Gel-Forming and Plugging Performance Evaluation of Emulsion Polymer Crosslinking System in Fractured Carbonate Rock

Abstract

The water channeling of fractured carbonate rock seriously affects oil recovery, and this problem is especially serious in the Kazakh North Troyes oilfield. A conventional powder polymer plugging system needs to be hydrated ahead of time, which increases the cost and difficulty of field operation and it cannot realize large-scale plugging operations. The new emulsion polymer crosslinked system can realize rapid hydration and real-time mixing, having low base liquid viscosity and good fluidity and injectability. The results of the laboratory study show that the gelling time of HR9806 emulsion polymer and organic chromium crosslinker was 6~8 h. 0.5 wt % HR9806, which is recommended for field use with P/C ranging from 2.5 to 5.0. The emulsion polymer crosslinking system was found to be highly adaptable in reservoirs and had salinity resistance. Mineral salt and reservoir core were able to enhance the gel strength of the system but shortened the gelling time of the system by about 2 h. The gel (HR9806) had good shear resistance. It still had a viscosity of 220 mPa·s under high-speed shearing (Temperature = 54 °C), and the formed gel system shear resistance increased with increasing concentration. The emulsion system of “0.50 wt % HR9806 emulsion polymer + 0.15 wt % organic chromium crosslinker + brine” had a strong plugging effect in the fractured core and sand-filled pipe model, with residual resistance coefficient ≥30, effective plugging rate ≥ 95.0%, and oil–water selectivity of 0.45. In this paper, the levels of weak gel strength were used, providing an experimental and theoretical reference for improving the application effect of the weak gel system in the field. The study found that the weak gel system can better enter the fractured carbonate reservoir and form a plugging effect in the fracture, improving the effect of subsequent water flooding matrix oil recovery.

1. Introduction

Injection water breakthrough time and velocity have great influence on oil recovery of natural fracture reservoirs. The development and application of tertiary oil recovery technology has greatly improved the water flooding problem of oil wells [1]. As one of the tertiary oil recovery technologies, crosslinked polymers have been widely used since the late 1990s [2,3]. Compared with polymer flooding technology, its biggest characteristic is that it can greatly reduce the amount of chemical agent, so this technology has attracted much attention in the world [3,4]. In reservoirs with severe heterogeneity, injection water flows along the high permeability layer, which results in the oil in the low permeability layer being unable to be swept by injection water [5,6]. At the same time, the polymer system can improve the fluidity of heavy crude oil such as asphaltenes [7,8]. The weak gel system of a polymer is mainly intermolecular crosslinking, and intramolecular crosslinking is complementary to formation of a three-dimension network structure with less crosslinking degree. A weak gel system does not form a strong shape. It can move slowly to the reservoir deep within the subsequent injection water, but because of its larger transport resistance, it can stay in the reservoir. Therefore, it has the comprehensive functions of deep profile control and oil displacement.

In 1964, Pye [9] and Sandiford [10] first tested the potential of polymer solution to improve crude oil recovery through indoor experiments and field trials, mainly by reducing the oil–water fluidity ratio and increasing oil production. This process has been successfully applied for more than 50 years [11,12,13,14,15,16]. Mccool et al. [17] studied the plugging mechanism of polyamide/Cr³⁺ by using an uncemented sand-filled pipe model in indoor experiments. The experimental results show that the morphology of the gel aggregate cakes will expand in the sand-filled pipe with the increase in time, and the apparent viscosity also increases gradually. Jordan et al. [18] carried out an indoor experiment on the change of polyacrylamide/Cr³⁺ crosslinking performance with temperature and salinity. The experimental results showed that the higher the temperature and the higher the salinity, the shorter the gelling time. Hajilary et al. [19] studied gel plugging and oil–water selectivity using a specially designed two-dimensional core flooding and oil–water injection. Brattekas et al. [20,21,22,23] systematically investigated EOR performance and dehydration resistance of gel systems in fractured reservoirs. In addition, in view of the toxicity of phenol and formaldehyde, especially the carcinogenicity of formaldehyde, low-toxicity substitutes of phenol and formaldehyde have been found, such as hydroquinone or catechol of phenol and hexamethylenetetramine of formaldehyde [24]. The above studies are based on the plugging and enhanced oil recovery performance of a gel system formed after hydration of powdery polymer. The advance hydration of polymer powder requires a large number of water tanks, and the single injection volume is limited, which limits the injection of 10 million cubic meters of modulated and flooding chemicals. In order to improve the field practicability of polymer gel, white oil emulsifier and polypropylene amine monomer are made into emulsion polymer form, which can realize the effect of online real-time mixing and greatly shorten the hydration time of polymer.

