Low Permeability Oil Reservoirs Research Articles

Key parameters and dominant EOR mechanism of CO2 miscible flooding applied in low-permeability oil reservoirs

CO2 miscible flooding is a prospective production method to enhance oil recovery (EOR), especially in low-permeability reservoirs. However, there is a lack of comprehensive and systematic understanding of the key parameters and dominant EOR mechanism of CO2 miscible flooding. In this work, the sensitivity of key parameters, such as oil viscosity, permeability, permeability ratio, and pressure, is analyzed by CO2 flooding physical simulation experiments. The adjuvants for CO2 miscible flooding of the Changqing crude oils are evaluated and optimized. The production performance of overpressure CO2 miscible flooding is studied by CO2 core flood test, and the oil micro-distribution before and after CO2 miscible flooding is characterized using nuclear magnetic resonance (NMR), and the micro EOR mechanism of CO2 miscible flooding is revealed. The results show that CO2 immiscible flooding is suitable for the development of low-viscosity crude oil (<50 mPa s), especially for oil viscosity of less than 10 mPa s. CO2 miscible flooding is advisable for low-permeability and medium and high-permeability reservoirs, especially for reservoir permeability of higher than 10 mD. Above the MMP, the oil recovery factor is over 85% and the increase rate slows down with pressure, CO2 miscible flooding is preferred for the high-pressure reservoir. CO2 miscible flooding is applicable for reservoirs with a permeability ratio of less than 2.5, especially for a permeability ratio of less than 2. Compared with 0.8 times MMP pure CO2 flooding, the time of gas channeling, and oil recovery for CO2 miscible flooding is delayed from 0.69 PV to 0.76 PV, and enhanced to 93.04% from 72.61%, respectively, with the help of adjuvants for CO2 miscible flooding, NP-9. The adjuvants for CO2 miscible flooding could effectively promote the realization of miscible flooding for CO2 and crude oils with an injection pressure of less than the MMP. CO2 has excellent oil displacement ability in low-permeability reservoirs, especially for miscible flooding, and the core oil saturation is obviously reduced. Overpressure CO2 miscible flooding could expand the swept volume and more efficiently displace oil in low-permeability reservoirs compared to an injection pressure of 1.0 times MMP. After overpressure CO2 miscible flooding, the residual oil in the low-permeability cores is distributed more evenly.

A numerical simulation investigation on low permeability reservoirs air flooding: Oxidation reaction models and factors

A precise oxidation reaction model determines the reliability of numerical simulation results and the prediction of field performance of air injection-based enhanced oil recovery (EOR). By reviewing the classical oxidation reaction model and combining with geological characteristics of a low permeability reservoir, this work creatively divides pseudo-components and temperature regions and further proposes the improved low temperature oxidation (LTO), middle temperature oxidation (MTO), and high temperature oxidation (HTO) numerical models with chemical reaction coefficients. The EOR effects of reservoir temperature, permeability, air flow rate and bottom hole pressure during LTO and full temperature regions are determined on the basis of a 3D reservoir simulation model via CMG STARS. The results show that peak oil production rates of N2 flooding and LTO are 17.70 and 29.97 m3/d, respectively. The cumulative oil production in LTO stage is about 35%, which is higher than that in N2 flooding. The oxygen addition reaction in LTO stage can release much heat and increase sweep efficiency from thermal expansion and viscosity reduction. The peak oil production rates of LTO and full temperature oxidation (FTO) reactions are 42.16 and 44.34 m3/d, respectively, and the cumulative oil production of the FTO model was about 17% higher than that of LTO. The FTO model could more truly reflect the production performance during air flooding of low permeability oil reservoir. Strong oxygen consumption capacity and significant heat release effects can be observed under higher initial temperature, permeability, air flow rate, and lower bottom hole pressure. Thermal flooding and flue gas flooding are the main EOR mechanisms in FTO process. Considering the inescapable field problem of gas channeling, thorough contact between oil and air can be promoted by artificially preheating oil reservoir and adjusting air injection rate and pressure. Thus, oil recovery can be further improved under the premise of ensuring the safety of field application of air flooding technique.

