Tight Oil Reservoirs Research Articles

Pore-throat structure, fractal characteristics and permeability prediction of tight sandstone: the Yanchang Formation, Southeast Ordos Basin.

As a typical tight reservoir and an important site for unconventional hydrocarbon accumulation, the Chang 6 member of the Yanchang Formation is characterized by complex pore structures and strong heterogeneity. Analysing and characterizing the pore-throat structure is highly important for optimizing oil recovery processes. To clarify the nonhomogeneity and structural characteristics of the pore throats in the southeastern Ordos Basin, tight sandstone from the Chang 6 member was selected for analysis. Casting thin section (CTS), scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), and mercury intrusion capillary pressure (MICP) analyses were conducted. The results, revealed that intergranular pores, feldspar-dissolved pores, intergranular-dissolved pores, and microfractures were the predominant pore types found within the samples. By combining the results of MICP analysis with those of fractal theory, the pore-throat structure of each sample can be categorized into two types: large-scale and small-scale. Fractal theory was employed to characterize the complex and irregular pore-throat structure of the reservoir quantitatively. The average fractal dimension of large pores (D1) was 2.8094, whereas for small pores (D2), it was slightly lower than that of large pores, averaging 2.5325. These findings underscore that large-scale pore-throat structures are more complex and exhibit greater heterogeneity. Compared with those of large pores, the pore-throat structure parameters of small pores exhibit a more significant correlation with reservoir properties and fractal dimensions. Therefore, small pores are the primary contributors to the reservoir storage space and are key factors influencing the pore-throat structure of the Chang 6 tight sandstone. Based on the pore-throat radius and considering the influence of fractal characteristics on the pore structure, a nonlinear permeability prediction model was created using multiple regression analysis. Among these equations, the pore-throat radius corresponding to a mercury saturation of 40% (r40) emerged as the most effective predictor of permeability for tight sandstone. The investigation of micropore-throat structures in tight oil reservoirs holds practical significance for comprehending the distribution and accumulation of tight oil and guiding oil field development.

The Saturation Calculation of NMR Logging Based on Constructing Water Spectrum Function

Tight sandstone oil reservoirs are characterized by complex structures, poor pore connectivity, and strong heterogeneity, with features such as low porosity and ultra-low permeability. Conventional methods for calculating saturation cannot accurately evaluate the hydrocarbon saturation of these reservoirs. To address this, a study was conducted from the perspective of non-electrical logging methods, focusing on the inherent nuclear magnetic resonance (NMR) characteristics of different fluids to develop a saturation calculation method that avoids the influence of the rock matrix, thus enabling precise saturation measurement in tight sandstone oil reservoirs. The traditional NMR porosity model was modified by segmenting it using the clay-bound water cutoff value, aiming to identify the distribution pattern of fluids in pores outside the clay-bound water zone. Through theoretical derivation and water spectrum function simulation, a water spectrum function and its parameter range suitable for the NMR T2 distribution in tight sandstone reservoirs were determined. Using core-sealed core saturation as a reference, the particle swarm optimization (PSO) algorithm was applied to optimize the parameter range and construct the final water spectrum function tailored to tight sandstone oil reservoirs. The accuracy and practicality of this method were validated by applying the derived water spectrum function to NMR logging in the exploration block, allowing for precise saturation calculations and the accurate evaluation of tight reservoir saturation.

Analysis of Spontaneous and Dynamic Imbibition Characteristics of Silica-Based Nanofluid in Microscopic Pore Structure of Tight Oil Reservoirs.

Imbibition behavior plays a crucial role in tight oil reservoir development, to increase tight oil production, a novel sodium lauryl ether sulfate (SLES) nanofluid was developed. Spontaneous and dynamic imbibition performance of nanofluid and the relative influencing factors were systematically investigated using the online low-field nuclear magnetic resonance (LF-NMR) technique. The microscopic mobilization characteristics and mechanism of nanofluid-enhanced matrix crude oil recovery in tight oil reservoirs were further explored. The experimental results showed that the proposed SLES nanofluid achieved the highest imbibition efficiency, and appropriate concentrations of nanoparticle and surfactant were helpful in enhancing the imbibition recovery. Excessive concentrations of chemical agents may block the tiny pores. A reasonable injection rate and shut-in time should be determined to fully leverage capillary forces for water phase imbibition and oil phase displacement as well as the displacement effect of the viscous force and increased water wetness of the rock surface provided by the nanofluid. In addition, NMR T2 cutoff was applied to distinguish the imbibition and displacement regions during dynamic imbibition process. The pore sizes corresponding to the T2 cutoff values after nanofluid and deionized (DI) water flooding were 0.6 and 5 μm, indicating that nanofluid considerably increased the movable crude oil in pores of tight oil reservoirs compared with DI water. Furthermore, imbibition behavior was dominant in micropores (<0.1 μm) and mesopores (0.1-1 μm), and displacement principally occurred in microfractures and macropores. Finally, the underlying mechanisms responsible for nanofluid enhanced oil recovery were related to wettability alteration, capillary pressure, and viscous force. This work provides further understanding of spontaneous and dynamic imbibition when employing nanofluid in tight oil reservoirs.

