Core Displacement Experiments Research Articles

Stimulation and Sequestration Mechanism of CO2 Waterless Fracturing for Continental Tight Oil Reservoirs.

CO2 fracturing is a promising technology for oil field development in tight, continental deposits, with potential advantages of enhanced oil recovery (EOR), CO2 sequestration, and water conservation. Compared with CO2-EOR techniques, such as CO2 huff and puff and CO2 flooding, CO2 can interact with reservoir rock and fluid under higher pressure conditions during fracturing, resulting in CO2 stimulation and sequestration effects that differ from those that occur during conventional CO2-EOR. In this paper, the CO2 interactions between CO2 and reservoirs in continental tight oil reservoirs under fracturing conditions are systematically studied through laboratory experiments. The results show that under high pressure, CO2 effectively changes the pore structure through the extraction of hydrocarbons, dissolution of the rock matrix, and migration of minerals. CO2 dissolution of the rock matrix can significantly increase the number and complexity of fractures. Furthermore, CO2 has a higher solubility in formation fluid under high-pressure conditions. Given the higher pressures, CO2 forms a miscible phase with crude oil, diffuses more deeply into the formation, and reacts fully with the reservoir minerals and fluid during CO2 fracturing. Accordingly, CO2 can improve the permeability of the reservoir and flowability of crude oil significantly. Hence, CO2 fracturing can enhance oil recovery and CO2 sequestration more effectively. Core displacement experiments indicate that oil recovery of CO2 soaking process after CO2 fracturing is 36%, which is 12% and 9% higher than those of CO2 huff and puff and CO2 flooding with 5 pore volume, respectively. Field tests show that average oil production after CO2 fracturing is 1.42 times higher than that after CO2 flooding, which further validates the advantage of CO2 fracturing and demonstrates its huge application potential.

Migration and plugging characteristics of polymer microsphere and EOR potential in produced-water reinjection of offshore heavy oil reservoirs

Due to the strong heterogeneity, the infaust mobility ratio of offshore heavy oil reservoirs and the high cost of produced water treatment, a “green” in-depth profile control technology was proposed, which integrated produced water reinjection and microsphere in-depth profile control and displacement technology. Experimental results show that RGO-PMSs maintained to be spherical and expanded 5.2–6 time after aging 15 days in brine. While the size of RGO-PMSs aggregation increased 15–25 times, which induced the enhancement of plugging efficiency when permeability was higher than 3000 mD. During RGO-PMSs migration in porous media, it could adjust profile by adsorbing on rock surface or forming plugging in the forms of single capture, bridging, and accumulation. Due to the elastic deformation ability of RGO-PMSs, the particles could enter in-depth reservoirs to form plugging and modulate profile. Moreover, RGO-PMSs system injection and subsequent water flooding could enhance the oil recovery in high permeability layer and low permeability layer of 31.3% and 73.5%, respectively in parallels core displacement experiments. It is believed that the proposed produced water injection combined with RGO-PMSs could be a potential “green” candidate for enhancing oil recovery in offshore heavy oil reservoirs.

Pore-Scale Investigation of Microscopic Remaining Oil Variation Characteristic in Different Flow Rates Using Micro-CT

The main means of secondary oil recovery is water flooding, which has been widely used in various oilfields. Different flow rates have a great impact on the recovery ratio and the occurrence of remaining oil. Scholars have carried out extensive research on it, but mostly on the macro scale, and research on the three-dimensional micro scale is also limited by accuracy and a lack of accurate understanding. In this paper, micro-CT and core displacement experiments are used to intuitively show the occurrence state of remaining oil under different flow rates. Through a series of quantitative image processing methods and remaining oil classification methods, the occurrence characteristics of remaining oil under different flow rates are systematically evaluated and studied. The results show that: (1) As the displacement rate increases, the remaining oil saturation decreases (61%; 35%; 23%), but the remaining oil is more evenly distributed along the slice; (2) Two lower displacement speeds (0.003 mL/min; 0.03 mL/min) can reduce the volume of huge oil clusters under oil-saturated conditions, and the highest displacement speed (0.3 mL/min) can completely break up large oil clusters into small oil droplets. At the same time, the shape factor of the oil clusters also gradually increases; (3) The proportion of continuous remaining oil volume decreases, and the proportion of discontinuous remaining oil increases. Discontinuous remaining oil is the main production target of EOR; (4) After water flooding, the microscopic remaining oil is more inclined to the middle and corner parts of the larger pores.