Experimental Investigation on the Imbibition Behavior of Nanofluids in the Tight Oil and Gas Reservoir through the Application of Nuclear Magnetic Resonance Method

Tight oil and gas resources are widely distributed and play an important role in the petroleum industry. Due to its nanoscale pore-throat characteristics, the capillary effect is remarkable, and spontaneous imbibition is very beneficial to the development of low-permeability reservoirs. In this study, the imbibition experiments of 2D nano blackcard, nanoemulsion, and water were carried out, respectively. The pore-throat fluid distribution characteristics before and after core imbibition were analyzed with nuclear magnetic resonance technology, and the enhanced oil recovery effects of 2D nano blackcard nanoemulsion, and water were comprehensively evaluated. The results show that the final recovery factors of cores soaked in 2D nano blackcard (0.005 ωt%) and nanoemulsion (0.02 ωt%) or imbibed in water are 32.29%, 26.05%, and 7.19%, respectively. It can be found that 2D nano blackcard is the fluid with the best imbibition effect. In this work, a new type of 2D nano blackcard was proposed and identified as a functional imbibition fluid for enhanced oil recovery in tight reservoirs, providing a practical reference for the effective development of tight, low-permeability oil and gas reservoirs.

Research on the viscosity‐increasing mechanism and performance analysis of modified polysaccharide natural polymer fracturing fluid gel

AbstractIn this paper, a guar gum‐based hydraulic fracturing fluid suitable for low permeability oil and gas reservoirs was prepared using alkylamine guar gum (J580) as a thickening agent. The viscosification mechanism and comprehensive properties were analyzed to provide theoretical support for improving the fracturing fluid utilization rate and oil and gas field development in Changqing Oilfield. In this experiment, the properties and microstructure of thickener J580 were analyzed by infrared spectroscopy (FT‐IR), nuclear magnetic resonance (1H‐NMR), X‐ray diffraction (XRD), and transmission electron microscope (TEM). The rheometer, dynamic filtration device, and acid erosion fracture conductive ability device were used to study the temperature and shear resistance performance, viscoelastic properties, dynamic filtration performance, and fracture conductive ability damage of the system. the gel breaking performance, formation water compatibility, and anti‐swelling performance of the system were measured according to the standard. The results show that J580 is an amine modified product of guar gum, and its viscosity increasing mechanism is similar to that of guar gum. The breaking time of the system is 375 s, the residue content is 413 mg/L, and the surface tension is 26.49 mN/m. At 90°C, the viscosity of the solution can be maintained at 180 mPa · s, loss modulus G" dominates, the anti‐swelling rate is 82.5%, the damage rate of the conductive ability is 22.40%, and the dynamic filtration coefficient is 1.3 × 10−5 m/s1/2. The fracturing fluid system has good dynamic filtration performance, conductive ability, temperature and shear resistance, good structural strength, can easily break glue and return, and less residue content.

Halotolerant Bacillus velezensis sustainably enhanced oil recovery of low permeability oil reservoirs by producing biosurfactant and modulating the oil microbiome

Low permeability oil reservoirs are widely distributed in China and rich in oil resources. Microbial enhanced oil recovery (MEOR) is a promising technology for low permeability oil reservoirs, but its application is limited by the harsh reservoir conditions. In this study, we demonstrated that halotolerant strain Bacillus velezensis BSA1 could produce biosurfactant and modulate oil microbiome for enhancing oil recovery in low permeability oil reservoirs. B. velezensis BSA1 could produce biosurfactant which comprised of surfactin and was stable in harsh environments. The MEOR column experiments showed that the oil recovered by B. velezensis BSA1 was 21.6 ± 1.87 %. We conducted successful field application in a low permeability reservoir and the cumulative oil production was more than 500 m3 with the effective period of 12 months. After monitoring of microbial community in the reservoir for a year, it showed that B. velezensis BSA1 promoted the abundance of surfactant-producing bacteria and hydrocarbon-degrading bacteria increasing. The enrichment of the functions of surfactant synthesis, hydrocarbon degradation, and methane gas production contributed to the enhancement of oil recovery. Overall, results of this study showed that using biosurfactant-producing and halotolerant B. velezensis BSA1 was a promising microbial strategy for sustainable MEOR of low permeability oil reservoir.

