Water Flooding Stage Research Articles

Two-Dimensional Physical Model Experimental Study on Sweep Efficiency of Offshore Heavy Oil Hot Water Flooding

Abstract The conventional water flooding approach for the development of ordinary heavy oil faces challenges such as high injection-production mobility, rapid increase in water cut, and low final recovery. By using the temperature-sensitive properties of heavy oil, the viscosity can be effectively reduced, and the flow capacity within porous media can be enhanced by increasing the temperature of injected water. Onshore hot water flooding is primarily used to exploit the remaining oil potential during the later stages of steam stimulation, while offshore is used to enhance efficiency during the mid to late stages of water flooding. The key to the success of hot water flooding technology lies in the improvement of the sweep coefficient. Firstly, a two-dimensional physical experiment model is designed in accordance with the geological and reservoir characteristics of the target oilfield, based on the principle of similarity. Secondly, parameters that quantitatively characterize the development law of the plane temperature field, such as the effective sweep coefficient, regular factor, and plane expansion speed of the high-temperature region, are studied. Then, through two-dimensional experiments, the effects of injection medium, formation rhythm, and timing of hot water injection on sweep efficiency and temperature field development were discussed. Finally, on the basis of two-dimensional experiments, the effects of heat injection temperature, timing of heat injection, hot water injection speed, and high permeability strip on the improvement of sweep efficiency were quantitatively analyzed by numerical simulation. The results show that compared with hot water flooding, hot water composite flooding can increase the effective sweep coefficient from 15.05 % to 28.71 %. The anti-rhythm is helpful to the upward expansion of the high temperature zone, which can increase the oil displacement efficiency by 1.5 %. Water channeling can be effectively controlled by injecting hot water with low water cut. The increase of heat injection temperature is helpful to increase the proportion of high temperature heating area. The higher the injection speed, the greater the expansion speed of the heating chamber. The research results provide a direction for the development of heavy oil conventional water flooding to improve oil recovery in offshore heavy oil.

Mechanisms of surfactant improving water injection huff and puff efficiency in tight reservoir

Water injection huff and puff is an economical and effective method to enhance the recovery of tight oil reservoir, in which the addition of suitable surfactants is critical, but its mechanism needs to be further studied. In this paper, the huff and puff process is divided into replenishment, imbibition and water flooding stages. This study compared and analyzed the effects of various surfactants on interfacial tension, wettability, flow resistance, and oil washing efficiency, using mineralized water as the control group. The relationships between different surfactants and imbibition recovery efficiency, water flooding recovery efficiency, and flooding pressure were investigated. The mechanisms by which surfactants influence the imbibition and flooding processes were also explored. The results show that, the effect of permeability on imbibition and water flooding recovery efficiency in natural cores can be ignored. During the imbibition stage, the maximum recovery efficiency with mineralized water is 18.33 %, while with surfactants it is 21.40 %. In the water flooding stage, the maximum recovery efficiency with mineralized water is 3.89 %. The addition of surfactants significantly increases the water flooding recovery efficiency to 19.82 %. Furthermore, surfactants can reduce the water flooding pressure by approximately 7.00 MPa and increase the total recovery rate by about 5.00 %. The primary mechanisms by which surfactants improve the water injection huff and puff effect include reducing interfacial tension, altering wettability, facilitating crude oil detachment from rock surfaces, and enhancing oil washing efficiency. Reduction of flow resistance, leading to a decrease in the pressure required for flooding. The research results provide a theoretical basis for the practical application of surfactants in water injection huff and puff in tight reservoirs.

