Introduction

Chemical EOR technologies have been used for decades and their development is increasing rapidly due to the massive need for hydrocarbons in the world and because most of the reservoirs have reached the tertiary recovery phase. The main reason for using surfactants is to lower the interfacial tension (IFT) between water and oil. While the use of polymer is generally linked with surfactant for mobility control to ensure the best sweep efficiency. Additionally, viscoelastic surfactants can be used as they can control mobility as well as reduce the IFT (Ahmed et al. 2022; Azad et al. 2014; Elmuzafar Ahmed et al. 2023).

Polymer flooding (P) for enhanced oil recovery (EOR) is a commonly utilized technique to enhance the effectiveness of oil displacement by reducing the mobility ratio between the displacing and displaced fluids. However, this technique does not have any impact on the residual oil, which requires high capillary forces to be mobilized. In order to overcome this limitation, surfactants are added to the process, which can reduce the interfacial tension (IFT) between oil and water, increase the ratio of viscous forces to capillary forces (capillary number), and hence improve the technique, known as SP flooding.

In carbonate reservoirs, particularly in the Middle East, CEOR process still faces challenges such as high salinity, high temperature, and reservoir heterogeneity which adversely affect recovery and efficiency. For instance, high temperatures cause hydrolysis that affects the polymer's stability, whereas the surfactants may precipitate in high salinity mediums, making it difficult to screen and choose the best chemicals to use. Additionally, carbonate reservoirs are known to have low permeability, with fractures possessing high permeability, leading to channeling and reduced sweep efficiency. For higher permeability formation it is preferred to use higher polymer molecular weight as it is found to increase the sweep efficiency while for lower permeability ones, there is an optimum value that should not be exceeded (Fang et al. 2022).

The early studies of CEOR flooding focused mainly on sandstone reservoirs (Arihara et al. 1999; Chiou and Kellerhals 1981; Osterloh and Jante 1992). However, recently its attention shifted toward carbonate reservoirs due to the increasing number of maturing carbonate fields (Al-Hashim et al. 2005; Azad and Sultan 2014; Han et al. 2013; Levitt et al. 2013; Wang et al. 2015).

SP flooding is more feasible than individual flooding of surfactant or polymer and ASP flooding by combining the benefits of IFT reduction and mobility control and by avoiding operational and precipitation problems associated with ASP flooding (Luo et al. 2013). Ding et al. did a comparative study between SP flooding and AP flooding in term of IFT, emulsification, and recovery and found that ultra-low IFT and oil-in-water dominates SP while water-in-oil (W/O) emulsification dominates the AP. AP is better than SP in terms of heavy oil recovery, however, SP can be improved by introducing foam to assist the ultra-low IFT (Ding et al. 2020).

The amount of chemicals used in CEOR is of great importance which leads to the need for concentration and slug size optimization; the optimum slug we are looking for is the slug that gives the highest possible recovery with the lowest cost.

The rock wettability affects the EOR process by influencing the oil recovery, even though oil-wet rock will enhance the film drainage (Al-Hashim et al. 2005; Omran et al. 2020). The highest overall oil recovery will be achieved under water-wet conditions (Zhu et al. 2013). Therefore, it is very important to restore the original wettability before starting a core-flooding experiment to avoid an optimistic recovery.

High salinity causes chemical precipitation due to the presence of divalent cations such as Ca++ and Mg++ (Mohammadi et al. 2008; Tabary et al. 2013) as well as decreasing the polymer viscosity and elasticity (Dang et al. 2013). On the other hand, high temperature affects the chemical stability and leads the polymer to degrade and act inefficiently (Azad and Sultan 2014; Han et al. 2013). To solve this problem a comprehensive study of the chemical was done which include thermal stability, fluid rheology, micro-emulsion stability, and IFT under these harsh conditions (Kamal et al. 2014; Kamal, Sultan, and Hussein 2015; Kamal, Sultan, Al-Mubaiyedh, and Hussein 2015; Kamal, Sultan, Al-Mubaiyedh, Hussein et al. 2015). Then the best candidates should be tested by core flooding to choose the one that gives the highest recovery. Besides, the occurrence of monovalent cations such as Na+ will decrease the pH of the solution due to the ion exchange with the H+on the rock surface. Therefore the pH drop below the isoelectric point (Somasundaran and Hanna 1979) will result in higher adsorption of chemicals on carbonate rock especially anionic surfactants (Glover et al. 1979; Journal et al. 2008; Lu and Pope 2017; Somasundaran and Hanna 1979).

