Application of a Multistage Plugging System in a Fractured Reservoir of CO₂ Flooding

Abstract

CO₂ flooding has been successfully used in numerous oil fields as a strategy to improve oil recovery. However, several issues, including gas channeling, profile control, CO₂ sweep efficiency, oil displacement efficiency, etc., have been revealed in the development of CO₂ flooding, particularly in a fractured reservoir. In this paper, in view of the focus issues, a novel multistage plugging system is investigated, mainly including the polymer-gel system. The static and dynamic polymer-gel system performances are comprehensively evaluated. Based on the features of a fractured reservoir, a multiscale fracture model is built, and the applicable limits of the polymer-gel system are proposed. When the fracture width is greater than 0.65 mm, the plugging effect of the polymer gel becomes worse. However, the plugging effect is clearly strengthened by the use of polymer gel, foam, and bulk particles, which also significantly improves the injection–production profile. The experimental results show that CO₂ flooding could increase the ultimate recovery by 7.67%.

1. Introduction

CO₂ flooding is one of the most promising enhanced oil recovery methods.¹ CO₂ flooding is commonly used to recover oil from reservoirs, in which the initial pressure has been depleted through primary production and possibly water flooding.² In recent years, with the increasing development scale of low-, ultralow-, and tight-permeability reservoirs, the technology of CO₂ flooding has received much more attention. However, gas channeling and the low CO₂ sweep coefficient are the main contradictions of CO₂ flooding.³ Reservoir heterogeneity, such as fractures and faults, has prevented the recovery of crude oil in an economic manner.⁴ The viscosity of CO₂ in a normal oil reservoir can be 10–50 times lower than that of the oil, making CO₂ more likely to channel through the oil and preferentially flow through more permeable rock sections.⁵

This issue can be solved by adding surfactants to produce in situ CO₂ foams. Khalil et al. studied a CO₂-foam system to reduce carbon dioxide mobility. The results show that more residual oil is recovered for CO₂-foam vs CO₂ and brine coinjection upon simulating the experiment process.⁶ Yi et al. found that the temperature, pressure, and surfactant concentration have an impact on CO₂ foam behavior.⁷ Chang et al. reported a series of steady-state CO₂-foam flow experiments performed at reservoir conditions.⁸ Casteel and Djabbarah screened foaming agents for specific CO₂ flooding and determined the effectiveness of foam in improving sweep efficiency in CO₂ flooding.⁹ According to Emadi’s findings, because of the substantially bigger viscosity differential between CO₂ and heavy oil, the reservoir sweep efficiency will be lower than in conventional reservoirs. Emadi and his colleagues investigated the mechanism of increased heavy oil recovery by CO₂-foam injection.¹⁰ The kinetics and equilibrium of a surfactant utilized as a CO₂–water foaming agent on Berea sandstone are discussed. The surfactant’s foam stability is studied before and after adsorption/desorption.¹¹ We investigate changes in pH (from 1 to 12), salinity (from 0 to 25 wt %), and surfactant concentration (from 0 to 1 wt %) for foam stability in a bubble chamber and adsorption in a static adsorption device, utilizing pure kaolinite powder.¹² The above research shows a more uniform front of foam that pushes oil rather than fingering through the reservoir’s most exposed geological structures.¹³ However, as the resistance generated by foam is weaker than that of the gel system, the effect of improving gas flooding in fractured reservoirs is relatively poor.¹⁴ As one of the effective measures to improve water flooding, a gel system has been applied to CO₂ flooding by domestic and foreign scholars.

Liang et al. investigated how different types of gels reduced permeability to water and gases in porous rock.¹⁵ Cai improved the CO₂ flood efficiency using cross-linked gel conformance control and a CO₂ viscosifier technique.¹⁶ Karaoguz et al. studied the pilot field application of polymer gels for a fracture reservoir conformance improvement in the ongoing CO₂ injection project at Bati Raman heavy oil field in southeastern Turkey.¹⁷ Asghari and Taabbodi investigated the effect of gel placement of CO₂ flooding in carbonate porous media.¹⁸ Seright built a model to quantify gel propagation and dehydration during the extrusion through fractures, accurately predicting the leak-off during the extrusion of a guar-borate gel.¹⁹ Large-volume polymer gel treatments are observed by Pipes and Schoeling to block high-permeability channels and conduits and direct injected CO₂ to unswept areas of the reservoir.²⁰ However, field tests have shown that it is difficult for gels to enter tiny fractures and gels are not good for plugging large-scale fractures. The cost of polymer-gel flooding is generally high, and it has a lower injection capability in reservoirs with medium and low permeability. In situations with high temperature, high salinity, and acidity, foam breaks down quickly. The plugging effect of the foam system in fractured reservoirs is poor. Therefore, overcoming the shortcomings of previous chemical reagents and developing low-cost, multifunction composite chemical reagents is a key issue that urgently needs to be solved in controlling gas breakthrough. For these reasons, the paper investigated a novel multistage plugging system, mainly including foam, polymer gel, bulk particles, etc., to effectively inhibit the gas channeling of CO₂ flooding in complicated fractured reservoirs. The static and dynamic plugging performance of the polymer-gel system and the plugging effect of the multistage plugging system are also studied in detail.

