Jian Zhang

Polymer flooding is one of the effective technologies for enhanced oil recovery (EOR) in offshore oilfields. However, traditional polymer maturation tanks are large in volume, heavy in weight, and slow in dissolution rate, limiting their application in offshore fields. In this study, Higee technology was adopted, with a rotating packed bed (RPB) as the core device. Combined with computational fluid dynamics (CFD) simulation and experiments, the effects of rotation speed, polymer concentration and number of wire mesh layers on the dispersion and dissolution behavior of polyacrylamide (HPAM) were analyzed. The results show that the higher the rotation speed, the better the HPAM dispersion effect, but the flow field stability decreases; a high-concentration polymer has a high viscosity and a poor flow capacity, requiring a longer time to achieve the ideal dispersion result; increasing the number of wire mesh layers can improve the uniformity of polymer distribution but will reduce flow capacity, among which the seven-layer wire mesh packing achieves the optimal balance between dissolution performance and flow capacity. Verification through small-scale RPB experiments shows that the HPAM dissolution effects of the seven-layer and nine-layer wire mesh structures are generally equivalent, but the seven-layer structure has a higher viscosity retention rate (93.6~95%), which has more advantages in practical field applications and validates the simulation results. This study optimizes the number of wire mesh layers and rotation speed range of RPB, providing theoretical and technical references for the development of large-scale industrial polymer solution preparation facilities without maturation tanks.

Discontinuous phase flooding (such as polymer microspheres) is an important method for enhancing oil recovery. With the hydration swelling and elastic properties, a unique “migration–entrapment–remigration” discontinuous flow behavior is identified during flooding. And a more pronounced conformance control effect is observed in high-permeability flow channels and deeper reservoir regions compared to continuous phase flooding. These complex seepage mechanisms pose significant challenges to reservoir numerical simulation. Based upon a chemical reaction framework, a multi-component mathematical model comprising oil, gas, water, pre-discontinuous phase, and discontinuous phase components is developed in this study. The discontinuous phase is generated through chemical reactions involving the pre-discontinuous phase. A minimum reaction porosity is first introduced in the chemical reaction process to enhance the discontinuous phase generation in high-permeability regions. A threshold pressure is incorporated into the discontinuous phase equation for the “migration–entrapment–remigration” discontinuous flow characteristics. The model is subsequently solved using a fully implicit finite volume method. A new numerical simulator implementing this approach is developed in C++. Validation through physical experiments confirms the method’s accuracy. The discontinuous migration process of “migration–entrapment–remigration” is clearly reflected through the injection pressure fluctuations during simulation. Mechanistic models and field-scale simulations both confirm that discontinuous phase flooding significantly enhances oil recovery efficiency, outperforming both water flooding and continuous phase flooding. The novel reaction specification enhances conformance control in high-permeability channels, as demonstrated by the simulation results. The proposed model accurately captures the migration characteristics of the discontinuous phase and holds important practical value for reservoirs with discontinuous phase flooding.

In the field of enhanced oil recovery (EOR), particularly for water control in high-temperature reservoirs, there is a critical need for effective in-depth water shutoff and conformance control technologies. Polymer-based in situ-cross-linked gels are extensively employed for enhanced oil recovery (EOR), yet their short gelation time under high-temperature reservoir conditions (e.g., >120 °C) limits effective in-depth water shutoff and conformance control. To address this, we developed a hydrogel system via the in situ cross-linking of polyacrylamide (PAM) with phenolic resin (PR), reinforced by silica sol (SS) nanoparticles. We employed a variety of research methods, including bottle tests, viscosity and rheology measurements, scanning electron microscopy (SEM) scanning, density functional theory (DFT) calculations, differential scanning calorimetry (DSC) measurements, quartz crystal microbalance with dissipation (QCM-D) measurement, contact angle (CA) measurement, injectivity and temporary plugging performance evaluations, etc. The composite gel exhibits an exceptional gelation period of 72 h at 130 °C, surpassing conventional systems by more than 4.5 times in terms of duration. The gelation rate remains almost unchanged with the introduction of SS, due to the highly pre-dispersed silica nanoparticles that provide exceptional colloidal stability and the system’s pH changing slightly throughout the gelation process. DFT and SEM results reveal that synergistic interactions between organic (PAM-PR networks) and inorganic (SS) components create a stacked hybrid network, enhancing both mechanical strength and thermal stability. A core flooding experiment demonstrates that the gel system achieves 92.4% plugging efficiency. The tailored nanocomposite allows for the precise management of gelation kinetics and microstructure formation, effectively addressing water control and enhancing the plugging effect in high-temperature reservoirs. These findings advance the mechanistic understanding of organic–inorganic hybrid gel systems and provide a framework for developing next-generation EOR technologies under extreme reservoir conditions.