Research on the stimulation mechanism of well shut-in imbibition and parameter optimization during fracturing-flooding

ABSTRACT In the development of low-permeability tight oil reservoirs, fracturing-flooding technology, with its dual advantages of “fracture creation and energy replenishment, and displacement by imbibition,” effectively addresses challenges such as poor water injection and low oil recovery. However, the mechanism of oil-water migration within the reservoir and the enhanced oil recovery during the shut-in imbibition process remain unclear, and the construction parameters are primarily based on empirical data. In this study, focusing on the Y block in the Bohai Bay Basin, eastern China, we conducted dynamic imbibition experiments and utilized nuclear magnetic resonance (NMR) technology to analyze the key factors influencing imbibition-driven oil displacement and the microscopic oil-water migration mechanisms within the pore space. Numerical simulation was then employed to optimize the construction parameters for fracturing-flooding operations. The results indicate that displacement and imbibition primarily occur in medium-sized pores, while the poor connectivity of micro- and small-sized pores leads to suboptimal effects. The shut-in process provides favorable conditions for imbibition displacement, allowing oil in small and medium pores to be further displaced into fractures. The main factors affecting imbibition efficiency include core permeability (optimal range: 1.5 mD to 4 mD), fracture length (approximately 2/3 of the core length), fracturing-flooding fluid concentration (optimal around 0.2%), and shut-in time (optimal range: 24 to 48 hours). Based on production capacity simulations, the optimal construction parameters for the Y block include an injection rate of 1152 to 1440 m3/min, a total injection volume of 20,000 to 25,000 m3, and a shut-in time of 30 to 45 days. The application of these optimized parameters resulted in an increase in the average daily oil production in the Y block from 4.4 tons to 7.7 tons, demonstrating a significant enhancement in reservoir productivity and oil recovery.

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Delineation of the reservoir petrophysical parameters from well logs validated by the core samples case study Sitra field, Western Desert, Egypt.

In the northern section of the Western Desert, there are many extremely profitable petroleum and natural gas deposits in the Abu EL-Gharadig Basin. This study aims to highlight the hydrocarbon potential of Abu Roash F Formation, which stands for high organic content unconventional tight reservoirs, and Abu Roash G Formation which stands for conventional sand reservoirs, in Sitra field located in the central-western part of the Abu EL-Gharadig Basin. The research employed well-log data from four wells to ascertain petrophysical properties combined with core samples of two wells for a comprehensive examination and description of lithology. Initially, we commenced the execution of petrophysical analysis, encompassing log quality control procedures. Subsequently, we identified and revealed zones of interest and hydrocarbon indicators in both formations. Additionally, we ascertained the three most influential parameters, shale Volume, effective Porosity, and water saturation, which serve as defining factors for reservoir quality. Subsequently, an examination of the core samples, which encompassed lithologic description, lithofacies analysis, paleoenvironmental interpretation, petrographic analysis, and porosity assessment is conducted. For the sake of a more accurate interpretation, we conclude our research with cartographic maps created to evaluate the geographical distribution of hydrocarbon potential based on petrophysical characteristics, Distribution of the net-to-gross ratio among wells by correlating the litho-saturation models (rock models) for the four wells. The foregoing results declare that The Abu Roash F carbonate-rich rocks are a contender for unconventional tight oil reservoir potential with thin secondary porosity and high organic content, which normally requires a kind of hydraulic fracturing for prospective oil extraction, Furthermore, the upper section of Abu Roash G formation, particularly in well sitra8-03, has highly favorable conventional reservoir characteristics.

