Open AccessArticle Research on High-Strength Balanced Plugging Removal System and Process Parameter Design 1 Tianjin Branch, CNOOC (China) Co., Ltd., Ocean High-Tech Development Zone, Tianjin Binhai New Area, 2121 Haichuan Road, Tianjin 300459, China 2 Hubei Provincial Key Laboratory of Oil and Gas Drilling and Production Engineering, School of Petroleum Engineering, Yangtze University, Wuhan 430100, China * Author to whom correspondence should be addressed. Processes 2026, 14(12), 1855; https://doi.org/10.3390/pr14121855 (registering DOI) Submission received: 23 March 2026 / Revised: 25 May 2026 / Accepted: 4 June 2026 / Published: 8 June 2026 Abstract Temporary plugging acidizing is a critical well stimulation technique for improving water absorption profiles and addressing low/zero water intake in individual intervals of heterogeneous reservoirs, serving as a core measure for production stabilization and enhancement in mature oilfields. However, there remains an urgent demand for balanced stimulation technologies tailored to the unique reservoir conditions of offshore water injection wells. In this study, targeting the reservoir characteristics of the target offshore oilfield, we systematically investigated the effects of Temporary Plugging Agent (TPA) concentration, acid injection slug size, injection rate, and permeability contrast on plugging and diversion performance. Three core innovations are achieved: (1) optimization of a high-strength self-diverting TPA; (2) development of a matched composite retarded acid system; (3) establishment of quantitative process parameter design methods for temporary plugging acidizing in heterogeneous reservoirs. Based on these, a high-strength balanced plugging removal technology for water injection wells was developed. This technology enables balanced stimulation of thin interbeds in offshore water injection wells with large vertical spans, long treatment intervals, and significant variations in reservoir properties and formation pressure, providing robust technical support for optimizing water absorption profiles, achieving precise layer-by-layer stimulation, and enhancing waterflood development efficiency. Keywords: TPDA; BPR; OWIWs; HORs; parameter optimization 1. Introduction Existing diversion technologies still have limitations: mainstream particle-type TPA causes secondary damage due to incomplete flowback, while crosslinked gel TPA requires long well shut-in time and has residual damage, and both have relatively low diversion efficiency [ 14]. 2. Experimental Materials and Method 2.1. Experimental Materials Experimental Materials: Acid system compositions: ① 15% hydrochloric acid; ② complex acid system; ③ fluoboric acid system; ④ combined acid system; ⑤ composite retarded acid system; ⑥ mud acid system; simulated formation water NaCl:CaCl 2:MgCl 2·6H 2O = 7%:0.6%:0.4%. Experimental Equipment: Hastelloy intermediate container, core holder, constant-flow pump, hand pump, digital pressure gauge, constant-temperature incubator, vacuum drying oven. Experimental Equipment: Hastelloy intermediate container, core holder and pipelines, constant-flow pump, hand pump, digital pressure gauge. 2.2. Experimental Method 2.2.1. Dissolution Performance Evaluation Test Add the acid solution and core powder to a conical flask at a mass ratio of 20:1 sequentially, shake well, and place it in a constant-temperature water bath. Start timing when the system temperature reaches 60 °C, and terminate the experiment after different reaction times. Then, perform vacuum filtration to separate the reaction system, collect the solid-phase components, dry them to constant weight, and weigh the mass of the core powder after dissolution. The dissolution rate (R m, %) is calculated using Formula (1), R m = m 0 − m 1 m 0 ୍ଠ 100 % (1) where m 0 and m 1 represent the mass (g) of the core powder before and after the dissolution reaction, respectively [ 25]. 2.2.2. Precipitation Performance Evaluation Experiment Prepare 100 mL of compound retarded acid and TPA solutions with concentrations of 3–15%. Add TPA solutions of different concentrations into the compound retarded acid, dissolve the TPA completely in the acid with a magnetic stirrer, then place the mixture in a constant-temperature oven at experimental temperatures of 60 °C and 75 °C, respectively. The precipitation state of the TPA is observed every 3 h. The particle precipitation rate of the TPA after acid contact is calculated by Formula (2): P r = m 1 m 2 ୍ଠ 100 % (2) where: P r—precipitation rate; m 1—mass of precipitates, g; m 2—mass of solute in the original solution, g. 2.2.3. Plugging Removal Performance Evaluation Experiment The natural core from the reservoir section was cleaned of oil, dried, and vacuum-saturated with simulated formation water. The core was then displaced with simulated formation water at a flow rate of 0.5 mL/min until the pressure stabilized, and the initial permeability (K 0) was measured. The core was subsequently displaced with field injection water at 0.5 mL/min for 40 