Introduction

Among many tertiary oil recovery methods and technologies (chemical flooding, miscible flooding, thermal oil recovery, and microbial oil recovery), surfactants and polymers are belonged to the most promising ones. The polymer can increase the viscosity of the water phase, reduce the permeability of the water phase, and thus reduce the water–oil mobility ratio to improve the sweep efficiency. Surfactants contacted with crude oil could significantly reduce the interfacial tension (IFT) between the phases through emulsification, increasing capillary number and ultimately affecting the relative permeability.

Field-scale surfactant injection experiments with small amounts of chemical slugs have been conducted in North America since the 1970s (Wanosik et al. 1978; Talash and Strange 1982). In the past 30 years, China has implemented the most ternary compound injection field projects in the Daqing, Shengli and Karamay fields (Guo et al. 2017). Successful cases of ternary composite injection in low acid value reservoirs in Daqing Oil Field have been reported (Liu 2013). The maximum reported water reduction is 90–50% (Chang et al. 2006). There have been extensive experimental, numerical, and most recently, data-driven-based studies on the evaluation of the performance of chemical flooding for EOR after waterflooding (Liu 2007; Stoll et al. 2011; Liu 2007; Druetta and Picchoni 2018; Dang et al. 2018; Wang et al. 2001; Sun et al. 2021). Among them, laboratory-based core flooding experiment is the most common method for the evaluation of chemical EOR processes. In terms of the research on the influencing factors of the ASP system, Wang et al. (2001) studied the influence of the viscosity of the ternary compound system and the effect of polymer flooding agent on the oil displacement through physical simulation experiments. Zhao (2000) studied the evolution and mechanism of rock wettability in ASP flooding through indoor simulation experiments. Li et al. (2001) used ASP reservoir numerical simulation software to carry out ASP flooding injection program and slug optimization design on the basis of indoor formula and pre-pilot field test in Daqing Oil Field.

The objective of this paper is to present the series of experiments on the evaluation of surfactant/polymer EOR after high salinity waterflooding in the Kumkol sandstone Oil Field in South Turgay Basin, Kazakstan. From 1990 to 2011, the average oil recovery rate of Kumkol Oil Field was 2.27%, and the average oil production per well was 34.17 t/D. In 2011, the average fluid production rate per well reached a maximum of 217.22 m3/D, and the Kumkol Oil Field has entered the high water-cut stage with a water cut of 95% and oil recovery rate of 0.87%. Therefore, this study serves as the feasibility study of surfactant/polymer flooding to further improve oil recovery in Kumkol Oil Field. We first present the screening of potential candidates among commercial surfactants and polymers based on IFT measurements, emulsification and rheology tests. Their performance on improving oil recovery is evaluated through a series of core flooding experiments including surfactant-only slug, polymer-only slug, polymer-surfactant mixture slug, and polymer + surfactant separate slug injection. The effect of different injection schemes is further studied on homogeneous and heterogenous sand packs.

Surfactant/polymer screening

Materials

The crude oil used is synthetic oil, which is prepared from ground dehydrated and degassed crude oil (viscosity is 1.76 mPa s at 55 °C) and kerosene at a volume ratio of 3:2. The viscosity is 2.35 mPa·s. The pH value of the formation water is 5.75, with high CI−, high Ca2+, high Mg2+, and high salinity of 44,590 mg/L. The compositions are displayed in Table 1. The synthetic brine is prepared according to the composition of the formation water of Kumkol Oil Field and filtered before experiments. The viscosity of the synthetic formation water at 55 °C is 0.6 mPa·s.

Table 1 Composition of the formation brine
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IFT measurements

A total of 13 surfactants (AES, CAB, CHSB, LAB, OA-12, LAO, AEO, KD-2, BS-12, BS 14-16, 1227, WLW and XBS) are selected based on their solubility in formation water. All the surfactant solutions are prepared with synthetic formation water at 0.3 wt% concentration. The interfacial tension between crude oil and surfactant solution is measured by using a spinning drop tensiometer at 55 °C and a speed of 6000 rpm.

