Development Of Low Permeability Reservoirs Research Articles

Preparation and Effect of CO2 Response Gel for Plugging Low-Permeability Reservoirs.

In order to solve the problem of gas channeling during CO2 flooding in low-permeability reservoirs, a novel CO2 responsive gel channeling system was prepared by using carrageenan, branched polyethylene imide and ethylenediamine under laboratory conditions. Based on the Box-Behnken response surface design method, the optimal synthesis concentration of the system was 0.5 wt% carrageenan, 2.5 wt% branchized polyethylenimide and 6.5 wt% ethylenediamine. The micromorphology of the system before and after response was characterized by scanning electron microscopy. The rheology and dehydration rate were tested under different conditions. The channeling performance and enhanced oil recovery effect of the gel system were simulated by a core displacement experiment. The experimental results show that the internal structure of the system changes from a disordered, smooth and loosely separated lamellae structure to a more uniform, complete and orderly three-dimensional network structure after exposure to CO2. The viscosity of the system was similar to aqueous solution before contact with CO2 and showed viscoelastic solid properties after contact with CO2. The experiment employing dehydration rates at different temperatures showed that the internal structure of the gel would change at a high temperature, but the gel system had a certain self-healing ability. The results of the displacement experiment show that the plugging rate of the gel system is stable at 85.32% after CO2 contact, and the recovery rate is increased by 17.06%, which provides an important guide for the development of low-permeability reservoirs.

The controlling effect of sedimentary characteristics on the heterogeneity of the Chang 6 reservoir in the Wuliwan area

The sedimentary system of the delta front is complex. The hydrodynamic conditions, changes in sediment supply, and mineral composition are crucial factors that influence the quality of reservoirs. Reservoir quality varies among different sedimentary units. In this field of research, there is a general tendency to mainly use core data and logging curves for reservoir characterization and prediction, while neglecting the combination with the microscopic scale of the reservoir. This article proposes a new method to characterize reservoir heterogeneity by studying the sedimentary characteristics of reservoirs. This method uses casting thin-section data to aid in core and logging research. This study consists of five parts: core analysis, casting thin-section study, logging facies study, geological analysis, and single-well prediction. Combining macroscopic and microscopic methods helps clarify the controlling effect of sedimentary characteristics on reservoir heterogeneity. The research results indicate that this research method effectively solves the challenge of characterizing reservoir heterogeneity in the middle and later stages of development of low-permeability reservoirs. The research outputs serve as valuable references for the advancement of analytical matching fields.

Quantitative characterization of imbibition in fractured porous media based on fractal theory

In low-permeability reservoirs, such as shale and tight sandstone, imbibition is an important mechanism for enhancing oil recovery. After hydraulic fracturing treatment, these reservoirs create a network of fracture pathways for fluid flow. Therefore, understanding the imbibition mechanisms in fractured porous media and quantitatively characterizing oil–water distribution are crucial for the development of low-permeability reservoirs. In this study, a mathematical model of two-phase flow in porous media with branching fractures was established. The phase-field method was employed to track the oil–water interface, and quantitative characterization of imbibition was conducted based on fractal theory, and the effects of wetting phase injection rate, the number of disconnected fractures, fracture spacing, and fracture morphology on imbibition in branched fracture porous media were discussed. The research findings indicate that in branched fracture porous media, both co-current and countercurrent imbibition processes occur simultaneously, and there exists a diffusion interface layer with a certain thickness at the oil–water interface. The hydraulic pressure generated by the wetting phase injection rate provides the driving force for imbibition oil recovery, but it also affects the contact time between the wetting and non-wetting phases. The presence of disconnected fractures hinders the propagation of hydraulic pressure, reducing the effectiveness of imbibition. The imbibition displacement zone is limited and occurs only within a certain range near the fractures. As the number of branching fractures increases, the channels for the wetting phase to enter matrix pores are enhanced, resulting in higher efficiency of imbibition displacement of the oil phase. The results of this research can provide guidance for the design of fracturing programs and recovery prediction in low-permeability reservoirs.