Experimental Study on CO2 Huff and Puff in the Daqing Fuyu Tight Oil Reservoir with Online NMR

Tight oil is a typical unconventional resource, and enhancing its recovery rate remains a challenge in current development efforts. In this study targeting the Daqing Fuyu tight oil reservoir, we combine a high-temperature and high-pressure long core physical simulation apparatus and a high-temperature and high-pressure online Nuclear Magnetic Resonance (NMR) testing system to conduct indoor simulation experiments on CO2 huff and puff in long cores. The results indicate that in the process, it is primarily the oil from micro-pores that is initially mobilized, but further along mobilization of fluids from a portion of sub-micro-pores and nanopores is enhanced, with an efficiency ranging from 25-33%. It was also found that there exist optimal conditions for huff and puff pressure, soaking time, and huff and puff cycles. Additionally, excessive extraction of light components by CO2 can prove disadvantageous for further improvement in huff and puff efficiency. This study can provide insight into the mechanisms of and data support for the development of CO2 huff and puff strategies in tight oil reservoirs, thereby contributing to the formulation of effective development plans.

Quantitative Characterization of Surfactant Displacement Efficiency by NMR—Take the Tight Oil of Chang 8 Member of Yanchang Formation in Fuxian Area, Ordos Basin, as an Example

Surfactant flooding is a pivotal technique for enhancing oil recovery efficiency. The Chang 8 member of the Yanchang Formation in the Ordos Basin exemplifies a quintessential tight oil reservoir. Specifically, 47.9% of wells yield less than 0.1 t/d, 27.0% produce between 0.1 and 0.2 t/d, and 18.8% generate outputs ranging from 0.2 to 0.3 t/d, while only a mere 6.3% exceed production rates of over 0.3 t/d, indicating minimal efficacy of water flooding development in this context. In this study, we conducted an extensive investigation into the geological characteristics of the Yanchang 8 reservoir within the Ordos Basin, leading to the identification and evaluation of three surfactants based on their interfacial tension properties. The optimal injection concentration was determined through on-line displacement nuclear magnetic resonance imaging analysis that refined surface activity conducive to developing the Chang 8 member, ultimately resulting in increased spread volume and enhanced crude oil production from individual wells. The results indicate the following: (1) The interfacial tension of NP-10, FSD-952, and GPHQ-1 at concentrations of 0.05%, 0.1%, 0.2%, 0.3%, 0.4%, and 0.5% exhibited a pattern of initial decrease followed by an increase. The mass concentration corresponding to the minimum interfacial tension for NP-10 is identified as 0.1%, which is also the case for GPHQ-1; however, for FSD-952, this occurs at a concentration of 0.4%. Among the surface-active agents NP-10, GPHQ-1, and FSD-952, GPHQ-1 demonstrated the lowest interfacial tension value at an impressive measurement of 0.0762 mN/m. (2) When the displacement of the 0.1% GPHQ-1 surfactant reaches 10 PV, the displacement efficiency improves from 69.69% to 76.36%, representing an increase of 6.67%. The minimum pore size observed during GPHQ-1 surfactant displacement is 0.01 μm. In contrast, when the displacement of the NP-10 surfactant at a concentration of 0.1% reaches 10 PV, the efficiency rises from 68.32% to 72.02%, indicating an enhancement of 3.7%. The corresponding minimum pore size for NP-10 surfactant displacement is recorded at 0.02 μm. Furthermore, when the displacement of the FSD-952 surfactant at a concentration of 0.4% achieves 10 PV, its efficiency increases from 69.93% to 74.77%, reflecting an improvement of 4.81%. The minimum pore size associated with the activated portion of FSD-952 is noted as being approximately 0.03 μm.

Investigation of drive mechanisms in fractured oil reservoirs with tight matrix: a case study of an Iranian reservoir

ABSTRACT Tight matrix oil reservoirs pose significant challenges for oil recovery due to their low permeability and intricate fracture networks. Effective reservoir development strategies require a thorough understanding of the recovery mechanisms; otherwise, it is difficult to maximize production rates and optimize the oil recovery factor. The reservoir examined in this study contains black oil within a tight matrix, complicating the planning and selection of appropriate recovery methods. Despite strong bottom water influence and high water-cut issues, the fractures in the reservoir facilitate economical extraction. However, the reservoir’s complexity, coupled with limited knowledge and experience in this area, further complicates recovery efforts. In this study, we investigated the multi-mechanistic flow dynamics within the porous media. Simulation results indicate that during the first month of production, the dominant recovery mechanism is rock expansion drive. Beyond this period, the water drive mechanism prevails. Over a ten-year period, oil recovery is distributed as follows: 13.1% from bottom water drive, 1.0% from gas cap drive, 0.2% from rock expansion, and 0.6% from oil expansion drive.

