Unconventional Oil Reservoirs Research Articles

A novel self-degradable gel (SDG) as liquid temporary plugging agent for high-temperature reservoirs

In recent years, the liquid temporary plugging agent has drawn extensive attention, especially in the repeated fracturing operation for stimulating unconventional oil and gas reservoir production. This paper developed a novel self-degradable gel (SDG) as a liquid temporary plugging agent for high-temperature reservoirs. The gelation process, viscoelasticity, pressure-bearing capacity, self-degradation, and formation protection performance of the SDG were systematically investigated. Moreover, the gelation and self-degradation mechanism of the SDG were revealed by studying the viscosity variation and the microstructures. Considering the gelation time and gel strength, the composition of the SDG was optimized as 6.0–10.0 wt% monomer, 0.004–0.012 wt% initiator, and 0.2–0.4 wt% crosslinker. The SDG transformed from liquid to solid-like gel within 30 to 90 min at 90–130 °C. The rheological results showed that the duration of the low viscosity state exceeded 75 % of the total gelation process at high temperatures, which was conducive to the injection of the SDG. In addition, the viscosity of the SDG after gelation was more than 100 Pa·s, which ensured its effective plugging in fractures. The experimental results with fractured cores showed that the bearing pressure of the SDG remained above 30 MPa/m in fracture with a width of 2.05–5.04 mm, which could meet the requirements of the repeated fracturing operation. Moreover, the SDG could spontaneously degrade from solid-like gel to liquid with a viscosity of lower than 10 mPa·s in 10–105 h at 90–130 °C. The broken-gel liquid could be completely displaced out of the fractured core, and the core damage rate was less than 5.0 %, which ensured the restoration of conductivity of the previously existing fractures. Micrographs showed that the dense three-dimensional network structure with high viscosity was formed by polymerization and crosslinking. Then, the acrylic acids in the polymer chain were broken at high temperatures, resulting in the gradual destruction of the gel and the spontaneous degradation of SDG.

Seismic physical modeling study for a shale oil reservoir with complex lithofacies and meter-scale structures

Shale oil reservoirs usually have various lithofacies with complex spatial patterns. Seismic reflections usually reveal the combination of sets of thin mud shales with various lithofacies. The seismic response characteristics of the lithofacies and the differences in seismic response of different lithofacies are still unclear, making the reservoir description difficult. The complex tectonic structures, diverse lithofacies, thin interlayers, fractures with various length scales, and various fracture development zones in the shale oil reservoir have placed very high demands on the design and construction method during the physical modeling of the shale oil reservoir. Facing these challenges, a physical modeling study on shale oil reservoirs with complex lithofacies and meter-scale structures is conducted. The target is the shale oil reservoir of the [Formula: see text] subsegment in the Jiyang depression. The complex physical model of a shale oil reservoir, with the thin stratigraphic layers and the complicated lithofacies and fracture patterns to date, has been designed and constructed in a laboratory. In total, 25 combinations of materials have been developed to simulate various lithofacies with different elastic parameters, and the error of the wave velocity simulation is less than 2.35%. The simulation of 1 m thick interlayers and the construction method for seismic physical models with meter-scale geologic structures has been realized. The quality control analysis finds that the simulation accuracy of small-scale geologic structure, complex lithofacies, and fractures is relatively reliable. Based on the physical model of the shale oil reservoir, high-density and wide-azimuth seismic data are acquired. Preliminary data processing and analysis find that the model layers have clear reflection characteristics, providing reliable data for the next step of seismic characteristics analysis of complex lithofacies shale oil reservoirs. The methodology has improved the capacity of seismic physical modeling to simulate complex oil and gas reservoirs, enabling the seismic physical simulation method to be applied in analyzing the commonly observed complex lithofacies, fractures, and meter-scale structures in unconventional oil and gas reservoirs.

Study on seepage model of Multiple Horizontal wells with complex fracture networks in tight Reservoir Based on boundary element method

Horizontal well and volume fracturing technology are the key technologies to develop unconventional reservoirs. Tight reservoir is belonging to multi-scale seepage mediaafter fracturing, and theflow of fluid in it is extremely complicated. In this paper, based on the boundary element method (BEM), the seepage model of horizontal wells with complex fracture networks in irregular boundary reservoir is established for the first time. The model takes into account the influence of irregular reservoir boundary, dual media, complex fracture network and interference of multiple wells on horizontal well seepage. Using this model, the sensitivity analysis of wellbore storage coefficient, skin factor, fracture permeability and interporosity transfer coefficient is carried out. The model expands the application scope of BEM in the field of seepage simulation of unconventional oil and gas reservoirs and provides theoretical guidance for the development of tight oil reservoirs.

