Improve Oil Displacement Efficiency Research Articles

Synthesis and properties of AM/AMPS/MMA and cationic monomer copolymer flooding agent

Abstract A novel hydrophobic association copolymer (PAMA) was synthesized by incorporating acrylamide (AM), 2-acrylamide-2-methylpropanesulfonic acid (AMPS), cationic monomer (MEDDA), and methyl methacrylate (MMA). The properties of MMA copolymers with varying contents were analyzed using infrared spectroscopy, nuclear magnetic resonance spectroscopy, and scanning electron microscopy. Optimal overall performance of the solution was achieved when the MMA content reached 1.4 % w/w. Compared to pure PAAM (without MMA), the PAMA-1.4 % polymer exhibited superior viscoelasticity, temperature resistance, and shear resistance. This enhancement in PAMA performance can be attributed to the significant inhibition of intermolecular water film formation within the polymer matrix by MMA, effectively improving and regulating solution solubility while strengthening molecular chain interactions and enhancing the structural network strength of PAMA polymers. Additionally, the inclusion of MMA transformed rock surfaces from non-wetting to wetting conditions, thereby greatly improving oil displacement efficiency. In displacement experiments, PAMA-1.4 % performed better in terms of enhanced oil recovery, the recovery rate of 0.1 % w/w PAMA-2.4 % solution is only 7.78 %, while the recovery rate of 0.1 % w/w PAMA-1.4 % solution is 13.06 %.

Effect of permeability on displacement efficiency and dominant oil–displacement mechanism in surfactant flooding

Interfacial tension (IFT) reduction and emulsification are two important mechanisms of surfactant flooding. However, for light oil reservoirs with different permeabilities, whether which mechanism is more important in improving displacement efficiency remains unclear. In this study, surfactants with strong emulsifying properties and ultralow IFT were screened using an interfacial tensiometer and a self-developed emulsification performance tester. The ability of the two surfactants to improve displacement efficiency was compared through a series of core flooding experiments. Experimental results showed that the surfactant with ultralow IFT did not have strong emulsifying properties. With the decrease in permeability, the oil displacement efficiency improved by emulsification increased first and then decreased, whilst that improved by IFT reduction declined. Moreover, IFT reduction was the dominant mechanism to improve oil displacement efficiency in medium-high and ultralow permeability reservoirs, whilst emulsification was dominant in low permeability reservoirs. The comprehensive utilization of multiple mechanisms and the combination of technologies should be considered when surfactant flooding is used in reservoirs with ultralow permeability. This work advances our current understanding of surfactant flooding and provides a reference for the formulation of plans to enhance oil recovery in light oil reservoirs.

Application of Polymeric CO2 Thickener Polymer-Viscosity-Enhance in Extraction of Low-Permeability Tight Sandstone.

The conventional production technique employed for low-permeability tight reservoirs exhibits limited productivity. To solve the problem, an acetate-type supercritical carbon dioxide (scCO2) thickener, PVE, which contains a large number of microporous structures, was prepared using the atom transfer radical polymerization (ATRP) method. The product exhibited an ability to decrease the minimum miscibility pressure of scCO2 during a solubility test and demonstrated a favorable extraction efficiency in a low-permeability tight core displacement test. At 15 MPa and 70 °C, PVE-scCO2 at a concentration of 0.2% exhibits effective oil recovery rates of 5.61% for the 0.25 mD core and 2.65% for the 5 mD core. The result demonstrates that the incorporation of the thickener PVE can effectively mitigate gas channeling, further improve oil displacement efficiency, and inflict minimal damage to crude oil. The mechanism of thickening was analyzed through molecular simulation. The calculated trend of thickening exhibited excellent agreement with the experimental measurement rule. The simulation results demonstrate that the contact area between the polymer and CO2 increases in direct proportion to both the number of thickener molecules and the viscosity of the system. The study presents an effective strategy for mitigating gas channeling during scCO2 flooding and has a wide application prospect.

