Deep Profile Control Research Articles

Research on Crack Sealing Performance of Polymer Microsphere/Hydrogel Composite System

Owing to their excellent water-absorption and swelling properties, polymer microspheres have been extensively applied as deep profile control agents in oilfields. These microspheres effectively seal large pore-throat channels in reservoirs, optimizing the water-absorption profile. In this study, a composite system was developed, comprising polymer microspheres and polyacrylamide polymers, with the inclusion of a cross-linking agent. The system leverages the synergistic effects of polymer microspheres and other plugging techniques to efficiently seal fractured reservoirs. Results indicate that the composite system exhibits strong blocking and scour resistance due to enhanced network integrity, higher viscosity, and improved elastic strength. Additionally, the composite system demonstrates a notable self-repairing capability, maintaining a high sealing efficiency even after a waterflood breakthrough.

Fabrication and Properties of in Situ Cross‐Linked Supramolecular Gel Based on Host‐Guest Interaction

AbstractWater‐cut control is critical to efficient reservoir development. In this investigation, a host‐guest inclusion polymer gels system with self‐assembly features was constructed stemming from the host‐guest recognition mechanism. Subsequently, the elements affecting polymer viscosity were discussed. Eventually, the injectivity and plugging performance of the host‐guest inclusion system were measured by core displacement tests. The results indicated that the optimum synthesis temperature of the host polymer and guest polymer were 30 °C and 40 °C, separately, and the optimum total monomer content should be 20 wt%. The polymer system had excellent thickening properties and shearing resistance resulting from host‐guest inclusion interaction and physical hydrophobic association. Meanwhile, it had better plugging performance than host polymer or guest polymer alone. This profile control agent system provides a novel method for settling deep profile control in oilfields.

Visualization Experimental Study on In-Situ Triggered Displacement Mechanism by Microencapsulated Polymer in Porous Media

Summary Polymer flooding in deep reservoir profile control presents challenges in balancing injectivity and effective mobility control. To address this, we propose a solution by utilizing a microencapsulated polymer that can be easily injected and thickens over time. However, limited research has been conducted on the flow characteristics and the impact on oil mobilization by such profile control agents. In this study, we approximately simulated the time-varying flow process of microencapsulated polymer through in-situ triggered experiments at high temperature and pressure. The flow characteristics and oil displacement mechanism of the microencapsulated polymer under different trigger times were analyzed, and the displacement efficiency during the triggered viscosity enhancement process in porous media was quantitatively evaluated. The experimental results reveal that microencapsulated polymer exhibits a dual mechanism of near-wellbore reservoir particle temporary plugging and deep formation consistency control mechanisms. The transient aggregation of capsule particles alters the flow path, intensifying after expansion. The interaction between the microcapsule particles and the partially released polymer further enhances the resistance-enhancing property of the solution. The viscosity-enhanced microencapsulated polymer fluid improves the displacement efficiency. Microscopic oil displacement and coreflooding experiments resulted in a decrease in oil saturation of 39.5 and 18.33%, respectively. This study provides valuable microscopic insights into the flow behavior and oil displacement performance of microencapsulated polymer, offering essential guidance for optimizing oil reservoir extraction strategies.

Experimental Performance Evaluation and Optimization of a Weak Gel Deep-Profile Control System for Sandstone Reservoirs.