Studying the flooding sequence is important to identify the best sequence that minimizes the fingering and maximizes the recovery. The literature reported many sequences such as polymer pre-flush to minimize the surfactant adsorption (Wang et al. 2015) and SP co-injection followed by polymer injection (Zhenquan et al. 2013) and other sequences.

Dead oil is very common in lab experiments due to the difficulty of handling live oil and maintaining it in its reservoir composition, however, gases such as methane and CO2 can be added to dead oil in known ratios under pressure to achieve live oil for core flooding purposes (Sui et al. 2019).

When chemicals pass through reservoir rock, adsorption on the surface of the rock can affect the feasibility of the process. Therefore, it is an important element to be considered in the design to select chemicals that are economical and technically achieve the goal. Some additives have proven to be effective in reducing surfactant adsorption such as Colloidal silica nanoparticles (CSNs). It is confirmed with SDS surfactant and reached up to 61% reduction in adsorption by using 25% CSNS with 2500 ppm SDS (Kesarwani et al. 2021).

In addition, hydrodynamic dispersion can occur when fluids mix while flowing through a permeable formation, resulting in a dilution of the slugs and decreased effectiveness. Another important factor to consider is viscous fingering, which occurs when low-viscosity fluid displaces higher-viscosity fluid. In the SP-EOR process, the difference in molecular weight of the polymers may cause slow movement in the pore system and result in chromatographic separation. It is crucial to investigate and evaluate adsorption and chromatographic separation through core flood experiments in the lab before scaling up the process to the field to avoid potential failure.

Enhanced oil recovery (EOR) is implemented to recover residual oil held up by capillary and viscous forces in porous media. This relationship can be expressed using dimensionless numbers such as the Mobility number, capillary number, Bond number, and Trapping number. The Mobility number represents the ratio of the mobility of the displacing phase to that of the displaced phase. Since oil has a lower mobility number, the viscosity of the displacing phase can be increased using polymer, or the viscosity of the oil can be reduced using heat.

$${{\varvec{N}}}_{{\varvec{M}}}=\frac{{{\varvec{\lambda}}}_{{\varvec{w}}}}{{{\varvec{\lambda}}}_{{\varvec{o}}}}=\frac{\left[\frac{{{\varvec{K}}}_{{\varvec{r}}{\varvec{w}}}}{{{\varvec{\mu}}}_{{\varvec{w}}}}\right]}{\left[\frac{{\varvec{K}}{{\varvec{r}}}_{{\varvec{o}}}}{{{\varvec{\mu}}}_{{\varvec{o}}}}\right]}$$
(1)

where:

\({\mathrm{N}}_{\mathrm{M}}\): Mobility Number;\({\uplambda }_{\mathrm{o}}\): Oil mobility;\({\uplambda }_{\mathrm{w}}\): Water mobility;

\({\mathrm{K}}_{\mathrm{ro}}\): Oil relative permeability;\({\upmu }_{\mathrm{o}}\): Oil viscosity;

\({\mathrm{Kr}}_{\mathrm{w}}\): Water relative permeability;\({\upmu }_{\mathrm{w}}\): Water viscosity.

Capillary number (Nca) is the ratio of viscous force to the capillary force acting on the displaced fluid, we can increase it by decreasing the IFT using a surfactant or by increasing the polymer viscosity.

$${{\varvec{N}}}_{{\varvec{c}}{\varvec{a}}}=\frac{{\varvec{\Delta}}{\mathbf{P}}_{\mathbf{v}\mathbf{i}\mathbf{s}}}{{\varvec{\Delta}}{{\varvec{P}}}_{{\varvec{c}}{\varvec{a}}{\varvec{p}}}}=\frac{{\varvec{\mu}}{\varvec{v}}}{{\varvec{\sigma}}}$$
(2)

where:

\({\mathrm{N}}_{\mathrm{ca}}\): Capillary number;

\(\Delta {\mathrm{P}}_{\mathrm{vis}}\): viscous forces;

\(\Delta {\mathrm{P}}_{\mathrm{cap}}\): Capillary forces;\(\mathrm{v}\): velocity;\(\upsigma\): interfacial tension.

Bond number (NB) is the ratio between hydrostatic forces and capillary forces. So, in SP, we can only increase the Bond number by decreasing the IFT through surfactant because the increment by increasing density is negligible.

$${N}_{B}=\frac{\Delta {P}_{grav}}{\Delta {P}_{cap}}=\frac{\Delta \rho g\left(\frac{k}{\phi }\right)}{\sigma }$$
(3)

where:

\({\mathrm{N}}_{\mathrm{B}}\): Bond number;

\(\Delta {\mathrm{P}}_{\mathrm{grav}}\): gravitational forces;\(\uprho\): density (g/cc);\(\mathrm{g}\): gravitational acceleration = 9.8 m/s2;\(\mathrm{k}\): Permeability (md).