The effect of amphiphilic monomer on the interaction between amphiphilic polyacrylamide and crude oil on the solid surface

Hydrophobically modified polyacrylamide (HMPAM) is one of most used amphiphilic polymers for polymer flooding in oilfield. The interaction between HMPAM and crude oil is key to the oil displacement efficiency of HMPAM. However, due to the lack of experimental research method, there is little research on this aspect. In this work, HMPAMs containing different types of amphiphilic monomers were prepared, their interactions with crude oil were studied by dual polarization interferometry (DPI) for the first time, and their adsorption conformations on the surface of crude oil were discussed. The DPI results directly shown that the influence of amphiphilic monomer type on the interaction strength was as follows: nonionic type > cationic type ≈ anionic type. This order was consistent with the adsorption capacity of amphiphilic monomer on the surface of crude oil, indicating that the interaction strength between HMPAM and crude oil mainly depended on the type of amphiphilic monomers. In addition, the DPI results indirectly shown that the effect of amphiphilic monomer type on the HMPAM molecular coiled conformation on the surface of crude oil was also determined by the adsorption capacity of amphiphilic monomer. The research results of this paper can provide useful information for the amphiphilic monomer selection from the perspective of improving oil displacement efficiency of HMPAM.

Pickering high internal phase emulsions stabilized by metal-organic framework nanoribbons

Pickering high internal phase emulsions (HIPEs) stabilized by colloidal particles are of great practical significance in the formulation of food, pharmaceutical, cosmetic, paint products and the chemical oil flooding. Herein, we report that a manganese-based metal–organic framework (MOF) (Mn3(BTC)2 (BTC = 1,3,5-benzenetricarboxylate)) nanoribbons synthesized by a simple solution method can stabilize water-in-oil (W/O) high-viscosity Pickering HIPEs with crude oil as oil phase for more than one month at 43 °C. The Mn3(BTC)2 nanoribbons assemble at the oil/water interface of HIPE, owing to its advantageous structural features with the size of several micrometers, thickness of about 100 nm and amphiphilicity originated from the hydrophilic metal ions and hydrophobic organic ligands. The phase behavior and properties of the as-prepared HIPEs strongly depend on the MOF concentration (CMOF) and internal phase volume fraction of water (Fw) of emulsion. The MOF dispersions and crude oil are miscible into stable W/O HIPEs at Fw = 75 % when the CMOF ranges from 50 ppm to 5000 ppm. More interestingly, the viscosity of W/O emulsions greatly increases as the Fw varying from 50 % to 80 % and a viscosity of 4.5 Pa·s is obtained at CMOF = 2000 ppm and Fw = 80 %, which is nearly 400 times higher than that of crude oil. Moreover, the pressure generated by HIPEs flowing in core is about 40 times more than that of water injection and can remain the highest stable value substantially. These results show that the MOF dispersions are favorable to form stable W/O emulsions with high internal phase volume fraction, which has a great potential in improving oil displacement efficiency of chemical flooding.

Investigation on displacement efficiency and enhance oil recovery performance of CO2 and CO2-chemical additive composite system flooding using LBM simulation

CO2 flooding is a promising EOR method. Chemical additives reduce oil viscosity and CO2-oil interfacial tension. In this study, we propose a multiphase and multi-component model based on the LBM to examine the effectiveness of CO2 flooding and identify the factors that influence its performance. Additionally, we present a novel approach for simulating CO2-chemical additive composite system (CCAS) flooding by modifying fluid interaction parameters and reducing oil viscosity when exposed to chemicals. A comparison was conducted between the CO2 flooding approach and the CO2-chemical additive compound systems. The results show that the force between fluid molecules has a significant impact on interfacial tension and miscibility, affecting the displacement process. The viscosity and injection speed of the displaced fluid play a crucial role in determining the initial momentum and CO2 displacement performance. Additionally, reservoir rock morphology has an impact on the velocity of fluid molecules, and affects the displacement efficiency. The CCAS flooding has the potential to increase oil recovery by 15% compared to using CO2 flooding alone. Optimizing additive concentration, injection timing, and injection rate can further improve oil displacement efficiency by 5%-10%. Valuable theoretical guidance for applying CO2 chemical additives is provided by these research findings.