Emulsification test

The surfactant solutions are prepared at 0.3 wt% concentration. The crude oil and surfactant solution are mixed at the volume ratio of 3:7, which are put into the glass tube. The emulsified water ratio, which is the ratio between volume of the water being separated and that of the original water, is measured and recorded to evaluate the emulsifying capability of the surfactant and stability of the emulsion.

Rheology test

Four polymers as well as their mixture with the surfactants are tested. The polymer and surfactant-polymer solutions are prepared by chemical and synthetic formation water stirring at the rate of 400r/min for 2 min. The rheological characteristics of the polymers and surfactant-polymer solutions are measured by the rheometer at temperature of 55 °C. To measure the viscosity variation of the injected polymer solutions under flowing condition, core flooding experiments are conducted, and effective viscosity is calculated via Darcy’s law:

$${\text{Effective}}\;{\text{Viscosity}} = \frac{{\left( {{\text{Core}}\;{\text{permeability}}} \right)\left( {{\text{Pressure}}\;{\text{difference}}} \right)}}{{\left( {{\text{Injection}}\;{\text{velocity}}} \right)\left( {{\text{Core}}\;{\text{length}}} \right)}}$$

Results and discussion

IFT and emulsification behavior of surfactant solution with crude oil

Figure 1 suggests that high concentration of surfactant solution could lower a certain value of interfacial tension. However, the overall ability of the surfactant at a concentration of 0.5% to reduce the interfacial tension is similar to that of a concentration of 0.3 wt% (Fig. 1). Thus, the 0.3 wt% surfactant solution is used in subsequent experiments. The similar observation is found in all of the 13 surfactants, while only the data of LAO and AEO is presented for illustration purpose.

Fig. 1
figure 1

Interfacial Tension (IFT) variation between surfactant LAO (left) and AEO (right) with crude oil

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Figure 2 shows the temporal evolution of the IFT between the 0.3 wt% surfactant solution and crude oil. It is shown that only WLW can reduce the oil–water interfacial tension to ultra-low condition, and the interfacial tension between other surfactants and crude oil is found to be within the range of 0.1–1 mN/m. As shown in Fig. 2 and Table 2, the best performance is found to be the surfactant AEO as water separation ratio and half-life of the emulsion are the highest among all surfactants. The surfactant WLW, which provides most significant IFT reduction effect, is not a good candidate because its water separation ratio and half-life of the emulsion are the lowest.

Fig. 2
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IFT (left) and emulsification test results (right) of different surfactants

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Table 2 Emulsification test and IFT measurements results of different surfactants
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Rheological characteristic of the polymer solution

Using the apparent viscosity value at the shear rate of 7.34 s−1 as the evaluation index of polymer viscosity, apparent viscosity of the polymer solutions is plotted against polymer concentration in Fig. 3. It can be seen from Fig. 3 that the viscosity of the five polymers all increases with the increase of concentration, among which the viscosities of the polymers Z2 and AN125VM solution change most significantly with the increase of concentration. Compared with the other three polymer solutions, the viscosities of Z2 and AN125VM are the top two when concertation is higher than 1500 mg/L. When the concentration reaches 3000 mg/L, the viscosities of Z2 and AN125VM are 37.08 mPa·s and 31.18 mPa·s, respectively. The viscosity of polymer AN125VM increases slowly within the concentration range of 500–1500 mg/L. When the concentration increases to 2000 mg/L, the viscosity increases more rapidly. The polymer AN132SH presents similar trends with AN125VM as the viscosity increases rapidly when the polymer solution concentration reaches 2000 mg/L, and the viscosity gets the highest value at 3000 mg/L of 24.96 mPa s.

Fig. 3
figure 3

Viscosifying effect of different polymers

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Based on the above comparisons, considering the actual injectability of the Oil Field, the polymer AN125VM which has low molecular weight and shows good thickening effect is determined as the polymer for the subsequent experiments, and its concentration is selected to be 2000–2500 mg/L.