Globally, most oil fields use excessive water flooding to recover oil. By injection of water between wells, channels are created, which result in lower oil recovery. Water-plugging deep-profile control must be used to control the excessive water production from an oil reservoir. This laboratory study used sulfonated polyacrylamides with a molecular weight of 10.3-13.0 × 106 Da (FPAM) and polyethylenimine (PEI-600) to formulate a weak gel system to control excessive water production from deep formations. Using different FPAM and PEI-600 concentrations, the Sydansk bottle test approach was applied to evaluate the gelation time, strength, and stability of the weak gel. The weak gel concentration of 0.5 wt % FPAM and 0.4 wt % PEI-600 was confirmed for deep-profile control by this approach. The temperature and salt resistance of the selected weak gel system were evaluated using the same bottle test methodology. The gelation time depends on temperature: 5-7 days at <100 °C to 0.5 days >100 °C. Salinity >20,000 mg/L significantly affected the weak gel system's strength. By performing a viscometer test, the viscosity of the weak gel system at different times was evaluated, confirming the gelation time of the selected weak gel. Next, a microfluidic chip flooding test analyzed weak gel performance and plugging ability in porous media. This micromodel provided a visual analysis of the weak gel plug. Finally, a low- to medium-permeability sandstone core-flooding was conducted to determine the plugging rate of weak gel at the core scale, followed by an evaluation of the injection pressure, blocking effect, and oil recovery. According to the study, the selected weak gel has an extended gelation time with a significantly low viscosity, which affects its injectivity and can move from injection wells into deep formations. In the core-flooding test, the weak gel's blocking rate after 7 days of gelation time exceeded 90%.

Evaluation of Profile Control and Oil Displacement Effect of Starch Gel and Nano-MoS2 Combination System in High-Temperature Heterogeneous Reservoir.

The Henan Oilfield's medium-permeability blocks face challenges such as high temperatures and severe heterogeneity, making conventional flooding systems less effective. The starch gel system is an efficient approach for deep profile control in high-temperature reservoirs, while the nano-MoS2 system is a promising enhanced oil recovery (EOR) technology for high-temperature low-permeability reservoirs. Combining these two may achieve the dual effects of profile control and oil displacement, significantly enhancing oil recovery in high-temperature heterogeneous reservoirs. The basic performance evaluation of the combination system was carried out under reservoir temperature. Displacement experiments were conducted in target blocks under different permeabilities and extreme disparity core flooding to evaluate the combination system's oil displacement effect. Additionally, the displacement effects and mechanisms of the starch gel and nano-MoS2 combination system in heterogeneous reservoirs were evaluated by simulating interlayer and intralayer heterogeneity models. The results show that the single nano-MoS2 system's efficiency decreases with increased core permeability, and its effectiveness is limited in triple and quintuple disparity parallel experiments. After injecting the starch gel-nano-MoS2 combination system, the enhanced oil recovery effect was significant. The interlayer and intralayer heterogeneous models demonstrated that the primary water flooding mainly affected the high-permeability layers, while the starch gel effectively blocked the dominant channels, forcing the nano-MoS2 oil displacement system towards unswept areas. This coordination significantly enhanced oil displacement, with the combination system improving recovery by 15.33 and 12.20 percentage points, respectively. This research indicates that the starch gel and nano-MoS2 combination flooding technique holds promise for enhancing oil recovery in high-temperature heterogeneous reservoirs of Henan Oilfield, providing foundational support for field applications.

Understanding of the Tracking and Adjusting Effect of Deep Profile Control and Flooding Expansion Application Blocks in Pubei Oilfield

In order to explore the development technology of enhancing oil recovery during the ultra-high water cut period in the Pubei Oilfield, deep profile control pilot tests and expanded application tests have been carried out in the Pubei Oilfield. This article mainly starts from the actual production performance of the deep profile control and flooding expansion application test, analyzes the main tracking and adjustment methods and the understanding of the results obtained in the development process of deep profile control and flooding, laying the foundation for the establishment of deep profile control and flooding matching tracking and adjustment technology in Pubei Oilfield.

Research Progress on Functionalized Polymer Microspheres for Deep Profile Control and Flooding

Research Progress on Functionalized Polymer Microspheres for Deep Profile Control and Flooding

Dynamic covalent hydrogel fabricated in porous media through dynamic acylhydrazone bond from reactive precursors for deep profile control