Experimental study on the mass transfer and microscopic distribution characteristics of remaining oil and CO2 during water-miscible CO2 flooding

Accurate understanding and quantitative characterization of the microscopic distribution and mobilization mechanisms of remaining oil are crucial for further enhancing oil recovery during CO2 flooding. In this study, miscible CO2 flooding experiments after water flooding were performed to investigate the mass transfer and microscopic distribution characteristics of remaining oil and CO2 using micro-computed tomography technique. Additionally, the distribution characteristics of multiphase fluids (oil, water and CO2) in the pores were comprehensively investigated. Furthermore, the mass transfer effects during the miscible CO2 flooding process, as well as the CO2 sequestration ratio (SR) and sequestration factor (SF) were systematically examined. The experimental results show that the ultimate oil recovery factor after miscible CO2 flooding were 80.9 %, 70.7 %, and 64.7 %, respectively. During the water flooding stage, the produced oil mainly consisted of light hydrocarbons (C5–C16), followed by medium hydrocarbons (C17–C27). The remaining oil was mainly in cluster and network pattern, followed by multiple and oil film pattern. After miscible CO2 flooding, the produced gas mainly consisted of CO2 and CH4, with a significant increase in the mass fraction of light hydrocarbons (C5–C16) in the produced oil. The remaining oil was mainly in multiple and singlet pattern, followed by network and film pattern, with a small portion in cluster pattern. The higher the displacement rate, the smaller the SR, but most of the injected CO2 (SR > 70 %) was retained in the porous media, demonstrating the feasibility of CO2 geological sequestration during the miscible flooding process.

Integrated optimization of well placement and perforation layer selection using a modified dung beetle algorithm

In the oilfield development process, a proper well pattern plays a crucial role in improving oil recovery and economic benefits. However, traditional well pattern optimization mainly focuses on two-dimensional plane well placement, overlooking the spatial alignment of perforated layers and well placements. This oversight presents significant challenges, especially in meeting the demands for fine development of high water-cut oilfields. Therefore, this paper introduces an innovative approach to well pattern optimization, termed integrated well pattern optimization (WPO–I), which couples well placements with perforation positions. By maximizing net present value, a novel mathematical model for well pattern optimization is established, considering the location of infill wells, the status and type of existing wells, and the perforation position of working wells as co-optimization variables. Besides, an improved discrete dung beetle optimization (IDDBO) algorithm is developed, utilizing multi-layer integer coding and an opposition-based learning strategy. To evaluate the proposed method's performance, the Egg model is used to compare it with five optimization algorithms. Furthermore, this study assesses the development effects of conventional plane well placement optimization (WPO–P) compared to WPO-I. The results highlight the distinct advantages of the IDDBO algorithm in solving discrete nonlinear programming problems. Particularly, the WPO-I method enables spatial matching of the well pattern with reservoir heterogeneity and remaining oil distribution, effectively utilizing spatial residual oil. This method provides a new development optimization strategy in mature oilfields, especially for fine adjustment of well patterns during the secondary recovery stage of water flooding.

Design of Janus Nanoparticles for Mobility Control in Heterogeneous Reservoirs.

Unfavorable mobility ratios in heterogeneous reservoirs have resulted in progressively poor waterflood sweep efficiency and diminishing production. In order to address this issue, our study has developed amphiphilic-structured nanoparticles aimed at enhancing the microscopic displacement capability and oil displacement efficiency. First, the transport process of Janus nanoparticles in porous media was investigated. During the water flooding, Janus nanoparticle injection, and subsequent water flooding stages, the injection pressure increased in a "stepped" pattern, reaching 0.023, 0.029, and 0.038 MPa, respectively. Second, emulsification effects and emulsion viscosity experiments demonstrated that the amphiphilic structure improved the interaction at the oil-water interface, reducing the seepage resistance of the oil phase through emulsification. In porous media, Janus nanoparticles transported with water exhibit 'self-seeking oil' behavior and interact with the oil phase, reducing the viscosity of the oil phase from 19 to 5 mPa·s at 80 °C. Finally, the core model displacement experiment verified the characteristics of Janus nanoparticles in improving the oil-water mobility ratio. Compared with the water flooding stage, the recovery percent increased by 20.8%, of which 13.7% was attributed to the subsequent water flooding stage. Utilizing the asymmetry of the Janus particle structure can provide an effective path to enhanced oil recovery in inhomogeneous reservoirs.