Influence of permeability on the minimum miscibility pressure between CO2 and crude oil

The slim tube test is the industry standard for measuring the minimum miscibility pressure at present. However, there is a huge gap between the pore parameters of the slim tube model and the actual reservoir, especially the influence of permeability on MMP is not considered. The previous studies have shown that the minimum miscibility pressure is related to the pore structure and permeability of the reservoir. It is believed that there are some theoretical defects in the MMP measured by the slim tube test. This paper aims at the defect of slim tube test, core displacement experiment is carried out by using natural core to measure the minimum miscibility pressure under different permeability, and to reveal the law of the influence of permeability on the minimum miscibility pressure.

Mechanism of Enhanced Oil Recovery for In-Depth Profile Control and Cyclic Waterflooding in Fractured Low-Permeability Reservoirs

When fractured low-permeability reservoirs enter a high water cut period, injected water always flows along fractures, water cut speeds increase rapidly, and oil production decreases quickly in oil wells. It is difficult to further improve the oil recovery of such fractured low-permeability reservoirs. In this paper, based on the advantages of in-depth profile control and cyclic water injection, the feasibility of combining deep profile control with cyclic water injection to improve oil recovery in fractured low-permeability reservoirs during the high water cut stage was studied, and the mechanisms of in-depth profile control and cyclic waterflooding were investigated. According to the characteristics of reservoirs in Zone X, as well as the fracture features and evolution mechanisms of the well network, an outcrop plate fractured core model that considers fracture direction was developed, and core displacement experiments were carried out by using the HPAM/Cr3+ gel in-depth profile control system. The enhanced oil recovery of waterflooding, cyclic water injection, and in-depth profile control, as well as a combination of in-depth profile control and cyclic water injection, was investigated. Moreover, variations in the water cut degree, reserve recovery percentage, injection pressure, fracture and matrix pressure, and water saturation were monitored. On this basis, the mechanism of enhanced oil recovery based on the combined utilization of in-depth profile control and cyclic waterflooding methods was analyzed. The results show that in-depth profile control and cyclic water injection can be synchronized to further increase oil recovery. The recovery ratio under the combination of in-depth profile control and cyclic water injection was 1.9% higher than that under the in-depth profile control and 5.6% higher than that under cyclic water injection. The combination of in-depth profile control and cyclic water injection can increase the reservoir pressure; therefore, the fluctuation of pressure between the matrix and its fractures increases, more crude oil flows into the fracture, and the oil production increases.

The experimental investigation of the HPAM/phenolic resin deep profile system in fractured low-permeability reservoirs

The problem of injected water channeling along fractures exists in the process of water injection in fractured low permeability reservoir, aimed at this problem, deep profile control technology applies to plug fractures to improve the recovery of low permeability reservoir. In this paper, partially hydrolyzed polyacrylamide (HPAM) is used as water-plugging/profile-modifying agent and phenolic resin as crosslinker agent. Several profile control systems are tested to find the one which is suitable for fractured low permeability reservoirs. The performances of profile control systems are evaluated, and effects of formation water salinity, that of shearing rate and that of temperature on the performance are studied. Finally, in order to study effects of this profile control system on displacing oil, flowability experiment and core displacement experiment are applied. It shows that with the increase of salinty of prepared water and the increase of the shearing rate, the viscosity of this system decreases. With the increase of temperature, the gelling time shortens, the viscosity increases, but the stability weekens. This kind of profile control system has a good effect on plugging fractures of low permeability cores. After water flooding, this kind of profile control system is injected into cores, the recovery ratio can increase 3.5%. So the profile control system composed of HPAM/ phenolic resin can apply to deep profile control in fractured low permeability reservoir to enhance oil recovery.