In this work, we proposed a novel hydrogel system for in-depth conformance control through the dynamic covalent bond. Diffluent ketone-bearing and acyl hydrazide-bearing reactive precursors with low molecular weight are injected into the formation simultaneously, then gels in situ through dynamic hydrazone bonds to divert the post-injected fluid to un-swept oil zones. Ketone-bearing and acyl hydrazide-bearing reactive precursors with different reactive group ratios were synthesized by simple radical polymerization and hydrazinolysis. Rheological measurement results proved the two reactive precursors formed dynamic covalent hydrogel (DCG) through dynamic hydrazone bonds in deionized water and mineralized water. The viscoelasticity, flow behavior, and profile control behavior in the porous media of the DCG were evaluated. When the flow behavior and profile control experiments were conducted with a 9 m core, the injection pressure of DCG-20 % of which the molar ratio of the reactive group was 20 % was low (0–0.22 MPa) throughout the injection process, and the resistance factor was 4.40. After fully gelation, the post-water injection pressure significantly increased (0.22–7.54 MPa). The residual resistance factor was 150.80, and the plugging efficiency was 99.34 %. This work proved that the DCG consisting of ketone-bearing and acyl hydrazide-bearing reactive precursors not only had a strong injection capacity but also had a good profile control effect in porous media which meant the DCG fully met the need for deep profile control.

Study of deep transportation and plugging performance of deformable gel particles in porous media

Deformable gel particles (DGPs) possess the capability of deep profile control and flooding. However, the deep migration behavior and plugging mechanism along their path remain unclear. Breakage, an inevitable phenomenon during particle migration, significantly impacts the deep plugging effect. Due to the complexity of the process, few studies have been conducted on this subject. In this paper, we conducted DGP flow experiments using a physical model of a multi-point sandpack under various injection rates and particle sizes. Particle size and concentration tests were performed at each measurement point to investigate the transportation behavior of particles in the deep part of the reservoir. The residual resistance coefficient and concentration changes along the porous media were combined to analyze the plugging performance of DGPs. Furthermore, the particle breakage along their path was revealed by analyzing the changes in particle size along the way. A mathematical model of breakage and concentration changes along the path was established. The results showed that the passage after breakage is a significant migration behavior of particles in porous media. The particles were reduced to less than half of their initial size at the front of the porous media. Breakage is an essential reason for the continuous decreases in particle concentration, size, and residual resistance coefficient. However, the particles can remain in porous media after breakage and play a significant role in deep plugging. Higher injection rates or larger particle sizes resulted in faster breakage along the injection direction, higher degrees of breakage, and faster decreases in residual resistance coefficient along the path. These conditions also led to a weaker deep plugging ability. Smaller particles were more evenly retained along the path, but more particles flowed out of the porous media, resulting in a poor deep plugging effect. The particle size is a function of particle size before injection, transport distance, and different injection parameters (injection rate or the diameter ratio of DGP to throat). Likewise, the particle concentration is a function of initial concentration, transport distance, and different injection parameters. These models can be utilized to optimize particle injection parameters, thereby achieving the goal of fine-tuning oil displacement.

A gel system with long‐term high‐temperature stability for deep profile modification of high‐temperature oil and gas reservoirs

AbstractProfile modification is the key for efficient development of oil and gas reservoirs, especially high‐temperature reservoirs, which requires the system to have good high‐temperature resistance. According to the characteristics of high‐temperature reservoir, a high temperature gel composed of terpolymer, modified phenolic resin, aromatic amine curing agent and thiourea was developed. The effects of different components on the properties of the gel system were clarified. Then, the long‐term thermal stability under high‐temperature conditions was studied. In addition, the plugging performance of gel system under different permeability and injection volume was studied. Finally, the gelation properties and plugging properties of gel system with the flow distance were studied by simulating the flow of porous media. The results show that the gel system has high strength and suitable gelation time, and it can be adjusted in real time according to different oilfield requirements. In the range of 75–150°C, the gel system had excellent long‐term stability. When the temperature was 75°C, no free water after 120 days, and the viscosity only decreased from 13,131 to 11,254 mPa·s. Even at 150°C, the viscosity was as high as 8350 mPa·s after 120 days, and the free water was only 5.5%. The gel system had good adhesion ability on the porous media surface and strong anti‐flooding properties. When the injection volume was 0.1 pore volume (PV in short), the plugging rate to the sand packed tube was 72.7%. When the injection volume was 0.5 PV, the plugging rate was as high as 97.6%. The plugging rate of the gel system for the sand packed tube with permeability of 500 mD was 98.7% when the injection volume was 0.5 PV. When the permeability increased to 3000 mD, the plugging rate still reached 92.3%. The gel system also had an excellent deep profile control ability, and the viscosity retention of at 60 cm was as high as 96%. When the flow distance was 2 m, the viscosity retention also reached 75%. The rheological properties also shown that the gel system had excellent shearing resistance and adsorption resistance. Finally, combined with the state of the gel system on the surface of the porous media, there was no cementation between the formation sand before the injection, and the sand particles did not stick to each other. After the gel was injected, the adhesion of gel system on the porous media surface was very strong. The 3D network structure was also very dense, the sand particles could have good cementation effect under the adhesion of gel system.