Iso-Permeability Point Trail Method to Determine the Relative Permeability Curve for a New Amphiphilic Polymer Flooding

Amphiphilic-polymer flooding, which can increase water viscosity, decrease oil viscosity, and improve oil displacement efficiency, is a promising oil exploitation method for heavy oil. Due to oil–water emulsification, shear-thinning, and changes in oil viscosity when determining the relative permeability data of new amphiphilic polymers, the conventional J.B.N. method is not accurate. This paper presents a new method called the iso-permeability point trial method to determine the relative permeability curve by combining the J.B.N. method, the Corey model, and the relationship between water saturation and the relative permeability ratio. To avoid using polymer viscosity, a mathematical equation was derived based on the characteristics of the relative permeability curve. The results indicate that the new method is feasible and the obtained curve is more reasonable and smooth. The influence of concentration, permeability, and oil viscosity on amphiphilic-polymer displacement relative permeability was also analyzed, demonstrating that under the same water saturation, the water relative permeability is lower than that of water flooding but the oil relative permeability is bigger, which manifests as the iso-permeability point moves to the right and results in a lower residual oil saturation. In addition, the aforementioned trends are more obvious when the amphiphilic-polymer concentration is high, formation permeability is low, and oil viscosity is low.

Application status and prospect of ionic liquids in oilfield chemistry

The ionic liquid, as a new treatment agent, has been increasingly applied in oil fields due to its strong temperature resistance, good solubility and high surface activity. In this paper, we systematically discuss the action mechanism and application effect of ionic liquids in oilfield chemistry. Ionic liquids can inhibit shale hydration expansion and reduce fluid loss through adsorption and intercalation, inhibit the formation of natural gas hydrate through imidazole five-membered ring structure as a space barrier, reduce viscosity of heavy oil by breaking chemical bonds of heavy oil macromolecules and charge transfer, improve oil displacement efficiency by forming ions pairs with carboxyl groups in crude oil, demulsify by forming channels between dispersed water droplets, acidify the formation by reacting with water to produce acid, interacts with organic material through weak hydrogen bonds and extracts it from oilfield wastewater, desulphurize by inserting sulfide molecules into the “stack” structure and form liquid inclusion complex, inhibit corrosion by forming a protective film on the metal surface. Based on the above aspects, the development direction of ionic liquids is proposed. The application of ionic liquids in oilfield chemistry is still in its infancy. It is urgent to fully explore the application performance of ionic liquids in oilfield chemistry, which also provides theoretical and technical supports for efficient reservoir development.

Visual experiments of bottom water and multi-well water and gas injection flooding for fault-controlled fractured-vuggy reservoirs

For fault-controlled fractured-vuggy reservoirs, the development characteristics of bottom water flooding and water and gas injection flooding under multi-well conditions must be clarified due to the structural complexity. To address this issue, we designed and manufactured fault-controlled physical experimental models based on the geological model of Tarim Oilfield and conducted flooding experiments. The results demonstrate significant variations in bottom water flooding characteristics due to differences in flow capacity within fractures, cavity area in caves, and filled area in caves under different filling modes. Different bottom water rates exhibit varying abilities to overcome gravity and breakthrough capillary resistance, significantly impacting the bottom water flooding characteristics. During the bottom water flooding period, the positioning of production wells primarily affects the macroscopic sweep range, while the filling modes significantly influence the distribution of remaining oil within individual caves. Throughout the three periods of multi-well water and gas injection, the early water injection stage mainly focuses on mobilizing “insufficiently controlled remaining oil” and some “attic remaining oil,” and the middle gas injection stage primarily targets the attic remaining oil. Finally, the late water injection stage aims to lift the oil–gas–water interface and improve oil displacement efficiency. Furthermore, different water and gas flooding directions affect displacement resistance in each channel and the longitudinal sweep range. This paper identifies the direction for the life cycle production of fault-controlled fractured-vuggy reservoirs and presents a mechanistic explanation.

