Research on High-Strength Balanced Plugging Removal System and Process Parameter Design

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.

1. Introduction

Acidizing and plugging removal is a core pressure reduction and injection enhancement technique widely used in Bohai Sea oilfields [1,2,3]. While mature for conventional wells with limited reservoir thickness, it performs poorly in complex wells featuring multi-layer systems, large vertical spans, long intervals, significant permeability/pressure variations, and long-term polymer flooding [4]. As waterflood development advances and tertiary recovery expands in Bohai, improving acidizing efficiency for these wells to achieve precision water injection has become a critical technical challenge [5,6,7,8,9].

Currently, ~50% of Bohai water injection wells rely on bullhead acidizing. In heterogeneous long-interval wells, acid preferentially channels through high-permeability low-pressure zones, causing uneven distribution: high-permeability layers are over-stimulated while low-permeability layers remain untreated. This exacerbates interlayer permeability contrasts, leading to premature water breakthrough in production wells, elevated water cuts, and reduced productivity [10]. Therefore, temporary plugging and diversion acidizing is urgently needed for balanced injection–production and fine late-field development [11,12,13].

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].

Against this background, this study develops a high-intensity balanced acidizing technology for Bohai complex reservoirs. Based on a commercial TPA, we optimize its pH response threshold from pH < 5.0 to pH < 4.5 and adjust its spontaneous degradation cycle to 72 h, matching Bohai’s polymer flooding well conditions and overcoming premature plugging/incomplete degradation issues [15,16,17,18,19]. A pH-buffered composite retarded acid system highly compatible with the TPA is developed, avoiding chemical incompatibility and enabling the synergistic “temporary plugging first, acidizing second, simultaneous degradation” mechanism. A quantitative correlation between permeability contrast, TPA dosage and diversion effect is established via parallel core flooding experiments, replacing empirical parameter design. This technology achieves balanced layered stimulation for complex offshore wells, optimizes water absorption profiles, and provides technical support for efficient late-stage waterflood development in the Bohai Oilfield [20].

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:CaCl₂:MgCl₂·6H₂O = 7%:0.6%:0.4%.

CS-03 pH-sensitive TPA (colorless transparent liquid, relative density 1.2–1.5, uniform dispersibility in acid, acid-insoluble content ≥95.0%, water solubility ≥99.0%); natural cores from the target oilfield (three core samples with typical permeabilities of 38.14 mD, 279.76 mD and 324.04 mD were selected); simulated formation water (with a composition of NaCl:CaCl₂:MgCl₂·6H₂O = 7%:0.6%:0.4%); composite retarded acid system (the optimal acidizing system for the target oilfield) [21,22,23,24].

The parameters of the experimental cores are shown in

Table 1. Rock mineral composition.

Mineral Composition	Relative Content/%	Mineral Composition	Relative Content/%	Mineral Composition	Relative Content/%
Calcite (CaCO3)	1	Clay	13	Montmorillonite	14
Fine Sand	35	Plagioclase	15	Illite	3
Orthoclase	10	Chlorite	2	Kaolinite	7

and

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

, Basic information on TPA productsare shown in

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

.

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),

$$R_{\mathrm{m}}={\displaystyle \frac{m_0-m_1}{m_0}}\times 100\mathrm{\%}$$

(1)

where m₀ and m₁ 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):

$${\mathrm{P}}_{\mathrm{r}}={\displaystyle \frac{m_1}{m_2}}\times 100\mathrm{\%}$$

(2)

where: P_r—precipitation rate;

m₁—mass of precipitates, g;

m₂—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 (K₀) 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 (K₁). 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 (K₂) was measured. The permeability recovery rate (R_d, %) was calculated using Formula (3) [26].

$$R_{\mathrm{d}}={\displaystyle \frac{K_2}{K_1}}\times 100\mathrm{\%}$$

(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 (K₁) 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 (K₂) 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 (K₃). Finally, the plugging efficiency was evaluated via the blocking rate calculated by Formula (4),

$$\mathrm{E}={\displaystyle \frac{{\mathrm{K}}_1-{\mathrm{K}}_2}{{\mathrm{K}}_1}}\times 100\mathrm{\%}$$

(4)

and the acidizing recovery capability was assessed via the unplugging rate calculated by Formula (5).

$$\mathrm{P}={\displaystyle \frac{{\mathrm{K}}_3-{\mathrm{K}}_2}{{\mathrm{K}}_1}}\times 100\mathrm{\%}$$

(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. Performance evaluation and technical indicators of TPAs.