At constant Bond number, hydrocarbon recovery increases with the increase of Capillary number up to a specific limit and then decreases dramatically because of the higher viscous forces and the flow stability (Tabrizy 2014).

Trapping number is a combination of Bond number and Capillary number in a way that can sufficiently address the combined effect of capillary, viscous, and buoyancy forces in three dimensions.

$${{\varvec{N}}}_{{\varvec{T}}}=\sqrt{{{\varvec{N}}}_{{\varvec{c}}{\varvec{a}}}^{2}+2{{\varvec{N}}}_{{\varvec{c}}{\varvec{a}}}{{\varvec{N}}}_{{\varvec{B}}}{\varvec{sin}}\,\boldsymbol{\alpha }+{{\varvec{N}}}_{{\varvec{B}}}^{2}}$$
(4)

where:

For horizontal flow \(\alpha\) = 0°, for vertical flow = 90°.

\({\mathrm{N}}_{\mathrm{T}}\):Trapping number.

As far as we know and based on our survey of the literature, there is no established optimization process that integrates the impact of chemicals, slug size, and sequence in a single study. Although some of these effects have been investigated separately or addressed within larger projects with limited emphasis. This has motivated us to address this research gap and explore this area further.

Experimental section

Materials

Synthetic formation brine with total dissolved solids (TDS) of 229,870 ppm was used to saturate the cores initially then displaced with oil to establish the initial water saturation. The composition of the formation brine is given in Table 1.

Table 1 Formation brine composition
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Synthetic seawater similar to Arabian Gulf water with a TDS of 57,612 ppm was used for water and chemical flooding as well as for the bulk fluid of the contact angle experiment, its composition is in Table 2.

Table 2 Seawater composition
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The brines were prepared carefully using deionized water. The weights of the salts were measured using an accurate weight balance of up to 4 decimal digits. They have been stirred for at least three hours to ensure complete dissolution, then filtered with 0.5-micron filter paper.

The crude oil used in this research was medium oil with 24.6 API and 0.89987 g/cc density measured at room temperature. Its viscosity at 90 °C is 3 cp and the density at that temperature is 0.77748 g/cc. It has been analyzed using Saturates, Aromatic, Resin, and Asphaltene (SARA) test as shown in (Table 3) which measures the mass percentage of each component in the crude oil mixture.

Table 3 Saturates, Aromatic, Resin, and Asphaltene (SARA) test analysis for Crude oil
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We used two types of polymers and two types of surfactants in this work. Acrylamido tertiary butyl sulfonate (ATBS)/acrylamide (AM) copolymer produced by SNF FLOERGER. It has 8 million Dalton molecular weight with the structure in Fig. 1a and it will be referred to as (P1). Thermoviscosifying polymer obtained from Hengju Polymer Co. laboratories, its molecular weight is 7.08 million Dalton, it contained 8% thermos sensitive monomer and has 3% degree of hydrolysis with the structure in Fig. 1b and it will be referred to as (P2).

Fig. 1
figure 1

Polymers chemical structures: a copolymer and b Thermoviscofying polymer

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While the surfactants were Amphoteric surfactant SS-880 Carboxybetaine provided by Oil Chem Technology, USA which will be referred to later in the paper as (S1). The other surfactant (S2) was Amphoteric surfactant SS-885 Carboxybetaine from the same source, both of them received in a solution with an active content of 40%. Both surfactants have similar IFT values and their critical micelle concentration (CMC) is around (0.025 wt%). The optimum surfactant concentration was chosen to be 0.05 wt% to compensate for any probable loss of surfactant due to retention or adsorption. We kept it as low as possible because there is no point in using additional surfactant concentration and increasing the cost of chemicals without an expected reduction in IFT as shown in Fig. 2.

Fig. 2
figure 2

The interfacial tension for Carboxybetaine amphoteric surfactant with concentration showing the critical micelle concentration (CMC)

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Those chemicals will be used with the following formulations in the contact angle, rheology, and core-flooding Table 4.

Table 4 Chemical formulations for the selected candidates and their concentration used in the study
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Rheology

The seawater-based solutions, as previously described, are prepared by first placing the solvent in a wide beaker and using a magnetic stirrer to create a vortex. The polymer powder is then gradually added to the top of the vortex to facilitate dissolution. If a surfactant is present, the surfactant solution is added to create the vortex.