Kazakh North Troyes oilfield is a carbonate reservoir with fracture development. Due to long-term depressurization exploitation, formation pressure maintenance level is low, water injection inrush is fast, the oil well production declines fast, water injection is used to maintain or restore formation pressure, and water cut rise contradiction is very prominent. Therefore, it is urgent for oilfield development to actively explore effective oil stabilization and water control comprehensive treatment technology. This paper is based on the reservoir temperature, formation of water salinity, and reservoir core in the North Troyes oilfield; physical simulation experiments were carried out on the dynamic characteristics of the emulsion polymer crosslinking system in fractured carbonate cores. On the basis of the test results of rheology, static gelling, and dynamic gelling, the gelation and deep channeling performance of an emulsion polymer crosslinked system in a fractured carbonate reservoir of North Troyes oilfield were comprehensively analyzed. The optimal formulation of the polymer cross-linking system was given priority, providing an experimental and theoretical basis for improving the application effect of the weak gel system in mines.

Because the conventional gel plugging system needs to be hydrated in advance to be injected into the formation to achieve the plugging effect, rapid hydration is required for fractured carbonates with larger injection rates. Therefore, the emulsion polymer plugging system with rapid hydration was developed, which was injected into the formation through a water injection pipeline, and a plugging technology suitable for fractured carbonate reservoirs was explored.

2. Materials and Methods

2.1. Experimental Material

The polymer monomer used in the experiment was emulsion polymer, which is composed of white oil, emulsifier, and polymer monomer. The main composition is modified polyacrylamide, the solid content is 30%, and the crosslinker is organic chromium produced by Jiangsu Hengfeng Chemical Co. Ltd. (Nantong, China). The mineral salts used to simulate formation water, including sodium chloride, potassium chloride, magnesium chloride, and calcium chloride, were all produced by Sinopharm; reservoir cores and crude oil were taken from the KT-1 reservoir in the North Troyes oilfield; calcium carbonate powder was produced by Sinopharm Pharmaceutical Co. LTD (Beijing, China). The reservoir temperature was 54.0 °C. Although the formation temperature will gradually decrease due to the influence of the injected water on the ground, it will also affect the gel-forming properties of the emulsion polymer system; however, the gel-forming properties of the emulsion polymer are mainly affected by the high temperature environment. Therefore, during the experiment, the effect of formation temperature of 54 °C on the gel-forming properties of the emulsion polymer was mainly studied; the salinity of formation water is 8.23 × 10⁴ mg/L, Ca²⁺ is 3002 mg/L, Mg²⁺ is 1000 mg/L, K⁺ is 15,705 mg/L, Na⁺ is 15,726 mg/L, and Cl⁻ is 46,857 mg/L. Ca²⁺ and Mg²⁺ ions were the main divalent cations. The emulsion polymer HR9806 and the organic chromium crosslinker are shown in Figure 1.

2.2. Experimental Procedure Sketch

As shown in Figure 2, the experimental procedure consists of five aspects: ① Viscosity test of the base liquid to determine whether the base liquid has good fluidity and injectability. This is in order to test whether the emulsion polymer has better fluidity on the ground [25]. ② Gel-forming performance test of the emulsion polymer. The gel-forming performance of the emulsion polymer under different conditions were investigated. The standard for determining the gel strength of the emulsion polymer is given in Wang et al. (2022) [26,27,28,29]. Since the emulsion polymer has the property of real-time mixing and does not need to be hydrated in advance, the effect of aging on the gel-forming properties is not considered [30,31]. ③ The shear resistance of the crosslinked system was tested to investigate whether the strength of the weak gel system was destroyed during the migration and shearing process in the reservoir. ④ The gel-forming and plugging performance of reservoir cores were investigated. The gelation and plugging performance of emulsion polymers in reservoir cores were investigated, and the selective plugging performance of oil and water in a crosslinked system was investigated by reverse flooding. ⑤ The plugging performance of the emulsion polymer crosslinked system to porous media was investigated by testing the plugging performance of the crosslinked system in a sand-filled pipe.