2. Results and Discussion

2.1. Overview of the Target Block

The target block discovered in 2002 is located in the south part of the Changling sag, south Songliao Basin. The northern part of the sag is deeper than that in the south. Its oil layers are mainly distributed in the Qingshankou Formation, and it is a structural lithologic hydrocarbon reservoir. Its oil–water distribution is complicated, and there is no unified oil–water contact in the oil field. It is revealed that the reservoir formation of the oil field is mainly fine sandstones and siltstones, with a thin sand body and good horizontal communication. Its reservoir rocks are of low and moderate porosity (15–20%) and extremely low permeability (0.05–10.8 mD).

According to the primary observation, the reservoir primarily develops high-angle fractures and horizontal fractures. The average fracture density is 0.312 fractures per meter. However, the fracture’s extension length is short, with the horizontal seam measuring 2–10 cm and the vertical seam measuring 30–120 cm. The natural fracture direction, according to imaging logging and in situ stress analysis, is east–west between NE85.9° and NE153.6°(Figure 1).

Figure 1.

Image of fractures displayed by imaging logging.

The target block basically has no water-free oil production period. Due to the low natural productivity, CO₂ injection is started. Following CO₂ injection in fractured reservoirs, the fracture permeability is high and CO₂ penetrates unidirectionally into the fractures, resulting in a low CO₂ sweep coefficient and early gas breakthrough. Figure 2 shows that the gas–oil ratio rises swiftly and remains high all the while. CO₂ progressively diffuses into the matrix following gas injection. There will be a period of stability or a modest fall in the graph following a quick rise.

Figure 2.

Gas–oil ratio curve of the fractured reservoir.

Foam is injected in order to prevent gas channeling. Injection of foam is mainly to adjust the CO₂ mobility to slow down the CO₂ penetration along the fracture direction. In the target block, the injection volume is 500 m³ for every round, the concentration is 4000 mg/L, and the foam dryness is about 80%. There are a total of three injection wells and ten effective oil wells. The average CO₂ injection pressure is 9.3 MPa before foam injection and increases to 13 MPa during foam injection. CO₂ is injected again when the foam agent is finished, while the injection pressure is basically maintained at 12.5 MPa. The CO₂ injection profiles were changed before and after foam injection. After foam injection, the ratio of the high profile is decreased, and the ratio of the low profile is increased (Figure 3). The apparent alteration in the production or injection profiles suggests that the foam agent is injected to function as an inhibitor of CO₂ channeling. However, the injectable foam has a short shelf life, and its injection pressure starts to drop after 6 months. In order to improve the oil recovery of CO₂ flooding, the multistage plugging system is studied.

Figure 3.

Injection profile changes in different layers.

2.2. Experiment

In order to improve the oil recovery of CO₂ flooding in the fractured reservoirs, novel multistage plugging experiments are conducted. The experiments principally include the polymer screening experiment, the multistage plugging experiment, and the performance experiment on static and dynamic polymer gel, etc.

2.2.1. Material

In this paper, the cross-linking agent is made by phenol and formaldehyde in the laboratory. The foaming agent is laboratory-made. The experimental water is prepared according to the water quality analysis results of the target block.

2.2.2. Study on the Polymer-Gel System

In the polymer-gel system, a water-soluble polymer and cross-linking agent are the essential elements. The water-soluble polymer molecules’ amide or carboxyl group can be subjected to cross-linking agents’ reactions, which link the single-chain polymer molecule together to form a network structure. The polymer solution’s viscosity has significantly increased, while its hydrodynamic characteristic size has obviously increased.

