Evaluation of the Driving Effect of the CO₂ Viscosity Enhancer Composite System in Extra-Low Permeability Sandstone Reservoirs

Abstract

CO₂ flooding is an important technology to enhance oil recovery and realize effective storage of CO₂ in ultra-low permeability reservoir. However, due to poor reservoir properties, strong interlayer heterogeneity, and unfavorable mobility ratio of CO₂, gas channeling easily occurs, resulting in low recovery. Chemically assisted CO₂ thickening technology has been developed to control the gas flow rate and improve the CO₂ repulsion effect. Through solubility and viscosity enhancement tests, the CO₂ viscosity enhancer composite system is preferably constructed and then combined with the core drive experiments, the effect of CO₂ viscosity enhancer composite system on oil drive in homogeneous and non-homogeneous cores is evaluated, the correlation between the drive efficiency and viscosity enhancement and solubility of the system is analyzed, and the mechanism of recovery enhancement is explored. The results show that the preferably constructed CO₂–ASA-LAP composite system has a good effect for improving the gas drive effect under simulated formation conditions, and its improvement effect is positively related to the solubility and viscosity increase of the system. Combining oil repelling efficiency and economic considerations, ASA:LAP = 1:1 is selected as the optimal CO₂ viscosity enhancer composite oil repelling system. For homogeneous cores, the CO₂–ASA-LAP combined system drive can increase the recovery rate by 6.65% as compared with CO₂ flooding. For heterogeneous cores, when the permeability difference is 5, the comprehensive recovery factor of the CO₂–ASA-LAP system flooding is 8.14% higher than that of CO₂ flooding. When the permeability difference increases from 5 to 10, the comprehensive recovery factor of the CO₂–ASA-LAP system flooding increases by 1.85%.The injection of the CO₂–ASA-LAP system has some injurious effect on the permeability of the reservoir core, and the smaller the permeability, the greater the degree of injury. The mechanism of the CO₂–ASA-LAP system to improve recovery includes increasing CO₂ viscosity, improving the oil repelling flow ratio, blocking high seepage channels, initiating low seepage residual oil, enhancing CO₂ dissolution, and expanding the oil repelling effect.

1. Introduction

Currently, with the recovery of international oil prices and the gradual implementation of carbon peaking and carbon neutral targets, CO₂ gas drive enhanced oil recovery technology, which can achieve both effective CO₂ storage and enhanced recovery of oil and gas reservoirs, is highly favored.¹⁻⁵ Supercritical CO₂ in the oil and gas system has special physical and chemical properties. First, its density is close to liquid, viscosity is close to gas, and has strong solvation ability and high diffusion coefficient. Second, because of its good mass transfer performance, supercritical CO₂ is also an ideal medium for reservoir energy supplement. The oil displacement mechanism of supercritical CO₂ flooding mainly includes: reducing crude oil viscosity, reducing interfacial tension, solubilizing swelling, miscible effect, molecular diffusion, dissolved gas flooding, acidification, and so forth. Many oil and gas reservoirs at domestic and abroad have achieved good social and economic effects through the application of CO₂ flooding,⁶⁻⁹ which also shows that CO₂ flooding has great application prospects.