Injectability of Partially Hydrolyzed Polyacrylamide Solutions Improved by Anionic-Nonionic Surfactant in Medium and Low Permeability Reservoirs

Injectability of the polymer solution is a very important factor that determines the effectiveness of polymer flooding for enhanced oil recovery. Here, the medium and low permeability oil reservoir was taken as a research object, and effects of relative molecular weight, concentration and core permeability on the flow and injection performance of a partially hydrolyzed polyacrylamide (HPAM) solution with and without anionic-nonionic surfactant (ANS) were studied by indoor outcrop core physical model experiments. It was found that the influence of HPAM concentration on the flow performance was related to the core permeability. When the core permeability was lower than 59 mD, the resistance factor and residual resistance factor of HPAM increased with increasing the concentration. High molecular weight and low core permeability were not conducive to the injectability of HPAM solutions. The addition of ANS was beneficial in enhancing the injectability of HPAM solution by reducing the critical value of injectability of HPAM solution, which was elucidated by the Hall curve derivative method. In the presence of ANS, the flow pressure gradient and the residual resistance factor of the HPAM solution decreased. It is believed that the injectability of HPAM solution improved by ANS in the medium and low permeability reservoirs can be attributed to decrease in fluid viscosity and competitive adsorption on the surface of porous media. The study provides a new idea and theoretical basis for improving the injectability of an HPAM solution and the application of polymer flooding and a polymer/surfactant binary flooding system in medium and low permeability reservoirs.

Study and Application of Ultrafine Temperature-Resistant and Salt-Tolerant Swellable Particles in Low Permeability Reservoirs

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

Shifts in Bacterial and Archaeal Community Composition in Low-Permeability Oil Reservoirs by a Nutrient Stimulation for Enhancing Oil Recovery

Indigenous microbial enhanced oil recovery technology by selective nutrient injection is a potential alternative that leads to oil production improvement in low-permeability oil reservoirs. Nutrient flooding in oil reservoirs can shift the balance of microorganisms within a population; an in-depth exploration of this phenomenon can enable us to selectively activate particularly beneficial microbial species for enhancing oil recovery. In this study, high-throughput sequencing was employed to analyse indigenous microorganisms (e.g., archaea and bacteria) in an oil production well (W226), compared to a control well (W202), in the Xingzichuan Oil Recovery Plant (Ansai, Shaanxi, China). According to alpha diversity analysis and community composition, the nutrient injection exhibited a significant impact on indigenous archaea at the genus level. The predominant archaeal genus Methanolobus (more than 66%) in the control well shifted to Methanocalculus (50.8%) and Methanothermococcus (30.6%) genera in the oil production well. Conversely, the activators increased bacterial community richness but reduced its evenness. Bacterial community analysis at the genus level revealed that nutrient injections significantly increased specific populations with the potential to emulsify, lower interfacial tension, and lower oil viscosity, including the genera Arcobacter, Halomonas, and Thalassolituus. At the same time, some microbial species that are harmful for the oil recovery process (e.g., the sulphate-reducing bacteria Desulfovibrus, Desulfocurvus, Desulfocarbo, and Desulfoglaeba), were inhibited. In conclusion, nutrient flooding reduced the abundance of harmful microorganisms and increased beneficial functional microbial populations linked to beneficial functions, contributing to the enhancement of oil recovery in low-permeability oil reservoirs.

Experimental investigation of zwitterionic surfactant-based silica nanofluid spontaneous imbibition at high salinity and elevated temperature conditions