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance.

Research on the Adjustment Strategy and Effect Evaluation of Oilfield in the Late Stage of Water Drive with Ultra High Water Cut

This article delves into the adjustment strategies for high water cut oil fields in the later stage of water flooding and their impact on oilfield performance. We conducted a series of experiments, including optimizing the layout of injection wells, comparing water quality improvement measures, comparing oilfield management and operation strategies, and applying efficient oil recovery technologies, to analyze and evaluate the effects of different strategies in detail. The experimental results indicate that the production and recovery rate of the oilfield show a stable increase over time, starting from an initial value of approximately 95 units. At the end of the 10th time cycle, this indicator accumulated to around 950 units. This indicates that artificial lifting technology has shown stable performance in improving oilfield performance. The results of this study emphasize the importance of adjusting strategies. By optimizing the layout of water injection wells, improving water quality, optimizing management and operation, and applying efficient oil recovery technologies, it is possible to significantly increase the production and recovery rate of oil fields in the later stage of water flooding with ultra-high water content, reduce the expansion of water shear zones, and achieve better economic benefits and sustainable development. These results are of great significance for practical applications in the field of petroleum engineering.

Lithological and mineralogical signs of the formation and destruction of the Bashkirian stage oil deposits within the Sokskaya saddle

Oil deposits in sections of the Bashkirian stage of the Sokskaya saddle are considered. It has been established those oil-bearing limestones are represented by leached peloidal-clumpy grainstones. The rocks were formed within the shallow shelf of sedimentation basin of normal salinity. The active hydrodynamics of the aquatic environment predetermined the dense structural packing of organic residues. The migration of aggressive oil-water fluids contributed to leaching of calcite cement from grainstones. Subsequently, the pore-cavernous space was filled with oil. The introduction of edge formation waters into oil-bearing reservoirs contributed to the oxidation of oil and the manifestation of secondary diagenetic mineralization. The initial stage of waterflooding was indicated by dolomitization of reservoir rocks. Due to an increase in the partial pressure of carbon dioxide in the pore space of rocks, calcite is metasomatically replaced by diagenetic dolomite. At this stage of reservoir rock alteration, a relatively small amount of oil is recovered from oil-bearing formations. The introduction of formation waters enriched with sulfate ions into reservoir layers leads to the precipitation of gypsum-anhydrite aggregates in the pore space of oil-bearing limestones. Calcium sulfate minerals clog the pore-capacitive space of reservoir rocks, reducing their productivity. At the stage of precipitation of gypsum-anhydrite aggregates, mainly mineralized brines with an admixture of oil are extracted from reservoir rocks.

Microfluidics investigation of the fracture/matrix interaction mechanisms during preformed particle gel (PPG) treatment in fractured porous media