Based on the distribution of remaining oil and gas resources and the adaptability of CO₂ injection drive technology, it is important to focus on grasping the development of low permeability and extra-low permeability reservoirs. CO₂ injection drive can solve the problem that conventional repellents are difficult to effectively inject into low permeability and extra-low permeability reservoirs. However, due to the low viscosity and low density of the gas, the gas drive is strongly influenced by the non-homogeneity of the reservoir, and the gas injection process is often faced with poor control of gas fluidity and problems such as viscous finger entry, gravitational overburden, the gas scramble, and so forth. High flowability of gas will reduce sweep efficiency and adversely affect enhanced oil recovery.^10,11 In addition to the sealing technology, the existing methods to improve the recovery of CO₂ flooding are mostly focused on reducing the minimum miscible pressure to implement miscible flooding, increasing the viscosity of the displacement phase CO₂ to adjust the mobility and sweep ability.¹²⁻¹⁴ Related studies show that¹⁵ it is more important to increase the macroscopic sweep volume of the CO₂ flooding than to reduce the minimum mixing pressure during the CO₂ injection drive. Given that fluid density is mainly influenced by the formation environment (temperature and pressure), CO₂ fluidity control techniques are mostly studied in the direction of increasing the viscosity of the injected fluid, such as water–air alternation,¹⁶ depth migration-controlled CO₂ foam,¹⁷ supercritical CO₂ microemulsion,¹⁸ direct CO₂ viscosity enhancement,¹⁹ and so forth. The most direct way to reduce CO₂ fluidity is to add one or more chemical agents to CO₂ to thicken the viscosity. By controlling the viscosity of CO₂, a reasonable flow ratio can be ensured. At present, the CO₂ viscosity enhancers researched at domestic and abroad mainly focus on fluorination, chain hydrocarbons, and silanes.²⁰ Kilic et al.²¹ prepared a series of aromatic acrylate-fluoroacrylate copolymers as CO₂ thickeners by controlling the ratio of monomer content, in which the copolymers with 71 mol % of fluoroacrylate had better solubility in CO₂ and achieved the best thickening effect, and the viscosity could be further improved with increasing pressure. Tapriyal²² prepared benzoyl-vinyl acetate copolymer (polyBOVA) by grafting benzoyl chloride onto polyvinyl acetate-vinyl alcohol [P(Vac-co-VA)] based on the better pro-CO₂ property of vinyl acetate, catalyzed by 4-dimethylpyridine and was able to increase the viscosity of CO₂ at 298 K, polyBOVA mass concentration of 1 and 2, respectively, were able to increase the viscosity of CO₂ by 1.4 and 1.8 times, while the cloud point pressure of polyBOVA-CO₂ solution reached 64 MPa when the mass concentration was 3 wt %, and the dissolution conditions were more severe. O’Brien et al.²³ synthesized a series of aromatic amide-functionalized low molecular weight polydimethylsiloxane (PDMS) and evaluated their solubility and thickening ability in supercritical CO₂. The results showed that anthraquinone-2-carboxamide-containing end-group PDMS derivatives could thicken supercritical CO₂ with the aid of hexane solubility, with the best thickening effect using anthraquinone-2-carboxamide-capped PDMS13, which was able to increase the viscosity of CO₂ by a factor of 9 at 20.7 MPa, 298.15 K, and CO₂ thickener dosage of 13.3 wt %. Although fluorine-containing CO₂ viscosity enhancers show significantly better solubility and viscosity enhancement in CO₂ than chain hydrocarbons and siloxanes due to their low cohesion energy and pro-CO₂ characteristics, they are mostly at the laboratory research stage due to their poor economic effect and biological toxicity; the solubility of chain hydrocarbon CO₂ viscosity enhancers in CO₂ is limited by the molecular weight, and low molecular weight compounds have good solubility in CO₂, and the viscosity enhancement effect is mediocre; long-chain high viscosity enhancers have good solubility in CO₂ or the viscosity enhancement effect is mediocre. The long-chain polymeric hydrocarbon CO₂ viscosity enhancers are similar to most siloxane-based CO₂ viscosity enhancers, which have poor solubility in CO₂ and need to add a lot of additives to promote dissolution, resulting in a high cost of thickening CO₂ and potential damage to the reservoir.^24,25

For such problems, an environmentally friendly surfactant-based CO₂ viscosity enhancer ASA was used in the indoor experiments. This viscosity enhancer can significantly improve the solubility in CO₂ with the assistance of additives and can significantly increase the CO₂ viscosity. In order to provide new ideas and theoretical references for the design of CO₂ oil repelling scheme in extra-low permeability sandstone reservoirs, we conducted core repelling experiments and core damage evaluation experiments to investigate the “synergy” between CO₂ and viscosifier composite system in oil repelling process in extra-low permeability sandstone reservoirs and the influence of the repelling method on the actual oil repelling efficiency.