High-efficiency development of low permeability reservoirs is significant to maintaining a balance between energy supply and social needs. Surfactant-based nanofluids with an excellent interfacial activity that can penetrate the small throats and narrow pores are considered promising EOR agents. However, the applications of nanofluids in harsh reservoir conditions remain to be challenging due to high stability requirements. In this work, a highly stable active nanofluid that could withstand high salinity (API brine) and elevated temperatures was prepared by mixing zwitterionic hydroxypropyl sulfobetaine surfactant with low-molecular-weight ligand modified silica nanoparticles. At a surfactant/nanoparticle concentration ratio of 0.5, the spontaneous imbibition recovery factor of dodecyl hydroxypropyl sulfobetaine-based nanofluid was 2.61 times higher than API brine, 1.29 times higher than API brine-based nanofluid and 0.37 times higher than surfactant alone. Meanwhile, the impacts of surfactant carbon chain length, permeability as well as hydrochloric acid were included. Experimental results indicated that surfactants with longer carbon chain length would destabilize the nanofluids due to increasing hydrophobic interactions, and nanoparticle aggregation/precipitation would impose adverse impacts on spontaneous imbibition because of pore/throat plugging. Though increasing permeability could partially ease the negative plugging effects, the potential risks should never be overlooked. Properly using hydrochloric acid could greatly enhance the stability of nanoparticles by forming an “H+” protection layer and extend their applications to over 80 °C, but the presence of acid also disturbed the adsorption behaviors of surfactants, therefore, different phenomena were noticed when the nanofluid formula changed. A good spontaneous imbibition system should possess both IFT reduction and wettability alteration capabilities, and nanoparticles’ ability to adsorb and disperse polar compounds such as asphaltene should be fully fulfilled. This study provides new guidance for nanofluid formulation to support the effective development of low-permeability oil reservoirs.

A New Method to Calculate the Relative Permeability of Oil and Water in Tight Oil Reservoirs by Considering the Nonlinear Flow

The theoretical research on the percolation mechanism and oil-water relative permeability of low-permeability oil reservoirs is the focus and hotspot of international researchers. Oil-water relative permeability is an important parameter that describes the characteristics of oil-water two-phase flow and is widely used in the dynamic analysis of development and numerical simulation technology in the reservoir. The traditional calculation method of oil-water relative permeability (i.e., the JBN method) is based on the Darcy flow law. When the velocity and the displacement pressure gradient do not follow the linear flow law, there are some errors in the results of oil-water relative permeability calculated by the JBN method. In this paper, the traditional JBN method is improved, and we establish a new processing method of experimental data for oil-water relative permeability considering the effects of nonlinear flow, capillary pressure, and gravity in tight oil reservoirs. The experiments on the flow characteristics of single-phase oil and oil-water relative permeability under nonsteady-state conditions were carried out. The flow velocity and displacement pressure gradient show nonlinear characteristics when single-phase oil is passed through a tight core. At the same time, when the air permeability decreases from 1.92 × 10 − 3 μ m 2 to 0.1 × 10 − 3 μ m 2 , the nonlinear characteristics are becoming more and more obvious. Compared with the traditional JBN method, when the nonlinear flow characteristics are considered, the oil phase relative permeability increases, and the water phase relative permeability is slightly lower. If nonlinear flow characteristics are considered, when the water saturation increases from 0.605 to 0.699, the difference of oil phase relative permeability calculated by the JBN method and this method is gradually decreasing and, with the increase of water saturation, decreases from 0.0029 to 0.0001. In addition, the effects of capillary pressure, gravity, and the nonlinear flow coefficient on the oil-water relative permeability in tight oil reservoirs are studied. The capillary pressure also has a great influence on the relative permeability of the oil phase, and the relative permeability of the oil phase increases with the increase in capillary pressure. In the development process of the low-permeability reservoir, the seepage characteristics of each flow area are different, and the oil-water relative permeability is also different. Therefore, the research results play an important role in guiding the understanding of seepage characteristics of low permeability of tight oil reservoirs.

Synthesis and evaluation of depressurization and injection treatment agent suitable for low-permeability reservoirs

In this paper, a microemulsion polymerization method is used to synthesize a depressurization and injection treatment agent suitable for low-permeability oil reservoirs using decofluoroheptyl methacrylate (DFMA)/Butyl acrylate (BA)/methyl methacrylate (MMA) as monomers. The agent can be adsorbed on the rock surface to form a nano-film, which can change the micro-nano structure and surface chemical composition of the rock surface, and make the rock surface from hydrophilic/lipophilic to hydrophobic and oleophobic. The experimental results show that the agent is successfully synthesized and has excellent properties. And the agent have broad application prospects in reducing injection pressure, increasing injection volume, and enhancing oil recovery.