Analysis of the impact of geological and engineering parameters on productivity in tight oil reservoirs

AbstractTight oil resources are abundant, but the factors affecting production capacity are complex. In this paper, focusing on tight oil reservoirs, three research works were conducted. First, using the numerical simulation software, a numerical model of tight oil reservoirs was established. Second, the influence of geological parameters such as porosity and permeability on oil production were analyzed. Third, the influence of rock compression coefficient and injection fluid on tight oil production were analyzed. Results show that: (a) When the porosity is 0.05, the cumulative oil production in the first 6 years is the highest, while in the later stage of the simulation, the cumulative oil production with a porosity of 0.1 is the highest. (b) The higher the permeability, the greater the cumulative oil production. The cumulative oil production under different permeability conditions are 1392.044, 2178.805, 2939.1704, and 4038.0878 m3, respectively. (c) Under tight reservoir conditions, the impact of different rock compression coefficients on the daily oil production of oil and gas reservoirs is not very significant. (d) The recovery effect is optimal when using the N2 injection scheme. The effectiveness of the CH4 scheme is second, and there is a certain gap compared to the N2 scheme. The development plan of injecting water has the worst effect. However, compared to the depletion development model, the cumulative oil production by injecting N2, CO2, CH4, and water has all increased.

Microscale heat and mass transfer characteristics of CO2 flooding in nanotubes of tight oil reservoirs

AbstractThe mechanism of heat and mass transfer in tight oil reservoirs after CO2 injection is complex. In this paper, first, a CO2 transfer model within microscale adjacent nanotubes in tight oil reservoirs is established. Then, the typical heat and mass transfer characteristics of microscale CO2 in tight oil reservoirs is analyzed, and the influence of grid density on the calculation results is discussed. Finally, the influence of thermal conductivity of tight oil reservoirs on CO2 physical properties parameters is revealed. Results show that: (a) From the inlet end of the thick nanotube to the outlet of the nanotube, the pressure of CO2 drops from 3.5 to 3.3697 MPa. (b) When the mesh length is equal to 5 nm, the CO2 pressure in the thin nanotube drops from 3.5 to 3.3329 MPa, and the CO2 pressure in the thick nanotube drops from 3.5 to 3.2018 MPa. (c) Organic amines react with CO2 to form salts, which can seal high permeability layers and cracks, but there is a risk of environmental pollution.

Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

Numerical Evaluation of Multi-well Cyclic Gas Injection Technique for Enhanced Oil Recovery in Composite Tight Oil Reservoirs

Numerical Evaluation of Multi-well Cyclic Gas Injection Technique for Enhanced Oil Recovery in Composite Tight Oil Reservoirs

Investigation the Impact of Different Injection Agents on Tight Oil Reservoirs of Recovery Performance

Abstract Objectives/Scope: Due to strong water sensitivity and extremely low permeability, conventional water flooding method is not suitable for the Mahu Conglomerate reservoir. In response to the complex reservoir physical properties, different injection agents such as CO2, N2, water and air huff and puff injection were carried out in order to optimize injection parameters for enhanced oil recovery in tight conglomerate reservoirs. Methods, Procedures, Process: By means of NMR, scanning electron microscopy, energy spectrum, pore fluids state in different media after different agents displacement were studied. Displacement and CT testing on different media and post fracturing state were conducted. Through experiments on on-site cores from two different layers, three different injection media (H2O, N2, CO2 and air with different O2 concentration) were tested for enhanced oil recovery. Then, the injection process was performed under different injection pressures. Finally, multiple cycles of enhanced oil recovery tests were conducted corresponding optimal injection pressures. Results, Observations, Conclusions: The remaining oil in the pores is mainly in free and bound states, with a free state of approximately 58% and a bound state of approximately 42%. Four pressures were selected for this test based on the minimum miscibility pressure of CO2 with crude oil: 15MPa, 20MPa, 23MPa, and 25MPa. The recovery factor under different pressures is 6.44%, 8.14%, 10.31%, and 10.38%, respectively. As the huff and puff pressure increases, the recovery of CO2 huff and puff gradually increases, and the increase of recovery is insignificant when the mixture pressure is reached. The gas flooding process involves oil production from large and submicron pores first. As the displacement pressure difference increases, oil production from large pores decreases, with medium pores becoming the main force of oil production, while oil production from nanoscale micropores shows an increasing trend. The increase in oxygen content results in significant development of sub-micron micron scale pores. The gas breakthrough time is long, the capillary force decreases, and air can undergo low-temperature oxidation with crude oil, resulting in an overall oil displacement efficiency of 65.81%. Novel/Additive Information: At present, there is few research on the pore fluid flow and status of oil displacement in tight conglomerate reservoirs with different injection media. This study provides a good understanding of the submicron to nanoscale pore throat structure characteristics of tight oil reservoirs, revealing the state of pore fluids in gravel after displacement by different injection media, and providing support for on-site application of CO2 enhanced oil recovery in tight conglomerate oil reservoirs.