IFT and emulsification behavior of surfactant mixture and surfactant-polymer solution

To screen out surfactants with better performance, WLW, KD-2, AES, AEO, LAB, CAB, CHSB are mixed. The mixed surfactant systems can be fully dissolved in synthetic formation water under room and reservoir temperature conditions. The interfacial tension of the compound system is measured, and the results are shown in Fig. 4. The mixture of WLW:KD-2 with the ratio of 1:2 and AES:BS14-16 with the ratio of 1:2 can reduce the interfacial tension to the range of 0.01–0.1mN/m.

Fig. 4
figure 4

(left) IFT and (right) emulsification test results of surfactant mixture

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The emulsification behavior of the surfactant mixture is summarized in Table 3. Observations from Fig. 4 and Table 3 suggest that performance of surfactant mixture of AES:BS14-16 = 1:2 and WLW:KD-2 = 1:2 is relatively good.

Table 3 Emulsification test and IFT measurements results of different surfactant mixtures
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Based on the previous tests on surfactants and polymers, the surfactant and polymer solutions are mixed and evaluated. The results of rheological characteristic, IFT and emulsification behavior of the SP mixture system are displayed in Figs. 5, 6 and 7 below. The polymer AN125VM solution with a concentration of 2000 mg/L is mixed with the surfactant KD-2, AEO and AB solutions with a concentration of 0.3 wt%. From the measurement results in Fig. 5, adding surfactant to the polymer solution has negligible improvement in thickening effect compared with that of polymer-only system.

Fig. 5
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Viscosity of surfactant-polymer mixture and polymer 125VM

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Fig. 6
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IFT measurement results of surfactant mixtures

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Fig. 7
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Emulsification test results of surfactant mixtures

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Figures 6 and 7 show that after the surfactant solution being added to the polymer, the interfacial tension between the mixture system and the crude oil increases, the change of interfacial tension of surfactant AB with time is relatively stable and maintained at a moderate interfacial tension of 0.1 mN/m. KD-2 and its mixture system have the largest interfacial tension variation. The SP mixture system with KD-2, AEO can reduce the interfacial tension greatly, reaching as ultra-low interfacial tension ultimately and the emulsifying ability is weakened. The emulsifying capability of surfactant AB and its mixed polymer system decreases with time quickly, and finally approaches zero, which is similar to that of KD-2 system. The emulsification performance of single surfactant AEO and its PS mixture system can be maintained at about 20% and 5%, respectively. In the subsequent test of mixed flooding experiment of surfactant + polymer, the effect of surfactant with both low interfacial tension and strong emulsification performance is better. Therefore, AEO is selected for polymer-surfactant mixture slug injection displacement efficiency experiments.

There are generally three main types of residual oil after water flooding: one is the residual oil droplets retained in the pore throat due to capillary force; the other is the residual oil due to microscopic hydrodynamic retention; the third is due to the microscopic heterogeneity of the reservoir, localized residual-oil-rich areas formed at low permeability spaces. The higher the velocity of the oil-displacing agent (water), the greater the driving force for residual oil such as pore-throat oil droplets, oil film, and corner oil. Due to the inevitable microscopic heterogeneity in the reservoir, the higher the displacement speed, the easier it is to quickly form microscopic water flow channels in the relatively large pores in the reservoir, thus resulting in a decrease in the microscopic sweep efficiency. Compared with conventional (low-velocity) water flooding, the main type of residual oil after high-speed production is residual oil due to microscopic heterogeneity. Therefore, the oil displacement agent for micro-heterogeneous residual oil requires strong emulsification performance and relatively low interfacial tension. According to these characteristics, AB (AES:BS14-16 = 1:2) with both strong emulsification performance and relatively low interfacial tension is selected as the surfactant agent for oil displacement in the target reservoir; WLW:KD-2 = 1:2 is selected as the back-up surfactant agent.

Evaluation of surfactant/polymer flooding for EOR

The performance of the preferred surfactant and polymer candidates found in Sec.2 in enhancing oil recovery in sandstones is evaluated via displacement experiments. We present studies on both homogeneous and heterogenous sand packs. The heterogeneous porous medium is packed with transverse/vertical (multilayer) heterogeneity, as each layer being macroscopically homogenous itself but possessing different magnitudes of permeability compared with other layers.