Proppant transport in rough fractures of unconventional oil and gas reservoirs

A method to generate fractures with rough surfaces was proposed according to the fractal interpolation theory. Considering the particle-particle, particle-wall and particle-fluid interactions, a proppant-fracturing fluid two-phase flow model based on computational fluid dynamics (CFD)-discrete element method (DEM) coupling was established. The simulation results were verified with relevant experimental data. It was proved that the model can match transport and accumulation of proppants in rough fractures well. Several cases of numerical simulations were carried out. Compared with proppant transport in smooth flat fractures, bulge on the rough fracture wall affects transport and settlement of proppants significantly in proppant transportation in rough fractures. The higher the roughness of fracture, the faster the settlement of proppant particles near the fracture inlet, the shorter the horizontal transport distance, and the more likely to accumulate near the fracture inlet to form a sand plugging in a short time. Fracture wall roughness could control the migration path of fracturing fluid to a certain degree and change the path of proppant filling in the fracture. On the one hand, the rough wall bulge raises the proppant transport path and the proppants flow out of the fracture, reducing the proppant sweep area. On the other hand, the sand-carrying fluid is prone to change flow direction near the contact point of bulge, thus expanding the proppant sweep area.

Simulation and Analysis of Proppant Transport Patterns in Wellbore-Fracture Systems

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m3/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block.

Synergistic effect of dual hydrogen-donor deep eutectic solvent for performance improvement of fracturing-oil expulsion fluids

Petroleum remains the main source of energy consumption over the past decade. The development of rich unconventional oil reservoirs is a huge challenge. Clean fracturing fluids (CFFs) have gained considerable attention for the unconventional reservoir development, owing to their integrated capabilities of fracturing and oil expulsion. Performance of CFFs is a vital factor in enhancing oil recovery. In this work, a ternary deep eutectic solvent (DES) with dual hydrogen donors (HBDs) was developed as a novel and green medium for improving CFF performance. With the hydrogen-bonding interactions, the ternary DES enable a robust micelle network, thereby strengthening the rheological property, temperature resistance and drag reduction performance of CFFs. The salt resistance performance was improved due to the ion–dipole interaction between HBDs and salt cations, decreasing the interactions between salt cations and surfactants. The DES also increase the imbibition efficiency from 30.7 % in 98 h to 43.7 % in 62 h. Besides, the gel breaking performance and reusability of gel-breaking fluid were enhanced in the presence of DES. The ternary DES showed more effective reinforcement for CFF properties as compared with binary DES, due to the synergistic effect of dual HBDs. This work will provide a promising alternative for intensifying CFF performance.

Composite stimulation technology for improving fracture length and conductivity of unconventional reservoirs

Unconventional reservoirs have strong heterogeneity, with significant differences in the distribution of porosity and permeability. Fracturing is an important technology for increasing natural gas production in unconventional oil and gas reservoirs. For unconventional reservoirs with high temperature and low permeability, the rapid increase in acid rock reaction rate leads to a significant decrease in the effective distance of acidic fluids and fracture conductivity, especially the inability to obtain effective support at the fracture tip, which restricts the increase in production of high-temperature unconventional oil and gas reservoirs. To address the above issues, a composite fracturing method is proposed, which first uses a proppant to support the crack tip, and then uses gelled acid to corrode the middle and rear parts of the crack. According to the fracture conductivity achievement test experiment and proppant migration experiment, when 40/70 mesh ceramsite and 100 mesh ceramsite are mixed at a mass ratio of 1:4, the fracture conductivity can reach 21.8 μm·cm2 under the effective closing pressure of 60 MPa, which is 123% higher than the fracture conductivity of cementitious acid corrosion. The gel is used to carry 40/70 mesh and 100 mesh ceramsite, and the Equilibrium level of the sand embankment can reach 38 cm. At the same time, the sand dike formed by different particle sizes of ceramic particles is smoother than the sand vein formed by a single particle size of proppant, and the migration ability of ceramic particles to the fracture tip is better. The composite stimulation technology has been applied to 9 wells in carbonate and shale oil and gas reservoirs. After fracturing, the production of oil and gas wells is 210% higher than that of gelled acid fracturing, and the composite stimulation technology has achieved good stimulation effects.