A cationic type long-lasting drag-reduction agent based on reduced interfacial water film thickness for enhanced injection in low-permeability reservoirs

In water injection development of low-permeability reservoirs, the elevated flow resistance between the rock surface and the injected water results in enhanced injection pressure. Reducing the thickness of interfacial water film to expand flow radius is a new thought to achieve a decrease in injection pressure. In this work, a hydroxyl-containing cationic surfactant tetradecyl methyl dihydroxy-ethyl ammonium bromide (HTTAB) was designed and synthesized. The introduction of hydroxyl groups enhances the binding to the negatively-charged rock surface. HTTAB can modify the strong hydrophilic rock surface to a hydrophobic state, with the water contact angle increasing from 20.2° to 110.3°. HTTAB shows excellent drag-reducing effect, maintaining a drag reduction rate of over 30 % even after 30 PV of flushing. Particle Image Velocimetry (PIV) experiments show that after HTTAB adsorption, the interfacial slip velocity and centerline velocity can increase by 1.67 times and 33.66 % respectively, and the flow radius expands significantly. In addition, the thickness of the interfacial water film is obtained using Atomic Force Microscope (AFM). The results show that the thickness of the interfacial water film is reduced significantly from 79.42 nm to 8.85 nm. This study provides important guidance for the design of drag-reducing agents and the understanding of interfacial drag-reduction behavior.

Numerical Simulation and Parameter Optimization for Water-to-CO2 Flooding in a Strongly Water-Sensitive Reservoir.

Carbon dioxide flooding can accelerate the development of low-permeability reservoirs of the Kexia group in the K region of the T oil field, thus resolving the issue of inadequate water drive effects. This study was focused on the well group 80513 in the K region, and based on the reservoir and fluid parameters, a simulation model of water-sensitive post-CO2 flooding was constructed to refine the gas injection strategy gradually. The injection rate of the continuous gas injection stage was preferred based on the degree of recovery. Multiindicator and multifactor injection and extraction schemes were established to optimize and analyze the key controlling factors, including the gas injection rate, gas injection period, gas-to-water ratio, and bottom-hole flow pressure, in the carbon dioxide gas-to-water alternation process. Recovery efficiency, oil exchange rate, formation pressure, and carbon dioxide storage rate were used as indicators. After 5 years of continuous CO2 flooding, the results indicated that switching to CO2 gas-water alternating flooding was more appropriate for the target block's environment. The best development plan was achieved when the gas injection rates were 1.0 and 1.25 × 104 m3·d-1 for continuous gas injection and CO2 gas-water alternating flooding, respectively, with a gas-water ratio of 1:1, a gas injection cycle of 90 days, and a bottom-hole flow pressure of 25 MPa in the production wells. A comparison between the results revealed that the formation pressure and oil recovery efficiency of this well group significantly increased upon CO2 flooding, and the parameter optimization results were well suited for controlling the gas flurry, offering a versatile model for future development of the block.

Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir

Summary Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.

Low-permeability reservoirs flooding using horizontal wells

For the first time in the practice of horizontal well flooding the study investigates the influence of horizontal well length, number of stages, and proppant loading on productivity during hydraulic development of low-permeability reservoirs using horizontal wells. To increase the sweep efficiency in systems with horizontal wells, a new development systems configuration is proposed, relying on longitudinal horizontal production wells and transverse horizontal injection wells with respect to the regional stress direction. The use of this configuration will not only increase the efficiency of reservoir pressure maintenance systems, but also reduce capital costs for well construction by reducing the injection wells to production wells ratio per development unit while maintaining system stiffness. Keywords: horizontal injection well; Auto-HF fracture; low-permeability reservoir; reservoir pressure maintenance system; oil recovery ratio increasing

Preparation of Preformed Submicron Crosslinked Polymer Coils for Conformance Control in Low-Permeability Reservoirs.