Materials

The permeability of the homogenous pack sand is 500mD. The heterogeneous sand pack is packed into three layers with different sand to provide permeability variation in the vertical direction (Fig. 8), and the permeability distribution is 200mD, 450mD, and 800mD from top to bottom.

Fig. 8
figure 8

(left) Heterogenous sand pack; (right) Schematic of core flooding experiment

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Core flooding experiment

In the core flooding experiments, water is first injected at the rate of 1.7 mL/min (5 m/D) until the water cut reaches 100%. After the pressure gradient stabilizes, surfactant or polymer (or P-S slug) solution is injected at the rate of 0.34 mL/min. The subsequent water flooding is carried out at a speed of 0.34 mL/min until 100% water cut is reached.

Results and discussion

Homogenous sand pack

A series of core flooding experiments are conducted by using the homogeneous sand pack to evaluate the performance of surfactant and polymer candidates found in previous section. Four different injection schemes are investigated: (1) surfactant-only slug injection, (2) polymer-only slug injection, (3) polymer-surfactant mixture slug injection, and (4) polymer injected first, followed by surfactant slug.

Surfactant slug injection

It can be seen from Fig. 9 that the ultra-low interfacial tension and strong emulsification performance of surfactants are not ideal for oil displacement in homogeneous cores, while the effect of AB with both low interfacial tension and strong emulsification performance is optimum. The oil displacement efficiency can be improved by 2.21% from water flooding. Overall, the improvement in the oil displacement efficiency by surfactant flooding after high-speed water flooding in the target reservoir is very small. This is because the surfactant injected into the reservoir after high-speed water flooding cannot get in touch with the micro-heterogeneous residual oil, which also confirms that the key to improve oil displacement efficiency in reservoirs after high-speed water flooding is to improve microscopic sweep efficiency.

Fig. 9
figure 9

Core flooding experiment results of different surfactant and surfactant mixtures

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Polymer slug injection

It can be observed in Figs. 10 and 11 that during the injection of the polymer solution, the pressure gradient increased rapidly, but the oil displacement efficiency did not increase significantly, and the water cut did not decrease significantly; While in the subsequent water flooding stage, the water cut significantly decreased, and the oil displacement efficiency also increased to a certain extent. Therefore, the improvement in the oil displacement efficiency of homogeneous core polymer flooding is mainly the contribution of subsequent water flooding. This result shows that the role of the polymer slug is to control the microscopic water flow direction and improve the microscopic sweep efficiency of the subsequent injected water.

Fig. 10
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Core flooding experiment results of 100 mg/L (left), 500 mg/L (middle), 1000 mg/L (right) of polymer 125VM injection

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Fig. 11
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Core flooding experiment results of 2000 mg/L (left), 2500 mg/L (middle), 3000 mg/L (right) of polymer 125VM injection

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From the comparison of experimental results in Figs. 10 and 11, when the polymer concentration is increased from 100 to 3000 mg/L, and the viscosity is increased from 1.94 to 62.39 mPa s, the pressure gradient is greatly improved, but the oil displacement efficiency does not change much. This is because the viscosity of the polymer is too large, which is accumulated and blocked at the entrance, and there is less polymer entering the core, resulting in poor oil displacement efficiency. In general, the salt-tolerant polymer 125VM has a good effect on improving the oil displacement efficiency, and chemical flooding improves the oil displacement efficiency by 3–8%.

Figure 12 shows the effect of polymer solution viscosity on the improvement in oil displacement efficiency after high-speed water flooding under target reservoir conditions. Increasing the viscosity of the polymer solution is generally helpful for the improvement in the microscopic oil flooding efficiency. When the viscosity is higher than 15 mPa·s, the increase magnitude of oil displacement efficiency slows down.