A simple method for fast simulation of total reflection waves of single-well imaging with eccentric tools

Abstract In the exploration of unconventional oil and gas reservoirs, single-well acoustic imaging has become an important technique to detect geophysical structures around the borehole. In this study, we propose a simple method to calculate the total reflection wavefields of pressure and displacement for single-well imaging (SWI) with eccentric monopole or dipoles. To calculate the pressure at the eccentric site for incident waves with different angles of incidence and azimuth, reciprocity is applied to the radiation from the eccentric monopole source and the far-field forces generating the waves corresponding to the incident waves. Displacement solutions are derived by calculating the gradient of the pressure fields. When considering eccentric monopole or dipole sources for an inclined reflector outside the borehole, reciprocity is again used to derive the total reflection waves, including the same type of waves (P-P/SV-SV/SH- SH) and the converted waves (P- SV/SV-P). The analytical results agree well with the reference solutions of the 3D finite-difference time-domain method, illustrating the validation of the method. The analysis shows that the pressure amplitude in the eccentric position is greater than that in the borehole axis, proving that the eccentric monopole can increase the weak amplitude of reflection waves. We also simulate the wavefields for the acoustic imaging model for eccentric monopole and dipoles. The results show that the pressure and displacement wavefields in the eccentric position are sensitive to the azimuth angle of the reflector, proving that SWI with eccentric logging tools is capable of identifying the azimuth angle.

Characteristics and Geological Implications of Lacustrine Carbonate of Nantun Formation in Hailar Basin

Abstract Globally, lacustrine carbonate rocks are often found in rift lake basins. Because they often do not form large-scale conventional or unconventional reservoirs, they have not received enough attention in previous oil and gas exploration. Recent years, exploration examples in China show that lacustrine carbonate has close relationship with unconventional oil and gas. Mudstone with carbonate deposits always has a good exploration effect in the area. However, the genesis of lacustrine carbonate is still controversial. The sediment environment difference between carbonate and mudstone and its effects on unconventional hydrocarbon accumulation are not yet clear. This paper focuses on lacustrine carbonate found in the Nantun Formation in Hailar Basin. Through the analysis of lithofacies, geochemistry, and logging data, several findings have been obtained in the current study. (a) Two kinds of lacustrine carbonates, micrite dolomite and marlstone, which represent semideep to deep lake environments, have been identified in the research area. (b) Lacustrine dolomite (LD), whose genesis may relate to magmatic movement and deep hydrothermal processes, shows an extremely dry, hot paleoclimate and a saline, anaerobic ancient water condition. (c) Carbonate deposition in mudstone is related to the condensation section, and marlstone and micrite dolomite represent the beginning and end of the condensation section, respectively. Compared with mudstone around carbonate rocks, LD represents a drier, hotter, and saltier environment, which is of significance for sedimentary environment identification. In addition, the mudstone with lacustrine carbonate deposits has better organic matter characteristics and can form good unconventional oil and gas reservoirs that are of great significance for further exploration.

A new mixed type crack propagation criterion in shale reservoirs

Hydraulic fracturing is a mainstream technology for unconventional oil and gas reservoirs development all over the world. How to use this technology to achieve high-level oil and gas resource extraction and how to form complex fracture networks as hydrocarbon transportation channels in tight reservoirs, which depends to a large extent on the interaction between hydraulic and pre-existing cracks. For hydraulic fracturing of fractured reservoirs, the impact of natural fractures, perforation direction, stress disturbances, faults and other influencing factors will produce a mixed Ⅰ&Ⅱ mode hydraulic fracture. To forecast whether hydraulic fractures cross pre-existing fractures, according to elastic mechanics and fracture mechanics, a stress state of cracks under the combination of tensile (Ⅰ) and shear (Ⅱ) is presented. A simple mixed-mode Ⅰ&Ⅱ hydraulic fracture's crossing judgment criterion is established, and the propagation of hydraulic fractures after encountering natural fractures is analyzed. The results show that for a given approaching angle there exists a certain range of stress ratio when crossing occurs. Under high approaching angle and large stress ratio, it is likely that hydraulic cracks will go directly through pre-existing cracks. The reinitiated angle is always controlled within the range of approximately 30° among the main direction of penetration.