Experimental Study of Oil Displacement and Gas Channeling during CO2 Flooding in Ultra—Low Permeability Oil Reservoir

Aiming to solve the problems of poor CO2 displacement efficiency and serious gas-channeling and low well-opening rates in ultra-low permeability reservoirs, we carry out CO2 displacement experiments under different permeability reservoirs by using different development methods, water drive to gas drive procedures, and different fracture positions to clarify the effects of physical formation properties, injection methods, and fracture parameters on CO2 displacement efficiency in C8 ultra-low permeability reservoirs. The experimental results show that the recovery degree of CO2 miscible drive increases with an increase in permeability. When the gas–oil ratio is greater than 2000 m3/m3, serious gas channeling can be observed in both the miscible drive and immiscible drive. In addition, when the water drive is altered to be a gas drive, the water cut of 0.45 mD and 0.98 mD cores decreased, and the recovery degree increased by 13.4% and 16.57%, respectively. A long fracture length will deteriorate gas channeling and lower the CO2 oil-displacement efficiency. However, the fracture location is found to have little impact on the recovery of CO2 displacement.

Prediction of reservoir key parameters in ‘sweet spot’ on the basis of particle swarm optimization to TCN-LSTM network

In oil reservoirs, the sweet spot is found that the well could be positioned quickly and accurately, the drilling rate and the oil-gas production are increased, development cost is reduced. Among them, sorting, granularity and porosity are important factors to evaluate whether the exploration area is a sweet spot. A low permeability oil reservoir is taken as the research object, this paper mainly focuses on the prediction of the above evaluation parameters. In order to solve this problem, this paper proposed a new deep learning hybrid model. The model is constructed based on temporal convolutional network (TCN) and long short-term memory network (LSTM). Firstly, the influence of logging parameters on the prediction of evaluation indexes is analyzed. Secondly, the model is used to predict the screened sequence data. In the process of model construction, particle swarm optimization (PSO) is used to optimize the global hyperparameters, and finally the prediction model is obtained. The model is compared with TCN algorithm, traditional machine learning and empirical formula. This model improves the prediction accuracy of reservoir evaluation parameters in low permeability oilfield.

Investigation on the microscopic damage mechanism of fracturing fluids to low-permeability sandstone oil reservoir by nuclear magnetic resonance

Hydraulic fracturing has become an essential stimulation treatment for improving the development efficiency of low-permeability oil reservoirs. However, fracturing fluid inevitably causes reservoir damage. This study proposed a combined method of microscopic and macroscopic experiments to investigate the nature of formation damage of fracturing fluid by quantifying its influence on porosity, permeability, and pore structure. Nuclear magnetic resonance technology combined with core flooding test and parallel sample comparison method was applied to quantitatively evaluate the damage degree and identify the main damage types of hydroxypropyl guar (HPG) fracturing fluid and slickwater fracturing fluid. The microscopic damage mechanisms of these fracturing fluids were analyzed by thin section petrography, X-ray diffraction, rate-controlled mercury intrusion, scanning electron microscopy, and wettability tests. The results show that the total permeability damage degree of HPG fracturing fluid filtrate is 30.43%, of which water sensitivity, water lock, and macromolecule adsorption account for 6.06%, 23.26%, and 1.11%, respectively. Water lock is the major damage factor. Regarding the damage of slickwater fracturing fluid filtrate, water sensitivity causes the severest damage, corresponding to 39.08% of core permeability loss, whereas macromolecule adsorption and water lock contribute 13.21% and 0.97%, respectively. Water sensitivity damage causes reduced porosity, decreased permeability, and narrower pores, resulting from hydration, swelling, dispersion and migration of clay minerals. Water lock damage increases the movable pore volume, decreases the permeability, increases the pore radius, decreases the throat radius, and increases the pore throat ratio, which increases the flow resistance to the oil phase. The magnitude of water lock damage is closely related to the surfactant content and performance, rock wettability, and pore throat radius ratio. Macromolecule adsorption damage leads to a decrease in permeability, a reduction in the number of large pores, an increase in the number of small throats, and an increase in the pore throat radius ratio due to the absorption and retention of macromolecules on the surfaces of the pores and throats. Increasing the flowback volume of slickwater fracturing fluid can recover part of the macromolecule absorption damage. This research can provide a reliable reference for the optimization of fracturing fluid performance, enhancement of the fracturing effect and reservoir protection of low-permeability reservoirs.