Experimental Study on Enhanced Oil Recovery of the Heterogeneous System after Polymer Flooding

Daqing Oilfield faces increasing reservoir heterogeneity after years of polymer flooding, limiting further enhanced oil recovery. A novel preformed particle gel (PPG) was developed by Daqing Oilfield due to the limited profile control ability of polymer flooding. The preformed particle gel possesses strong deformation ability and the ability to pass through pore throats. The PPG was developed considering the in situ reservoir conditions and combined effects of plugging and flooding. Thus, a heterogeneous system was prepared by mixing polymers and the PPG. In this study, we measured the related properties of the system and assessed its profile control ability and oil displacement performance after polymer flooding. The experimental results demonstrate that typical polymer flooding cannot improve oil recovery under current reservoir conditions. Thus, deep profile control technology should be applied to remediate the highly heterogeneous reservoir issue. PPG can considerably increase the viscosity and stability of the system. The heterogeneous system has a strong plugging ability during the subsequent water flooding stage and is suitable to inject into the medium and high permeability layers. The water absorption profile of the core samples is significantly improved due to the impact of the PPG on the plugging of the layer with high permeability and the liquid flow direction. The system displays an excellent profile control effect in the core with a permeability ratio (high permeability/low permeability) of two under the conditions of a PPG concentration of 500 mg/L and an injection volume of 0.5 PV. In the oil displacement experiment, the recovery efficiency was raised by 16.56% using the polymer system, leading to significant swept volume increment and oil recovery improvement.

Study on Performance Evaluation of Multifunctional Microgel System

Soft Microgel (SMG) used to enhance oilfield recovery is a kind of aqueous dispersion chemical agent system of microgel particles. It is usually used in medium and low permeability reservoirs and is generally not used for plugging large pores of reservoirs due to the limitation of particle size. To resolve the problem that SMG cannot effectively block large pores of the reservoir, the multi-functional system (SMG-w) can be synthesized by introducing inorganic components into SMG under special conditions. The main physical and chemical properties of SMG-w are carried out in the laboratory. The results of the study show that SMG-w has an excellent resistant ability to temperature and salinity. Besides, it can also decrease the interfacial tension of oil and water. What’s more, it can react with Ca2+ or Mg2+ in formation water from a large number of flocs in the high salinity reservoir, which can enhance physical and chemical properties of SMG-w and make it be applied in deep profile control of high permeability reservoirs with high temperature and high salinity.

Improved oil recovery in sandstone reservoirs with deep profile control technology: A comparative study between modified starch gel and polymer gel

Deep profile control technology was implemented to alleviate the issue of oil recovery in sandstone reservoirs caused by varying permeability. Rheological tests, injection and plugging capacity experiments, core flooding experiments combined with Computed Tomography (CT) analysis were performed to study the mechanisms of profile control, oil displacement, rheology, and plugging properties of modified starch gel and polymer gel. Moreover, a comparison was made regarding the oil recovery, sweep efficiency, and displacement efficiency for both the starch gel and polymer gel. The results show that the ease of injection and plugging properties of the modified starch gel are superior to those of the viscoelastic polymer gel. The visual and quantitative distribution profiles and migration characteristics of water, oil, and gels are characterized. During the gel flooding stage, the modified starch gel maintained a rigid shape compared to the lax behavior observed with polymer gel. During the subsequent water flooding stage, the modified starch gel became immobile. It plugged the high permeability layer of the core plug, increasing the sweep efficiency of the low permeability layer by 60.00%. The sweep efficiency of the low permeability layer increased by 37.26% as the polymer gel continued to flow through the core plug. In addition, the high permeability layer is easily swept clean, so enhancing the displacement efficiency is the key to maximizing recovery. The displacement and relatively easy sweep efficiencies must be improved simultaneously to maximize the recovery in the low permeability layer. The study's findings shed light on the significance of modified starch gel in enhancing oil recovery in sandstone reservoirs with varying permeability.