Product Code	Technical Specifications	Experimental Results
CS-01	• Appearance: Light yellow particles • Density: ≥1.1 g/cm3 • 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/cm3	Rejected: No precipitation observed over extended period
CS-05	• Appearance: Silver liquid • Density: 1.3–1.6 g/cm3 • Hardness: >75 HB • Dissolution rate: 15–180 mg/(h·cm2)	Rejected: Precipitation products non-degradable over extended period
CS-06	• Appearance: Black liquid • Density: 1.3–1.6 g/cm3 • Hardness: >75 HB • Compressive strength: 370 MPa • Elongation at break: >10% • Dissolution rate: 15–180 mg/(h·cm2)	Rejected: No acid precipitation observed over extended period

.

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(CH₃)₂) and carboxyl groups (-COOH), with a small number of amide groups (-CONH₂) 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 < 4), tertiary amine groups in the molecular chain undergo protonation to form quaternary ammonium cations, causing the molecular chains to transform from an extended conformation to a coiled conformation. Simultaneously, the intermolecular hydrogen bonding between protonated carboxyl groups is significantly enhanced, triggering intermolecular crosslinking and aggregation. Solid precipitate particles with a particle size of 100–500 nm are formed within 30 s at 60 °C, which form a dense plugging layer through bridging and filling in the core pore throats [27,28,29].

Core reaction equations:

-N(CH₃)₂ + H⁺ ⇌ -NH⁺(CH₃)₂

n(-COOH) + n(-COOH) ⇌ (-COOH···HOOC-)_n

(2)

Degradation and Plug Removal Mechanism under Neutral/Weakly Alkaline Conditions

During subsequent injection of neutral formation water (pH = 7–8), protonated tertiary amine groups undergo deprotonation, and carboxyl groups dissociate into carboxylate anions. The intermolecular hydrogen bonds break, the crosslinked network disintegrates, and the solid precipitates redissolve into water-soluble linear polymer molecules, which are completely discharged from the formation with the injected water without solid residue. Experimental verification shows that this degradation process can be completed within 72 h at 60 °C, with a plug removal efficiency ≥ 90%, which is consistent with the previous experimental results [30,31,32].

The core advantage of this mechanism is its well-defined pH response threshold (plugging triggered at pH < 4, degradation triggered at 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. Comprehensive evaluation of core performance and economic efficiency of commercial pH-sensitive TPAs.

Product Name	CS-03 pH-Sensitive TPA	SGA® 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.

.

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^® 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. Plugging removal performance of acid systems and composite corrosion-inhibited acid systems.

Core No.		22	23	24	25	26	27
Initial Permeability/mD		1160	1594	1938	766	2469	1782
Post-Contamination Permeability/mD		881.43	1084.45	1532.91	431.8	1851.09	1053.65
15% HCl	Post-Treatment Permeability/mD	1454.3	1843.57	2713.25	742.70	3239.41	1875.50
	Permeability Recovery Rate/%	165	170	177	172	175	178
Complex Acid	Post-Treatment Permeability/mD	1119.42	1453.16	2115.42	582.93	2535.99	1464.57
	Permeability Recovery Rate/%	127	134	138	135	137	139
Combined Acid	Post-Treatment Permeability/mD	907.87	1160.36	1778.18	474.98	2110.24	1253.84
	Permeability Recovery Rate/%	103	107	116	110	114	119
Fluoboric Acid	Post-Treatment Permeability/mD	1652.96	2056.31	3029.72	824.49	3626.66	2099.12
	Permeability Recovery Rate/%	188	190	198	191	196	199
Composite Retarded Acid	Post-Treatment Permeability/mD	1799.48	2252.54	3316.14	854.94	3854.85	2208.54
	Permeability Recovery Rate/%	204	208	216	198	208	210
Mud Acid	Post-Treatment Permeability/mD	1357.40	1756.81	2559.96	708.15	3091.32	1770.13
	Permeability Recovery Rate/%	154	162	167	164	167	168

.

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. Core plugging efficiency.