Study of Water Huff-n-Puff in Low-Permeability Oil Reservoirs With Horizontal Fractures: A Case Study of Chang 6 Reservoir in Yanchang, China

Water huff-n-puff is an effective technology to enhance oil recovery (EOR) of low-permeability reservoirs, which are usually developed with hydraulic fracturing. Fluid exchange between fractures and the matrix is the main EOR mechanism. However, the presented water huff-n-puff simulations usually assume vertical fracture morphology, while the horizontal fractures formed in shallow reservoirs are rarely reported. In this study, we first introduced the water huff-n-puff process in a low-permeability oil reservoir with horizontal fractures and described the multiphase flow characteristics during the huff, soak, and puff stages. Then combined with a series of experiments, a comprehensive method is used to determine the key flow parameters, that is, capillary pressure and relative permeability. Finally, using the Chang 6 reservoir as an example, a series of numerical simulations were conducted to demonstrate the effect of water huff-n-puff on the well performance in this field. The simulation results showed that oil production is mainly affected by the injection volume and injection rate, while water production mainly depends on the well shut-in time. For a typical well in this field, the optimal injection volume, injection rate, and well shut-in time are 300 m3, 10 m3/d, and 30 days, respectively. In addition, our results showed that increasing the number of cycles not only benefits fluid exchange but also enhances the formation pressure. Both of them can accelerate the development of low-permeability oil reservoirs.

Research on Exploration System of Petroleum Geological Development Based on Oilfield Fracturing Technology

Oil and gas energy is one of the necessary energy sources for social development. In the process of oil development and exploration, hydraulic fracturing technology plays a vital role. Hydraulic fracturing technology can not only stabilize the production of conventional oil and gas fields, realize the development of low-permeability oil and gas reservoirs, help the development and adjustment of old oil fields, but also increase the development production of special oil reservoirs and tap the potential of oil and gas fields. In this paper, an electrical simulation experiment method for the productivity of horizontal well staged fracturing is studied. Firstly, according to the actual formation conditions after staged fracturing of horizontal wells, a set of three-dimensional electric field simulation device is simulated and developed; According to the wellbore trajectory, formation permeability and formation thickness, etc., the electrolyte and electrolytic cell size for electrical simulation are set. Finally, the current signal is collected to determine the size of the production capacity. Using this experimental method, we carried out the optimization simulation of horizontal well fracturing fracture shape and location, optimization simulation of fracture number and spacing, and comparison of different formation thicknesses for a fluvial facies sedimentary sand body. This electrical simulation experiment method can accurately simulate the influence of various parameters of horizontal well fracturing and completion on productivity, and has certain guiding significance for the design of horizontal well fracturing and completion.

Semianalytical model of complex fracture growth in vertical wells based on boundary element theory

The recent developments in low-permeability oil and gas reservoir mining technology have led to the application of various forms of well fracturing models to determine the physical formation parameters and flow laws in porous media. However, most related studies have been aimed at conducting a pressure transient analysis after the formation of fractures, ignoring the pressure change characteristics during fracture formation. In this study, a fracture growth model based on vertical fractured wells was established and solved using the source function theory and boundary element method. The rationality of the model calculation method was verified by the superposition principle. The pressure change laws before and after fracture growth were analyzed, and the model was subjected to hydraulic fracturing experiments. The results showed that with the increase in the local pressure at the bottom of the well, main fractures, branch fractures, and microfractures were generated in three stages. When the fracture was formed, the pressure and pressure derivative curves fluctuated but gradually returned to a stable state under the fracture shape with the extension of the flow time. Moreover, from the main fracture to the microfracture stage, the pressure recovery time period was gradually shortened. The fitting results of the analysis model and fracturing experiment were found to be accurate, providing a theoretical support for analyzing the transient pressure changes during the formation of complex fractures. The different curve characteristics also provide a new reference basis for evaluating the fracture propagation behavior and predicting the fracture conductivity.