Research on Optimization Design of Deep Profile Control Injection Scheme in Block S

Research on Optimization Design of Deep Profile Control Injection Scheme in Block S

Numerical Simulation of the Microscopic Plugging Mechanism and Particle Flow Process of the Microsphere System.

The microsphere system has small initial particle size, excellent swelling performance, simple manufacturing process, and strong plugging ability. It has great application potential in the field of plugging and profile control of deep reservoirs. Microspheres can effectively plug the pores of fractured cores, inhibit the rapid breakthrough process, and improve the sweep efficiency of the injected fluids. However, the microscopic plugging mechanism of microspheres on fractured cores is still unclear. In this study, the distribution of microspheres after plugging was observed through specially prepared core models. Furthermore, the microscopic plugging mechanism of microspheres in fractured reservoir cores was clarified, including direct microsphere plugging, cluster bridging plugging, adhesion plugging, extrusion-deformation plugging, and extrusion-crushing plugging. Then, particle flow simulation software was used to establish the fluid-solid coupling model of microsphere plugging, and then, the numerical simulation of the plugging process was realized by Python module programming. Through this study, the plugging effect of microspheres under different fracture opening conditions was clarified. Moreover, the effects of injection pressure difference, fracture width, and particle size ratio on the fluid-solid structures of microsphere plugging were analyzed. The results show that the smaller the particle size ratio, the greater the injection pressure difference, the fracture width, and the reduction magnitudes in fracture porosity and core permeability and the higher the plugging rate. The numerical simulation results well support the microsphere plugging mechanism obtained by experiments. The results of this study can provide theoretical and technical support for the development of deep profile control and flooding and enhanced oil recovery technology of the polymer microsphere dispersion system in fractured low-permeability reservoirs.

Preparation and migration study of multi-walled carbon nanotube hybrid polymer gel particles: EOR implication

Multi-walled carbon nanotube hybrid polymer gel particles (MWCNTs-HPGP) were synthesized using the free radical polymerization approach to reduce water cut at first. The microstructure, particle size distribution, swelling characteristics, strength, and rheology of MWCNTs-HPGP were then studied. Subsequently, the migration and plugging properties of MWCNTs-HPGP were assessed at the core scale. The morphology of MWCNTs-HPGP was irregular with interpenetration networks, and MWCNTs-HPGP could expand by 48.2–94 times in brine with varying salinities (0 ∼ 20 × 104 mg/L NaCl), according to experimental results. After 60 d of age, MWCNTs-HPGP retained 95.2% of strength. Furthermore, the MWCNTs-HPGP dispersion solution’s shearing thinning feature and good viscoelasticity supplied it with favorable injectivity and deep migrating capacity. In addition, when the matching coefficient (β, the ratio of MWCNTs-HPGP median particle size to the average pore diameter) was 1.06 and the flooding rate was 0.5 mL/min, MWCNTs-HPGP could efficiently plug large pores with a plugging efficiency ranging from 82.7% to 98.5%. All the experimental results demonstrated that MWCNTs-HPGP could be a potential candidate for deep profile control and displacement in high temperature and high salinity reservoirs.

Synthesis and In‐Situ Aggregation Plugging Capacity of Nanoparticles as Potential Deep Profile Control Agents

AbstractTo address the poor injectivity of conventional chemicals, and the drawbacks of existing elastic polymer particles in deep conformance control of low permeability reservoirs, nanoparticles with self‐aggregation properties were fabricated in this study. The injectability, aggregation properties, and in‐situ aggregation plugging capacity of nanoparticles in the reservoir were systematically investigated. Results show that the increase of the ion concentration and cationic charge number is beneficial to the aggregation of nanoparticles. Moreover, the aggregation time was longer when sulfonic acid groups were grafted on the surface of nanoparticles. Core flooding experiments show that when the core permeability is between 50×10−3 μm and 450×10−3 μm, the nanoparticles with an average particle size of 252.9 nm can successfully propagate to the deep formation and plug water channeling areas through the particle clusters formed by in‐situ aggregation. The negative change of Gibbs free energy and enthalpy indicates the reduced energy of the mixture system in the process of aggregation of nanoparticles, which reveals the essence of aggregation of nanoparticles.