2. Results and Discussion

2.1. Dissolution and Viscosity Building Properties of Viscosity Enhancers in Supercritical CO₂

The solubility and viscosity of different viscosity enhancers in supercritical CO₂ under reservoir conditions (50 °C, 8.9 MPa) are shown in Table 1. It can be seen that different viscosifiers and viscosifying additives have certain solubility and viscosifying property in supercritical CO₂, among which the solubility and viscosifying property of PDMS decreases with the increase of molecular weight, the solubility and viscosifying effect of viscosifying agent ASA, and viscosifying additives.

Table 1. Solubility and Viscosity Data of Viscosity Enhancers and Viscosity Building Aids in CO₂ (50 °C, 8.9 MPa).

type	solubility (g/L)	viscosity (mPa·s)
PDMS (700)	39.44	0.84
PDMS (1000)	19.87	0.55
PDMS (1500)	12.48	0.38
PDMS (3200)	8.01	0.27
PDMS (5000)	3.05	0.24
adhesion enhancer ASA	1.46	0.21
viscosity increasing additives LAP	0.52	0.35
ASA + LAP(1:1)	40.9	2.16
PDMS (700) + LAP (1:1)	22.46	0.86

LAP is not good when used singly. However, compounding PDMS with LAP did not improve the effect. In general, the solubility and viscosity enhancement test methods in the experimental section can effectively evaluate the solubility and viscosity enhancement performance of different types of viscosity enhancers.

2.2. Tackifying Performance of the Tackifier-Additive Compound System in Supercritical CO₂

In order to further investigate the synergistic thickening law between the tackifier ASA and the tackifier LAP, the solubility and viscosity of the tackifier ASA/tackifier LAP compound system in supercritical CO₂ at different ratios were studied under reservoir conditions (50 °C, 8.9 MPa) (the experimental results are shown in Figure 1).With the increase of the proportion of tackifying additives, the solubility of the compound system increased significantly, and the tackifying effect was also significantly enhanced. When the proportion of tackifying additives increased from 25 to 75%, the viscosity of the system increased from 0.34 to 4.05 mPa·s. It shows that there is a good synergistic effect between the tackifier ASA and the tackifier LAP. The proportion of additives plays a leading role in the synergistic effect, and the low proportion of additives cannot effectively play the role of tackifying. Therefore, it is necessary to further combine the actual needs of the target reservoir, by adjusting the proportion of additives to optimize the CO₂ thickening system.

Figure 1.

Solubility and viscosity of the tackifier ASA tackifier LAP compound system in supercritical CO2 at different ratios.

2.3. Homogeneous Core Oil Drive Effect

The construction of the ASA-LAP composite system is a key factor affecting the oil drive effect and economic efficiency. The oil drive efficiency curves of CO₂ and CO₂–ASA-LAP composite system are shown in Figure 2, and detailed data are shown in Table 2 after the water drive of single pipe outcrop cores in the same permeability range (kg = 5 mD) at 50 °C.

Figure 2.

Curve of displacement efficiency and injected PV number of CO₂–ASA-LAP composite system in the homogeneous core.

Table 2. Solubility and Viscosity Data of Adhesives and Adhesives in CO₂ (50 °C, 8.9 MPa).

repulsion system	permeability/mD	water-drivenrecovery rate/%	final recovery/%	improved recovery/%
CO2	5.401	49.17	67.48	18.31
ASA:LAP(2:1)	5.54	50.18	69.22	19.04
ASA:LAP(1:1)	5.142	47.32	72.28	24.96
ASA:LAP(1:2)	5.157	48.24	73.94	25.7
ASA:LAP(1:3)	5.234	48.94	75.04	26.1