The performance of the grinding pump, a device for crushing and stretching conventional polymers, is mainly affected by its stage number, diameter, and tooth count. In this paper, Fluent software was utilized, employing the Eulerian model in conjunction with non-Newtonian fluid models (such as the power-law model and Bingham plastic model) and turbulence models (like the k-ε model) to establish a model for CFD (Computational Fluid Dynamics) simulations. These simulations analyzed the turbulence characteristics of non-Newtonian fluids in grinding mixing pumps, as well as the basic performance of the pumps, including pressure, velocity, viscosity, and volume fraction distributions. The effects of different structural parameters (stage number, pump diameter, and tooth count) on the instant dissolving effect of polymers were compared, and the optimal structure was determined. Based on pressure profile, velocity profile analysis, and polymer distribution simulation results, the optimal grinding mixing pump was found to have three stages, with a diameter of d = 140 mm and 60 teeth yielding the best grinding effect. Increasing the stage number and pump diameter can improve the grinding and mixing effect, but an excessively large pump diameter can reduce it. Changes in tooth count have a minor impact on viscosity but affect distribution uniformity.

Polymer flooding has been gradually applied in Chinese offshore oilfields to enhance oil recovery (EOR). Injectivity loss during polymer flooding is a common issue that could cause lower displacement speed and efficiency, and eventually compromise the polymer flooding result. This paper presents a case study of a Chinese offshore field where injectivity loss issues were encountered in the polymer flooding project. A series of measures are applied to enhance the injectivity. The injectivity enhancement strategies are proposed and conducted from three main aspects, namely, (1) surface polymer fluid preparation; (2) downhole wellbore stimulation; and (3) reservoir–polymer compatibility, respectively. For the surface polymer fluid preparation, a series of sieve flow tests are conducted to obtain the optimal mesh size to improve the polymer fluid preparation quality and reduce the amount of “fish eyes”. The downhole wellbore stimulations involve oxidization-associated acidizing treatment and re-perforation. Polymer–reservoir compatibility tests are conducted to optimize the molecular weight (MW). Regarding the surface measures, the optimal filtration sieve mesh number is 200, which could reduce fish eyes to a desirable level without causing mesh plugging. After mesh refinement, the average injection pressure of the twelve injection wells decreases by 0.5 MPa. For the downhole stimulations, acidizing treatment are applied to six injection wells, which decreases the injection pressures by 6 to 7 MPa. For Well A, where acidizing does not work, the re-perforation measure is used and enhances the injectivity by 300%. Moreover, the laboratory and field polymer–reservoir compatibility tests show that the optimal polymer molecular weight (MW) is sixteen million. Proposed strategies applied from the surface, downhole, and reservoir aspects could be used to resolve different levels of injectivity loss, which could provide guidance for future offshore polymer projects.

Due to the high formation temperature of high-temperature reservoirs, ordinary polyacrylamide microspheres cannot meet the requirements for temperature resistance. To address the challenge of deep profile control in high-temperature reservoirs, we prepared AM/PF polymer microspheres with excellent temperature resistance through the copolymerization of water-soluble phenolic resin (PF) and acrylamide (AM). The swelling properties of AM/PF polymer microspheres were examined using a visible light microscope, SEM, and laser diffraction. The plugging and migration characteristics of the microspheres were evaluated using membrane filtration tests and sand-filled tube displacement tests. The results indicate that the average particle size of AM/PF microspheres prepared via inverse suspension polymerization is approximately 30 μm, and the swelling process is relatively slow. The microspheres take approximately 15 days to fully swell, with a volume swelling ratio of roughly 34.25. At high temperatures, the swollen microsphere dispersion system can effectively block microporous membranes with specific pore sizes. As the concentration of microspheres increases, their plugging effect gradually enhances; however, this effect diminishes as permeability increases. The AM/PF polymer microspheres exhibit excellent temperature stability along with favorable plugging and migration characteristics at specific permeabilities.