The gel network structure contains the aromatic ring–benzene ring, and the whole molecule is fully stretched in water solution, resulting in a bigger volume. The system’s stiffness increases, as does the difficulty of conformation change and the system’s temperature and salt resistance. The copolymerization between the amide group and the cross-linking agent hindered the hydrolysis of the amide group, reducing the influence of calcium and magnesium ions on the polymer and increasing the system’s resistance to calcium and magnesium ions.

2.2.2.1. Synthesis of Cross-Linking Agent

The cross-linking agent with a cross-linking structure at high temperature is investigated based on the reservoir properties in the target block. Considering the economic cost of synthetic raw materials, a water-soluble phenolic resin cross-linking agent is optimized through synthesis technology.

Soluble phenolic resin is a hydrophobic aromatic ring coupled with a hydrophilic hydroxymethyl, phenol hydroxyl, and phenol oxygen anion group, and the structural unit is bridged by methylene. Because the aromatic ring is stiff and the connecting structural unit is just one carbon atom, the overall rigidity of the molecule is high and the deformation is low.

2.2.2.2. Screening of the Polymer

With preparation water, the mother liquor of six different polymers is formed, the mother liquor is diluted to a polymer concentration of 1500 mg/L, the cross-linking agent is added to a concentration of 500 mg/L, and the polymer gel is made by mixing uniformly. The polymer gel is pumped out and deoxygenated, then put into a 50 mL ampule, and sealed with an alcohol blowtorch. These samples are put in an oven at 97 °C for cross-linking aging and are taken out periodically. The adhesive is measured by a Brookfield DV-III viscometer at a rotating speed of 6 r/min (0# rotor), and the temperature is 97 °C.

According to the results of the experiments (Table 1), all six polymers may have a strong cross-linking reaction with the cross-linking agent within 12 h, and the viscosity after cross-linking is greatly increased, reaching more than 20 times the initial viscosity. The initial viscosity of No.1 is the lowest (13.9 mPa·s) in the cross-linking reaction experiment of different polymers, and the adhesive is reasonably high. Because the adhesive performance is rather good, No.1 is the recommended polymer.

Table 1. Evaluation of Gelling Properties of Different Polymers.

	change of polymer-gel viscosity with time (mPa·s)
polymer no.	0	6 h	12 h	1 d	5 d	10 d	30 d	60 d
1	13.9	393	648	667	693	660	633	613
2	20.3	260	446	544	554	537	525	506
3	14.6	297	478	567	588	563	553	542
4	35.2	326	513	593	667	560	526	510
5	30.9	348	598	619	606	593	562	543
6	21.3	369	468	645	650	646	623	602

2.2.2.3. Study on the Static and Dynamic Plugging Performance of the Polymer Gel

2.2.2.3.1. Static Plugging Performance of the Polymer Gel

Static plugging performance of the polymer gel in a porous medium has been studied. To simulate artificial fracturing, the model is filled with 40–60 mesh quartz sand. The permeability of the model is 31–34 D. Table 2 shows the fundamental parameters of the sand-packed model. The formula of the designed polymer gel is 0.4% polymer +0.3% cross-linking agent +0.03% thiourea.

Table 2. Fundamental Parameters of the Sand-Packed Model.

no.	pore volume cm3	porosity %	permeability D
1	64.69	43.95	33.44
2	65.40	44.43	32.81
3	64.53	43.84	31.72
4	66.16	44.95	32.93
5	65.58	44.55	33.68

The experimental procedures are described as following:

• ①Permeability and porosity tests are performed on a sand-packed model. Water is saturated in the model.

• ②At a rate of 2 mL/min, 0.6 PV of preprepared polymer-gel aqueous solution is injected into each model.

• ③The sand-packed model is sealed at both ends and the mixture is put in a 97 °C oven for coagulation.

• ④A sand-packed model is taken out every once in a while, and water is injected at the rate of 2 mL/min to measure the plugging performance of the polymer gel.

The experimental results show that the diminishing range is larger in the beginning and smaller in the latter period. At high temperatures, the cross-linking network structure shrinks and the volume decreases, as does the plugging effect; the cross-linking network generated by the polymer molecular chain and cross-linking is readily disrupted, diminishing the gel’s strength. However, the experimental results demonstrate that even after 46 days, there is still a 1 MPa pressure difference at both ends of the 30 cm long core model (Figure 4), and the plugging ratio is greater than 98% (Figure 5), indicating that the system’s plugging strength is sufficient to plug the reservoir’s fracture.

Figure 4.

Polymer-gel plugging effect at different times.

