploration and development of complex carbonate reservoirs ensures production growth. A major challenge is that the target Triassic Feixianguan Formation is characterized by extremely high sulfur. Use of radioactive source measurements such as density and neutron, are prohibited, for the sake of safety, giving rise to uncertainty in the interpretation of lithology and porosity. It is necessary to introduce source-less measurements as substitutions for the formation evaluation. This paper discusses a novel application of logging-while-drilling (LWD) nuclear magnetic resonance (NMR) and quadrupole sonic measurements for formation evaluation of this carbonate reservoir. The LWD NMR offers simultaneous measurement of T1 and T2, and the joint inversion of T1-T2 data provides real-time answers of the porosity, permeability, and pore structure of the reservoir. The LWD quadrupole sonic tool not only acquires formation compressional, shear, and Stoneley slowness, but also provides unique insight into high angle fracture identification. The integration of NMR and sonic measurements reveals the potential of the carbonate reservoir in the Triassic Feixianguan Formation. A case study is presented from a carbonate reservoir of Triassic Feixianguan Formation in the PetroChina SouthWest Oil and Gas Company. The lithologies of Feixianguan Formation are composed of dolomite and calcite. Mineralogy is successfully estimated by integration of NMR porosity and formation compressional slowness. The NM-derived effective porosity of the dolomite reservoir ranges from 2-20%, and the permeability ranges from 0.01-1000 mD. The well is drilled using oil-based mud, so the NMR free fluid T2 cutoff could be higher than the default 100 ms. Factor analysis based on the NMR T2 data indicates the free fluid T2 cutoff to be 210 ms in the dolomite reservoir. The pore structure of the dolomite reservoir is dominated by macro pores. The integration of NMR free fluid volume, crossover of compressional and shear slowness, and fracture analysis based on Stoneley data proves effective and robust in potential zone identification. This paper discusses integration of LWD NMR T1-T2 logging and quadrupole sonic measurements in the carbonate formation evaluation. It helps operator to understand the potential of the reservoirs. The gas production of the well that adopts the technology breaks the gas field production record. The workflow can also be applied to other high-sulfur reservoirs in China.

Current study uses chemical agents and ultrasonic waves to degrade the partially hydrolyzed polyacrylamide (PHPAM) solution. Due to the decrease in the effectiveness of polyacrylamide solution, it is essential to degel the leftover of the solution. Various chemicals, including hydrogen peroxide (H2O2) and chlorine dioxide (ClO2), remove polyacrylamide residue. However, due to consumable procurement and environmental insecurity, this technology is not appealing. In contrast, ultrasonic waves perform well in hydrolyzed polyacrylamide degradation and are more reliable, cost-effective, and environmentally friendly. The transducer #1 with a frequency of 18.0 KHz functioned admirably, successfully degrading the polymer solution. After 10 min of irradiation, the solution's viscosity dropped from 114 to 6.45 mPa-s. Transducers #2 and #3, with frequencies of 20.0 KHz and 25.0 KHz, reduced the viscosity to 6.62 and 6.5 mPa-s, respectively. ClO2 degrades polyacrylamide more effectively than H2O2 due to its higher oxidizing potential, reducing the viscosity to 15.8 mPa-s after 12 h. Ultrasonic-assisted PHPAM degradation is mainly due to cavitation, heat energy, and hydroxyl radical (HO center dot) generation, while chemical treatment involves hydroxyl radicals (HO center dot) and nascent oxygen [O]. This study is the first to compare chemical-assisted and ultrasonic-aided degradation of polyacrylamide.

How to effectively plug the multi-scale fractured water channeling has always been the key to achieving efficient water flooding of fractured low-permeability oil reservoirs. In this paper, a new type of supramolecular–polymer composite gel is developed, which is suitable for plugging multi-scale fractured water channeling. The supramolecular–polymer composite gel is composed of a polymer (such as polyacrylamide), cross-linking agent (such as polyethyleneimine), supramolecular gel factor (such as cyclodextrin) and polarity regulator (such as ethyl alcohol). The mass fraction of polyacrylamide, polyethyleneimine, cyclodextrin and ethyl alcohol are 0.15%, 0.2%, 1% and 0.2%, respectively. At the initial state, the viscosity of the composite gelant system is less than 20 mPa·s. It has good injection performance in micro-scale fractures and can enter the deep part of a fractured reservoir. At 40 °C, the composite gelant system can form a gel with a double network structure after gelation. One of the networks is formed by the covalent interaction between polyacrylamide and polyethyleneimine, the other network is formed by the self-assembly of cyclodextrins under the action of the ethyl alcohol. The comprehensive performance of the composite gel is greatly improved. The strength of the composite gel is >5 × 104 mPa·s, and it has good plugging strength in large-scale fractures. The composite gel can be used as a conformance control agent for fractured low-permeability oilfields.