With the increasing development of low-permeability reservoirs, the significance of conformance control treatment has risen considerably. To address the conflict between injectability and plugging performance, as well as to enhance the deep migration capacity of conformance control agents, preformed submicron crosslinked polymer coils (SCPCs) have been manufactured using aqueous solution dispersion polymerization. Fourier transform infrared and scanning electron microscopy were employed to examine the chemical structure and micromorphology, while particle size distribution, zeta potential, rheological, and filtration properties were analyzed. The effectiveness of conformance control was confirmed through the parallel core displacement. The effective particle size of SCPCs was at a submicron level (500~800 nm). SCPCs exhibit a transitional threshold concentration between gel and sol states (0.25 wt%~0.5 wt%). SCPCs can efficiently block the 1.2 μm microporous filter membrane. The filtration time is up to 67.8 min. SCPCs can improve the water absorption rate of lower permeability cores from 21.21% to 57.89% with a permeability difference of 5. Therefore, SCPCs have good injectability, plugging performance, and deep migration capacity and can be used for conformance control in low-permeability reservoirs.

Numerical Simulation Study of Pressure-Driven Water Injection and Optimization Development Schemes for Low-Permeability Reservoirs in the G Block of Daqing Oilfield

Pressure-driven water injection technology shows significant potential in addressing the key challenges of low-permeability oil reservoirs, improving water flooding development efficiency. Grounded in FDEM theory, this study establishes fluid matrix constitutive equations and employs FDEM to resolve rock stress–strain fields. A numerical simulation method for pressure-driven water injection in low-permeability reservoirs is developed to study the impact of different well pattern densities. The results indicate that the 90° horizontal well pattern using the five-spot method yields optimal outcomes, with approximately 32.32% higher cumulative liquid production than vertical well patterns. The 45° horizontal well pattern with the reversed nine-spot method also performs well, with about 30% higher cumulative liquid production than single-row vertical wells. Pressure-driven water injection improves matrix oil–water permeability and expands water flooding coverage. Based on the pressure gradient distribution driven by different well patterns, an evaluation method for the inter-well utilization capacity and its effectiveness was established. This method quantitatively assesses the reservoir depletion under various horizontal well encryption schemes. For research on timing of water injection in pressure-driven water flooding. Compared to pressure-driven water injection after 90 days, there is increased cumulative oil production after 40 days, emphasizing the importance of early pressure maintenance for higher cumulative oil production and enhanced recovery rates in low-permeability reservoir development. These findings provide crucial theoretical and practical support.

Study on the main factors and mechanism of functional silica nanofluid spontaneous imbibition for enhanced oil recovery

Nanofluids have shown great potential as chemical additives for enhanced oil recovery in low-permeability reservoirs owing to their unique properties. However, their application in harsh reservoir conditions poses challenges due to the demanding stability requirements. In this work, the functional silica nanofluid capable of withstanding high salinity and elevated temperature was prepared by blending 0.1 wt% hydrophilic silica sol with the 0.1 wt% modifier lauramidopropyl hydroxy sulfobetaine. Multiple experiments of the nanofluid were conducted, encompassing characterization, interfacial tension (IFT) and contact angle measurements. The nanoparticles had an average size of approximately 17 nm, and the nanofluid exhibited excellent stability, interfacial activity and wettability alteration ability. Spontaneous imbibition tests demonstrated that the nanofluid achieved a remarkable recovery of 35.30 %, compared with only 5.53 % for simulated formation water. Subsequently, the relationship between spontaneous imbibition recovery and factors, such as temperature, salinity and core permeability, was investigated. The influence weight for each factor on the recovery is as follows: temperature (64.61 %) > core permeability (19.07 %) > salinity (16.32 %). Furthermore, a comprehensive description of the spontaneous imbibition mechanism of nanofluids was provided, incorporating insights from 1HNMR results. We expect that this study can offer valuable insights into nanofluid formulation, supporting the efficient development of low-permeability reservoirs and provide a theoretical basis for field applications.