The Bohai oilfield is characterized by severe heterogeneity and high average permeability, leading to a low water flooding recovery efficiency. Polymer flooding only works for a certain heterogeneous reservoir. Therefore, supplementary technologies for further enlarging the swept volume are still necessary. Based on the concept of discontinuous chemical flooding with multi slugs, three chemical systems, which were polymer gel (PG), hydrophobically associating polymer (polymer A), and conventional polymer (polymer B), were selected as the profile control and displacing agents. The optimization design of the discontinuous chemical flooding was investigated by core flooding experiments and displacement equilibrium degree calculation. The gel, polymer A, and polymer B were classified into three levels based on their profile control performance. The degree of displacement equilibrium was defined by considering the sweep conditions and oil displacement efficiency of each layer. The effectiveness of displacement equilibrium degree was validated through a three-core parallel displacement experiment. Additionally, the parallel core displacement experiment optimized the slug size, combination method, and shift timing of chemicals. Finally, a five-core parallel displacement experiment verified the enhanced oil recovery (EOR) performance of discontinuous chemical flooding. The results show that the displacement equilibrium curve exhibited a stepwise change. The efficiency of discontinuous chemical flooding became more significant with the number of layers increasing and heterogeneity intensifying. Under the combination of permeability of 5000/2000/500 mD, the optimal chemical dosage for the chemical discontinuous flooding was a 0.7 pore volume (PV). The optimal combination pattern was the alternation injection in the form of “medium-strong-weak-strong-weak”, achieving a displacement equilibrium degree of 82.3%. The optimal shift timing of chemicals occurred at a water cut of 70%, yielding a displacement equilibrium degree of 87.7%. The five-core parallel displacement experiment demonstrated that discontinuous chemical flooding could get a higher incremental oil recovery of 24.5% compared to continuous chemical flooding, which presented a significantly enhanced oil recovery potential.

Nuclear magnetic resonance (NMR) and high-pressure mercury injection (HPMI) have been widely used as common characterization methods of pore-throat. It is generally believed that there is a power function relationship between transverse relaxation time (T₂) and pore-throat radius (r), but the segmentation process of the pore-throat interval is subjective, which affects the conversion accuracy. In this paper, ordered clustering is used to improve the existing segmentation method of the pore-throat interval, eliminate the subjectivity in the segmentation process, and obtain a more accurate distribution curve of the pore-throat. For the three kinds of cores with ordinary-low permeability (K > 1 mD), ultra-low permeability (0.1 mD < K < 1 mD), and super-low permeability (K < 0.1 mD), the pore-throat distribution curves of the cores were obtained by using the improved T₂ conversion method. Then, the oil and gas two-phase displacement experiment was carried out to investigate the degree of recovery and cumulative gas–oil ratio changes during the displacement process. Finally, the converted T₂ spectrum was used to quantify the utilization of different pore sizes. The improved T₂ conversion method not only has better accuracy but also is not limited by the pore-throat distribution types (such as unimodal, bimodal, and multi-modal, etc.) and is suitable for any core with measured HPMI pore-throat distribution and an NMR T₂ spectrum. Combined with the results of core displacement and the degree of pore-throat utilization, it is found that the potential of miscible flooding to improve the recovery degree is in the order of ordinary-low permeability core (18–22%), ultra-low permeability core (25–29%), and super-low permeability core (8–12%). The utilization degree of immiscible flooding to the 2 flooding on K < 0.1 mD reservoirs is not good, the seepage resistance of CO₂ is large, the miscible flooding makes it difficult to improve the recovery degree, and the utilization effect of pore-throat is poor.

High-internal-phase water-in-oil (W/O) emulsions generated in situ have garnered considerable attention as novel profile control systems. However, conventional emulsifiers are unreactive and poorly dispersed in water, necessitating large dosages and resulting in poor injectivity. In this study, we synthesized amphiphilic nanoparticles (SiO₂–NH₂–DAC NPs) containing amine and long-chain alkyl groups using a one-pot method and investigated the stabilized emulsion properties. Our results indicated that W/O emulsions with a water-to-oil ratio (WOR) of 7:3 to 8:2 could be prepared with just 0.1 wt% of SiO₂–NH₂–DAC NPs under neutral and basic conditions, with demulsification occurring under acidic conditions (pH = 2.1), demonstrating the pH-responsiveness of the W/O emulsions. The emulsion viscosity increased from 150 to 2555 mPa·s at different WORs. An additional 18.7% oil recovery was achieved using SiO₂–NH₂–DAC NPs in a heterogeneous core, highlighting their potential as a promising profile control candidate.