The experiment used fractured core and matrix core are shown in

Table 1. The parameters of fracture core and matrix core.

NO	Core Type	Liquid Permeability, mD	Fracture Equivalent Width, mm	Length, cm	Diameter, cm	Porosity, %
1	Matrix core	1.63	-	30.10	2.50	23.01
2	Matrix core	1.62	-	30.12	2.49	23.04
1.1	Fractured core	8.77	0.0119	30.10	2.50	26.25
2.1	Fractured core	780	0.5680	30.12	2.49	29.04

.

2.3. Flooding Experiment Procedure for Core and Sand-Filled Pipe

The gelation, plugging, and oil–water selective plugging performance of emulsion polymer in fractured core were studied by a core flow experiment, and the plugging performance of the emulsion polymer crosslinked system in porous media was studied by a sand-filled pipe experiment. The schematic diagram of the three experimental flows is shown in Figure 3.

3. Results and Discussion

3.1. Viscosity Test of Emulsion Polymer Base Liquid

A Fann 35 six-speed viscometer was used to test the viscosity of HR9806 solution to determine whether the base liquid without gel had good fluidity and injectivity. The results are shown in Figure 4 and Figure 5. The simulated North Troyes injection water and formation water were selected to make HR9806 base fluid. The relationship between the viscosity of base fluid and shear rate (Figure 4 and Figure 5) showed that at the shear rate was 100RPM and the viscosities of 0.8 wt % HR9806 in injection water and formation water were 5.0 and 0.8 mPa·s, respectively. HR9806 solution had low viscosity, good fluidity, and injectivity. In addition, due to the influence of salinity, the viscosity of HR9806 solution in simulated formation water was relatively low.

3.2. Evaluation of Gelling Effect of Emulsion Polymer Solution

The gel-forming performance test of emulsion polymer solution included the influence of different concentration ratios of polymer/cross-linking agent (P/C), salinity, and admixture on the gel-forming performance of emulsion polymer solution. The water bath curing temperature was 54.0 °C.

3.2.1. Influence of Different P/C on Gelling Effect of HR9806 Solution

HR9806 with the concentrations of 0.3 wt %, 0.5 wt %, and 0.8 wt% was selected as the concentration of the emulsion polymer, and the organic chromium crosslinker was added with the concentration of 0.1~0.6 wt % to test the gelling time and strength of emulsion polymer solution. The emulsion polymer and organic chromium crosslinked system with the highest cost performance were selected and extended to the field application. The experimental water was distilled water. As shown in Figure 6, 0.3 wt % and 0.5 wt % of HR9806 was able to achieve level 4 strength when P/C was greater than 1.5 and 2.5, while 0.8 wt % of HR9806 was able to achieve level 4 strength when P/C was equal to 3.0. The time required for the above HR9806 fluid to form effective strength was 6~8 h. Since the effective concentration of polymer in weak gel formed by 0.3 wt % HR9806 is weak, it is recommended that 0.5 wt % HR9806 be used as a base liquid in the field, with P/C ranging from 2.5 to 5.0.

3.2.2. Influence of Additives on Gelling Effect of the System

As discussed in Section 3.1 and Section 3.2.1, the influences of the viscosity of base liquid of HR9806 emulsion polymer on its gel-forming performance were tested, respectively. Since HR9806 was to be applied to carbonate reservoir, it was necessary to investigate the influence of reservoir core on its gel-forming performance. In this section, the gel-forming performance of calcium carbonate powder and pulverized KT-1 reservoir core from North Troyes mixed with HR9806 solution was tested.

Table 2. Effect of CaCO₃ on gelling effect.