Although water injection is one of the most common methods for enhancing the recovery from oil reservoirs, its effectiveness in severely heterogeneous porous media such as fractured rocks, is debatable. Preformed Particle Gel (PPG) treatment is one of the most promising methods which is considered for water shut-off in the near wellbore area or improving the sweep efficiency of the injected water deep in the reservoir. Recognizing the PPG transport mechanisms in fracture, fracture/matrix interactions during and after PPG treatment, and the contributing parameters on such mechanisms, is a prerequisite for designing an effective water shut-off process and possible enhanced oil recovery (EOR). With this aim, the dynamic behavior of PPG samples is studied in two different fractured porous media representing the near wellbore area (dual permeability model) and deep in the reservoir zones (single permeability model). During encroachment of the gel particles in fracture, the dehydration of gel produces a large volume of filtrate which sweeps the oil inside the matrix. PPG particles might go through deformation, shrinkage and/or breakage, before infiltrating into pores of matrix where they form an impermeable cake. The experimental results shows that formation of such cake, is one of the main affecting parameters in the performance of the conformance control and EOR. Additionally, the affecting parameters such as concentration of nano-silica (n-SiO2), width of fracture, particles size, ionic strength of brine and injection rate of gel were examined. The concentration of n-SiO2 affects the gel loss factor (ratio of loss modulus to storage modulus) and hence its encroachment behavior. The gel sample with 1 wt% n-SiO2 has the highest loss factor which makes it more favorable for water shut-off considering lower injection pressure and less volume required for treatment. The water shut-off treatment is more effective in the case of systems with wider fractures. Based on the size of the PPG particles, the plugging mechanisms of the fracture can be either direct plugging, bridge plugging or a combination of both mechanisms, however all the studied samples provided same degree of plugging efficiency in the performed experiments. Swelling the samples in brines with higher salinities reduces the required volume of gel, while the injection pressure remained unaffected. To reduce the required volume of gel, highest possible injection rate is recommended, since the shear thinning rheology of the gel damps increment of injection pressure. In the case of single permeability model, water shut-off treatment reduced the fracture conductivity effectively, so that in the subsequent flooding, the injected brine was diverted toward matrix and the displaced oil was recovered through the fracture. During water flooding stage after gel placement, the withstanding pressure of PPG must be taken into account to avoid gel rupture, movement and washout.

Study Evaluates CO2 Storage Potential During CO2 Mobility-Control Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212969, “Evaluation of CO2 Storage Potential During CO2 Mobility-Control Optimization for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani, SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of Wyoming, et al. The paper has not been peer reviewed. _ CO2 mobility control through foam technology has enabled better sweep efficiency and, consequently, better oil productivity during enhanced oil recovery (EOR) processes. Along with enhancing oil production, a sound potential exists for in-situ generated foam to enhance CO2 storage. However, the effect of the different in-situ foam generation strategies on the combined goal of maximum oil production and carbon storage is not well elucidated in the literature. In the complete paper, the authors methodically evaluate the simultaneous optimization of CO2 storage and oil recovery using multiple injection strategies. Introduction The current investigation is a continuation of two previous studies that provided a methodology for screening and using foaming agents for optimized CO2 storage in sandstone and carbonate formations. A base case of tertiary CO2 flooding was established for comparison with in-situ foam generation by two approaches: single-cycle surfactant-alternating-gas (SAG) flooding and coinjection of CO2 and surfactant. Additionally, the effect of surfactant concentration on foam efficiency, CO2 storage capacity, and oil recovery were evaluated in both approaches at reservoir conditions. Materials and Methods Fluids and Porous Medium. In this study, a synthetic brine with total dissolved solids of 20 wt% was used as blank brine and laden with a commercial zwitterionic surfactant that was used to prepare surfactant solutions with concentrations of 0.5 and 1 wt% active matter in the synthetic brine. Three core plugs were drilled from an Indiana limestone outcrop block. The cores were then cleaned and oven-dried at 95°C. Experimental Procedure. Vacuum saturation with brine was commenced for the three cores. The porosity of the cores was calculated using their dry and brine-saturated weights. Then, the 100% brine-saturated core was placed in a core holder and loaded into an oven set to 90°C. The pore pressure was fixed at 2,000 psi, and the confining pressure was controlled at 3,000 psi throughout the flooding experiment. The brine permeability of the core samples was evaluated by measuring the pressure drop across the core at different brine-injection flow rates. In the first experiment (IL1), oil drainage with a flow rate of 0.2 cm3/min was performed to establish irreducible water saturation of 46.9%. This total flow rate was kept the same throughout the three experiments. Then, a waterflooding stage was begun and the oil recovery was recorded. After reaching a plateau in oil recovery, supercritical CO2 (scCO2) was injected during the EOR process until the oil production plateaued.