PV, and the pressure changes were recorded to determine the permeability after contamination (K 1). Different PV volumes of the acidizing system were then injected in reverse, and the system was allowed to react for 4 h at the reservoir temperature of 60 °C. Finally, the core was displaced with simulated formation water at 0.5 mL/min until the pressure stabilized, and the permeability after plugging removal (K 2) was measured. The permeability recovery rate (R d, %) was calculated using Formula (3) [ 26]. R d = K 2 K 1 ୍ଠ 100 % (3) 2.2.4. Optimization of TPA Concentration The entire core flooding experiment was conducted at a constant temperature of 60 °C, with the injection flow rate precisely controlled at 0.05 mL/min and pressure and flow parameters monitored at 1 min intervals throughout the test. First, initial water flooding was performed to measure the baseline permeability (K 1) of different core samples. TPA solution was then injected until pressure stabilized, the agent consumption was recorded and pressure was maintained, and the post-plugging core permeability (K 2) was subsequently calculated using Darcy’s law. Next, acid was injected until the pressure reached 5 MPa, the valve was closed, and the mixture was left to react for 2 h to ensure full reaction between the acid and the TPA. Secondary water flooding was then carried out to determine the post-treatment permeability (K 3). Finally, the plugging efficiency was evaluated via the blocking rate calculated by Formula (4), E = K 1 − K 2 K 1 ୍ଠ 100 % (4) and the acidizing recovery capability was assessed via the unplugging rate calculated by Formula (5). P = K 3 − K 2 K 1 ୍ଠ 100 % (5) 2.2.5. Balanced Plugging Removal Process Parameter Design and Optimization for Water Injection Wells All core flooding experiments were conducted at a constant temperature of 60 °C, with pressure and flow rate monitored at 1 min intervals throughout the test. The general procedure was as follows: ① polymer flooding to simulate reservoir damage; ② acid pretreatment; ③ injection of the CS-03 TPA until pressure stabilized, followed by pressure holding; ④ acid injection to 5 MPa and static reaction for 2 h; ⑤ secondary water flooding for effect evaluation. (1) Core Permeability Contrast Optimization Experiment This experiment investigated the effect of permeability contrast on temporary plugging diversion performance. The injection rate was fixed at 0.05 mL/min, and dual-core parallel flooding mode was adopted to test three permeability contrasts (3.3, 10, 20). The selective plugging effect was quantitatively evaluated by the flow distribution ratio. (2) Acid Slug Optimization Experiment This experiment compared the temporary plugging acidizing effects of different slug sequences. The injection rate was fixed at 0.05 mL/min, and two modes were tested: ① 0.025 PV TPA + 0.025 PV spacer slug + 0.1 PV acid; ② 0.1 PV acid + 0.025 PV spacer slug + 0.025 PV TPA. The optimal scheme was selected based on plugging rate and the permeability recovery effect. (3) Injection Rate Optimization Experiment This experiment balanced deep plugging capability and construction economy. Three injection rates (0.05, 0.1, 0.3 mL/min) were tested, and the plugging effect and permeability recovery were compared to determine the optimal field injection rate range. 2.2.6. Long-Term Stability Simulation Experiment on TPA The prepared 7% CS-03 TPA solution was sealed in a high-pressure reactor and placed in a constant-temperature oven at 60 °C for aging for 7 d, 30 d, 90 d, 180 d and 360 d, respectively. Samples were taken regularly to test their physicochemical property indicators, and the plugging efficiency, plugging strength and plugging removal rate of the aged TPA were tested using the same core flooding experimental method as in Section 2.1. Meanwhile, experimental groups with different temperatures, salinities and pH values were set up to study the influence of reservoir environmental factors on the long-term performance of the TPA. 2.2.7. Physicochemical Property Evolution at Different Aging Times The basic physicochemical properties of the TPA are the prerequisites for maintaining its acid response characteristics and engineering performance, and the evolution of physicochemical properties under long-term reservoir conditions directly determines the effective service life of the system. To quantitatively characterize the chemical stability of the CS-03 TPA under simulated reservoir conditions, key indicators such as appearance, pH value, relative density, acid-insoluble content and water solubility of samples at different aging times were systematically tested, and the results are shown in Table 10. 