Diagenesis and Pore Formation Evolution of Continental Shale in the Da’anzhai Lower Jurassic Section in the Sichuan Basin

As an unconventional oil and gas reservoir, the diagenesis and evolution of continental shale controls the formation and occurrence of inorganic and organic pores. In order to quantitatively characterize the pore characteristics of a continental shale reservoir and their influence on the evolution of the diagenesis stage, the characteristics of organic and inorganic pore types of continental shale in the Da’anzhai section of the lower Jurassic Ziliujing Formation were identified by means of X-ray diffraction mineral composition analysis and argon ion polishing scanning electron microscope measurements and observations, and the influence control of the diagenesis stage on the pore development of the continental shale reservoir and its control were clarified. The results show the following: ① The organic matter pores in continental shale are developed in large quantities, including organic matter pores in the mineral asphalt matrix and organic matter pores in the kerogen; the pore types of inorganic minerals are very rich, the main pore types are linear pores between clay minerals, intergranular (intergranular) pores, and intragranular corrosion pores, and microcracks are also developed. ② When affected by compaction diagenesis, the inorganic pores of continental shale decrease with an increase in the burial depth and diagenesis degree. ③ The burial depth of continental shale is 2000–3000 m in the middle of diagenetic stage A, and a large number of organic matter pores and dissolved inorganic pores develop at this depth, meaning that the total porosity of shale increases significantly. The burial depth of continental shale is 3000–4000 m at diagenetic stage B, where kaolinite and other clay minerals are dehydrated and converted into illite, the brittleness of shale is increased, and the interior of the shale is subject to external stress, causing microcracks to form. In the late diagenetic stage, when the buried depth of the continental shale is more than 4000 m, the organic matter is subject to secondary cracking and hydrocarbon generation, the organic pores of shale increase in number again, and the inorganic pores decrease in number due to compaction. In conclusion, we found that the burial depth is the main control factor for the development of pores and microfractures in continental shale reservoirs; diagenesis caused by burial depth is the main factor affecting the development of pores and microfractures in continental shale reservoirs; and the shale burial depth in this case is more than 3500 m, which is in the middle of diagenetic stage B. Inorganic porosity in shale is reduced, and the number of microfractures is increased. When the shale is buried more than 4000 m deep in the late diagenetic stage, the thermal evolution of organic matter in shale is high, and methane gas is generated in large quantities, which is conducive to the formation and development of organic matter pores in continental shale.

Experimental Study for the Effects of Different Factors on the Sand-Carrying Capacity of Slickwater

With the continuous exploration and development of unconventional oil and gas reservoirs, volume fracturing technology becomes one of the necessary measures for developing shale gas and tight sandstone gas reservoirs effectively. Volume fracturing technology usually uses slickwater and drag-reducing agent as the core of the fracturing system. The composition of the fracturing system is the main factor determining its performance. Polyacrylamide has many amide groups in its main chain, high activity, and controllable performance, often in solid powder and liquid emulsion states. Furthermore, polyacrylamide which is the water-soluble drag-reducing agent is most widely used in applying current shale gas slickwater fracturing operations. Due to the low viscosity and poor sand-carrying capacity of slickwater, proppant easily settles at the bottom of hydraulic fractures. This phenomenon influences the stimulation effect of volume fracturing. Therefore, the law of sand carrying and placement of proppant in hydraulic fractures in volume fracturing plays an essential role in determining the success of the stimulation effect of volume fracturing. Through the visualization device of proppant transport in the fracture, the settlement of proppant in the fracture was studied experimentally. And through experimental equipment, the effects of different operation pumping rates, liquid viscosity, proppant type, and proppant pumping schedule on the stimulation effect were studied. The experimental results can provide strong support for volume fracturing into well material optimization and operation parameter optimization for unconventional oil and gas reservoirs.

Molecular dynamics simulation of CO2-oil miscible fluid distribution and flow within nanopores