Geological characteristics and volume fracturing adaptability of tight oil reservoirs in the Ordos Basin of China

Abstract In recent years, China’s dependence on foreign crude oil has gradually increased. The Ordos Basin has abundant oil, gas, and coal resource. Tight oil and shale reservoirs have become very important replacement resources. This article studies the geological characteristics and volume fracturing adaptability of the Yanchang Formation tight oil reservoir in the central region of the Ordos Basin, and uses X-ray diffraction experiments to analyze the mineral composition of the reservoir; Utilizing high-pressure mercury intrusion technology to achieve precise quantitative characterization of multi-scale pore structures in reservoirs; Using the Analytic Hierarchy Process, establish a numerical judgment matrix and factor weights to study the adaptability of volume fracturing in the region. The results indicate that the volume fracturing adaptability of tight oil reservoirs in the Ordos Basin is good.

A New Productivity Prediction Model for Multi-fractured Horizontal Wells in Tight Oil Reservoirs

Abstract The productivity of Multi-fractured horizontal wells (MFHWs) in the tight oil reservoirs is the key index to evaluate the effect of volume fracturing. In this study, to find a solution for this problem, firstly, the big data affecting the productivity of MFHWs were collected, and then a multi-level evaluation system was built by using the analytic hierarchy process(AHP). Secondly, the gray theory was used to calculate the correlation coefficients between different parameters and production capacity to screen out the key parameters affecting the production capacity. Finally, a new horizontal well productivity prediction model by coupling key geological and engineering parameters was established, to calculate the similarity coefficient and realize quantitative prediction of single well productivity. The results show that the length of horizontal section, formation pressure, fracturing fluid volume, number of stages, net pay thickness and permeability are the key parameters affecting productivity of MFHWs. The new productivity prediction model has been successfully applied to 175 wells in China’s typical tight oil fields, with prediction errors less than 5%. It can be used in productivity prediction of horizontal wells after volume fracturing in similar unconventional tight oil reservoirs, has broad application prospects, and can guide the efficient development of and fracturing scheme selection for tight oil reservoirs effectively.

Study on the Law and Influencing Factors of Spontaneous Imbibition in Chang 7 Reservoir of Ordos Basin

Abstract This paper examines the imbibition and oil displacement process of fracturing fluid in a laboratory setting, focusing on the Chang 7 tight oil reservoir block in Ordos Basin. The study investigates the capability of different imbibition fluid systems to alter wettability and reduce interfacial tension. Additionally, it explores the imbibition and oil displacement abilities of cores with varying levels of wettability and permeability focusing on the imbibition equilibrium time, imbibition recovery rate, and the imbibition recovery multiplier. The reasons for these results were also examined. A multivariate nonlinear regression model is established to analyze the relationship between imbibition recovery, capillary radius, wettability angle, and interfacial tension. Additionally, neural network analysis is employed to determine the significance of these influencing factors. The findings from this research provide theoretical guidance for enhancing understanding of imbibition mechanisms and improving recovery rates in tight oil reservoirs.