Research on Targeted Acidizing Technology in Long Horizontal Section of Carbonate Reservoir

The upper layer of Oil field A is developed by horizontal linear well pattern with long well segment. After completion, there is relatively serious formation damage, and the tested epidermal factor is up to 6.21 on average. Due to the length of horizontal well section and the serious vertical heterogeneity of formation, some strata were over-acidized in the early stage, so it was very difficult to distribute acid evenly. For this reason, the low contribution layer of horizontal section was determined by using amino carboxylic acid system and coiled tubing hydrojet acidification process, combined with reservoir characteristics, and the spindle-type acid distribution method was adopted to optimize nozzle combination parameters to predict construction displacement and ground construction pressure. The laboratory experiment was carried out to compare with the conventional acid system for core displacement experiment. The acid could form acid-etch wormhole, effectively extend the acid-action distance, and achieve the purpose of slow and deep penetration.

Study of Polymer Flooding in Heterogeneous Porous Media by Using Nuclear Magnetic Resonance

Polymer has been successfully used to enhance crude oil recovery at high water cut stage. However, the application of polymer flooding is limited by the heterogeneity of reservoir. In this work, the role of polymer flooding in heterogeneous reservoir was explored by nuclear magnetic resonance (NMR) spectroscopy. Parallel core displacement experiments were carried out to study polymer flooding in heterogeneous formation. The results showed that the polymer flooding area was related to permeability and pore connectivity. At the end of the water flooding stage, the residual oil was not evenly distributed in porous media. The percent crude oil recovery increased with the increase of pore diameter. Crude oil recovery from cores with larger pores was higher, and water broke through the highly permeable core first. After 0.3 PV polymer injection, the water mobility of the high permeability core decreased. Polymer injection showed a dual effect, an oil displacement effect and a traction effect. The oil displacement effect was responsible for driving out the crude oil in large pores, whereas the traction effect was responsible for driving out residual oil from small pores. After 1 PV polymer injection, the polymer solution channeled through the highly permeable core rapidly. The crude oil in large pores was washed out completely. The NMR water-phase spectrum line of the highly permeable core was much higher than that of the low permeable core. Under different core permeability and porosity, the NMR peak of the crude oil-phase spectrum line indicated that the polymer flooding is mainly effective on pores > 40 μm.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Experimental Investigation on a Novel Polyelectrolyte Molecular Deposition Film for Improved Injectivity in Low-Permeability Reservoirs.

Acrylamide and dimethyl diallyl ammonium chloride were used as monomers to synthesize a polyelectrolyte molecular deposition film (PMDF) injection agent for solving the problem of high injection pressure of water wells in low-permeability reservoirs. The structure of the PMDF injection agent was determined through IR and 1H nuclear magnetic resonance (NMR). The performance evaluation results show a change of wettability from hydrophilic to neutral wetting with the contact angle changing from 22.32 to 73.31° because of agent injection. It can also change the negative ζ-potential on the surface of the sand to a positive value. For comparison, core displacement experiments involving the commercial Gemini surfactant DF-G reveal that the effects of the depressurization of PMDF are more obvious than those of DF-G. The adsorption stability of the former is better than that of the latter. Especially, under a high-speed water flow of 30 pore volume (PV) injection, the depressurization rate of PMDF is still as high as 43.59%. Finally, the oil–water relative permeability curves and core nuclear magnetic resonance (NMR) experiments demonstrate that the PMDF treatment can reduce the irreducible water saturation, which indicated that the porosity of the flowable part of the core increased and the swept volume was increased. The suitable range of PMDF according to NMR pore-radius distribution within a low-permeability reservoir: the flowable partial pore required the throat radius greater than 0.01 μm.