The water drive starts with a long water-free oil recovery phase, and water drive is followed by a continuous CO₂ flooding and CO₂–ASA-LAP composite system drive, and the drive efficiency all shows a trend of slow rise and rapid rise stabilization. The introduction of viscosity-enhancing system ASA-LAP can improve the CO₂ flooding effect to a certain extent, and its improvement effect is positively related to the solubility and viscosity-enhancing property of the system, the higher the solubility and the stronger the viscosity-enhancing property, the better the effect of improving the recovery rate, and the phenomenon of foam oil flow can be observed in the export section during the drive replacement. The reason for this phenomenon is that the supercritical CO₂ in contact with the crude oil phase will effectively start the residual oil in the pore channel that has not been reached by water repulsion by reducing the interfacial tension, solubilizing and swelling, and dissolving the gas repulsion, so the oil repulsion efficiency can be increased rapidly while continuing to increase the injection volume, CO₂ occurs viscous finger in through the core until the phenomenon of gas scramble occurs, and this seepage process can only carry a small amount of residual oil, so the subsequent CO₂–ASA-LAP composite system can improve the flow efficiency of high-fluid CO₂ through low-fluid crude oil by increasing viscosity of CO₂, and increase the utilization rate of CO₂, which can effectively delay the time of CO₂ to occur gas flushing and effectively expand the wave volume of subsequent fluids.

Although the oil drive efficiency increased with the increase in the percentage of additives, when the percentage of additives was less than 50%, the oil drive efficiency of the system showed a rapid growth trend with the increase in the percentage of additives, while after the percentage of additives was higher than 50%, the growing trend of oil drive efficiency slowed down with the increase in the percentage of additives (Figure 1). For example, when the percentage of additives increased from 33 to 50%, the recovery improvement increased by 5.92%, and when the percentage of additives increased from 50 to 75%, the recovery improvement only increased by 1.14%, so the contribution of increasing the percentage of additives to the recovery increase was small. Combined with the oil drive efficiency and economic considerations, it is suggested to choose the viscosity increasing system (ASA:LAP = 1:1) with 50% of additives as the optimal CO₂ viscosity increasing agent composite oil drive system (Figure 3).

Figure 3.

Relationship between the percentage of additives and oil drive efficiency.

2.4. Effect of Oil Repelling from Non-homogeneous Cores

At 50 °C, we investigated the effect of the CO₂ flooding to improve the recovery rate with water drives to 98% at a permeability grade difference of 5 between the two cores, and the effect of CO₂—viscosifier (ASA:LAP = 1:1) combined system drive to improve the recovery rate with water drive to 98% at a permeability grade difference of 5 and 10 between the two cores. The relationship between injection volume and oil drive efficiency is shown in Figure 4, and detailed data are shown in Table 3.

• (a)Oil drive efficiency after water drives to CO₂ at a permeability pole difference of 5
• (b)The CO₂–ASA-LAP complex system oil drive efficiency after water drive to CO at an extreme permeability difference of 5
• (c)Oil drive efficiency after water drive to the CO₂–ASA-LAP complex system at an extreme permeability difference of 10

Figure 4.

Relationship between oil drive efficiency and PV number of injection for CO₂ and the CO₂–ASA-LAP composite system in non-homogeneous cores.

Table 3. Evaluation of Oil Drive Efficiency of Non-homogeneous Cores.

		water-drivenrecovery rate/%			EOR/%
system	level difference	low osmosis	high osmosis	comprehensive	low osmosis	high osmosis	comprehensive
CO2 flooding	5	1.35	49.52	27.91	0.79	20.25	11.52
CO2–ASA-LAP	5	1.33	48.52	27.1	8.08	29.28	19.66
CO2–ASA-LAP	10	0	54.51	30.73	16.46	25.5	21.51

The water drive recovery rate is more obviously affected by the permeability grade difference of double pipe cores; the recovery rate of high permeability pipe cores is always higher than that of low permeability pipe; the larger the permeability grade difference, the lower the recovery rate of corresponding low permeability pipe cores; and the existence of the permeability grade difference accelerates the difficulty of water drive in low permeability channels or the difficulty of using low permeability formations. At an extreme permeability difference of 5, after the water drive to 98% water content, the use of continuous CO₂ to improve the recovery rate is less effective, and the recovery rate of high permeability pipe core increases more (20.25%), but the recovery rate of low permeability pipe core is lower only 0.79% increase. It indicates that in the non-homogeneous extra-low permeability reservoir, the use of a single CO₂ flooding cannot reach the relatively low permeability area in the formation, and the comprehensive recovery improvement effect is not obvious, while the use of CO₂–ASA-LAP drive after the water drive increases the recovery rate by 8.08% in the low permeability pipe core and 29.28% in the high permeability pipe core, both of which are significantly higher than that of CO₂ flooding, indicating that the introduction of ASA-LAP does have a better effect on the non-homogeneous core or reservoir. This indicates that the introduction of ASA-LAP does have a good effect of oil washing or improving oil drive efficiency on the non-homogeneous cores or reservoirs, which may be closely related to the mechanism of dissolution, extraction, and swelling of remaining oil in the high permeability channels by CO₂. After the permeability polar difference was increased from 5 to 10, the enhanced recovery of the low permeability pipe increased significantly from 8.08 to 16.46%, and the increase of recovery increased with the increase of permeability grade difference, which should also prove that the system can seal the relatively high permeability channel and initiate the residual oil in the low permeability channel.