Feasibility Study on Infiltration of Sidetracking Horizontal Wells in Fuyu Tight Oil Field

Abstract The Fuyu oil layer in well area 1 is a tight reservoir. Due to poor reservoir properties, conventional fracturing production wells have low production and rapid decline, with a recovery rate of only 2.22%.. Moreover, the surface of the well area is a wetland protection zone along the river. Under the new safety and environmental protection policies, new drilling is not allowed in the protection zone. In order to improve the development effect of the well area and increase the recovery rate, based on the geological and development characteristics of the oil reservoir, and in response to the problem of fast water breakthrough in east-west oil wells and ineffective water injection in non east-west oil wells in the Fuyu oil layer, the main oil layer with high well control degree, small well network density, and well-developed reservoir is selected. The original development well points are used to sidedrill stepped horizontal wells, combined with volume fracturing of tight oil horizontal wells, to avoid adjacent reserve losses, Exploring a new infill model for sidetracking horizontal wells in tight oil reservoirs in Fuyu, providing reference for effective development of similar reservoirs.

Enhance Oil Recovery by Carbonized Water Flooding in Tight Oil Reservoirs

The low permeability of tight sandstone reservoirs limits the application of water flooding to enhance oil recovery. Due to the properties of CO2, people improve crude oil recovery by carbonizing water flooding. However, many studies have not prioritized determining the concentration of carbonated water before comparing the recovery rates of carbonated water flooding and pure water flooding after water flooding. This article takes the Chang 6 oil reservoir as the research object, and uses a combination of nuclear magnetic resonance testing and displacement experiments to conduct experiments on optimizing the concentration of carbonated water. Based on this, experiments on water flooding and carbon water flooding after water flooding to improve crude oil recovery are conducted to compare and analyze the oil enhancement potential of carbonated water flooding. The experimental results show that the physical properties, pore throat structure and seepage capacity of sandstone samples of type I, II and III decrease in turn. With the increase of carbonated water concentration, the expansion coefficient, viscosity reduction rate, contact angle reduction rate and core permeability loss rate of crude oil increase. The damage rate of 0.4mmol/cm3 carbonated water solution (17.6g CO2: 1L water) to the core permeability is only 0.98%, which is the optimal experimental concentration. During the water flooding process, crude oil in pores of different scales in Type I rock cores is utilized, and the degree of utilization in large pores is relatively high. Continuing to use carbonated water to drive oil in the rock cores after water flooding increased the recovery rate of crude oil by 15.24%; The degree of crude oil utilization in small pores of Tpye II core after carbonization and water flooding increased by 29.4%, and the final recovery rate of crude oil increased by 11.35% compared to the core after water flooding; The physical properties of Tpye III core are poor, with a small proportion of large pores, resulting in a 9.04% increase in crude oil recovery rate. Compared with pure water flooding, the recovery rate and utilization degree of large and small pores in the three types of rock cores after carbonization water flooding have been improved to varying degrees. Among them, the utilization degree of crude oil in large pores is the most significant, which increases the recovery rate of crude oil in the rock core after displacement. This study can provide a theoretical basis for improving crude oil recovery by carbonizing water flooding.

Feasibility Theory and Practice of CO2-EOR in High CO2-Content Near-saturated Edge-bottom Water Reservoir

Abstract CO2-EOR technology for low-permeability tight oil and gas reservoir is in the ascendant, and CO2-EOR technology for old oilfields has not been paid enough attention, but the implementation scale has great potential, and the expected effect and implementation conditions are good. The feasibility of CO2-EOR technology in the ultra-high water cut stage of high CO2 content, near saturation pressure and edge-bottom water reservoir was studied theoretically, and the field implementation effect was tracked and evaluated. Via petrophysics, reservoir engineering, and site case analysis, a relatively comprehensive reservoir numerical model was developed, clarifying the impact of periodic gas injection volume, gas injection rate, soak time and liquid production rate on the production effect of CO2 huff and puff were clarified. The key injection-production parameters of CO2 huff and puff test wells were designed, and the feasibility study progress of CO2-EOR in near-saturated edge-bottom water reservoirs with high CO2 content was summarized. The theoretical research shows that the change rules of gas-water dual-drive, CO2 water control and oil increase in the process of CO2 huff and puff in high CO2 near-saturated edge and bottom water reservoirs, and reveals the synergistic mechanism of CO2 huff and puff to suppress water and increase energy. The tracking evaluation shows that the sweep condition of CO2 after huff and puff in the test well is complex, the storage ratio is in the range of 40%-70%, the stage oil increase is in the range of 700t-3000t, and the optimized oil increase and oil change rate can reach 2.7t/t. Based on the comprehensive theory and practice, it is considered that CO2-EOR has good potential for high CO2 near-saturated edge and bottom water reservoirs under fine control. This study has guiding and reference significance for CO2-EOR technology and application in similar oilfields at home and abroad.