Figure 5.

Polymer-gel plugging ratio at different times.

The difference between the greatest pressure difference and the equilibrium pressure difference decreases with experiment time. Figures 6 and 7 depict the difference between the two as 2.87 MPa at 5 days and 1.28 MPa at 46 days, respectively. Since water injection has always been done during the experiment, there is a chance that this will harm the created blockage, which is why the pressure rises and then falls.

Figure 6.

Pressure difference curve measured 5 days after gluing.

Figure 7.

Pressure difference curve measured in 46 days after gluing.

2.2.2.3.2. Dynamic Plugging Performance of the Polymer Gel

It is crucial to study the polymer-gel performance under flow conditions since the fluid in the reservoir is dynamic and the polymer-gel system flows at a constant rate after being injected into the formation. An experiment is carried out by utilizing a model made of packed sand (length 2.51 cm). The model is filled with 40–60 mesh quartz sand, and the two ends are sealed with 20–40 mesh quartz sand. The model has three pressure detecting points that are equally spread across the artificial fracture (Figure 8). The model’s porosity is 42.28%, and the permeability as measured by gas is 28.8 D. The formula of designed polymer gel is 0.4% polymer +0.3% cross-linking agent +0.03% thiourea.

Figure 8.

Schematic diagram of the sand-packed model (1, 2, and 3 are pressure measuring points, respectively).

The experimental procedures are described as following

• ①Permeability and porosity tests are performed on a sand-packed model. Water is saturated in the model.

• ②At a rate of 2 mL/min, 0.4 PV of preprepared polymer-gel aqueous solution is injected into each model. Finally, the injection pressure difference is 0.18 MPa.

• ③The pressure is set to 3.2 MPa and the mixture is put in a 97 °C oven for coagulation.

• ④The simulated brine is continuously injected at 0.005 mL/min to keep the polymer-gel solution dynamic. After 3 weeks, the injection rate is 2 mL/min, and the strength of the polymer gel is analyzed.

The experiment shows that the pressure difference between the inlet and point 3 gradually increases in the first 5 days (Figures 9 and10), while the pressure tends to be smooth afterward, and it can be assumed that the first 5 days are the cross-linking time of the polymer-gel system, after which the reaction is complete and the pressure no longer changes. Before polymer-gel formation, the polymer gel may be moved forward in the sand-filled model, and the pressure is smooth owing to the slow velocity, which is about 1.47 cm per day.

Figure 9.

Pressure data of each measuring point in the flow experiment.

Figure 10.

Pressure difference curve between the inlet and measuring point 3.

The experiment lasted 21 days, and the injection rate was set at 2 mL/min. Figure 11 shows that the pressure difference between the two ends of the model reaches 0.91 MPa, which is significantly higher than 0.033 MPa before polymer-gel injection, and the gel plugging ratio reaches 96.4%, indicating that the polymer gel plays a role in inhibiting gas channeling. Furthermore, the formed polymer gel has strong scouring resistance, and the total quantity of water injection is larger than 1 PV after 100 min of continuous water injection, and the pressure is steady at all points in the latter stage.

Figure 11.

Pressure curves of each pressure measuring point after gluing.

The experimental temperature is lowered to 30 °C, and simulated brine is added at a rate of 2 mL/min in order to continue analyzing the gel’s plugging effect. According to the experimental results, Figures 12 and 13 show that the pressure difference between the model’s two ends is higher than that it has been at reservoir temperature. This is mostly because of the drop in temperature and rise in fluid viscosity, and the experimental findings followed the reservoir temperature’s general pattern. When the pressure of the polymer-gel solution injected is compared, it is obvious that the plugging ratio exceeds 95.7%. Following the experiment, the model is opened and the polymer is located at the end outlet. The polymer gel has migrated to the end of the model but is not found in the produced solution.

Figure 12.

Pressure curves of each measuring point after gluing at 30 °C.

Figure 13.

Pressure difference curves of each section after gluing at 30 °C.

2.2.2.4. Study on Adaptive Limits of Polymer-Gel Systems

The creation of a fractured core model necessitates the simulation of not just a matrix with extremely low permeability but also fractures of various sizes. The old procedures of splitting, filling with sand, and gluing the outcrop core are no longer applicable. Different scales of fractures may be replicated by inserting different thicknesses of yarn in preparation to ensure the experiment’s reproducibility (Figure 14).

Figure 14.

Core models with different thicknesses of yarn.