PROBLEMS OF EVALUATION OF THE EFFICIENCY OF THE STIMULATION OF LOW-PERMEABILITY RESERVOIRS OF HYDROCARBONS

The article discusses the conditions for the formation of hydrocarbon deposits and their changes during the development of lowpermeability reservoirs, as well as the most effective technologies for developing deposits of this type, which help increase the coverage of residual hydrocarbon reserves. Low-permeability reservoirs are susceptible to foreign fluid damage, so it is necessary to continuously reduce damage throughout the fracturing process through the use of optimized fluid systems and process parameters. The most effective technologies are: the use of horizontal wells with multi-stage hydraulic fracturing, which ensures the largest volume of hydrocarbon recovery at the initial stage, the use of multilateral wells with branched horizontal ends when it is impossible to use multi-stage hydraulic fracturing. To increase the connectivity of flow channels and provide increased hydrocarbon production, the multi-stage hydraulic fracturing process damages low-permeability reservoirs. The fracture extends in height and length over tens of meters and, thanks to this, can provide hydrodynamic connection to formation zones remote from the perforation interval. Thus, the need for well research methods that are capable of recording formation performance regardless of the position of the secondary opening (perforation) interval is relevant

Preparation and Performance Evaluation of Quaternary Ammonium Cationic Clay Stabilizer for Oilfield Use

Acidizing is a crucial technique in the development of low permeability reservoirs in offshore oil fields. The introduction of acid into the formation can lead to the degradation of the clay mineral structure, causing the expansion and migration of clay particles that obstruct the flow of acid channels. The addition of a clay stabilizer with excellent properties can prevent the hydration and expansion of clay, as well as recover damage caused by long-term acidification, such as expansion, dispersion, and migration. To achieve this, the dendritic quaternary ammonium salt ZS-A was synthesized through a quaternization reaction, and subsequently used to develop the clay stabilizer ZSFP. In this study, the properties of clay stabilizer were investigated, including anti-swelling, acid and alkali resistance, water washing resistance, mudstone loss rate, and permeability retention. The results demonstrate that the ZSFP clay stabilizer performs well in terms of anti-swelling, acid-base compatibility, water washing resistance. This clay stabilizer can effectively reduce water-sensitive damage to the reservoir and protect it during acidizing operations.

Optimization Study of Injection-Production Parameters for CO2 Enhanced Oil Recovery and Storage in Low Permeability Oil Reservoirs

To address the difficulty of water injection in the late stage of developing a certain low-permeability reservoir, CO2 injection and fracturing parameter optimization were conducted. The Latin hypercube sampling and numerical simulation methods were used to study the five-spot well network model established, and evaluate the impact of injection and fracturing parameters on oil recovery and CO2 storage using a comprehensive evaluation factor of oil displacement and storage. The results show that the injection rate is the main controlling factor affecting the oil recovery and storage effect, and the optimal injection rate is 6000m3/d. There is a certain contradiction between the oil recovery and storage objectives at different stages of injection development, but after ten years of injection development, the objectives of oil recovery and storage are consistent. The optimal combination of ijection and fracturing parameters yields a recovery rate of 72.54% and a CO2 storage amount of 101635.81 tons. This paper proposes that there is a certain contradiction between the oil recovery and storage objectives at different stages and evaluates schemes with different injection development periods by constructing a comprehensive evaluation factor for oil displacement and storage, which has certain reference value for optimizing parameters in the CO2 injection development of low-permeability reservoirs.

Investigation of Polymer-Assisted CO2 Flooding to Enhance Oil Recovery in Low-Permeability Reservoirs.