Fig. 12
figure 12

Oil recovery improvement in polymer injection

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It can be observed from Fig. 12 that the microscopic oil displacement efficiency of polymer flooding (including subsequent water flooding) shows insignificant improvement (< 10%) under high-speed water flooding within the viscosity range of the polymer solution in the experiment. Therefore, if the traditional polymer flooding method is used, the polymer viscosity of the oil displacement agent is not a key performance indicator of the oil displacement efficiency.

In the results of polymer injection (0.3PV) shown in Figs. 10 and 11, the improvement in oil displacement efficiency is not obvious. It can be observed that the improvement in oil displacement efficiency is mainly due to the contribution of subsequent water flooding. This result shows that the polymer slug injection can improve the microscopic sweeping efficiency by fine-tuning the subsequent injected water and eventually improve the displacement efficiency of the residual oil due to microscopic heterogeneity.

According to the special requirements of micro-heterogeneous residual oil flooding, injecting polymer solution is not traditional polymer flooding, but to achieve "fine-tuning" in the target reservoir. For this reason, there are special requirements not only for the viscosity of the polymer solution used as fine-tuning, but also for other properties of the oil-displacing agent that is combined with solution.

Based on the observations above, the surfactants injected into the sand pack after high-speed water flooding does not yield improvement of the oil recovery because the surfactant does not get in touch with the micro-heterogeneous residual oil. These observations are consistent with previous findings by Sheng (2011) and Liu (2007). In the subsequent subsections, oil recovery behavior under combined polymer + surfactant injection is studied.

Polymer–surfactant mixture slug injection

The oil flooding experiment of the polymer-surfactant mixture system is to mix the polymer AN125VM with the surfactant, keep the polymer concentration at 2000 mg/L and the surfactant concentration at 0.3 wt%, and then inject 0.3PV of this mixture system after water flooding. For oil displacement, Fig. 13 shows that such mixture slug can improve the oil recovery by more than 10%.

Fig. 13
figure 13

Core flooding experiment results Polymer-surfactant mixture AN125VM + KD-2(left) and AN125VM + AEO(right)

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Polymer + surfactant separated slug injection

The flooding experiment of polymer + surfactant separated injection, that is, after water flooding, 0.15PV of polymer AN125VM (2000 mg/L) was injected first, and then 0.15PV of surfactant solution KD-2 (0.3 wt%) was injected. The results in Fig. 14 show that it improves the oil displacement efficiency by 5.16%, which is several times better than 1.04% by injecting 0.3PV surfactant KD-2 alone.

Fig. 14
figure 14

Core flooding experiment results of polymer (AN125VM) + surfactant(KD-2) (Separated) injection

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Heterogenous sand pack

Based on the observations of the displacement experiments on homogenous sand pack, for the core flooding on heterogenous sand pack shown in Fig. 8, polymer-surfactant injection schemes are investigated: polymer-surfactant mixture slug injection, polymer + surfactant separated slug injection, and polymer is injected first, followed by surfactant injection.

Polymer–surfactant mixture slug injection

Figures 15 shows results of recovery performance of the three-layer heterogeneous sand pack under PS mixture slug injection and subsequent water flooding. 2000 mg/L polymer AN125VM solution and 0.3 wt% surfactant AB solution were mixed, and 0.3PV of this mixture was injected after water flooding and enhanced the oil recovery by 10.67%. When the injected volume is reduced to 0.1PV, the enhanced oil recovery rate of PS mixture flooding is only 6.15%.

Fig. 15
figure 15

Core flooding experiment results of 0.3PV(left) and 0.1PV(right) mixture injection

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Polymer + surfactant separated slug injection

To study the optimum oil displacement capacity of the emulsifier after polymer slug, displacement experiment of continuous injection of emulsifier after polymer profile control was designed. The polymer is AN125VM, the concentration is 2500 mg/L, the injection slug is 0.3PV, and the subsequent oil displacement agent is 0.3 wt% surfactant AB mixture (AES:BS14-16 = 1:2). The oil displacement performance is shown in Fig. 16. In the stage of polymer injection and emulsification of oil displacement agent, the water cut is significantly reduced, reaching the minimum value of 82.35%. PS separated slug can increase the recovery factor by 12.98% from water flooding, and the contribution of surfactant flooding to recovery factor is greater than that of polymer flooding. This shows that injecting an appropriate amount of polymer solution as a conformance control slug before injecting the emulsified displacing agent can make the emulsified oil-displacing agent injected later get in touch with the microscopic and macroscopic residual/residual oil, emulsify and mobilize the residual crude oil. Notably, emulsification of the produced fluid can be observed during the surfactant injection stage (Fig. 17).