2.5. Effect of the CO₂–ASA-LAP Composite System on Reservoir Rock Damage

Considering that the introduction of ASA-LAP may cause some degree of damage to the reservoir rocks, the changes of water measured permeability before and after CO₂–ASA-LAP drive for different permeability cores were investigated at 50 °C. The experimental results are shown in Table 4.

Table 4. Degree of Permeability Injury of CO₂–ASA-LAP Drive on Cores with Different Permeabilities.

gas-measured permeability/mD	water measurement permeability/mD	CO2–ASA-LAP post-drive water measured permeability/mD	degree of penetration injury/%
1.223	0.146	0.118	19.178
4.682	0.402	0.349	13.184
11.631	0.906	0.864	4.636

After injecting the CO₂–ASA-LAP system into the cores with different permeabilities, the permeability of water measurement will be reduced to a certain extent, and the lower the permeability of the cores, the greater the degree of damage to the permeability of the CO₂–ASA-LAP system. When the permeability of the cores increases from 1 to 10 mD, the degree of damage to the permeability of the cores decreases from 19.178 to 4.636%. This may be related to the fact that the lower the core permeability, the smaller the corresponding pore throat, the more easily the viscosity-enhancing system is adsorbed and retained in the pores and pore throat, and it is not easy to desorb or be flushed out.

In addition, during the core damage performance evaluation experiments, it can be found that the resistance coefficient increases with increasing core permeability when switching to CO₂–ASA-LAP drive after the water drive, and the residual resistance coefficient of subsequent water drive decreases with increasing core permeability (as shown in Table 5). This indicates that the sealing ability of the CO₂–ASA-LAP system to the core has permeability selectivity. In the case of an extra-low permeability reservoir or core, the higher the permeability is relatively, the larger its pore size is relatively, and the CO₂–ASA-LAP system is easier to enter the core or reservoir pore, and the shear rate is relatively low, making the CO₂–ASA-LAP system relatively higher in viscosity, easier to seal the relatively larger pore or permeability cores, and the higher the sealing strength, the better the effect.

Table 5. CO₂ Resistance Coefficient and Residual Resistance Coefficient of the ASA-LAP System vs Core Permeability Data.

gas-measuredpermeability/mD	resistance factor	residual resistance coefficient
1.223	1.953	1.314
4.682	2.397	1.198
11.631	4.192	1.096

2.6. CO₂–ASA-LAP Composite System Oil Drive Mechanism

2.6.1. Increasing CO₂ Viscosity and Improving Oil Drive Flow Ratio

Combining Figures 1 and 2, it can be seen that the viscosity of the CO₂ viscosity enhancer composite system can be adjusted by adjusting the proportion of additives, and when the viscosity of the CO₂ viscosity enhancer composite system is increased, the better the effect of improving water drive recovery that is, increasing the viscosity of the CO₂ viscosity enhancer composite system can effectively improve the flow ratio between the replacement medium and crude oil, slow down the occurrence time of CO₂ gas migration, and improve the oil drive efficiency.

2.6.2. Blocking High Permeability Layer and Initiating Low Permeability Layer

From Tables 3 and 5, it can be seen that when the same polar difference double pipe drive, the water drive followed by the CO₂–ASA-LAP system drive increases the recovery rate of low permeability pipe 10.23 times more than that of water drive followed by CO₂ flooding. When the double pipe grade difference increases from 5 to 10, the sealing strength of CO₂–ASA-LAP to high permeability pipe is enhanced, and the recovery rate of low permeability pipe increases significantly, such as from 8.08 to 16.46%. It can be seen that the sealing ability and sealing permeability selectivity of the CO₂–ASA-LAP system to the core of the high permeability pipe makes the subsequent fluids easy to turn to divert and inject into the low permeability pipe, efficiently starting the remaining oil in the core of the low permeability pipe, and greatly improving the recovery rate of the low permeability pipe.