Experimental Study on Microscopic Water Flooding Mechanism of High-Porosity, High-Permeability, Medium-High-Viscosity Oil Reservoir

After the development of high-porosity, high-permeability, medium-high-viscosity oil reservoirs enters the high-water-cut stage, the remaining oil is highly dispersed on the microscopic scale, which leads to a change in the oil-water-flow law. If the enrichment and mobilization laws of the microscopic remaining oil cannot be truly and objectively described, it will ultimately affect the production of oil fields. At present, few studies have directly revealed the microscopic water flooding mechanism of high-porosity, high-permeability, medium-high-viscosity oil reservoirs and the main controlling factors affecting the formation of remaining oil. Starting with micro-physical simulation, this study explores the water flooding mechanism on the microscale, the type of remaining oil and its evolution law, and analyzes the main controlling factors of different types of remaining oil so as to propose effective adjustment and development plans for different types of remaining oil. It is found that this type of reservoir has a serious jet filtration phenomenon in the early stages of water flooding and is accompanied by the penetration of injected water, detouring flow, pore wall pressing flow, the stripping effect, and the blocking effect of the rock skeleton. The remaining oil is divided into five types: contiguous flake shape, porous shape, membrane shape, striped shape, and drip shape. Among them, the transformation of flake-shape and porous-shape remaining oil is greatly affected by the viscosity of crude oil. The decrease effect of crude oil viscosity on contiguous residual oil was as high as 33.7%, and the contiguous residual oil was mainly transformed into porous residual oil. The development of membrane-shape, striped-shape, and drip-shape remaining oil is more affected by water injection intensity. The decrease in water injection intensity on membrane residual oil was as high as 33.3%, and the membrane residual oil shifted to striped and drip residual oil. This paper classifies remaining oil on the microscopic scale and clarifies the microscopic water flooding mechanism, microscopic remaining oil evolution rules, and the main controlling factors of different types of remaining oil in high-porosity, high-permeability, medium-high-viscosity oil reservoirs.

Study on Residual Oil Distribution Law during the Depletion Production and Water Flooding Stages in the Fault-Karst Carbonate Reservoirs

The fault-karst carbonate reservoir is a new type of deep carbonate oil and gas resource and a target for exploration and development. The distribution of remaining oil in this kind of oilfield is very complicated because of its unique reservoir characteristics of vertical migration and accumulation, segmented accumulation, and differential accumulation. Therefore, the S91 reservoir block, a typical fracture-vuggy carbonate reservoir in the Tahe oilfield, was taken as the object of this research. According to the development characteristics as well as the porosity and permeability characteristics of the fracture-vuggy, the reservoirs were divided into three types: cave, pore, and fracture. A numerical simulation model of the fracture-vuggy reservoir of the S91 unit was established, and the historical fitting accuracy with dynamic production data was more than 90%. Then, the distribution characteristics of the remaining oil in the depletion stage of the fault-karst carbonate reservoir were further studied and based on the analysis of the reservoir water-flood flow line, the remaining oil distribution characteristics in the depletion stage of the fault solution reservoir were revealed. The results show that the remaining oil distribution patterns during the depletion production stage can be divided into three types: attic type, bottom water coning type, bottom water running type. Due to the serious problem of the bottom aquifer lifting caused by the reservoir development, the residual oil between wells was relatively abundant during the depletion production stage. According to the simulation results, the remaining oil distribution modes in the water drive development stage were identified as three types: sweeping the middle between wells, bottom water connection and circulation, and oil separation through high-permeability channels. In addition, the reservoir connectivity was the main controlling factor for the remaining oil distribution in the fault-karst carbonate reservoir.

Microbial communities succession post to polymer flood demonstrate a role in enhanced oil recovery.