Analysis of low permeability reservoir development technology

As an important energy source for social production and development, oil is non-renewable. In the process of development and utilization, attention should be paid to continuously improve the exploitation technology, enhance the ability of oil exploration, and strengthen the development of low permeability reservoir resources, so as to provide sufficient oil resources for social production and development. However, low permeability reservoir resources have their own characteristics and are limited by multiple factors in the process of exploitation. It is difficult to improve the exploitation efficiency of low permeability reservoir resources without adopting corresponding exploitation technology. This it is scientific and reasonable exploitation of low permeability oil reservoir resources technology are analyzed and discussed, in the comprehensive analysis based on the characteristics of low permeability oil reservoirs, mining characteristics, puts forward the well pattern optimization, waterflood recovery, fracturing technology and mining method, working for the effective implementation of the low permeability reservoir development provides the technical support, also need to continue well technology application in the construction process in the future.

Fabrication of a Spontaneous Emulsification System for Low-Permeable Oil Reservoirs and Study of an Enhanced Oil Recovery Mechanism Based on the Nuclear Magnetic Resonance Method

An emulsifier that can spontaneously emulsify oil by a gentle disturbance is an ideal displacement agent for enhanced oil recovery (EOR) in low-permeability reservoirs. Herein, a novel spontaneous emulsification (SE) system with a low concentration of alkali was fabricated in this work. An optimum SE system was screened by interfacial tension (IFT) measurement; the diameter distribution and microscopic morphology of emulsions were observed by an optical microscope and multiple light scattering; the EOR mechanism was studied by nuclear magnetic resonance (NMR) and magnetic resonance imaging (MRI); and the applicability of the SE system in heterogeneous reservoirs was further explored by parallel-core flooding tests. The result showed that the ion pairs formed as a result of the electrostatic attraction of surfactant head groups between cetyltrimethylammonium bromide (CTAB) and nonylphenol polyoxyethylene ether carboxylate (SS-231), which caused the IFT of the CTAB/SS-231 system to reach the ultralow level. The synergistic effect between alkali and surfactants occurred by adding only 0.1 wt % NaOH, which greatly enhanced the capability of emulsification. As a result, the IFT of the SE system (0.4 wt % CTAB/SS-231 + 0.1 wt % NaOH, with massCTAB/massSS-231 = 3:7) could reach 2.1 × 10–3 mN/m, and the SE system could emulsify the crude oil by inverting once. The crude oil in small pores and throats could be displaced by the SE system because the in situ emulsions formed by the SE system were small enough to flow through the small pores; therefore, they exhibited a higher EOR efficiency than the weak emulsification (WE) system. In addition, the SE system showed stronger capabilities in conformance control as a result of the deformation and migration of emulsions. This work revealed the EOR mechanism of the SE system from the level of the pore structure using NMR and MRI, which is important for evaluating the production efficiency of low-permeability reservoirs. Furthermore, the low concentration of alkali (0.1%) in the SE system avoids the scale formation of low-permeability reservoirs effectively.

Enhancing Oil Recovery from Low-Permeability Reservoirs with a Thermoviscosifying Water-Soluble Polymer.

Water-soluble polymers, mainly partially hydrolyzed polyacrylamide (HPAM), have been used in the enhanced oil recovery (EOR) process. However, the poor salt tolerance, weak thermal stability and unsatisfactory injectivity impede its use in low-permeability hostile oil reservoirs. Here, we examined the adaptivity of a thermoviscosifying polymer (TVP) in comparison with HPAM for chemical EOR under simulated conditions (45 °C, 4500 mg/L salinity containing 65 mg/L Ca2+ and Mg2+) of low-permeability oil reservoirs in Daqing Oilfield. The results show that the viscosity of the 0.1% TVP solution can reach 48 mPa·s, six times that of HPAM. After 90 days of thermal aging at 45 °C, the TVP solution had 71% viscosity retention, 18% higher than that of the HPAM solution. While both polymer solutions could smoothly propagate in porous media, with permeability of around 100 milliDarcy, TVP exhibited stronger mobility reduction and permeability reduction than HPAM. After 0.7 pore volume of 0.1% polymer solution was injected, TVP achieved an incremental oil recovery factor of 13.64% after water flooding, 3.54% higher than that of HPAM under identical conditions. All these results demonstrate that TVP has great potential to be used in low-permeability oil reservoirs for chemical EOR.