CO2 Huff-n-Puff is a promising technology for recovering unconventional oil reservoirs nowadays. Studying the structural properties of CO2-oil inside nanoscale pores and the transport mechanism during production can help further improve crude oil recovery. In this work, molecular dynamics simulations are performed to explore the distribution and flow of CO2-decane within a 6 nm SiO2 nanopore under reservoir conditions. CO2 will substitute the decane adsorbed on the surface under the strong electrostatic interactions with the SiO2 surface. The variation of CO2 content in the adsorbed layer was quantitatively described. The flow behavior of CO2-decane on the pore surface does not obey the continuous hydrodynamics theory. The adsorbed CO2 forms an adhesion layer on the pore surface, shifting the flow boundary condition from slip to negative slip. The CO2-decane permeability model is established to investigate the influences of the negative slip on the permeability. The adhesion layer reduces the permeability of CO2-decane in pores. By contrast, the dissolved CO2 reduces the bulk phase viscosity and raises the decane mobility. The flux analysis results indicate that viscosity reduction contributes more than the flux loss due to negative slip, and CO2 improves the decane transport ability within the nanopore. Besides, sensitive factors such as oil content, pore pressure, and pressure gradient are considered. This study provides new insights into the surface flow behavior of CO2-oil in nanopores, which is essential for the accurate prediction of CO2-oil transport behavior under confined conditions.

A Scientometric Review on Imbibition in Unconventional Reservoir: A Decade of Review from 2010 to 2021

Spontaneous imbibition is a phenomenon of fluid displacement under the action of capillary force, which is of great significance to reservoir protection, enhanced oil recovery, flow-back optimization, and fracturing fluid selection in unconventional oil and gas reservoirs. Remarkable progress has been made in the imbibition research of oil and gas, and the overall research situation of research needs to be analyzed more systematically. This paper aims to provide a scientometric review of imbibition studies in unconventional reservoirs from 2010 to 2021. A total of 1810 papers are collected from the Web of Science Core Correction database based on selected keywords and paper types. Using CiteSpace software, a quantitative scientific analysis is carried out on the main aspects of national cooperation, institutional cooperation, scholarly cooperation, keyword co-occurrence, journal co-citation, article co-citation, and keyword clustering. The principal research countries, institutions, scholars, keywords, published journals, influential articles, and main research clusters are obtained, and the cooperation relationship is analyzed from the centrality and number of publications. At the end of the paper, the existing knowledge areas are discussed based on the analysis of scientometric results. This study constructs a comprehensive research knowledge map of imbibition, providing relevant research with a more valuable and in-depth understanding of the field.

A Comprehensive Review on Screening, Application, and Perspectives of Surfactant-Based Chemical-Enhanced Oil Recovery Methods in Unconventional Oil Reservoirs

A Comprehensive Review on Screening, Application, and Perspectives of Surfactant-Based Chemical-Enhanced Oil Recovery Methods in Unconventional Oil Reservoirs

Rock brittleness index inversion method with constraints of seismic and well logs via a CNN-GRU fusion network based on the spatiotemporal attention mechanism

Rock brittleness is an important parameter for evaluating the fracability of the unconventional oil and gas reservoirs such as tight sandstone and shale oil. Compared with the laboratory measurement, rock brittleness in 3D stratum using the joint inversion of seismic and well logs is more significant for oil exploration and development, but the resolution of the inversion results is low due to the narrowly effective bandwidth of seismic data. Deep neural network (DNN) can establish the complex nonlinear mapping relationship between input and output data to improve the resolution of inversion results, but it has the problem of unstable prediction results in the case of insufficient training samples in the geophysical field. Aiming at the problem, firstly, the ratio of Young ‘s modulus to Poisson ‘s ratio is defined as the rock brittleness index, and an AVO approximation equation with brittleness index is derived, thus establishing the convolution model between the rock brittleness index and seismic data. Secondly, an objective function containing the loss of logging data, seismic data and low-frequency components obtained by the inverse distance weighted interpolation of seismic and well logs is proposed to improve the spatial constraints of seismic and well logs. Then, the spatiotemporal attention mechanism is fused with the convolutional neural network (CNN) and gate recurrent unit (GRU) network to improve the sensitivity of the network proposed to important spatiotemporal characteristics. Finally, a DNN based on the double constraints of convolution model and data is established to solve the inversion stability in the case of small samples. The inversion results of the geological model with sand body superposition and pinchout and the tight sandstone reservoir in Junggar Basin verify that the generalization and prediction accuracy of the network proposed.