The role of indigenous microbial communities in residual oil extraction following a recovery process is not well understood. This study investigated the dynamics of resident microbial communities in oil-field simulating sand pack bioreactors after the polymer flooding stage resumed with waterflooding and explored their contribution to the oil extraction process. The microbial community succession was studied through high-throughput sequencing of 16S rRNA genes. The results revealed alternating dominance of minority populations, including Dietzia sps., Acinetobacter sps., Soehngenia sps., and Paracoccus sps., in each bioreactor following the flooding process. Additionally, the post-polymer waterflooding stage led to higher oil recovery, with hydroxyethylcellulose, tragacanth gum, and partially hydrolyzed polyacrylamide polymer-treated bioreactors yielding additional recovery of 4.36%, 5.39%, and 3.90% residual oil in place, respectively. The dominant microbial communities were previously reported to synthesize biosurfactants and emulsifiers, as well as degrade and utilize hydrocarbons, indicating their role in aiding the recovery process. However, the correlation analysis of the most abundant taxa showed that some species were more positively correlated with the oil recovery process, while others acted as competitors for the carbon source. The study also found that higher biomass favored the plugging of high permeability zones in the reservoir, facilitating the dislodging of crude oil in new channels. In conclusion, this study suggests that microbial populations significantly shift upon polymer treatment and contribute synergistically to the oil recovery process depending on the characteristics of the polymers injected. KEY POINTS: • Post-polymer flooded microbial ecology shows unique indigenous microbial consortia. • Injected polymers are observed to act as enrichment substrates by resident communities. • The first study to show successive oil recovery stage post-polymer flood without external influence.

Investigation of the plugging capacity and enhanced oil recovery of flexible particle three-phase foam

In the later stage of water flooding in reservoirs, the oil production decreases. The stability of three-phase foam system is strong, enhancing oil displacement effects of ultrahigh water cut reservoirs. In this paper, the flow state of the foam system was studied by using a microscopic visualization model. Second, sandpack flooding experiments were performed to analyze the optimal plugging conditions of three-phase foam through resistance factors. Finally, single and parallel sandpack flooding experiments were carried out to analyze plugging effect and production conditions under different injection systems and permeability ratios. The research shows that three-phase foam is more stable and capable of plugging. The stable residual resistance factor after injection of the three-phase foam system is 172.75. When the foam and particles are injected simultaneously, the gas–liquid ratio is 1:1, the formation permeability is 5526.5 mD, and the plugging effect of three-phase foam is the best. The oil recovery increases by 24.9% after the injection of three-phase foam system. The three-phase foam system combines Jamin effect of foam and dynamic plugging characteristics of flexible particles. The highest oil recovery factor of 80.87% is achieved at a permeability ratio of 9.99. Three-phase foam flooding has broad application prospects.

Evolution Law of Dominant Flow Channel and Enhanced Oil Recovery Measures for Water Flooding in Reservoirs with Partially Sealed Faults.