Removal of Ca2+ and Mg2+ from oilfield wastewater using reusable PEG/Fe3O4/GO-NH2 nanoadsorbents and its efficiency for oil recovery

The high salinity of oilfield-produced water caused by the presence of metal ions, such as Ca2+ and Mg2+, has a significantly adverse effect on oil recovery. It is crucial to remove these metal ions efficiently before the oilfield wastewater is reinjected down into the oil wells. To address this issue, we prepared a PEG/Fe3O4/GO-NH2 nanoadsorbent by aminating GO, incorporating magnetic Fe3O4 nanoparticles and coating with PEG (PEG = poly(ethylene glycol); GO-NH2 = aminated graphene oxide). We investigated the removal ratios of the nanoadsorbent for Ca2+ and Mg2+. The respective removal ratios for Ca2+ and Mg2+ reached 69.8 % and 61.1 % at 10 min, indicating that the nanoadsorbent was capable of efficiently removing Ca2+ and Mg2+. We also evaluated the reusability of the nanoadsorbent by recycling and reusing it 5 times. At the fifth recycling run, the nanoadsorbent retained relatively high reuse rates (79.1 % for Ca2+, 69.5 % for Mg2+) and removal ratios (69.5 % for Ca2+, 64.3 % for Mg2+), suggesting that the nanoadsorbent possessed relatively high reusability. Oilfield wastewater treated with the nanoadsorbent was employed for oil recovery in core displacement experiments. The oil recovery efficiency significantly increased by 11.8 % compared with untreated oilfield wastewater. Therefore, the PEG/Fe3O4/GO-NH2 nanoadsorbent exhibits considerable potential for the treatment of oilfield wastewater to enhance oil recovery.

Experimental evaluation of live oil oxidation together with its physical properties during air injection in a tight oil reservoir

In this paper, an integrated and pragmatic framework has been developed to experimentally determine the live oil oxidation with its physical properties and evaluate performance of air injection in a tight reservoir. In addition to continuously measuring interfacial tension, slim tube tests were performed to monitor and quantify miscibility between air and live oil collected from the Upper Triassic Yanchang Formation of the Chang 7 tight oil reservoir in the Ordos Basin, China. The displacement experiments showed that oil recovery factor of air injection is obviously higher than that of nitrogen injection in core plugs collected from the tight oil reservoir, while static and dynamic oxidation experiments were then conducted to identify the inherent oxidation mechanisms. The comparative core displacement experiments of live oil by air and nitrogen injection under reservoir temperature and pressure were carried out to evaluate the enhanced oil recovery (EOR) performance of air injection. It is found that heat released by the oxygen addition reaction under the formation conditions of 60.0 °C and 16.00 MPa leads to the bond scission reaction. The gas generated by the bond scission reaction forms a flue gas displacement front together with the remaining nitrogen contained in the air. Although miscibility cannot be achieved, air injection followed by the oxygen addition reaction and the bond scission reaction can reduce oil viscosity and thus increase its flowability. As for the commonly experimental studies with dead oils excluding porous media, the oxidation degree and the corresponding physical properties are normally overestimated since light components are limited in the dead oils and porous media constrain the corresponding oxidation.

Characteristics of Weak-Gel Flooding and Its Application in LD10-1 Oilfield.

Weak gel is a kind of three-dimensional cross-linking system with low polymer concentration and appropriate cross-linking agents, dominated by intermolecular cross-linking, supplemented by intramolecular cross-linking, and with a weak cross-linking degree. In this paper, the microstructure and properties of the weak gel were observed and evaluated under different conditions. Seepage behavior experiments and parallel core displacement experiments were carried out to evaluate profile control and flooding performance of the weak gel. Under a certain polymer concentration, with the increase in cross-linker concentration, the reticular structure of the weak gel becomes more uniform and the strength of the weak gel was further enhanced. Weak gel has more retention in porous media and greater strength. The profile control and flooding performance of the weak gel are much better than those of the polymer. A field test of weak-gel flooding was successfully carried out in LD10-1 oilfield. Most of the production wells around the weak gel injection wells responded after weak-gel injection and the accumulative oil incremental oil production of the test area was 57.8 × 104 m3 up to December 2018.