Construction of fracturing fluid with excellent proppant transport capacity using low molecular weight hydrophobic association polymer and surfactant

Slick water fracturing fluid is widely used for fracturing unconventional reservoirs such as shale and tight gas, and it has aided in developing unconventional oil and gas reservoirs. However, the problem of slick water in terms of its weak proppant transport capacity has not been effectively solved. Conventional methods of increasing the proppant transport capacity of a fracturing fluid by increasing viscosity and pumping rate have resulted in serious reservoir damage and increased costs, showing more and more limitations. To address this issue, a low molecular weight polymer/surfactant (LMPS) fracturing fluid system was developed. LMPS increased the fluid elasticity through the interaction between the hydrophobic groups on the polymer and the surfactant while maintaining low viscosity, thus obtaining excellent proppant transport capacity. The low molecular weight polymer is a type of hydrophobic association water-soluble polymer (HAWSP) prepared by photoinitiation. Its viscosity-average molecular weight was determined to be 1.24 × 106 g/mol, much more than that of a typical drag reducer of traditional slick water (about 1 × 107 g/mol). The low molecular weight of HAWSP is conducive to preparation, dissolution, pumping, and reducing the damage of polymer to the reservoir. When 300 mg/L of sodium dodecyl benzene sulfonate (SDBS) surfactant was added to a 0.2 wt% HAWSP solution, it formed a robust self-assembled network that significantly enhanced the elasticity and raised the storage modulus G' from 0.11 to 5.95 Pa. The 20/40 mesh ceramsite proppant remained suspended in the LMPS solution (36 mPa·s) for 30 min, whereas ceramsite completely settled within 30 s in an ordinary linear polymer solution with similar viscosity. Simultaneously, despite having a lower molecular weight, the drag reduction rate test shows that the drag reduction performance of the LMPS fracturing fluid was similar to the tested conventional commercial linear polymer. The self-assembled network of HAWSP/surfactant can increase the viscoelasticity of the fracturing fluid, which is expected to overcome the weakness of insufficient proppant transport capacity of slick water, thus improving development efficiency of unconventional gas reservoirs.

The development of a smart gel for CO2 mobility control in heterogeneity reservoir

CO2 flooding is regarded as one of the most effective ways to enhance oil recovery for unconventional oil and gas reservoirs, that is also conducive to the capture and storage of CO2. However, due to the heterogeneity of the reservoir, the gas channeling of CO2 becomes more serious, limiting the sweep efficiency of CO2 flooding. Herein, to make the most use of CO2 flooding, a CO2-responsive smart gel system is designed to improve the formation profile and control the mobility of CO2. Through rheological tests, the basic properties, such as shear resistance, viscoelasticity and responsiveness, are evaluated. The system has good viscoelastic and shear resistance, and can quickly form high strength gel within 150 s. At the same time, the self-assembly mechanism of the system is revealed by SEM. The influence of permeability, injection concentration and volume of smart gel on the plugging performance of the CO2-responsive smart gel system are also explored. Finally, the mobility control ability and EOR performance of the CO2-responsive smart gel system are revealed by the double pipes flooding experiments. This work puts forward a new idea of enhancing oil recovery for CO2 flooding with the aid of CO2-responsive smart gel.

Whole petroleum system and ordered distribution pattern of conventional and unconventional oil and gas reservoirs

Whole petroleum system and ordered distribution pattern of conventional and unconventional oil and gas reservoirs

Preparation and performance of pH-temperature responsive low-damage gel temporary plugging agent

Temporary plugging to fracturing has become the main production enhancement and transformation method for low-permeability, unconventional oil and gas reservoirs. In this paper, copolymers (PANA) were firstly prepared by free-radical aqueous solution polymerization with monomers acrylamide, N-vinylpyrrolidone, and 2-acrylamido-2-methylpropanesulfonic acid, and then gel temporary plugging agents (PJPs) were prepared using polyethyleneimine as cross-linker. The successful preparation of the target products was also demonstrated by using infrared and nuclear magnetic characterization. The results of rheological performance tests on PJPs show that they have good temperature and shear resistance. Validation experiments on the pH and temperature response performance of PJPs based on the visual code method and viscoelastic strength showed that PJPs could not be gelled at low temperature (<30 °C) and low pH (<7), thus proving that PJPs is controlled by both temperature and pH. Then the gelling mechanism of PJPs was investigated by characterizing the state of PJPs before and after gelling by SEM. The experiments to evaluate the temporary plugging performance of PJPs show that when the pH is 10 and the temperature is 120 ℃, the temporary plugging agent can completely seal the fracture with a repellent pressure of 2 MPa, and the final flow rate tends to 0 mL/min. The maximum breakthrough pressure reaches 12.6 MPa with a fixed repellent flow rate of 5 mL/min, which has good plugging pressure-bearing performance. Finally, the damage performance evaluation experiment of PJPs concluded that the permeability damage of fractured cores was below 13 %, thus indicating that PJPs have good protection performance for the reservoir.