Core models with varied fractures are chosen, matrix permeability is 0.41 mD, permeability is measured first, and the polymer gel is injected one time with the fracture volume. A specified amount of polymer gel is extracted and placed in an incubator for control, and after 24 h of coagulation, the subsequent water flooding is done to examine the pressure change.

Table 3 shows the core parameters of the different reservoir properties. The fracture width of the core 1# is 0.08 mm. During the permeability test, the pressure at the input end is 252 KPa after stabilizing, and the permeability is 1.94 mD. In the polymer-gel injection stage, the inlet pressure increases fast following polymer-gel injection, reaching 3.6 MPa with a significant rise in injection pressure gradient. In the following water flooding stage, the inlet pressure climbs slightly but not significantly and then begins to fall constantly.

Table 3. Core Parameters of Different Fracture Widths.

core no.	pore volume (cm3)	saturated water (mL)	porosity (%)	matrix: pressure by water flooding (MPa)	matrix permeability (mD)	fracture width (mm)	fracture permeability (mD)
1#	607.5	86	14.17	3	0.41	0.08	1.94
2#	607.5	91	14.97	3	0.41	0.42	295.42
3#	607.5	98	16.13	3	0.41	0.65	658.44

Similarly, the sealing effect of a fractured core with fracture widths of 0.42 mm and 0.65 mm (5 and 8 layers of gauze mesh) is investigated. The inlet pressure begins to rise after polymer-gel injection in the 2# core gluing stage, but the rate gradually slows and eventually stabilizes at around 2.7 MPa for a period of time, indicating that the inlet pressure rises rapidly after the polymer gel enters the fracture steadily in the subsequent water flooding stage. The rise is significant, reaching 24.9 MPa, suggesting that the polymer gel effectively seals the fracture and the sealing strength of the 0.42 mm fracture is excellent.

The polymer gel can be injected stably in the fracture of the 3# core, and the inlet pressure rises rapidly in the subsequent water flooding, with a large rise to 16.0 MPa. It indicates that the polymer gel has blocked the fracture after gluing, but it stops rising after the later water flooding and begins to decline sharply. It shows that the polymer gel has a weak sealing capability on the fracture width of 0.65 mm, while the pressure dramatically drops.

2.2.3. Study on the Bulk Expansion Particle

With the results above, the polymer-gel sealing effect is restricted for a fracture width larger than 0.65 mm. In this paper, a novel bulk expansion particle is injected that may expand in water to limit gas breakthrough in large fractures.

A 250 mL reaction container is taken; acrylic acid, sodium acrylate, acrylamide, ammonium persulfate, sodium sulfite, and others are dissolved evenly in distilled water, montmorillonite is added and the mixture is stirred to hydrate it and disperse it in the reaction system, and finally, latex is added. Under nitrogen protection, during the reaction at 80 °C for 4–5 h, the solid rubber block is obtained and then vacuum-dried and broken; after plasticization, mixing, adding a cross-linking agent, an accelerator, an antiaging agent, and other materials, and vulcanization, the sample forms a rubber molecular network, that is, the bulk particle sample. The ability of bulk expansion particles to control CO₂ breakthrough in fractures is confirmed by physical model experiments.

2.2.3.1. Injection Capacity of Bulk Expansion Particle

Crushed bulk particles at a concentration of 0.6% are fed into the sand-filled tube model. The sand-filling pipe is 30 cm long and 2.54 cm in diameter, and it is pumped into a 250 mL container. The injection pressure is recorded at regular intervals, and the results are given in Figure 15.

Figure 15.

Injection pressure at different times.

Pressure rises continuously after bulk expansion particles are injected. On day 23, the pressure increases to 2.8 times the initial level, and water mobility falls by 64.4% compared to the starting level. On day 28 of the experiment, the water mobility reduces to 68% of its starting level, at which point particles pour out at the output end, suggesting that the bulk expansion particles have been migrating and expanding.

2.2.3.2. Capacity of Bulk Particles to Seal Big Fractures

The sand-filled tube model is 70 cm long × 2.54 cm wide. The model of the sand-filled pipe is illustrated below. The measurement for the gas permeability is 42 D. A 7.5 g crushed bulk expanded particle sample is mixed with 40–60 mesh quartz sand, and the bulk expanded particle is injected at a rate of 2 mL/min, with pressure monitored at each site.