2.6.3. Enhancement of CO₂ Dissolution and the Swelling Oil Repellent Effect

From Table 3, it can be seen that the simple CO₂ flooding can improve the integrated recovery of the core by 11.52% on the basis of water drive through its own mechanism of solubilization and swelling of crude oil and viscosity reduction, while the CO₂–ASA-LAP system drive can further improve the integrated recovery on the basis of water drive compared with the simple CO₂ flooding. The reason for this phenomenon is that the introduction of viscosity-enhancing system ASA-LAP while increasing the CO₂ viscosity and improving the CO₂ flow rate, can further increase the CO₂ contact time with crude oil. This is because the introduction of ASA-LAP, a viscosity-enhancing system, increases the viscosity of CO₂ and improves the flow of CO₂. At the same time, it has a better blocking and shunting effect on the non-homogeneous core, which can further increase the contact time between CO₂ and crude oil, so that CO₂ can be more fully dissolved in crude oil and enhance the viscosity reduction and swelling drive of CO₂.

The mechanism of the CO₂–ASA-LAP system can be summarized as follows: increase the viscosity of CO₂, improve the flow ratio of oil drive, seal the high seepage channel, start the low seepage residual oil, and enhance the dissolution and expansion of CO₂ oil drive; among them, the viscosity increasing effect of ASA-LAP on supercritical CO₂ is the key.

3. Summary and Conclusions

• (1)The viscosity enhancers ASA and viscosity enhancement additive LAP can be used in combination, which can significantly improve its solubility and viscosity enhancement effect in supercritical CO₂. The additive ratio plays a leading role in the synergistic viscosity enhancement effect, and the low additive ratio cannot effectively play the viscosity enhancement effect.
• (2)Homogeneous core oil drive experiments show that the recovery of CO₂ flooding can be increased by 18.31% after water drive to 98%, and the introduction of viscosity building system ASA-LAP can improve the effect of CO₂ flooding to some extent, and its improvement effect is positively related to the solubility and viscosity building property of the system. Combined with the oil drive efficiency and economic considerations, ASA:LAP = 1:1 was selected as the optimal CO₂ viscosity enhancer composite drive system, which can improve the recovery rate by 24.96%.
• (3)The oil drive experiments in non-homogeneous cores show that the CO₂–ASA-LAP system has a better effect of sealing the high permeability channel and regulating the flow rate in non-homogeneous cores or reservoirs, and when the polar difference is 5, the CO₂–ASA-LAP system drive increases the integrated recovery by 8.14% and the low permeability recovery by 7.29% compared with the CO₂ flooding. After the polar difference increases from 5 to 10, the CO₂–ASA-LAP system drive further improves the integrated recovery and low permeability recovery by 1.85 and 8.38%. After the polar difference was increased from 5 to 10, the integrated recovery and low permeability recovery were further improved, and the integrated recovery increased by 1.85%, and the low permeability recovery increased by 8.38%.
• (4)In the injection of the CO₂–ASA-LAP system, there is some harm to the reservoir core permeability, and the degree of harm is closely related to the reservoir core permeability. Moreover, its resistance coefficient increases with the increase of core permeability, and the residual resistance coefficient of subsequent water drive decreases with the increase of core permeability.
• (5)The CO₂–ASA-LAP system oil repelling mechanism includes: increasing CO₂ viscosity, improving the oil repelling flow ratio, blocking high seepage channels, starting low seepage residual oil, enhancing CO₂ dissolution, and expanding the oil repelling effect.