3. Results and Discussion 3.1. Optimization of Temporary Plugging Materials Through investigation of TPAs, six products were selected for preliminary evaluation, with research conducted on their water solubility, precipitation characteristics, and plug removal performance for each product. Performance evaluation and technical indicators of TPAs are shown in Table 4. The film-forming TPA did not completely degrade after 72 h. Among water-soluble TPAs, some products cannot form effective plugs in acidic environments, while others fail to degrade over extended periods. For oil-soluble TPAs, some are insoluble in acid, some are insoluble in water, and others are unsuitable for reservoir temperatures—none meet the requirements. The pH-sensitive TPA CS-03 can form effective plugs in acidic environments and easily degrades when pH increases during water injection, fulfilling reservoir conditions. 3.2. Response Mechanism of CS-03 pH-Sensitive TPA CS-03 is an aqueous solution of a ternary random copolymer based on partially hydrolyzed polyacrylamide (HPAM) grafted with acrylic acid (AA) and 2-(dimethylamino)ethyl methacrylate (DMAEMA). Its core responsive functional groups are tertiary amine groups (-N(CH 3) 2) and carboxyl groups (-COOH), with a small number of amide groups (-CONH 2) retained in the molecular chain to regulate water solubility and degradation rate. The pH responsiveness of this TPA originates from the reversible protonation–deprotonation reaction of tertiary amine groups and the synergistic effect of hydrogen bond association–dissociation of carboxyl groups. The specific processes are as follows: (1) Acid-Induced Plugging Nucleation Mechanism Upon contact with the acidizing system (pH 6), which perfectly matches the on-site acidizing system and formation water environment, achieving reversible regulation of “acid-induced plugging and water-induced self-degradation”. 3.3. Acidizing System Performance Evaluation Plugging response speed, plugging strength, removal thoroughness and economy are the four core factors determining the field application effect of TPAs. To visually compare the performance differences among various products, based on laboratory parallel experimental data, publicly available industrial technical indicators and field application feedback from the Bohai Oilfield, this paper standardizes and quantifies the key parameters of six mainstream pH-sensitive TPAs. A comparative analysis is carried out from five dimensions: rapid plugging capacity, stable plugging capacity, pressure bearing capacity, removal efficiency and full-life-cycle cost. Taking the optimized CS-03 TPA in this study as the benchmark, the performance difference percentage of each product is calculated, and the results are shown in Table 5. 3.3.1. Comparison of Mainstream pH-Sensitive TPAs Based on the investigation and experimental evaluation of mainstream pH-sensitive TPAs, the following conclusions are drawn. In summary, the comprehensive multi-dimensional quantitative comparison ( Table 5) demonstrates that the optimized CS-03 pH-sensitive TPA is the only product that fully matches the development characteristics of the Bohai Oilfield, namely “large vertical span, long intervals, strong heterogeneity and extensive polymer flooding”. Specifically, CS-03 achieves a 30 min rapid plugging efficiency of 92%, which is 22.7% higher than the second-ranked PAE nanocomposite gel and 67.3% higher than the slowest core–shell-type agent. Its 24 h removal efficiency reaches 93.2%, the highest among all products, with a final 72 h removal rate of 99.1% ensuring zero solid residue. Notably, it forms a fiber–gel composite structure with residual polymers, increasing the overall pressure bearing capacity to 21 MPa, which effectively solves the industry-wide problem of polymer–TPA composite damage. With a comprehensive cost-performance index of 1.00, CS-03 costs only one-third of imported core–shell agents while delivering superior performance. PAE nanocomposite gel, despite having the highest plugging strength (1.87 MPa/m), has a high single-well cost of 180,000–250,000 yuan and poor salt tolerance, making it only suitable for temporary plugging in ultra-high-pressure deep wells. Easily degradable cellulose microspheres have the lowest cost (70,000–110,000 yuan per well) but suffer from low plugging strength (0.12 MPa/m) and poor temperature resistance, limiting their application to shallow low-cost wells. The remaining products (SGA ପ୍ପ self-diverting gelled acid, PF-SMARTSEAL and core–shell dual-responsive agents) have significant limitations in plugging efficiency, removal performance or cost-effectiveness. Therefore, CS-03 is the optimal selection for temporary plugging acidizing in heterogeneous water injection wells in the Bohai Oilfield. 