CO2 flooding is a favorable technical means for the efficient development of low-permeability reservoirs, and it can also contribute to the realization of net-zero CO2 emissions. However, due to the unfavorable viscosity ratio and gravity overriding effect, CO2 channeling will inevitably occur, seriously affecting its storage and displacement effects. This paper conducts a systematic study on the application of polymer-assisted CO2 flooding in low-permeability reservoirs. Firstly, the polymer agent suitable for low-permeability reservoirs is optimized through the viscosity-increasing, rheological, and temperature- and salt-resistant properties of the solution. Then, the injectivity performance, resistance-increasing ability, and profile-improving effect of the polymer solution were evaluated through core experiments, and the optimum concentration was optimized. Finally, the enhanced oil recovery (EOR) effects of polymer-assisted and water-assisted CO2 flooding were compared. The results show that the temperature-resistant polymer surfactant (TRPS) has a certain viscosity-increasing performance, good temperature resistance performance, and can react with CO2 to increase the solution viscosity significantly. Meanwhile, TRPS has good injection performance and resistance-increasing effect. The resistance increasing factor (η and η') of TRPS-assisted CO2 flooding increases with increased permeability, the concentration of TRPS solution, and injection rounds. Considering η' and the profile improvement effect comprehensively, the application concentration of TRPS should be 1000 mg/L. The EOR effect of TRPS-assisted CO2 flooding is 8.21% higher than that of water-assisted CO2 flooding. The main effective period is in the first and second rounds, and the best injection round is three. The research content of this paper can provide data support for the field application of polymer-assisted CO2 flooding in low-permeability reservoirs.

Optimizing tight oil extraction from low permeability tight reservoirs: a study on stress sensitivity effects and applications in carbon capture, utilization, and storage

This paper takes into consideration the impact of stress sensitivity on bioenergy production from low permeability tight reservoirs, focusing on the post-fracturing phase. This paper established a trilinear flow model that effectively takes into account the dynamics of such reservoirs. This model incorporates stress sensitivity parameters and uses the perturbation transformation and Laplace transformation to solve the productivity prediction formula. The final productivity prediction curve post-fracturing is achieved through a numerical inversion method. This study shows that the stress sensitivity effect significantly diminishes the productivity of fractured horizontal wells used in bioenergy extraction. By introducing stress sensitivity effect parameters, this paper manages to uncover the influence law of mobility and artificial fracture parameters on productivity. Notably, as the reservoir mobility increases, the cumulative bioenergy production from fractured horizontal wells improves significantly. In addition to the above, this paper also scrutinizes the sensitivity of artificial fracture parameters and optimize both the quantity and length of these fractures. This plays a crucial role in enhancing the productivity and efficiency of bioenergy extraction from these tight reservoirs. The applicability and reliability of this method are extensively tested, thereby establishing its potential in guiding the development of low permeability reservoirs post-fracturing. Importantly, this research sets the groundwork for combining bioenergy production with Carbon Capture, Utilization, and Storage (CCUS) technologies. By focusing on optimization and stress management in tight reservoirs, this paper contributes to the sustainable production of bioenergy and reduce carbon emissions, moving a step closer to a cleaner and sustainable future.

Performance Evaluation and Formation Mechanism of Viscoelastic Surfactant Fracturing Fluids with Moderate Interfacial Activity Enhanced by Janus-SiO2 Nanoparticles.

Nanoparticles (NPs) exhibit great potential to improve various properties of viscoelastic surfactant (VES) fracturing fluids in the development of low-permeability reservoirs. In the present study, the amphiphilic Janus NPs (JANPs) were fabricated via the Pickering emulsion method and employed to construct the novel JA12C (JANPs with dodecyl hydrophobic carbon chains)-assisted VES fracturing fluid (JAVES). The successful fabrication of JANPs was confirmed via Fourier transform infrared spectroscopy (FTIR) measurements and water contact angle tests. The rheology behavior of the VES fracturing fluid incorporating various SiO2 NPs including hydrophilic SiO2 NPs (HLNPs), JA8C (JANPs with octyl hydrophobic carbon chains), and JA12C was systematically investigated. It was revealed that the additional JA12C significantly improved the tolerance and proppant suspension properties. To explore the subsequent oil recovery performance of various gel breaking liquids, the formation wettability and the oil-water interfacial tension (IFT) were studied after the evaluation of breaking properties and formation damage properties of various fracturing fluids. The results suggested that the JAVES gel breaking liquid showed remarkable wettability alternation capability and moderate oil-water IFT reduction ability, which can partially reduce the impact on reservoir permeability. Moreover, the formation mechanism of the JAVES was proposed by molecular dynamics simulations at the molecular level, which was further visually verified via the cryo-TEM images. The improved viscoelasticity of developed the JAVES with moderate interfacial activity is advantageous to enhance subsequent oil recovery.