4. Experimental Part

4.1. Experimental Materials and Apparatus

The experimental water is simulated water prepared according to the ion composition and content of the actual formation water in Yanchang oilfield. The water type is CaCl₂ and the salinity is 79 390 mg/L. The specific ion composition is shown in Table 6. CO₂, purity 99.9%, purchased from Hunan Yuanchuang Gas Company; CO₂ surfactant tackifier ASA, provided by College of Petroleum Engineering, Yangtze University; linear block copolymer tackifier additive LAP, provided by College of Petroleum Engineering, Yangtze University; and PDMS with molecular weight of 700, 1000, 1500, 3200, and 5000, purchased from Huangshan Qiangli Chemical Co., Ltd. The core displacement experiment uses the natural outcrop core of the Yanchang oilfield in China, and the permeability is in the range of 1–10 × 10^–3μm².

Table 6. Simulated Formation of Water Ion Composition.

ion concentration (mg/L)
Na+	K+	Ca2+	Mg2+	Cl–	SO42–	HCO3–	mineralization degree (mg/L)
10134.4	81.29	19148.13	70.11	49233.33	653.88	98.77	79419.91

The main instruments used in the experiment are shown in Table 7.

Table 7. Instruments and Factory.

instrument	factory
UCP-3 high-pressure high-temperature sampler	Jiangsu Lianyou Research Instruments Co., Ltd.
LY-ND-01 kinematic viscosity tester	Jiangsu Lianyou Research Instruments Co., Ltd.
CO2 gas multifunctional replacement physical simulation system	Haian Petroleum Research Instruments Co., Ltd.
HSB-1 high-pressure displacement pump	Haian Petroleum Research Instruments Co., Ltd.
LMF-1 wet gas flowmeter	Beijing Jinzhiye Instrument and Equipment Co., Ltd.
experimental device for core oil displacement	Changzhou Zhongbei Instrument Co., Ltd.

4.2. Experimental Methods

4.2.1. Determination of Dissolution Performance of Viscosity Enhancers

The solubility test device of tackifier (Figure 5) was used to record the volume change of CO₂ (pump position before and after measurement) and the mass of separated tackifier at the same pressure and temperature, so as to determine the solubility of tackifier in CO₂. Specific experimental procedure: (1) take a certain amount of tackifier samples into the middle chamber of UCP-3 high-pressure and high-temperature dispenser and seal and inject a certain pressure of CO₂; (2) connect the sample dispenser with the double-cylinder constant speed and pressure repellent pump, set the temperature and pressure required for the experiment on the control panel, then turn on the rotary inversion switch to make the CO₂ and viscosity enhancer mix well; (3) when the temperature, pressure, and pump position are basically stable, turn off the rotary inverted switch, make the sample placed in the instrument for 30 min and then record the pressure, pump position L₁; (4) connect the outlet end and gas–liquid separation device and then slowly open the valve so that the pressure is slowly reduced to the pump level of 2 mL. After closing the valve, record the quality of the liquid mass m, to be recorded after the pump level is stable at this time the pump for L₂, using Formula 1 to calculate the solubility of viscosity enhancers in supercritical CO₂; and (5) the operation was repeated three times, and the average value of solubility was obtained.

1

Figure 5.

Diagram of solubility test of viscosity enhancer in supercritical CO₂.

4.2.2. Evaluation of the Viscosity Enhancement Effect of the CO₂ Viscosity Enhancer Composite System

The viscosity test device (Figure 6) was used to calculate the system viscosity by recording the relevant data of the CO₂ viscosity builder composite system at constant pump speed flowing through the capillary section of the LY-ND-01 kinematic viscosity tester (L = 2 × 10³ cm, r = 0.05 cm, 0.1 cm) under the set temperature and pressure, and the software was used to calculate the system viscosity, and the formula for calculating the viscosity of CO₂ viscosity builder composite system is shown in eq 2. Specific experimental procedure: (1) prepare the CO₂ viscosifier composite system under the required temperature and pressure (same as 2.2.1); (2) when the water bath temperature of the LY-ND-01 kinematic viscosity tester reaches the experimental temperature, connect the outlet end of the middle chamber of UCP-3 high-pressure and high-temperature dispenser and set the back pressure; (3) open the valve switch at the outlet end of the intermediate chamber and set the double-cylinder constant-speed and constant-pressure repellent pump to constant-speed mode at the same time so that the CO₂ viscosity enhancer composite system enters the kinematic viscosity tester evenly; and (4) after the data is stable, close the middle chamber outlet valve, the double cylinder constant speed constant pressure displacement pump is set to constant pressure mode, to the end of the test.