Oil displacement performance and mechanism of Interfacially Active polymer (IAP)-Emulsifying viscosity Reducer (EVR) supramolecular compound system in heterogenous heavy oil reservoirs

Chemical Cold Heavy Oil Production (CCHOP) represents an effective approach to exploit heavy oil by injecting Oil Viscosity Reducer (OVR). However, the challenge lies in the crossflow of traditional OVR through high permeability channels in heterogeneous heavy oil reservoirs. a supramolecular compound system comprising Interfacially Active Polymer (IAP) and Emulsifying Viscosity Reducer (EVR) were proposed as a novel CHHOP agent to address this problem. A series of experiments were conducted to investigate the heavy oil displacement performance and mechanism of the IAP-EVR compound system, including assessments of heavy oil emulsification, emulsion stability, rheological properties, single-core oil displacement, and heterogeneous microscopic oil displacement. The results demonstrate that a stable O/W emulsion can be formed with the 0.1 wt% IAP-0.3 wt% EVR compound system under a low mixing rate of 200 rpm. The emulsion exhibits only an 8.0% dewatering rate and a low TSI value of 0.8. Moreover, the compound system effectively reduces the heavy oil viscosity from 1000 mPa·s to 325.7 mPa·s, facilitating the emulsification of the remaining oil after water flooding and enhancing its flowability, thus improving oil displacement efficiency. Additionally, the 0.1 wt% IAP-0.3 wt% EVR compound system increases the solution viscosity to 600 mPa·s, leading to a low W/O mobility ratio, which enhances the swept volume. Supramolecular association is identified as a crucial mechanism for stabilizing the emulsion and increasing the solution viscosity, as evidenced by a high elastic modulus of 144.7 mPa and a transition area observed in the viscosity-shear rate curve. In comparison to HPAM and IAP, the 0.1 wt% IAP-0.3 wt% EVR compound system yields higher oil recoveries of 21.84 %OOIP in the single core experiment. Moreover, noticeable emulsification is observed in the produced fluid, and oil recoveries of 89.85 %OOIP and 92.98 %OOIP are achieved in high and low permeable areas, respectively, in the heterogeneous microscopic model. These results indicate a mechanism that enhances both the swept volume and oil displacement efficiency. Overall, the findings of this study provide a laboratory foundation for the promising application of the IAP-EVR compound system in heterogeneous heavy oil reservoirs.

Progress and prospect of carbon dioxide capture, utilization and storage in CNPC oilfields

The development history of carbon capture, utilization and storage for enhanced oil recovery (CCUS-EOR) in China is comprehensively reviewed, which consists of three stages: research and exploration, field test and industrial application. The breakthrough understanding of CO2 flooding mechanism and field practice in recent years and the corresponding supporting technical achievements of CCUS-EOR project are systematically described. The future development prospects are also pointed out. After nearly 60 years of exploration, the theory of CO2 flooding and storage suitable for continental sedimentary reservoirs in China has been innovatively developed. It is suggested that C7–C15 are also important components affecting miscibility of CO2 and crude oil. The mechanism of rapid recovery of formation energy by CO2 and significant improvement of block productivity and recovery factor has been verified in field tests. The CCUS-EOR reservoir engineering design technology for continental sedimentary reservoir is established. The technology of reservoir engineering parameter design and well spacing optimization has been developed, which focuses on maintaining miscibility to improve oil displacement efficiency and uniform displacement to improve sweep efficiency. The technology of CO2 capture, injection and production process, whole-system anticorrosion, storage monitoring and other whole-process supporting technologies have been initially formed. In order to realize the efficient utilization and permanent storage of CO2, it is necessary to take the oil reservoir in the oil-water transition zone into consideration, realize the large-scale CO2 flooding and storage in the area from single reservoir to the overall structural control system. The oil reservoir in the oil-water transition zone is developed by stable gravity flooding of injecting CO2 from structural highs. The research on the storage technology such as the conversion of residual oil and CO2 into methane needs to be carried out.