In pipelines and process equipment, especially in cold oceanic environments, gas hydrate development presents a serious problem to the petroleum industry. Getting around this problem efficiently requires an understanding of the chemical thermodynamics of gas hydrate formation. In order to forecast the temperature of gas hydrate formation, the current investigation compares the effectiveness of three different types of machine learning algorithms: Support Vector Regression (SVR), Artificial Neural Networks (ANNs), and Decision Tree Regression (DT). The research was conducted using Python 3.11.3 as the programming framework, which made use of its extensive ecosystem of open-source tools, including scikit-learn (version 1.2.2) and Keras with TensorFlow. With ANNs, there was no activation function in the output layer and the hyperbolic tangent function was used as the activation function in a hidden layer. The Radial Basis Function (rbf) was used as the Kernel function for Support Vector Regression (SVR). A maximum tree depth of 15 was imposed on the Decision Tree (DT) regression. Throughout the whole dataset, evaluation measures such as Root Mean Square Error (RMSE) and coefficient of determination (R2) were calculated. The findings showed that the R2/RMSE values for SVR, ANNs, and DT regression were, respectively, (0.9999, 0.0631), (0.9986, 0.5011), and (0.9278, 3.5606). In conclusion, the models' output was rated as follows in descending order: Support vector regression (SVR) is a subset of decision tree regression (DT) and artificial neural networks (ANNs). Following that, a Web User Interface (WUI) was created using the Decision Tree paradigm, which proved to be the most efficient. In theoretical terms, this work opens the door to further developments in gas engineering. The prediction capability of the models could potentially further improved by adding more experimental data to the dataset used for training.

BZ13-2 oil field is a deep submerged strongly volatile reservoir in Bohai Sea. This oil reservoir has the characteristics of high gas oil ratio and small difference in formation pressure and saturation point pressure. It usually adopts gas injection development to avoid crude oil degassing and fast decreasing production capacity. However, the phase characteristics and miscibility mechanism of this high-temperature and high-pressure fluid after gas injection are not clear. Therefore, it is necessary to study the feasibility of CO2 injection to improve oil recovery in near critical volatile oil reservoirs through CO2 injection experiments. In the early stage of the depletion experiment, the content of heavy components in the remaining oil increased significantly, so the depletion method is not conducive to the development of such reservoirs. With the increase of CO2 injection, the volumetric expansion coefficient of formation crude oil increases significantly, while the saturation pressure and formation crude oil viscosity remain basically unchanged. The minimum miscible pressure experiment shows that CO2 injection under formation pressure conditions can achieve multiphase miscibility. Based on experimental research results, the BZ13-2 oilfield is suitable for early gas injection development and can significantly improve recovery.

为了实现对大裂缝水窜通道的高效封堵,提高低渗透油藏的水驱效果,开展了凝胶颗粒与聚合物本体凝胶联合封堵技术研究.先利用凝胶颗粒将大裂缝通道转变为多孔颗粒介质通道,再利用聚合物本体凝胶封堵颗粒介质间的通道.结果表明:对于开度为1.8 mm的裂缝,凝胶颗粒在粒径为2.5 mm、质量浓度为8 000 mg/L、注入速度为1.0 mL/min的注入参数条件下,可密集均匀地分布在裂缝通道中,并呈活塞式均匀向前推进;当凝胶颗粒充填整条裂缝后,所形成的多孔颗粒介质的渗透率为2 300.0x10-3μm2.基于裂缝性岩心基质的渗透率,要求优选的聚合物本体凝胶在渗透率为2 300.0x10-3μm2的多孔颗粒介质中的封堵压力梯度应大于3.3 MPa/m,从而启动基质中的流体.以此为依据,所需聚合物本体凝胶的强度应大于66 Pa,所用的聚合物本体凝胶的组成为质量浓度4000 mg/L的HPAM+质量浓度150mg/L的Cr3+.这一调剖方法在延长油田5088-3井组取得了较好的增油效果,可以为裂缝性低渗透油藏的可持续高效开发提供技术支撑.