2

r is the capillary inner diameter r₀, cm; p₁ is the inlet pressure, MPa; p₂ is the outlet pressure, MPa; d_v/d_r is the shear rate, s^–1; and L is the length of the capillary tube, cm.

Figure 6.

Schematic diagram of viscosity test of viscosity enhancer in supercritical CO₂.

4.2.3. Evaluation of Oil Repelling Effect of the CO₂ Viscosity Enhancer Composite System

4.2.3.1. Homogeneous Core Flooding Experiment

Figure 7 is the process of homogeneous core flooding experiment. Five cores with similar permeability were selected to be saturated with water, established bound water saturation and saturated oil and then aged at reservoir temperature (50 °C) for 24 h. Then, a water drive was conducted in the form of a constant-flow drive until the instantaneous water content at the outlet end of the core reached 98%, and CO₂ flooding and CO₂–ASA-LAP composite system drive experiments were conducted to compare the oil drive efficiency under different drive methods. The specific experimental procedures of saturated water, established bound water saturation and saturated oil are as follows: (1) saturated formation water: Cores with similar permeability to the experiment are weighed dry, vacuumed, and pressurized to saturate the formation water, and weighed wet after saturation, and the pore volume of the core is calculated by combining with the density of formation water; (2) established bound water saturation: At reservoir temperature, N₂ flooding is used to establish the required ideal irreducible water saturation, and the irreducible water saturation is accurately calculated by weighing the cores before and after N₂ gas flooding; (3) saturate oil: The establishment of irreducible water saturation of the core into the holder, and it is subjected to confining pressure and vacuuming. At the reservoir temperature, the reservoir pressure is established by live oil flooding, and the core pore volume (the volume of live oil entering the pump under constant pressure) is accurately measured. Then, the valve at the outlet end is opened until the gas–oil ratio of the produced oil sample at the outlet end is consistent with the compound live oil.

Figure 7.

Homogeneous core flooding experiment process.

4.2.3.2. Non-homogeneous Material Model Oil Drive Experiment

The experimental process of heterogeneous core flooding is shown in Figure 8. The cores conforming to formation heterogeneity conditions are selected to carry out saturated water, establish irreducible water saturation and saturated oil, respectively. Then, aging for 24 h at reservoir temperature (50 °C); the core is assembled in the form of parallel connection of double-tube oil displacement. After the assembly is completed, a water flooding is carried out until the instantaneous water content at the core outlet reaches 98% and then the CO₂ flooding and CO₂–ASA-LAP composite system flooding experiments are carried out, respectively. Finally, the oil displacement efficiency under different displacement modes is compared.

Figure 8.

Experimental process of heterogeneous core flooding.

4.2.4. Evaluation of Core Injury Performance

At the reservoir temperature of 50 °C, the displacement is carried out in a constant current manner. During the displacement process, the injection stable pressure difference is monitored to calculate the water permeability of the core. When the core permeability measurement is completed, the CO₂–ASA-LAP composite system is transferred to the stable pressure difference between the inlet pressure and the outlet pressure and then the constant flow water flooding is transferred. The permeability after core damage is measured, and the degree of core permeability damage is calculated. The damage rate calculation formula, resistance coefficient calculation formula, and residual resistance coefficient calculation formula of core water phase permeability are shown in Formulas 3–5, respectively.

3

4

5

Η is the injury rate, %. K₁ is the permeability before the core injury, mD. K₂ is the permeability after core injury, mD. R_F is the resistance coefficient, dimensionless. Δ P_w and ΔP_f are the pressure differences between water drive and CO₂–ASA-LAP composite system drive stabilization, respectively, MPa. R_k is the residual drag coefficient, dimensionless. ΔP_b and Δ P_a are the water drive pressure differences before and after the CO₂–ASA-LAP composite system repulsion, respectively. MPa.

The authors declare no competing financial interest.