Development Adjustment Scheme of a Low-Permeability Reservoir in the SN Oilfield

Due to the complexity of low-permeability reservoirs, there is no set of established plans to adjust the development of specific low-permeability reservoirs, and the final development adjustment plan should be determined through comprehensive consideration of many aspects. At present, the development of low-permeability reservoirs in the SN oilfield faces problems. It is urgent to formulate corresponding development adjustment plans to improve the current development situation. In view of the problems of the current development surface of low-permeability reservoirs in the SN oilfield, this paper used the previous research results of a low-permeability reservoir development adjustment for reference, evaluated the reservoir development effect, analyzed the remaining oil distribution via numerical reservoir simulation, and finally designed and optimized a development adjustment plan. The research results show that the injection–production ratio and pressure of low-permeability reservoirs in the SN oilfield were generally maintained, the oil production decreased, the water cut increased, and the remaining recoverable reserves were considerable; the historical matching quality of a reservoir numerical simulation was good. There was more remaining oil in the northeast of the J007 well block and the north of the J008 well block, and the potential of the L2 and L3 layers was great. The remaining oil was mainly concentrated in the areas with high positions, poor physical properties, and imperfect well patterns; the predicted cumulative oil production of Scheme IV in 15 years and recovery were the highest, with the best development effect and the highest economic benefit. This was determined as the development adjustment plan for low-permeability reservoirs in the SN oilfield. The research results of this paper aim to improve oil production, the ultimate recovery factor, and economic benefits of low-permeability reservoirs in the SN oilfield, and to provide a reference for the development of similar oilfields.

Study on Production Characteristics during N2 Flooding in Low Permeability Reservoirs: Effect of Matrix Permeability and Fracture

The N2 flooding enhanced oil recovery process is an important technical means for the development of low permeability reservoirs due to its good energy enhancement effect and good injectivity. Low permeability reservoirs have a large permeability span and strong heterogeneity, which will have a significant impact on gas injection development. In order to explore the influence of matrix permeability and fractures on the production characteristics of N2 flooding, this study conducted a series of displacement experiments with full-scale matrix permeability (0.1–50 mD) and different fracture conditions. The research results indicate that, in non-fracture low permeability cores, the pressure difference decreased with the matrix permeability increase, and the volume of N2 injection required to achieve the highest injection pressure decreased. In addition, the increase in matrix permeability accelerates the gas breakthrough and gas channeling, but is beneficial for improving no-gas oil recovery and ultimate oil recovery due to the decrease in crude oil flow resistance. The impact of different matrix permeability ranges on production characteristics varies. When the matrix permeability is less than 2 mD, the characteristics of oil and gas production are significantly affected by changes in matrix permeability. When the matrix permeability is greater than 2 mD, the impact of changes in matrix permeability on development effectiveness is weakened. The existence of fracture causes a high permeability channel to appear in the low permeability matrix, exacerbating the gas breakthrough and channeling, and significantly reducing the utilization of matrix crude oil (about a 50% decrease in oil recovery). The increase in matrix permeability is beneficial for weakening the heterogeneity between fractures and the matrix, alleviating the gas channeling, thereby increasing the swept volume in the low permeability matrix and improving oil recovery.