Concentration of HR9806, wt %	Concentration of Crosslinker, wt %	P/C	CaCO3 Powder, g	Gel Strength, Level	Gelling Time, h
0.50	0.10	5.0	1.0	5	4
0.50	0.20	2.5	1.0	5	4
0.50	0.30	1.7	1.0	4	4
0.50	0.40	1.3	1.0	4	4
0.50	0.15	2.5	0.0	4	8
0.50	0.15	2.5	0.5	4	6
0.50	0.15	2.5	1.0	4	4
0.50	0.15	2.5	3.0	5	4

shows the gelation after adding CaCO₃ powder to 100 mL 0.5 wt % HR9806 solution. Compared with HR9806 solution without CaCO₃, the gelling time of the system with CaCO₃ was shortened by 2~4 h. CaCO₃ powder made the solution slightly alkaline, which was beneficial to the rapid gelation of HR9806. At the same time, the higher the dosage of CaCO₃ powder, the faster the gelling time, but when the dosage of CaCO₃ powder exceeded 1.0 g, the gelling time of the solution remained unchanged.

Table 3. Effect of natural rock powder on the gelling effect of the system.

Concentration of HR9806, wt %	Concentration of Crosslinker, wt %	P/C	Natural Rock Powder, g	Gel Strength, Level	Gelling Time, h
0.50	0.10	5.0	1.0	4	4.0
0.50	0.20	2.5	1.0	4	3.5
0.50	0.30	1.7	1.0	4	3.5

shows the gelling effect of KT-1 reservoir natural rock powder mixed with HR9806 solution under different P/C. It can be seen that the 0.5 wt % HR9806 solution had good gelling effect under different P/C, which shows that this kind of emulsion polymer crosslinking system can be successfully used in the field.

3.3. Evaluation of Shear Resistance of Emulsion Polymer Crosslinked Gel System

The migration of the weak gel system in the reservoir is subject to shear force. Therefore, it is necessary to test the shear resistance of the weak gel system under different P/C and emulsion polymer concentrations to determine whether the viscosity of the gel system will degrade.

Figure 7 shows the test results of shear resistance of 0.5 wt % HR9806 under different P/C. The experimental temperature was fixed at 54.0 °C, and the shear rate was set at 0~60 min; the shear rate increased from 0 to 170 1/s, and the shear rate was constant at 100 1/s for 60 min, and then decreased from 100 1/s to 0 for 60 min. The shear resistance and viscosity recovery ability of HR9806 were tested. According to Figure 7, with the increase in shear rate, the strength of 0.5 wt % HR9806 emulsion polymer after crosslinking decreased continuously. At a constant shear of 100 1/s, the gel viscosities corresponding to 0.10 wt %, 0.15 wt %, and 0.30 wt % organic chromium crosslinker were 152.32 mPa·s, 222.64 mPa·s, and 241.34 mPa·s, respectively, indicating that HR9806 has good shear resistance. It still has high viscosity under high-speed shear, and the higher the P/C, the higher the viscosity of the system. In the process of shear rate decrease, the viscosity of HR9806 gradually recovered, indicating that HR9806 has good shear recovery performance.

It can be seen from Figure 8 that the cross-linked emulsion polymer had good strength stability, and with the increase in the concentration of HR9806, the gel strength gradually increased.

3.4. Evaluation of Plugging and Oil–Water Selectivity of Emulsion Polymer Crosslinked Gel System

In order to investigate the adaptability of emulsion polymer in formation after cross-linking, reservoir cores were selected for the experiment. At the same time, relevant parameters were introduced for evaluation, and the specific calculation method is as follows [32,33]:

$$R_K=K_{wb}/K_{wa}$$

(1)

$$\eta =\left(1-K_{wa}/K_{wb}\right)\times 100$$

(2)

where R_k—residual resistance coefficient; K_wb, K_wa—weak gel system water phase permeability before and after plugging, mD; η—plugging rate of weak gel system, %.