Experimental investigation on stable displacement mechanism and oil recovery enhancement of oxygen-reduced air assisted gravity drainage

The effects of gravity, capillary force, and viscous force on the migration characteristics of oil and gas interface in oxygen-reduced air-assisted gravity drainage (OAGD) were studied through a two-dimensional visualization model. The effects of bond number, capillary number and low-temperature oxidation on OAGD recovery were studied by long core displacement experiments. On this basis, the low-temperature oxidation number was introduced and its relationship with the OAGD recovery was established. The results show that the shape and changing law of oil and gas front are mainly influenced by gravity, capillary force and viscous force. When the bond number is constant (4.52×10 −4 ), the shape of oil-gas front is controlled by capillary number. When the capillary number is less than 1.68×10 −3 , the oil and gas interface is stable. When the capillary number is greater than 2.69×10 −2 , the oil and gas interface shows viscous fingering. When the capillary number is between 1.68×10 −3 and 2.69×10 −2 , the oil and gas interface becomes capillary fingering. The core flooding experiments results show that for OAGD stable flooding, before the gas breakthrough, higher recovery is obtained in higher gravity number and lower capillary number. In this stage, gravity is predominant in controlling OAGD recovery and the oil recovery could be improved by reducing injection velocity. After gas breakthrough, higher recovery was obtained in lower gravity and higher capillary numbers, which means that the viscous force had a significant influence on the recovery. Increasing gas injection velocity in this stage is an effective measure to improve oil recovery. The low-temperature oxidation number has a good correlation with the recovery and can be used to predict the OAGD recovery.

Experiment investigation of microemulsion enhanced oil recovery in low permeability reservoir

Microemulsion flooding is a effective enhanced oil recovery for low permeability. In this paper, combined the advantage of sulphobetaine surfactant and gemini surfactant, a kind of gemini sulphobetaine surfactant (DPSB) was used to prepared microemulsion. The oil–water interfacial tension and adsorption for different concentration surfactant was measured to evaluate the DPSB property. The stability of microemulsion, the microemulsion volume percentage, solubilisation parameter and relative phase volume, microemulsion viscosity was also measured. The performance of this surfactant was further optimized by adding the additives. The relative permeability was determined to analyze the fluid flow characteristics, and the recovery efficiency was studied through natural core and visual core displacement experiment. The results show that the oil–water interfacial tension is 9.1 × 10−4 mN/m when DPSB concentration is 0.5%, and it can still maintain low interfacial tension after adsorption. The interfacial tension can be further decreased by adding n-butyl alcoholy. When the DPSB concentration is 1.5% and n-butyl alcohol concentration is 1.5%, the microemulsion volume percentage is 31%, and the viscosity is 4.37 mPa∙s. It can reduce the flow velocity of displacing fluid, and expand sweep volume. Compared with water flooding, the residual oil saturation reduces by about 30% in microemulsion flooding. The recovery efficiency is increased by about 4% compared with the low concentration of surfactant flooding.