3.3.2. Dissolution Performance Evaluation Experiment The dissolution performance of different acid systems on core powder from the target reservoir section was evaluated to optimize the acidizing system suitable for the target oil reservoir. The experimental results are shown in the Figure 1. The results indicate that with prolonged reaction time, the dissolution rates of different acid systems on core samples from the target reservoir section initially increase and then stabilize. When the reaction time exceeds 4.0 h, the dissolution rates remain essentially unchanged. The composite retarded acid system exhibits a lower initial dissolution rate, ultimately reaching 35–38%, with reaction equilibrium achieved at approximately 3 h. 3.3.3. Precipitation Performance Evaluation Experiment By evaluating the precipitation performance of the CS-03 TPA, the performance advantages of the self-developed TPA were clarified. The experimental results are presented in the Figure 2. It can be concluded from the experimental results that the CS-03 TPA can react with acid immediately to precipitate solid substances, which enables rapid plugging establishment in reservoir throats in practical application, and the precipitated solids can be degraded by subsequent water injection. When the concentration of CS-03 is between 5% and 15%, its precipitation rate is higher than 70% within 20 min, and exceeds 80% at 60 °C and 75 °C. In addition, temperature and salinity have little effect on the precipitation and plugging removal performance of CS-03. 3.3.4. Plugging Removal Performance Evaluation By evaluating the plugging removal performance of different acid systems on core samples from the target reservoir section, the optimal acidizing system suitable for the target oil reservoir was selected. The experimental results are shown in the Table 6. The results demonstrate that after contamination, the permeability of natural core samples from the target reservoir section decreased significantly, indicating severe core damage. After treatment with different acid systems, the permeability of the natural cores increased substantially, and the permeability recovery values (plugging removal efficiency) progressively improved. Among them, the composite retarded acid system showed the best recovery performance for contaminated cores, achieving a recovery rate of up to 210%. Considering both dissolution performance and plugging removal effectiveness, the composite retarded acid system was selected as the optimal acidizing treatment for the target oilfield. 3.4. Optimization of TPA Concentration TPA concentration is one of the core parameters governing the effectiveness of temporary plugging acidizing. An excessively low concentration fails to form effective plugs, resulting in continued acid channeling through high-permeability zones; conversely, an excessively high concentration causes excessive TPA accumulation, leading to difficult plug removal and even secondary formation damage. This experiment aims to investigate the plugging efficiency and plug removal performance of the CS-03 pH-sensitive TPA at different concentrations in cores with varying permeabilities, determine the optimal TPA concentration range that meets field operation requirements, and provide critical parameter support for the field implementation of the balanced plugging removal technology for offshore water injection wells. The post-plugging core permeability was obtained using Darcy’s law, and the blocking rate and unplugging rate were calculated. This quantitatively characterized the plugging selectivity of the TPA in cores with different permeabilities and the effectiveness of acidizing in removing blockages, providing key parameters for optimizing the temporary plugging acidizing process. The experimental results are shown in Table 7. The experimental results indicate that the permeability of all cores decreased after TPA injection. The plugging efficiency decreased as core permeability increased, because lower-permeability cores with denser pore structures facilitate more effective plugging. Core 1 demonstrated the best plugging performance, achieving a plugging efficiency of 94.01%. During secondary water flooding, the temporary plugging particles dissolved upon water contact, eliminating the formed plugging barriers and restoring core permeability, with all unplugging efficiencies exceeding 90%. The pressure curves of different concentrations of TPAs in cores with varying permeabilities during the experiment are shown in Figure 3. Analysis of the pressure curves reveals that during primary water flooding and TPA injection, the pressure exhibits an increasing trend. During acid injection with pressure buildup, the pressure rises rapidly and then decreases after pressure release. Secondary water flooding shows an initial pressure increase followed by a decrease. This occurs because the injected TPA blocks pore throats within the core, leading to pressure buildup. During the initial stage of secondary water flooding, the plugging remains intact, causing continued pressure rise. When the injected water volume reaches a certain threshold, the temporary plugging particles dissolve, disrupting the plugging and reducing the pressure—hence the observed pressure trend of first increasing then decreasing during secondary water flooding. For cores with the same permeability, higher concentrations of TPA result in faster pressure rise, indicating better plugging efficiency. The plugging pressure exceeds 4 MPa, with plugging efficiency > 90% and unplugging efficiency > 90%, meeting field operation standards. Therefore, to achieve optimal plugging