The national policy of peak carbon dioxide emission and carbon neutrality has pointed out the technological direction for the development of the petroleum industry in China. In order to efficiently utilize CO 2 gas source to enhance oil recovery, n -butylamine is taken as the plugging channeling agent for experiment study to plug the produced channeling-path during the process of CO 2 flooding in ultra-low permeability reservoir. The contents of the experiment included three parts: reaction mechanism of n -butylamine with CO 2 , evaluation of the injection performance of n -butylamine, and the extent of enhanced oil recovery after plugging the gas channeling by using n -butylamine. Reaction product of n -butylamine and CO 2 is white solid, which is a type of organic urea so that it can be used to plug the gas channeling. N -butylamine has a good injection performance after adding protecting slug on the condition of high temperature. 80% of the whole volume of core can be spread after injecting 0.3 PV of n -butylamine. During plugging and displacement experiment of heterogeneous cores, oil recovery can be greatly enhanced by 25–30% after injecting n -butylamine. Experimental results show that it can provide a new train of thought for the gas injection development of fractured, heterogeneous and ultra-low permeability reservoirs by using n -butylamine to plug the high permeability area.

能否封堵裂缝水窜通道是裂缝性低渗透油田实现高效注水开发的关键.封堵裂缝水窜通道需要高强度的凝胶堵剂,但是传统的丙烯酰胺类凝胶的强度偏低.针对此问题,文章通过添加成本低廉的微米级石墨粉以大幅度提升丙烯酰胺类凝胶的强度及综合性能.对比单一的丙烯酰胺凝胶体系,添加0.3％的微米级石墨粉后,弹性模量从120 Pa增加至400 Pa、黏性模量从48.6 Pa增加至268 Pa(1 Hz条件),相变温度由167℃增加至212℃,突破压力梯度由255 kPa/m增加至440 kPa/m(0.13 mm裂缝),断裂伸长率由700％增加至1100％,拉伸应力由38 kPa增加至110 kPa.可视化裂缝封堵实验对比显示,添加了石墨粉之后,再次注水所形成的网状水流通道特征明显,注入水突破压力高,封堵效果更有意义.石墨粉片层上的羟基、羧基参与了凝胶合成的物理化学反应,并且刚性结构的石墨粉可以支撑聚丙烯酰胺分子链的柔性骨架,从而大幅度提升了凝胶综合性能.实验结果尝试为裂缝性高含水油田的堵水作业提供出一种性能优异的新凝胶材料.

玛湖1井区百口泉组为典型的低孔低渗致密油储层.该井区大规模水力压裂面临3大难题,如压裂液减阻效果差、对储层伤害大;水资源匮乏,油田污水处理困难;缝间剩余油分布,采收率有待提高.针对这些问题,以羟甲基苯乙烯、醋酸乙烯酯、丙烯酰胺、聚乙烯基苄基三甲基氯化铵等为原料,通过分散聚合法制备了减阻剂(JHFR),将其与多功能添加剂(JHFD)复配制得滑溜水压裂液.研究了目标区块的压裂水源、储层岩石的黏土矿物含量对黏土在滑溜水中水化膨胀性能的影响,评价了滑溜水对玛湖致密油藏储层的伤害情况.结果表明,减阻剂JHFR溶解时间(15 s)短,可实现免配直混.由0.1％JHFR和0.2％JHFD组成的滑溜水具有高效减阻(减阻率76.9％)、低油水界面张力(0.89 mN/m)、防膨效果好(防膨率81.12％)等特点,且与玛湖1井区的地层水和返排水的配伍性良好、对岩心渗透率损害程度低,适用于该井区的大规模连续压裂施工.

Before a wide range of enhanced oil recovery (EOR) techniques were implemented for an oilfield, the EOR potential and economic evaluation of the techniques should be evaluated in advance for each reservoir to determine which EOR technique was proper. In an oilfield developed with fluvial delta reservoirs, the complicated distribution of scattered small reservoirs in vertical and horizontal directions brought trouble for evaluation work. A rapid and reliable evaluation model for EOR techniques applicability was necessary to deal with the evaluation simulation for many small reservoirs of an oilfield. Combining fraction theory model with auxiliary equations, which describe the effect of formation heterogeneity and mechanism of different EOR technique on fractional flow rate, an evaluation analysis method for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding was proposed. In the gas flooding model, the minimum miscible pressure of impure gas was introduced, and the relative permeability was modified by the minimum miscible factor. In the foam flooding model, changes in the mobility ratio and chemical adsorption were considered and a reduction factor of mobility ratio was introduced. In the surfactant flooding model, calculation formulas of viscosity and interfacial tension as well as the relative permeability were introduced. Finally, the model was simulated for a low permeability reservoir, and the simulation results were compared with that from Eclipse software. The similar results, little calculation time and feasibility of predicting optimal injection parameter had shown the reliability of the rapid evaluation model.