The Research and Application of Adjustable Drive Improve Oil Recovery Technology in Ansai Low Permeable Fracture Reservoir

In order to solve the serious problem that the injected water channeling is serious and water flooding effect is getting worse in Ansai low permeability fractured reservoir. Developed the gelling movable gel profile control displacement-agent RD which Can control the gel time and the strength. Select out the surfactant XSY-1 that can reduce water interfacial tension to ultra-low and can significantly improve oil displacement efficiency. Designed five group profiling experiments on parallel cores, optimized movable frozen rubber slug of surfactant slug best combination of 0.2 of the PV profile control agent add 0.40 PV surfactant, compared with the water flooding ways to enhance oil recovery of 22.5％ . Adjustable drive combined with technology is the effective way to improve the Ansai low permeability fractured reservoir water flooding effect.

MULTIPHASE TRANSPORT OF FOAM FLUID IN POROUS STRUCTURES FOR ENHANCING OIL RECOVERY

Foams in pores affect the sweep range and oil displacement efficiency for low-permeability reservoir. In this paper, regular porous media with different coordination numbers are constructed to study how the parameters of microscopic pore structure affect foam flooding, and to identify the relationship between foam flooding efficiency and pore size. A two-dimensional microscopic pore structure model is established by computed tomography (CT) and the Imagej software. The sweep range and oil displacement efficiency of foam flooding are compared with that of water flooding. The results show that porous media with low coordination numbers can lead to higher foam flooding efficiency. When the pore size of porous media with a coordination number of 3 is 1 μm, the oil displacement effect is the best. Compared with water, foam can significantly improve oil displacement efficiency. Foam can block the dominant channel and drive out the residual oil in the narrow pore throat with higher efficiency. When the gas-liquid ratio of the foam is 3:1, the residual oil saturation is the lowest, and the flooding effect is the best. The higher contact angle of the wetting wall can produce better efficiency of foam flooding. When the wetting angle is 45°, the oil displacement effect is the best. When the injection rate is 0.5 m/s, the oil displacement effect is the best, but when the injection rate reaches 5 m/s, the residual oil saturation is the smallest. When the coordination number is 4, the oil displacement effect is the best.

Imbibition mechanisms of high temperature resistant microemulsion system in ultra-low permeability and tight reservoirs

Lower-phase microemulsions with core-shell structure were prepared by microemulsion dilution method. The high temperature resistant systems were screened and the performance evaluation experiments were conducted to clarify the spontaneous imbibition mechanisms in ultra-low permeability and tight oil reservoirs, and to direct the field microfracture huff and puff test of oil well. The microemulsion system (O-ME) with cationic-nonionic surfactant as hydrophilic shell, No.3 white oil as oil phase core has the highest imbibition recovery; its spontaneous imbibition mechanisms include: the ultra-low interfacial tension and wettability reversal significantly reduce oil adhesion work to improve oil displacement efficiency, the nanoscale “core-shell structure” formed can easily enter micro-nano pores and throats to expand the swept volume, in addition, the remarkable effect of dispersing and solubilizing crude oil can improve the mobility of crude oil. Based on the experimental results, a microfracture huff and puff test of O-ME was carried out in Well YBD43-X506 of Shengli Oilfield. After being treated, the well had a significant increase of daily fluid production to 5 tons from 1.4 tons, and an increase of daily oil production to 2.7 tons from 1.0 ton before treatment.

Experiments of Gas-water Cooperative Flooding in Fracture Network System

Fractures are the main seepage channels and the critical oil storage space in fracture-vuggy reservoirs. In this paper, the staggered fracture system was abstracted into an orthogonal fracture network. A physical experimental model was made with a laser-etched acrylic plate. The physical experiments of water flooding, gas flooding, water-alternating-gas, and simultaneous-water-and-gas were carried out using the physical experiment model of the fracture network. The results show that gas is more accessible to break through in gas flooding than water in water flooding, resulting in a lower recovery factor. Water-alternating-gas and simultaneous-water-and-gas can effectively improve oil displacement efficiency through the action of gravity difference and the interaction mechanism of gas and water. Increasing the injection rate properly, increasing slug size properly before water and gas breakthrough during water-alternating-gas simultaneous-water-and-gas, and decreasing the gas-water ratio properly during simultaneous-water-and-gas simultaneous-water-and-gas can effectively expand the sweep scope and improve recovery. The experiment provides a basis for efficient water and gas injection development in fracture-vuggy reservoirs.