pressure, the recommended field concentration for the TPA is 5–10%. To further determine the optimal concentration of the TPA, based on the experimental data of three concentrations (5%, 7%, and 10%), this section will plot and comparatively analyze the correlation between plugging efficiency and unplugging efficiency within this concentration range, systematically demonstrate the synergistic matching between plugging strength and unplugging effect at different concentrations, ultimately identify the optimal concentration, and refine the broad recommended concentration range of 5–10% to a precise single value, significantly improving the scientificity and operability of on-site process parameter design. The experimental results are shown in the Figure 4. As shown in the figure, as the TPA injection volume gradually increases from 0 PV to approximately 1.0 PV, the plugging efficiencies of the core samples at the three concentrations of 5%, 7%, and 10% all show a continuous upward trend. Meanwhile, the unplugging efficiency remains stable at around 0% throughout the TPA injection process, indicating that the TPA can be effectively retained in the core pores and form a tight plug without premature unplugging. The plugging performance exhibits obvious concentration dependence: the higher the TPA concentration, the faster the plugging efficiency increases at the same injection volume, and the higher the final stable plugging efficiency achieved. When the injection fluid is switched to acid solution after the injection volume exceeds 1.0 PV, the acid rapidly reacts with the TPA in the cores. The plugging efficiency of all three concentration groups decreases sharply, while the unplugging efficiency increases rapidly simultaneously. The unplugging performance also enhances with the increase in TPA concentration, and the final unplugging efficiencies of the 7% and 10% concentration groups both exceed 94% with negligible difference between them. Comprehensive analysis of technical performance and economic benefits shows that although the plugging and unplugging effects of the 10% concentration are slightly superior, the performance gap with the 7% concentration is very limited. However, the 7% concentration can significantly reduce the chemical usage cost. Therefore, 7% is the optimal application concentration for this TPA system. 3.5. Balanced Plugging Removal Process Parameter Design and Optimization for Water Injection Wells Based on the physical properties of the target reservoir, this study establishes a multi-factor synergistic evaluation mechanism to systematically investigate the impacts of key parameters on acidizing and temporary plugging performance, including acid injection slug size, injection rate, and core permeability contrast. The primary objective is to optimize a temporary plugging acidizing process tailored for heterogeneous reservoirs, which achieves balanced formation stimulation by effectively plugging high-permeability thief zones while thoroughly unblocking under-stimulated low-permeability intervals. Ultimately, this optimized process is designed to improve plugging removal efficiency in water injection wells, restore balanced water intake profiles, and prolong the effective duration of the stimulation treatment. 3.5.1. Core Permeability Contrast Optimization Experiment Analysis of the flow distribution rate curves for high- and low-permeability cores reveals that during primary water flooding and TPA injection, pressure increases with the injection process, with the high-permeability core exhibiting a higher flow distribution rate than the low-permeability core. After acid injection with pressure buildup concludes and pressure drops, the flow distribution rate of the low-permeability core increases while that of the high-permeability core decreases. This indicates that the TPA forms plugs in the high-permeability core upon acid contact, causing acid diversion that enhances the permeability and flow distribution rate of the low-permeability core. At permeability contrasts of 3.3, 10, and 20, the low-permeability flow distribution rates were 71.42%, 73.43%, and 75.43%, respectively, all exceeding 70% and meeting the diversion requirement. 3.5.2. Acid Slug Optimization Experiment By recording flow rate variations during flooding under two different injection modes, this experiment analyzes core permeability recovery and evaluates the synergistic effects between TPAs and acid systems. The results provide critical experimental basis for optimizing injection procedures in temporary plugging acidizing treatments for heterogeneous reservoirs. The injection pressure curves and plugging rates under different injection modes are presented in Figure 8 and Table 8. Data analysis indicates that for cores with the same permeability, the pressure increases faster and the plugging rate is higher when injecting the TPA prior to acid. Therefore, the injection sequence of the TPA first followed by acid should be adopted, achieving up to a 94% plugging rate in low-permeability cores. 