3.4.1. Plugging Performance Evaluation of Weak Gel System in Small Fractures

The core length was 30.0 cm, and the fracture equivalent width was 0.0119 mm. Pressure measuring points were arranged at the entrance of the core holder, 10 cm and 20 cm, respectively, to measure the pressure values along the process and calculate the core permeability values in sections. Figure 9 shows the pressure curve of 0.50 wt % HR9806 + 0.15 wt % crosslinker plugging experiment. Figure 10 shows the calculated core permeability of three pressure stable sections in the core flow experiment. According to the results, after the plugging experiment, the average permeability of core decreased from 8.77 to 0.28 mD; the residual resistance coefficient R_k of the weak gel system was up to 31.14; and the plugging rate η was 96.79%, indicating an obvious plugging effect.

3.4.2. Evaluation of Plugging and Oil–Water Selection Performance of Emulsion Polymer System in Changed Fractures

The emulsion polymer crosslinking system (HR9806) was used in different fractures; this section involves the testing of its performance in plugging fractures. The core with 0.5680 mm equivalent crack width was selected for the experiment. According to the calculation of experimental results shown in Figure 11, the liquid permeability of the fractured core before plugging was 780 mD, the forward water flooding permeability was 22.02 mD, and the reverse oil flooding permeability was 49.37 mD after plugging. In large fractures, the residual resistance coefficient R_k was as high as 35.42, the plugging rate η was 97.18%, and the oil–water selective ratio Ko/Kw was 0.45, indicating that the HR9806 weak gel system had a strong plugging effect on large fracture cores and good oil–water selectivity. Figure 12 shows the gelling effect of 0.50 wt % HR9806 + 0.15 wt % crosslinker solution in fractured core after the experiment. This system not only had a good gelling effect, but also formed effective adhesion with the carbonate fracture wall.

3.4.3. Evaluation of Plugging Performance of the Weak Gel System in Porous Media

In order to study the plugging effect of the weak gel system in porous media, the core of KT-1 reservoir in North Troyes oilfield was ground into powder and filled in a sand-filled pipe with a length of 1.0 m and an inner diameter of 2.55 cm. The experimental results are shown in Figure 13. The measured permeability of the sand-filled pipe fluid before weak gel plugging was 1958.34 mD, and the water flooding permeability after weak gel plugging was 56.36 mD. After plugging, the residual resistance coefficient R_k was as high as 34.75, and the plugging rate η was 97.12%. Th weak gel system had a good plugging effect in porous media.

4. Conclusions and Suggestions

Taking the reservoir temperature of 54 °C and the reservoir core of the fractured carbonate reservoir in North Troyes, Kazakhstan, as experimental conditions, the viscosity, gel-forming performance, and shear resistance of the base fluid of the emulsion polymer crosslinking system were tested. The plugging performance and oil–water selectivity of the emulsion polymer crosslinking system in fractured cores and porous media were comprehensively evaluated. The main conclusions and suggestions are as follows:

(1) The content of the effective components’ polyacrylamide in the emulsion polymer was 30%, and the cost was much lower than the use of powder polyacrylamide; at the same time, the emulsion polymer had a real-time mixing function, which can be used in conjunction with the water injection pipeline, reducing the use of ground equipment and greatly reducing the use of ground equipment, saving operation cost and time.

(2) HR9806 emulsion polymer can realize fast hydration and real-time mixing, reduce the cost and difficulty of field operation, lower the viscosity of base solution, and have good fluidity and injectability.

(3) The gel strength of weak gel formed by mixing HR9806 emulsion polymer with organic chromium crosslinker can be divided into five grades. The gelation time required for the system is 6~8 h. It is recommended that 0.5 wt % HR9806 be used as base liquid in the field, with P/C between 2.5 and 5.0. The system has good salinity resistance and reservoir adaptability. Mineral salt and reservoir core can enhance the gel strength of the system but shorten the gelling time of the system by about 2 h.

(4) The shear resistance test results show that HR9806 has good shear resistance and still has a viscosity of 220 mPa·s at high shear speed. The higher the concentration of emulsion polymer HR9806, the stronger the shear resistance of the gel system.

(5) The system of “0.50 wt % HR9806 emulsion polymer + 0.15 wt % organic chromium crosslinker” had a strong plugging effect in fractured core and sand-filled pipe model, with residual resistance coefficient ≥ 30, effective plugging rate ≥ 95.0%, and oil–water selectivity 0.45.