Experimental Study on the Application of Cellulosic Biopolymer for Enhanced Oil Recovery in Carbonate Cores under Harsh Conditions.

Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology and oil displacement properties of okra mucilage were investigated for its enhanced oil recovery potential at a high temperature and high pressure (HTHP) in carbonate cores. The cellulosic polysaccharide used in the study is composed of okra mucilage extracted from okra (Abelmoschus esculentus) via a hot water extraction process. The morphological property of okra mucilage was characterized with Fourier transform infrared (FTIR), while the thermal stability was investigated using a thermogravimetric analyzer (TGA). The rheological property of the okra mucilage was investigated for seawater salinity and high-temperature conditions using a TA rheometer. Finally, an oil displacement experiment of the okra mucilage was conducted in a high-temperature, high-pressure core flooding equipment. The TGA analysis of the biopolymer reveals that the polymeric solution was stable over a wide range of temperatures. The FTIR results depict that the mucilage is composed of galactose and rhamnose constituents, which are essentially found in polysaccharides. The polymer exhibited pseudoplastic behavior at varying shear rates. The viscosity of okra mucilage was slightly reduced when aged in seawater salinity and at a high temperature. Nonetheless, the cellulosic polysaccharide exemplified sufficiently good viscosity under high-temperature and high-salinity (HTHS) conditions. Finally, the oil recovery results from the carbonate core plug reveal that the okra mucilage recorded a 12.7% incremental oil recovery over waterflooding. The mechanism of its better displacement efficiency is elucidated.

Physical and numerical simulation of inter-fracture flooding in heterogeneous tight oil reservoirs

The existing tight oil reservoirs are mainly developed after hydraulic fracturing of horizontal Wells with low recovery. Traditional enhanced oil recovery (EOR) methods are difficult to apply in tight reservoirs, because huff-puff drives oil to the distal end, water breakthrough exists in inter-well flooding, and ASP flooding cannot enter the small pore throat of the tight reservoir. A new EOR method of inter-fracture flooding is proposed. This method solves the problem that the injection water cannot enter the matrix in tight reservoir by inter-fracture flooding. Inter-fracture flooding reduces the distance between the injection and production ends and reduces the risk of water channeling. Inter-fracture flooding increases the pressure gradient during water flooding in the reservoir and establishes an effective water displacement system in the heterogeneous tight reservoir. In this paper, physical simulation experiments and numerical simulation are designed to study the EOR effect of inter-fracture water flooding in heterogeneous tight reservoirs. The results showed the following: (1) Inter-fracture asynchronous water flooding (IFAWF) can improve oil displacement efficiency by 6%–16% compared with inter-fracture synchronous water flooding (IFSWF). (2) Compared with IFSWF, IFAWF can greatly improve the oil displacement efficiency of the core with low permeability in the heterogeneous model by more than 20%. (3) Effective water sweep cannot be achieved by IFSWF, but can be achieved by IFAWF. (4) IFAWF established effective displacement in 0.1mD tight heterogeneous reservoir. Studies have shown that inter-fracture flooding can lower the reservoir development permeability threshold and will be an important EOR method for tight oil and shale oil in the future.

Synthesizing CNT/MgO nanocomposite to form stable pickering emulsion at high temperature and salinity and its application to improved oil displacement efficiency

In this work CNT/MgO nanocomposites is synthesized to investigate their effect on oil displacement efficiency in porous media. Characterization methods confirmed that the CNT/MgO nanocomposite is synthesized successfully where the MgO nanoparticles covered the CNTs homogenously. The stability of the formed emulsions confirmed that the CNT/MgO nanocomposite form stable emulsions at high temperatures and salinity conditions. It was found that while using this nanocomposite, the interfacial tension (IFT) is reduced significantly. Moreover, the contact angle measurements proved that the synthesized nanoparticle is able to alter the wettability of the porous media from the oil-wet condition to the water-wet condition, which is highly demanded in the EOR application. As a dynamic method to investigate the EOR mechanism of nanofluid injection, microfluidic flooding method is employed to verify the result of static tests and show the potential of the prepared nanocomposites on enhancing the recovery factor. It is observed the investigated nanofluid with a concentration of 0.5 wt%‌ provides a higher recovery factor (about 60%) in comparison to deionized water flooding (about 20 %).