3.5.3. Injection Rate Optimization Experiment By comparing the plugging effectiveness and permeability recovery under different injection rates, this experiment reveals the influence mechanism of injection rate on TPA migration/distribution and acid–rock reaction efficiency, providing a scientific basis for optimizing field operation rates. The experimental results are presented in Figure 9 and Table 9. After injection at different rates, results show that lower injection rates lead to faster pressure increases, allowing more complete deposition of TPAs in core pore throats and better plugging effectiveness. Therefore, lower injection rates are recommended for field operations. 3.6. Laboratory Simulation of Field Experiment 3.6.1. Simulation of Diverting Acidification Effect Using a 0.05 mL/min injection rate, synthetic cores were sequentially subjected to contamination, TPA injection, acid injection, and secondary water flooding to evaluate permeability recovery in low-permeability cores after diversion acidizing. The experimental results are presented in Figure 10 and Table 10. Experimental results demonstrate that when contacting acid, the TPA forms effective plugs in high-permeability cores, thereby enhancing low-permeability core permeability and increasing its flow distribution rate to 75.18%, meeting field operation requirements. 3.6.2. Long-Term Stability Simulation Experiment for TPA To address the deficiency of long-term stability data of the system in previous studies, this subsection supplements long-term aging experiments under simulated reservoir conditions of the Bohai Oilfield (60 °C, 12 MPa, 7% salinity). The physicochemical property evolution, plugging performance retention law and environmental factors influencing characteristics of the CS-03 TPA at different aging times were systematically tested, providing data support for the long-term safe application of the technology. (1) Physicochemical Property Evolution at Different Aging Times The basic physicochemical properties of the TPA are the prerequisites for its acid response characteristics and engineering performance, and the evolution of physicochemical properties under long-term reservoir conditions directly determines the effective service life of the system, so it is necessary to quantitatively characterize the chemical stability of the CS-03 TPA under simulated reservoir conditions. The results are shown in Table 11. The results show that the physicochemical properties of the CS-03 TPA remain stable within 180 d, with no obvious precipitation or delamination in appearance; the acid-insoluble content remains above 92%, and the water solubility is >97%. After 360 d of aging, the molecular chain undergoes slight degradation, and the acid-insoluble content decreases to 89.5%, but it still meets the field application requirements (≥85%). (2) Retention Law of Plugging Performance with Time Changes in physicochemical properties will eventually be reflected in the core engineering performance of the TPA, and the plugging strength retention capacity and plugging removal thoroughness are the core indicators for evaluating its long-term application safety. To clarify the attenuation law of the CS-03 TPA’s plugging performance with aging time, standard core flooding experiments were used to test the plugging efficiency, plugging strength, 24 h plugging removal rate and permeability recovery rate of samples at different aging times, and the results are shown in Table 12. The results show that the plugging performance of the CS-03 TPA shows a slow downward trend with aging time. Within 180 d, the plugging efficiency remains above 92%, the plugging strength is >0.28 MPa/m, and the 24 h plugging removal rate is >88%, which is highly consistent with the 6-month field tracking data (permeability recovery rate > 85%). After 360 d of aging, the plugging efficiency decreases to 85.6% and the plugging removal rate drops to 82.7%, indicating that the effective stability period of the system is about 180 d. 3.7. Conclusions This study developed an optimized pH-sensitive TPA CS-03 and its matched composite retarded acid system, forming a high-strength balanced plugging removal technology specifically designed for offshore heterogeneous water injection wells. The technology achieves rapid acid-induced pore-throat plugging in high-permeability zones with spontaneous water-induced degradation and no secondary damage, while the acid system delivers a maximum core permeability recovery rate of 216% through precise removal of pre-induced polymer damage and moderate matrix acidizing. Core flooding experiments demonstrate that CS-03 exhibits a peak plugging rate of 94.84% in 300 mD cores with >90% unplugging efficiency for all samples, and effectively diverts acid to under-stimulated low-permeability layers in heterogeneous parallel cores, achieving flow distribution ratios up to 75.43% at a permeability contrast of 20. 