The injection pressure increases with continuous water flooding, showing that the bulk expansion particles expand slowly. After 11 days, the water mobility dropped by more than 80%, and after 300 days, it decreased by 99.88% (Figures 16 and 17). The impact of limiting water mobility comes gradually, showing that the bulk expansion particles may grow slowly, allowing the effect to last a long time.

Figure 16.

Pressure difference of saline injection at different times.

Figure 17.

Plugging ratio vs time curve.

2.2.4. Optimization of the Multistage Plugging System

2.2.4.1. Modeling of Heterogeneous Multiscale Fractured Core

To examine the plugging effect of the polymer-gel system, a model of multiscale fracture core is built. On scale-sized fractures, foam, polymer gel, and bulk particles are used. The model is designed with multiscale fractures (the main fracture gradual width of 1–7 mm and the small fracture width of 2 mm), and the fracture angle is 45°. The model is designed with a high permeability layer and a low permeability layer. The thickness of the high permeability layer is 1.5 cm and its permeability is 100 mD. The other’s permeability is 5 mD and its thickness is 3.0 cm. Figure 18 depicts the physical image of the model.

Figure 18.

Physical image of the model.

2.2.4.2. Experimental Scheme Design

Based on the optimization of the injection parameters of the polymer-gel system, the total injection volume of the polymer-gel system is the same and the injection speed of the fixed plugging agent is 1.0 mL/min. To maximize the effectiveness of various plugging agents, the injection dosage of bulk particles is calculated as the volume of the large-scale fracture, the injection amount of polymer gel as the volume of the small-scale fracture, and the injection amount of foam as the volume of the 0.1 PV high matrix permeability. The polymer gel is used to plug small- and medium-sized fractures, while foam is used to plug high-permeability bands.

The formula of the designed polymer gel is 0.4% polymer +0.4% cross-linking agent. The bulk particle concentration is 1 wt %, and its size is from 0.45 to 1.0 mm. The foaming agent concentration is 0.4 wt %, and the gas-to-liquid ratio in the foam system is 1:1. For the injection method of the foam system, a foaming agent is injected first, followed by a gas, and for bulk particles, the polymer solution of low concentration is injected together.

2.2.4.3. Effects of Various Sealing and Plugging Techniques

The impacts of different systems on the plugging effect are investigated. It includes a foam system, a bulk particle system, a polymer-gel system, and a composite system of foam, polymer gel, and bulk particles.

Table 4 shows that a single polymer-gel system has a relatively good effect on plugging, followed by a single bulk particle. Despite their function as bridging particles, bulk particles’ effect is inferior to polymer gels. The multistage plugging system obviously strengthens the plugging effect on the gas channeling. The bulk particles serve as the bridge and filler, the polymer gel has strong filling and adhesion to fracture, and the foam serves as a regulator in a high permeability layer (Figure 19).

Table 4. Comparison of Recovery Degree of Different Plugging Agent Systems.

plugging agent system	recovery degree of the first CO2 flooding	recovery degree of the second CO2 flooding	increased degree of recovery
foam system	9.49	13.04	3.56
bulk particle	9.73	14.16	4.43
polymer-gel system	9.53	15.41	5.88
bulk particle + polymer gel	9.86	16.41	6.55
foam + bulk particle + polymer gel	9.63	17.3	7.67

Figure 19.

Channeling effect of different plugging agent systems: (a) polymer-gel system; (b) bulk particles; and (c) composite system.

2.3. Results

A single foam had a relatively poor effect after CO₂ channeling and failed to effectively plug the fracture. On the contrary, the multistage plugging system is capable of successfully plugging the fracture. It has the potential to increase the oil recovery factor by 7.67%.

3. Conclusions

The following conclusions about the multistage plugging system may be taken from this work:

• (1)The polymer-gel static plugging experiment demonstrates that the plugging impact reduces as time goes on. Yet, the experimental findings demonstrate that even if the experiment lasts 46 days, the plugging ratio is still larger than 98%, which is enough to plug the fracture.
• (2)The polymer-gel dynamic plugging experiment demonstrates that the polymer gel might flow forward in the sand-filled model before gumming, and the pressure is stable owing to the slow speed. Compared to the pressure of polymer-gel solution injection, the plugging ratio is more than 95.7%.
• (3)The experimental research of the multistage plugging system reveals that in a heterogeneous permeability model, the fracture cannot be prevented by foam injection alone, but it can be blocked after polymer-gel injection, and the crude oil can be driven in a low permeability model. Pure polymer gel does not have the best plugging effect, but the multistage plugging system does.

The author declares no competing financial interest.