Synergistic mechanism of well pattern adjustment and heterogeneous phase combined flooding on enhancing oil recovery in mature fault-block reservoirs

With the maturity of fault-block reservoirs, the water percolation channels are formed after long-term waterflooding, which leads to large amounts remaining oil unrecovered and low recovery efficiency. Thus, it is imperative to seek for enhancing oil recovery methods to improve the development performance of mature fault-block reservoirs. Well pattern adjustment and heterogeneous phase combined flooding are both feasible technologies for enhancing oil recovery in mature fault-block reservoirs. Nevertheless, both technologies have their limitations. Thus, a hybrid approach combining WPA and HPCF was proposed. In this study, the large-scale plate sand-pack model flooding experiments were conducted to investigate whether hybrid strategy has better EOR ability than the single WPA or HPCF. Thereafter, on the basis of incremental oil recovery and distribution of remaining oil, the mechanism of the synergistic effect of WPA and HPCF was illustrated. Finally, the influence of reservoir inclination on development performance was proposed. The results show that EOR of hybrid strategy is the highest, followed by single HPCF, and single WPA is the least. The HPCF mainly recovers remaining oil on both sides of main streamline after water flooding, and it prolongs the period of EOR validity. WPA can change the fluid flow direction and force the subsequent liquid enters the un-swept non-main streamline areas in the water flooding stage. Furthermore, by combining WPA and HPCF, the HPCF can enter the non-main streamline areas to expand sweep volume and improve oil displacement efficiency under the induction of WPA. Besides, the reservoir inclination has an obvious influence on the development performance of fault-block reservoir. With the increase of reservoir inclination, the incremental oil recovery of the single strategy or hybrid strategy decreases. Thus, these findings of this study can help for better understanding the synergetic effect of HPCF and WPA, which can provide a hybrid strategy for enhancing oil recovery in mature fault-block reservoir.

Experimental and Numerical Investigation on Oil Displacement Mechanism of Weak Gel in Waterflood Reservoirs.

The production performance of waterflood reservoirs with years of production is severely challenged by high water cuts and extensive water channels. Among IOR/EOR methods, weak gel injection is particularly effective in improving the water displacement efficiency and oil recovery. The visualized microscopic oil displacement experiments were designed to comprehensively investigate the weak gel mechanisms in porous media and the numerical simulations coupling equations characterizing weak gel viscosity induced dynamics were implemented to understand its planar and vertical block and movement behaviors at the field scale. From experiments, the residual oil of initial water flooding mainly exists in the form of cluster, column, dead end, and membranous, and it mainly exists in the form of cluster and dead end in subsequent water flooding stage following weak gel injection. The porous flow mechanism of weak gel includes the preferential plugging of large channels, the integral and staged transport of weak gel, and the residual oil flow along pore walls in weak gel displacement. The profile-control mechanism of weak gel is as follows: weak gel selectively enters the large channels, weak gel blocks large channels and forces subsequent water flow to change direction, weak gel uses viscoelastic bulk motion to form negative pressure oil absorption, and the oil droplets converge to form an oil stream, respectively. The numerical simulation indicates that weak gel can effectively reduce the water-oil mobility ratio, preferentially block the high permeability layer and the large pore channels, divert the subsequent water to flood the low permeability layer, and improve the water injection swept efficiency. It is found numerically that a weak gel system is able to flow forward under high-pressure differences in the subsequent water flooding, which can further improve oil displacement efficiency. Unlike the conventional profile-control methods, weak gels make it possible to displace the bypassed oil in the deep inter-well regions with significant potential to enhance oil recovery.