4. Field Test To verify the practical performance of the high-strength dynamically adaptive acidizing temporary plugging technology, 12 typical water injection wells (including 5 long-term polymer flooding wells) were tested in Block X, Bohai Oilfield. The target reservoirs have a vertical span of 35–82 m, permeability contrast of 8–22, and formation pressure difference of 12–18 MPa. Technical applicability and engineering value were evaluated by comparing water injection pressure, water absorption profile and injection increment before and after acidizing. 4.1. Temporary Plugging Diversion and Injection Enhancement After treatment, the average water injection pressure of the 12 wells decreased from 18.3 MPa to 12.1 MPa (33.9% reduction). The daily incremental injection per well was 45–128 m 3 (average 76 m 3/d), with a treatment efficiency of 91.7%. For long-term polymer flooding Well B-23H (permeability contrast 20), using the CS-03 TPA with compound retarded acid increased the low-permeability layer water absorption from 14.3% to 68.9%, diversion rate to 75.18%, and profile equilibrium index from 0.29 to 0.71. Isotope tracing showed the acid’s effective interval in low-permeability layers increased by 4.2 times, confirming excellent dynamic diversion performance. 4.2. High-Strength Plugging and Long-Term Performance For high-permeability layers (>500 mD), the CS-03 TPA achieved a plugging pressure gradient of 0.35 MPa/m at 110 °C, 94% higher than conventional acid-soluble particles (0.18 MPa/m). Field pressure monitoring showed the effective plugging duration exceeded 4 h during acidizing, meeting layered plugging removal requirements for 60 m long intervals. Six-month follow-up showed water injection pressure fluctuation 85%, and no secondary plugging. 4.3. Complex Working Condition Adaptability In polymer flooding Well G-17 with residual polymer, the CS-03 TPA formed a fiber–gel composite plugging structure, increasing temporary plugging strength to 21 MPa (vs. 12 MPa for conventional technology). After acidizing, low-permeability layer permeability increased 3.8 times, polymer injection pressure decreased by 27.4%, and water cut dropped from 92.1% to 86.3%, confirming effective resolution of polymer–TPA composite damage. The TPA water-induced degradation rate reached 93.2% within 24 h, meeting offshore environmental requirements. A single-well operation cycle was 36 h). 4.4. Economic Benefits Compared with conventional blanket acidizing, the new technology extended the effective injection enhancement period to 14 months (6–8 months for conventional), increased the incremental injection per ton of acid by 2.3 times, and achieved a cumulative block oil increment of 1.7 × 10 4 t and an input–output ratio of 1:4.6. In reservoirs with >40% high-permeability layers, the water absorption profile equilibrium index improved by 86%, effectively alleviating interlayer contradictions and reducing water flooding breakthrough risk. Author Contributions Conceptualization, X.M.; methodology, B.H.; software, S.L.; validation, B.H.; investigation, S.L.; resources, Y.F.; data curation, D.P.; writing—original draft preparation, X.T.; writing—review and editing, Q.A.; supervision, B.H.; project administration, X.M.; funding acquisition, H.C. All authors have read and agreed to the published version of the manuscript. Funding No funding was received for conducting this study. 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Variation curves of precipitation rate of CS-03 TPA with time in acid fluid at different temperatures and concentrations. Figure 3. Pressure curves of TPAs with different concentrations in cores with varying permeabilities. Figure 3. Pressure curves of TPAs with different concentrations in cores with varying permeabilities. Figure 4. Effect of CS-03 TPA concentration on plugging and unplugging efficiency. Figure 4. Effect of CS-03 TPA concentration on plugging and unplugging efficiency. Figure 5. Flow experiment curves of high-permeability (Core 8) and low-permeability (Core 2) cores under permeability contrast of 3.3. Figure 5. Flow experiment curves of high-permeability (Core 8) and low-permeability (Core 2) cores under permeability contrast of 3.3. Figure 6. Flow experiment curves of high-permeability (Core 10) and low-permeability (Core 3) cores under permeability contrast of 10. Figure 6. Flow experiment curves of high-permeability (Core 10) and low-permeability (Core 3) cores under permeability contrast of 10. Figure 7. Flow experiment curves of high-permeability (Core 13) and low-permeability (Core 3) cores under permeability contrast of 20. Figure 7. Flow experiment curves of high-permeability (Core 13) and low-permeability (Core 3) cores under permeability contrast of 20. Figure 8. Pressure curves of different injection methods. Figure 8. Pressure curves of different injection methods. Figure 9. Injection pressure curves of high-/low-permeability cores under different injection rates. Figure 9. Injection pressure curves of high-/low-permeability cores under different injection rates. Figure 10. Core permeability recovery after simulated field diversion