The presence of strongly sealed faults can divide a reservoir into complex fault blocks, while partially sealed faults can be created by farewell faults within each block, leading to more intricate fluid migration and residual oil distribution. However, oilfields often overlook these partially sealed faults, focusing instead on the entire fault block, which can impact the efficiency of the production system. In addition, the current technology struggles to quantitatively describe the evolution of the dominant flow channel (DFC) during the water-flooding process, especially in reservoirs with partially sealed faults. This limits the ability to formulate effective enhanced oil recovery measures during the high water cut stage. To address these challenges, a large-scale sand model of a reservoir with a partially sealed fault was designed, and water flooding experiments were conducted. Based on the results of these experiments, a numerical inversion model was established. By combining percolation theory and the physical concept of DFC, a new method was proposed to quantitatively characterize DFC using a standardized flow quantity parameter. The evolution law of DFC was then studied, considering the variations of volume and oil saturation of DFC, and the water control effect of different measures was evaluated. The results revealed that, during the early stage of water flooding, a vertical uniform dominant seepage zone formed near the injector. As the water was injected, DFCs from the top of the injector to the bottom of the producers gradually formed in the unoccluded area. However, DFC was only formed at the bottom in the occluded area. During water flooding, the volume of DFC in each area gradually increased and then tended to stabilize. The development of the DFC in the occluded area lagged behind due to gravity and fault occlusion, leading to the formation of an unswept area near the fault in the unoccluded area. The volume of the DFC in the occluded area was the slowest, and the volume was the smallest after stabilization. Although the volume of the DFC near the fault in the unoccluded area grew the fastest, the volume was only higher than that in the occluded area after stabilization. During the high water cut period, the remaining oil was mainly distributed in the upper part of the occluded area, the area near the unoccluded fault, and the top of the reservoir in other areas. The plugging of the lower part of the producers can increase the volume of DFC in the occluded area, and the DFC moves up throughout the entire reservoir. This improves the utilization degree of the remaining oil at the top of the entire reservoir, but the remaining oil near the fault in the unoccluded area remains inaccessible. The combination of producer conversion, drilling infill wells, and producer plugging can alter the injection-production relationship and weaken the occlusion effect of the fault. The occluded area forms a new DFC, leading to a significant increase in the recovery degree. The deployment of infill wells near the fault in the unoccluded area can effectively control the area and improve the utilization of the remaining oil.

Frozen core experimental study on oil-water distribution characteristics at different stages of water flooding in low permeability oil reservoirs

The distribution pattern of oil and water in different stages of low permeability reservoirs is one of the main research topics in oilfield development. This paper takes low-permeability and tight oil reservoirs as the research object, systematically carries out experimental research on water flooding efficiency, and carries out theoretical comparative analysis. The innovations of this paper mainly include three aspect: (a) the experimental study of water drive efficiency under the conditions of different water drive stages is carried out, and the dynamic evolution characteristics of remaining oil distribution is analyzed. (b) The comparative analysis of water drive efficiency under different combination conditions of “permeability and crude oil physical properties” is studied. (c) The dynamic evolution mechanism of the coupling of “bound water - semi-bound water - free water” is explored by using the frozen core method. Results show that: (a) At the original oil bearing stage of the core in F Oilfield, the free microscale residual oil is the majority, followed by the bound and semi-bound residual oil. (b) Water flooding mainly develops the free residual oil. The remaining oil in clusters decreased from 22.35% to 2.21%. The residual oil in the form of inter-particle adsorption decreased from 28.56% to 2.53%. (c) It is difficult to develop bound and semi-bound residual oil in water drive. As the cluster like remaining oil is developed, the facial mask like remaining oil on the pore surface increases from 1.13% to 4.04%.

Experimental study on the plugging and profile control of preformed particle gels in high temperature and salinity reservoir

AbstractA novel modified polysaccharide composite preformed particle gel (MCPG) was synthesized as a profile control agent to improve the situation of high water cut and low oil recovery. Then, the structure of MCPG was characterized by Fourier transform infrared spectroscopy (FTIR), X‐ray diffraction (XRD), and environmental scanning electron microscope (ESEM). Subsequently, the impact of MCPG on enhanced oil recovery was investigated through nuclear magnetic resonance (NMR) and core displacement experiments. The results of FTIR, XRD, and ESEM indicate that monomers have been successfully intercalated into the layered structure of nanoscale sodium bentonite. In the condition of 130°C and salinity of 240,000 mg/L, the value of the swelling ratio and the toughness factor can reach about 30 and 0.87, respectively. The results of nonlinear fitting indicate that the relationship between the resistance coefficient and residual resistance coefficient with the matching coefficient (β) followed a power function, while the blocking water efficiency with β followed an exponential function. When the permeability ratio was as high as 30.58, MCPG still exhibited excellent profile improvement performance. NMR experiments proved that MCPG increased the displacement resistance in large pores and effectively enhanced the displacement efficiency in medium pores and small pores. The oil displacement efficiency in MCPG flooding and subsequent water flooding stages increased by 18.65% and 8.42%, respectively.