Analysis on Mechanism to Improve the Recovery in Tight Oil Reservoirs by Imbibition

In order to explore the mechanism to improve the recovery percent in tight oil reservoirs, the mechanisms and main controlling factors of improving the recovery percent by different production mechanisms are analyzed by combining spontaneous imbibition, core displacement experiment and nuclear magnetic resonance (NMR) test. It is shown by the study that the recovery percent can be improved from 20% to more than 40% by increasing the displacement differential pressure for tight rock samples. During differential pressure displacement, the reservoir fluid in large and medium pores is mostly produced. It is proven by the pressured imbibition experiment that in the process of soaking, the fluid exchange between fractures and matrix and between large and small pores can be realized to improve the recovery percent of fine pores, and the recovery percent (mainly of fine pores) can be improved by 7-10% through pressured imbibition displacement. Large contact area caused by the complex fractures formed by stimulated reservoir volume (SRV) fracturing is the basis to improve the recovery percent by imbibition, but the recovery percent of simple fractures is limited. The research results of this paper will provide guidance for the stimulation technology and fluid system optimization to improve the recovery percent of tight oil.

Novel Spherical Polymer Sealing Agent for Oil-Based Drilling Fluids to Overcome Borehole Instability Problem in Low Permeability Reservoirs

Due to borehole instability problem in low permeability formations, a new type of spherical polymer sealing agent (OLBS) for oil-based drilling fluids was prepared via suspension polymerization, and the sealing effect of polymer sealing agent on low permeability cores was evaluated. The results indicated that OLBS had no influence on the rheological properties of oil-based drilling fluids. The core displacement experiments indicated that OLBS could reduce the core permeability by a significant amount, and thus stop fluid invasion into the formations, so OLBS could provide an excellent sealing effect and improve wellbore strength. Using this polymer sealing agent to plug the low permeability formations is a very powerful approach to address borehole instability problem in troublesome low permeability formations. This sealing agent is suitable for the drilling of long sections of horizontal laterals. In the future, the oil-based drilling fluids containing OLBS might hold great promise to resolve borehole instability problem in low permeability formations.

Effect of a Partial Pressure Tool on Improving the Heterogeneous Oil Recovery and Polymer Solution Microstructure.

To improve the oil displacement effect of polymer solutions in heterogeneous oil layers and increase the energy utilization rate, Daqing Oilfield proposes a partial pressure tool to control the polymer solution injection amount in high-permeability oil layers and increase the injection amount in low-permeability oil layers to enhance the total oil recovery. To study the effect of the partial pressure tool on enhancing oil recovery and the action mechanism of the tool on polymer molecules in high-permeability reservoirs, core displacement experiments were performed to study the effects of various factors on oil recovery. Microscopic experiments were then carried out to study the differences in molecular morphology and molecular coil size of the microscopic polymer solution before and after the action of the partial pressure tool. The experimental results show that the partial pressure tool increased the oil recovery by 4.4% and that the throttling pressure difference was directly proportional to the oil recovery. The partial pressure tool subjected the polymer solution to shear deformation and reduced the molecular coil size. When the concentration of the solution was changed, the degree of change in the molecular structure and the coil size was small, and the influence on the oil displacement effect was minimal. This experiment is of great significance for improving the energy utilization rate.

Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs.

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

Experimental investigation on plugging and transport characteristics of Pore-Scale microspheres in heterogeneous porous media for enhanced oil recovery

To reduce water cut and improve sweep efficiency of water flooding, a novel pore-scale microsphere (NMPS) as profile control agent was firstly prepared through inverse emulsion polymerization technology. Then, its physical properties were investigated, including morphology, particle size distribution, elasticity, swelling property and long-term stability. Subsequently, the plugging and transport characteristics of NMPS were studied through dual parallel core displacement experiments. And then, oil displacement efficiency was evaluated through dual parallel core displacement experiments and nuclear magnetic resonance (NMR) experiment. Experimental results demonstrated NMPS possessed favorable elasticity, water swelling property, dispersibility and long-term stability with an initial average particle size of 7.58 μm. Also, NMPS could effectively plug high permeability channel and regulate heterogeneity. Moreover, NMPS effectively diverted subsequent injected water into low permeability zone and improve sweep efficiency. As a result, 10.83–31.6% of crude oil was produced during NMPS flooding and subsequent water flooding. It was believed that NMPS was a promising candidate for heterogeneity reduction and oil recovery enhancement.