Fig. 16
figure 16

Core flooding experiment results of high concentration polymer slug + surfactant AB mixture (separated) injection

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Fig. 17
figure 17

Produced fluid is emulsified

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To compare the conformance control and oil recovery improvement effects of different polymer + surfactant slug combinations, three groups of high-concentration polymer conformance control + surfactant slug + subsequent water flooding experiments were carried out. The experimental results are shown in Fig. 18. The polymer used in the experiment is AN125VM, the surfactant is AB-mixture. Three injection schemes are investigated:

Fig. 18
figure 18

Core flooding experiments results of Option A, B and C (from left to right)

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Option A: 0.3PV polymer (2000 mg/L) + 0.3PV active agent (0.3 wt%) + subsequent water flooding (enhanced oil recovery 10.56%).

Option B: 0.1PV polymer (2000 mg/L) + 0.1PV active agent (0.3 wt%) + subsequent water flooding (enhanced oil recovery 9.5%).

Option C: 0.067PV polymer (3000 mg/L) + 0.1PV active agent (0.3 wt%) + subsequent water flooding (enhanced oil recovery 10.63%).

The comparison of the combined effect of different polymers and surfactant slug is shown in Fig. 19. Comparing the 0.3PV polymer + 0.3PV surfactant slug with 0.1PV polymer + 0.1PV surfactant slug, the difference in oil recovery is insignificant, and chemical flooding is shown to be effective after the injection volume reaches 0.3PV. In addition, it can be seen from the comparison between the third and second options that under the same amount of chemical agent, increasing the viscosity of the polymer can improve the final recovery. This is mainly because the polymer plays the role of conformance control. Increasing the viscosity of the polymer can improve the conformance control in the vertical direction, thus enhances the final recovery.

Fig. 19
figure 19

Recovery performance comparisons of different injection schemes

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Concluding remarks

This work presents an experimental study on the surfactant/polymer injection for EOR in Kumkol sandstone reservoirs, which enters high water-cut stage after years of high-velocity water flooding. Different from the common enhanced oil recovery technology in the reservoirs under low water injection, the enhancement of microscopic oil displacement efficiency in Kumkol Oil Field focuses on the displacement of residual oil due to microscopic heterogeneity. Motivated by above, the performance of the preferred surfactant and polymer candidates used in EOR is evaluated through a series of core flooding experiments on both homogeneous and heterogenous sand packs. The main observations are summarized as follows:

  1. 1.

    The oil recovery improvement in surfactant-only flooding after water flooding is negligible. This is because the micro-heterogeneous residual oil cannot get in touch with the injected surfactant.

  2. 2.

    The improvement in the oil recovery of homogeneous sand pack under polymer flooding is mainly due to the subsequent water flooding. The role of the polymer slug is to control the microscopic conformance and improve the sweep efficiency of the subsequent injected water.

  3. 3.

    Increasing viscosity of the polymer solution by increasing concentration is generally beneficial for improving the microscopic oil flooding efficiency, but actual field applications need to go through a “fine-tuning" process in the target reservoir as the interaction with oil-displacing agent must be considered.

  4. 4.

    Polymer slug followed by surfactant slug and polymer-surfactant mixture slug can both effectively improve the oil recovery because surfactant could get in touch with residual oil as the polymer improves the sweep efficiency.

  5. 5.

    Injecting polymer in the first, followed by surfactant slug yields the better performance compared with polymer-surfactant-mixture slug in heterogenous sand pack. This is because the polymer pre-flush improves the vertical conformance of the surfactant solution and the final recovery.