Effect of water saturation on CO2 minimum miscibility pressure and oil displacement performance

The CO2 miscible flooding is an effective technology for development of low permeability reservoirs due to high oil displacement efficiency. However, CO2 miscible flooding for tertiary recovery technology typically occur after water flooding. Water hindered the contact and mass transfer of CO2 and oil, produce water resistance effect. Water can block CO2 and contact and mass transfer of crude oil (ie water blocking effect). The impact of this effect on the miscibility pressure and oil displacement effect is still unclear. In this study, homogeneous artificial cores with the same permeability as the reservoir were designed according to the miscible mechanism. Subsequently, the minimum miscibility pressure(MMP) between CO2 and crude oil at different water saturation was measured by the coreflood test. Based on the MMP, CO2 miscible flooding experiments were conducted by natural cores at different water saturation. The results showed that when the water saturation was 30%, 45%, and 60%, respectively, the corresponding MMP between CO2 and crude oil was 18.56, 19.48, and 21.76 MPa. The higher the water saturation, the longer the gas breakthrough time. But the oil recovery factor did not rise with the increase of water saturation. When the water saturation was 45%, the oil recovery factor in the miscible flooding experiment was the highest. In addition, the higher the water saturation, the weaker the CO2 extraction of various components in the crude oil. And the light components below C5 were most affected by water saturation. The mechanisms underlying these results are discussed. This study contributes to the development of CO2 miscible flooding reservoir plan.

ANALYSIS OF EFFICIENCY OF HORIZONTAL WELLS WITH MULTI-STAGE HYDRAULIC FRACTURING ON THE EXAMPLE OF KONDINSKOYE FIELD

In the structure of potential oil reserves in Western Siberia, the share of hard-to-recover reserves (HRR) is growing. At the same time, a significant share of these reserves is concentrated in low-permeability reservoirs. Horizontal wells using multi-stage hydraulic fracturing are the basis of technological solutions used for cost-effective development of low-permeability reservoirs by Russian oil and gas producers [1-4]. Due to the high efficiency of the subsea development systems with MSHF, oil production from such facilities exceeds oil production from traditional reservoirs and accounts for more than 60 % of the total oil production of the Company's fields [5]. The following characteristics are identified as the key parameters of the horizontal section, the number of hydraulic fractures, as well as the specific weight of the injected proppant at the frac stage. The decisions approved as part of the design documents for the development of facilities with TPP indicate a tendency to increase the length of the horizontal hole and the number of frac operations with a decrease in the specific mass of proppant on the port. The article examines the impact of these characteristics on the technological efficiency of wells. The purpose of the work is to assess the feasibility of increasing the technological complexity of HW with multi-stage hydraulic fracturing of the MSHF formation in the form of increasing the number of stages and length of the horizontal hole, as well as the specific mass of proppantane in the example of the AS10/1 Kondinskoye field development target. Within the framework of the study, three types of HW with MSHF were identified, the technological effectiveness of which was assessed in two ways. The first method consisted in comparing the magnitudes of the dimensionless productivity coefficient Jd (d. units) of three different types of wells with a horizontal end in relation to directional wells (FWS with frac) of the environment. Taking into account the similarity of the geological conditions of the neighboring wells, this method made it possible to assess how effectively the completion of the horizontal wells under study was completed. The multiplicity assessment methodology was developed by RN-BashNIPIneft LLC [6]. The second method was to compare the ratio of dimensionless productivity factor to the specific weight of proppant Jd/Mpr _ specific of the identified types of HW with multi-stage hydraulic fracturing (MSHR). This approach made it possible to take into account the effective thickness and permeability of the formation in the well drilling zone, as well as the weight distribution of the injected proppant. The results showed that if the length of the horizontal hole is constant, an increase in the number of frac stages while reducing the proppant weight on the port is impractical. Confirmation was also obtained based on statistical data that there is a relationship between the cumulative fluid withdrawal and the weight of the injected proppant. It has been established that drilling HW with multi-stage hydraulic fracturing of the (MSHF) formation of the most common type (1000 m, 10 stages) is not optimal for the study target: for a length of 1000 m, the maximum number of stages should be limited to 7–8 units per well. Further monitoring and analysis of production wells with horizontal termination is recommended to collect more statistical data and compare them over time.