Graded regulation technology for enhanced oil recovery and water shutoff in pore-cavity-fracture carbonate reservoirs

• Clarified the types of chemical agents for graded regulation of pore-vug-fracture carbonate reservoirs. • Plugging effect and oil–water selectivity of gel and nanospheres. • Wetting modifiers improve the efficiency of injection water to wash the oil are investigated. • Comprehensively discussed the synergistic mechanism of profile control and water shutoff and improving the efficiency of oil washing with injected water. Although a single type of chemical agent (eg, gels, microspheres, surfactants, etc.) has achieved some effects in enhanced oil recovery of carbonate reservoirs, for pore-cavity-fracture carbonate reservoirs, the use of a single type of chemical agent does not perform well. The main objective of this study is to study the effect of different types of chemical agents in enhanced oil recovery of complex carbonate reservoirs. In order to determine the screening principle of chemical agents, the types of water channeling in the North Troyes reservoir were analyzed. For complex fractures, step by step plugging, multi-agent and multi-slug comprehensive intervention is carried out to ensure the plugging of high-permeability channels and inhibit the seepage of large channels. It can plug channeling fracture channel, adjust secondary dominant channel and reduce matrix flow resistance, so as to expand macroscopic swept volume and improve microscopic water flooding efficiency. The results show that it is difficult to comprehensively control water channeling in pore-cave-fracture carbonate reservoir, and the reservoir heterogeneity in the test area can be improved by mixing different types of control and flooding agents and carrying out deep profile control. The plugging rate of gel is 97.18 %, and the oil–water selection ratio is 0.45 in fractured core; the expansion rate of nano - microspheres is more than 3 times; the wetting modifier can improve the imbibition oil displacement efficiency by 14.76%, and the test result shown that nano - microspheres and wetting modifier have good synergistic oil displacement effect. The field application result shown that daily oil production of oil well in the test area increased by 5.0 m 3 /d and the daily water rate decreased by 19.0% compared with that before the control flooding. The findings of this study can help for better understanding of enhanced oil recovery in pore-cave-fracture carbonate reservoir.

Pressure prediction model for deep profile control of expanded granular/viscoelastic movable gel formulation in low permeability reservoir

The low permeability reservoir perfect an important role of energy replacement in petroleum industry. Aiming at the problem of low prediction accuracy of the deep profile control in low permeability reservoirs and the lack of theoretical basis for the tracking and adjustment of projects, the variation characteristics of relaxation time are determined based on the viscoelastic experiments of movable gels with different concentrations, shear rates and angular velocities. The viscoelastic mobile gel apparent viscosity model considering the relaxation time kinetics is established based on the Maxwell theory and the pressure prediction model for the expanded granular/mobile gel deep profile control in low permeability reservoirs is established. Finally, the real production data of profile control wells in Yushulin oilfield in China is taken as an example, the application effects of the new pressure prediction model considering the viscoelasticity, the pressure model without viscoelasticity and the numerical simulation model are compared and verified. The results show that the gel exhibits viscoelasticity at high shear rate, and when the gel concentration is increased from 500 mg/L to 1500 mg/L, the relaxation time decreases from 1.04 s to 0.08 s and from 6.3 s to 0.8 s before and after gelation, respectively. The application effects of the models show that the new model takes into account the viscoelasticity of the gel, which is 12.3 percentage points higher than that of the traditional pressure model based on the reservoir engineering method and 10.6 percentage points higher than that of the numerical simulation model.

Research and Application of Deep Profile Control and Flooding Technology in Water Flooding Reservoir

Research and Application of Deep Profile Control and Flooding Technology in Water Flooding Reservoir