Core No.	Water Flooding Permeability /mD	Post-Plugging Water Flooding Permeability /mD	Plugging Efficiency /%	Post-Unplugging Water Flooding Permeability /mD	Unplugging Efficiency /%
1	38.14	2.28	94.01	37.53	92.4
9	279.76	26.25	90.62	279.75	90.61
12	324.04	32.4	90.00	324.63	90.18

.

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

Data from dual-core parallel flow experiments were processed to obtain injection pressure and flow distribution curves for high- and low-permeability cores, providing critical experimental evidence for optimizing the diversion control capability of temporary plugging acidizing. The experimental results are shown in the Figure 5, Figure 6 and Figure 7.

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. Plugging rates of different injection methods.

Core No.	Gas Permeability/mD	Injection Method	Plugging Rate/%
5	317.26	TPA first then acid	94.01 ± 0.52
6	318.40	Acid first then TPA	83.15 ± 0.76
11	1125.34	TPA first then acid	90.54 ± 0.58
7	1078.26	Acid first then TPA	81.55 ± 0.72
14	3715.74	TPA first then acid	89.73 ± 0.61
15	3628.53	Acid first then TPA	80.94 ± 0.79

.

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. Plugging rates at different injection rates.

Core No.	Gas Permeability/mD	Injection Rate/mL·min−1	Plugging Rate/%
16	317.26	0.05	94.07 ± 0.43
17	320.42	0.1	92.87 ± 0.51
18	318.21	0.3	92.59 ± 0.57
19	3729.56	0.05	86.97 ± 0.62
20	3625.34	0.1	86.33 ± 0.68
21	3376.18	0.3	85.94 ± 0.74

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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. Core parameters.

	Permeability Contrast	Porosity /%	Water Permeability /mD	Gas Permeability /mD	Post-Contamination Water Permeability /mD	Recovered Water Permeability /mD	Flow Distribution Rate /%
Low permeability	20	12.29	34.02	183.24	20.37	53.76	75.18
High permeability		28.10	353.42	3654.80	242.54	351.44	24.82

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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. Physicochemical property changes of CS-03 TPA at different aging times.

Aging Time/d	Appearance	pH Value	Relative Density	Acid-Insoluble Content/%	Water Solubility/%
0 (Fresh sample)	Colorless transparent liquid	6.8 ± 0.2	1.32 ± 0.03	96.2 ± 0.2	99.5 ± 0.1
7	Colorless transparent liquid	6.7 ± 0.2	1.31 ± 0.03	95.8 ± 0.2	99.3 ± 0.1
30	Slightly yellow transparent liquid	6.5 ± 0.3	1.30 ± 0.04	95.1 ± 0.2	99.0 ± 0.1
90	Light yellow transparent liquid	6.3 ± 0.3	1.29 ± 0.04	94.3 ± 0.3	98.7 ± 0.2
180	Light yellow transparent liquid	6.1 ± 0.4	1.27 ± 0.05	92.7 ± 0.3	97.9 ± 0.2
360	Yellow transparent liquid	5.7 ± 0.5	1.24 ± 0.06	89.5 ± 0.4	95.2 ± 0.3

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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. Changes in plugging and plugging removal performance of CS-03 TPA at different aging times.

Aging Time/d	Plugging Efficiency/%	Plugging Strength/(MPa·m−1)	24 h Plugging Removal Rate/%	Permeability Recovery Rate/%
0 (Fresh sample)	98.7 ± 0.3	0.35 ± 0.01	93.2 ± 0.4	92.4 ± 0.5
7	98.2 ± 0.3	0.34 ± 0.01	92.8 ± 0.4	91.9 ± 0.5
30	97.5 ± 0.4	0.33 ± 0.01	92.1 ± 0.5	91.2 ± 0.6
90	96.1 ± 0.4	0.31 ± 0.02	90.5 ± 0.5	89.7 ± 0.6
180	92.3 ± 0.5	0.28 ± 0.02	88.3 ± 0.6	86.5 ± 0.7
360	85.6 ± 0.5	0.22 ± 0.02	82.7 ± 0.7	79.1 ± 0.8

.

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 m³ (average 76 m³/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 < ±0.8 MPa, a permeability recovery rate > 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 <20 h, significantly better than conventional diverting acidizing (>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 × 10⁴ 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.