acidizing. Figure 10. Core permeability recovery after simulated field diversion acidizing. Table 1. Rock mineral composition. Table 1. Rock mineral composition. Mineral Composition Relative Content/% Mineral Composition Relative Content/% Mineral Composition Relative Content/% Calcite (CaCO 3) 1 Clay 13 Montmorillonite 14 Fine Sand 35 Plagioclase 15 Illite 3 Orthoclase 10 Chlorite 2 Kaolinite 7 Table 2. Core parameters. Table 2. Core parameters. Core No. Porosity/% Water Permeability/mD Gas Permeability/mD 1 12.49 38.14 180.30 2 12.25 143.35 315.46 3 12.97 34.05 181.65 4 12.29 34.02 183.24 5 12.75 163.35 317.26 6 13.52 173.44 318.40 7 18.24 273.67 1078.26 8 18.35 266.10 1041.02 9 18.66 279.76 1377.39 10 19.32 280.17 1821.54 11 19.36 278.56 1125.34 12 27.47 324.04 3729.56 13 28.10 353.42 3654.80 14 28.37 325.81 3715.74 15 29.45 337.67 3628.53 16 14.75 155.75 317.26 17 13.69 169.87 320.42 18 15.77 142.59 318.21 19 23.72 1632.17 3729.56 20 22.94 1578.23 3625.34 21 21.76 1526.49 3376.18 22 1674 1594 30.5 23 1218 1160 28 24 2035 1938 30 25 26 766 804 26 2592 2469 32 27 1871 1782 30 Table 3. Basic information on TPA products. Table 3. Basic information on TPA products. Product Code Product Type Supplier CS-01 Film-forming TPA Shandong Kerui Petroleum Technology Co., Ltd. CS-02 Oil-soluble TPA Jereh Oil & Gas Engineering Corporation CS-03 pH-sensitive TPA CNOOC Energy Technology & Services Limited, Oilfield Chemicals Division CS-04 Water-soluble TPA Anton Oilfield Services (Group) Ltd. CS-05 Water-soluble TPA SINOPEC Research Institute of Petroleum Engineering Co., Ltd. (SRIPE) CS-06 Water-soluble TPA Research Institute of Petroleum Exploration & Development (RIPED), CNPC, Institute of Oilfield Chemistry Table 4. Performance evaluation and technical indicators of TPAs. Table 4. Performance evaluation and technical indicators of TPAs. Product Code Technical Specifications Experimental Results CS-01 • Appearance: Light yellow particles • Density: ≥1.1 g/cm 3• Particle size: 5–100 mesh • Water solubility: ≥90.0% • Compressive strength: ≥50 MPa Rejected: Incomplete degradation after 72 h CS-02 • Appearance: Colloidal particles • Particle size: 0.1–10 mm • Plugging efficiency: 95% • Unplugging rate: 90% Rejected: Water-insoluble, acid-soluble but no precipitation observed over extended period CS-03 • Appearance: Colorless transparent liquid • Relative density: 1.2–1.5 • Acid dispersibility: Uniform dispersion • Acid-insoluble content: ≥95.0% • Water-soluble content: ≥99.0% Candidate CS-04 • Appearance: White powder • Temperature resistance: 180 °C • Density: 1–1.8 g/cm 3Rejected: No precipitation observed over extended period CS-05 • Appearance: Silver liquid • Density: 1.3–1.6 g/cm 3• Hardness: >75 HB • Dissolution rate: 15–180 mg/(h·cm 2) Rejected: Precipitation products non-degradable over extended period CS-06 • Appearance: Black liquid • Density: 1.3–1.6 g/cm 3• Hardness: >75 HB • Compressive strength: 370 MPa • Elongation at break: >10% • Dissolution rate: 15–180 mg/(h·cm 2) Rejected: No acid precipitation observed over extended period Table 5. Comprehensive evaluation of core performance and economic efficiency of commercial pH-sensitive TPAs. Table 5. Comprehensive evaluation of core performance and economic efficiency of commercial pH-sensitive TPAs. Product Name CS-03 pH-Sensitive TPA SGA ପ୍ପ Self-Diverting Gelled Acid PF-SMARTSEAL Intelligent TPAnt PAE Nanocomposite Gel TPAnt Core–Shell pH/Temperature Dual-Responsive TPAnt Easily Degradable Cellulose Microspheres Temporary Plugging Efficiency (30 min Rapid Plugging Rate, %) 92 (Baseline) 98.7 (Baseline) 0.35 (Baseline) 12.0 (Baseline) (Polymer Composite System: 21.0) 93.2 (Baseline) 99.1 (Baseline) Final Plugging Efficiency (Stable Plugging Rate, %) 65 (−29.3%) 88.5 (−10.3%) 0.18 (−48.6%) 8.0 (−33.3%) 84.0 (−9.9%) 92.0 (−7.2%) Plugging Strength(MPa/m)60 (−34.8%) 85.0 (−13.9%) 0.15 (−57.1%) 6.0 (−50.0%) 78.0 (−16.3%) 85.0 (−14.2%) Pressure Bearing Capacity (Overall MPa) 75 (−18.5%) 92.5 (−6.3%) 1.87 (+434.3%) 35.0 (+191.7%) 91.0 (−2.4%) 95.0 (−4.1%) 24 h Removal Efficiency (%) 55 (−40.2%) 94.0 (−4.8%) 0.80 (+128.6%) 15.0 (+25.0%) 65.0 (−30.3%) 90.0 (−9.2%) Final Removal Efficiency (72 h, %) 70 (−23.9%) 90.5 (−8.3%) 0.12 (−65.7%) 5.0 (−58.3%) 82.0 (−12.0%) 95.0 (−4.1%) Single-Well Material Cost (10,000 RMB) 92 (Baseline) 98.7 (Baseline) 0.35 (Baseline) 12.0 (Baseline) (Polymer Composite System: 21.0) 93.2 (Baseline) 99.1 (Baseline) Comprehensive Cost-Performance Index (CS-03 = 1.0) 65 (−29.3%) 88.5 (−10.3%) 0.18 (−48.6%) 8.0 (−33.3%) 84.0 (−9.9%) 92.0 (−7.2%) Note: All data are derived from parallel experiments under simulated reservoir conditions of 60 °C and 7% salinity, as well as publicly available industrial standard values. The values in parentheses represent the percentage performance difference compared with CS-03; a positive value means superior to CS-03, while a negative value means inferior to CS-03. Table 6. Plugging removal performance of acid systems and composite corrosion-inhibited acid systems. Table 6. Plugging r