Experimental study on water flooding mechanism in low permeability oil reservoirs based on nuclear magnetic resonance technology

Low permeability oil reservoirs are characterized by complex pore-throat structure and complex mechanism of oil and water storage and transmission. At present, the research on cross-scale characteristics of pore-throat structure in low permeability reservoirs needs to be strengthened, and the research on oil-water evolution characteristics needs to be improved. In this paper, based on NMR method, different “porosity-permeability-original oil saturation” coupling evaluation systems are constructed, the study on oil and water distribution characteristics at different water flooding stages has been carried out, and the distribution mechanism of residual oil in pores with different sizes is analyzed. It is found out that: (a) the higher the core permeability, the lower the displacement pressure; the lower the core permeability, the higher the displacement pressure. (b) The T2 spectrum shows that micropores, mesopores and macropores in core samples are well developed. (c) The morphology of T2 spectrum can be divided into three types: high right peak and low left peak, high left peak and low right peak, and basically equal left and right peaks. In addition, under saturated oil conditions, medium and large pores are the main oil storage spaces. (d) There are three factors affecting the water flooding efficiency: the influence of micro-fractures, the influence of pore-throat heterogeneity and the influence of the degree of producing pore-throat.

Effect of CO2 Huff and Puff Rounds on Crude Oil Properties

In view of the deterioration of oil well liquid supply capacity and oil increase effect after multiple rounds of carbon dioxide (CO2) huff and puff, according to the actual conditions of the Ng12 reservoir in the XA oilfield, an indoor physical simulation experimental model was established. The experimental parameters were determined, five rounds of CO2 huff and puff experiments were carried out, and the crude oil produced in the water flooding stage and different rounds of CO2 huff and puff were collected. The effects of CO2 huff and puff rounds on crude oil viscosity, density, composition, paraffin content, and gum asphaltene content were studied. The results show that with the increase in CO2 huff and puff rounds, the viscosity and density of produced crude oil decrease. The content of light component (C2∼C6) and intermediate component (C7∼C10) increased, while the content of heavy component (C11+) decreased. CO2 has the strongest extraction effect on light components and the weakest extraction effect on heavy components. At the same time, the content of paraffin and gum asphaltene in the produced crude oil is reduced. For oil wells with multiple rounds of CO2 huff and puff, colloidal asphaltene precipitation inhibitor and scavenger should be considered to reduce the impact of colloidal asphaltene on formation permeability and liquid supply capacity.

Evaluating the performance of designed terpolymers for polymer flooding

AbstractIn this work, polymeric materials designed for enhanced oil recovery (EOR) were evaluated for their intended application. Properties including viscosity, flow through porous media (resistance factor and residual resistance factor), and heavy oil displacement (incremental oil recovery) were assessed for designed terpolymers of 2‐acrylamido‐2‐methylpropane sulphonic acid (AMPS), acrylamide (AAm), and acrylic acid (AAc). The same properties were evaluated for two commercially available reference materials (e.g., partially hydrolyzed polyacrylamides or HPAM) with similar characteristics, which allowed for direct comparison between the newly designed terpolymers and materials that are currently on the market for the polymer flooding application. The incremental oil recovery directly associated with polymer flooding, which includes both the polymer flooding and post‐polymer waterflooding stages (excluding the initial waterflooding injection (or secondary) oil recovery), demonstrates that the designed terpolymers provided a higher incremental recovery (42% and 58%) than the reference materials (33% and 46%). Therefore, the terpolymers provided a higher contribution to incremental (or enhanced) oil recovery than the typical HPAM. Additionally, both designed terpolymers showed better injectivity in unconsolidated porous media and are less likely to cause plugging than the commercially available reference materials. Therefore, using a targeted design approach ultimately led to polymeric materials with excellent performance for EOR polymer flooding applications.