The equipment employed for this process is the Discovery Hybrid Rheometer (DHR3) provided by TA Instruments Trios, with the use of a concentric cylinder geometry. The resulting data were fitted to established models such as the Carreau-Yasuda.

Contact angle

The process of measuring contact angle is a way to determine the wettability of a rock by observing the angle of a drop on its surface when surrounded by another fluid. Typically, the drop fluid used is oil, and the surrounding fluid is either air or reservoir fluid, such as seawater or EOR chemicals. For this study, we used surfactant or polymer as the surrounding fluid. To prepare the discs, we used two types of rocks: carbonate outcrop rock from Riyadh and Indiana limestone core. The discs were cut to a diameter of 1 inch and a thickness of 3 mm, then carefully smoothed using sandpapers with increasing grades of fineness. We used silicon carbide abrasive paper electro-coated that was made in Korea for sandpapering. The discs were then dried in an oven at 100 °C for 24 h to remove all water. To restore the discs to their native state reservoir wettability, we immersed them in crude oil and heated them in an oven at 90 °C for one week for outcrop discs and two weeks for Indiana discs. The drop fluid used was the same crude oil used for saturation, which was filtered with a 0.7-micron filter and filled into the drop tank in the machine using a manual screw pump. The bulk fluid was a combination of surfactant and polymer in four different ratios, prepared using the seawater described earlier with the polymer powder or surfactant solution at the required concentration. The IFT 700 provided by VINCI Technologies was used for contact angle measurement at a temperature of 90 °C and pressure of 1500 psi. VINCI Technologies also provided computer software for image analysis and angle calculation. Before attaching the disc holder, air bubbles were released from the bulk line to prevent them from affecting vision. The cell was filled first with the bulk fluid and connected to the bulk and drop fluid lines. After reaching the required temperature, the disc was placed on the disc holder and attached to the cell to start building pressure. The drop was released carefully, and the drop angle was measured for at least half an hour of stabilization time. Contact angle is measured through the oil phase, with water-wet conventionally being defined as greater than 90° and oil-wet as less than 90°. Figure 3 shows this convention for contact angle.

Fig. 3
figure 3

Contact angle convention used throughout this experimental set

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Core-flooding

Core-flooding is a laboratory method used to imitate reservoir recovery. To do this, a cylindrical rock sample is prepared to match the conditions of the downhole formation in terms of temperature, pore pressure, and overburden pressure. The core is cut into small 2-inch plugs with a 1.5-inch diameter and polished using a grinding machine to create a composite core. The plugs are then cleaned with toluene solvent and dried overnight in a 90 °C oven. Air permeability is measured and corrected to Klinkenberg liquid permeability. The core is then saturated with formation water brine, vacuumed for three hours to remove any air from the pores, and subjected to 3000 psi pressure overnight using a positive displacement pump. Porosity and pore volume are calculated from the weight difference between the saturated and dry cores. Oil saturation is achieved by displacing the formation water with crude oil using a centrifuge machine. The cores are wrapped carefully with nylon and aluminum sheets and aged for two weeks in a 90 °C oven to restore the native state reservoir wettability.

The core-flooding experiment is conducted using a VINCI core-flooding machine, which consists of a core holder with a rubber sleeve, accumulators linked with displacement pumps for injection fluids, and a fluid separator or fraction collector (Fig. 4). Computer software is used to monitor the pressure transducers, pumps, and separator camera in real time. The core is loaded inside the sleeve and pushed to ensure no spaces between the plugs, and the sleeve is placed inside the core holder and tightened carefully to avoid any leaks. The oven is turned on to 90 °C, and the reservoir pressure is gradually built up to 1500 psi overnight to guarantee a stabilized temperature inside the core. The injection rate is 1 cc/min for all fluids, starting with water-flooding, followed by chemical flooding, and finishing with water-flooding again.

Fig. 4
figure 4

Schematic diagram of the core-flooding system

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Results and discussion

Rheology

Studying the rheological properties of chemicals intended for injection into a reservoir is crucial, especially when dealing with heterogeneous formations. It helps to comprehend the divergence and impact of shear on viscosity, whether it exhibits shear-thinning or shear-thickening behavior. Rheological properties are also required for surface calculations related to injection pressure and flow rate. In this section, we will delve into the rheological properties of chemical combinations where polymers are mixed with surfactants, as detailed in Table 4. Figure 5 illustrates the impact of changing chemicals on shear scan behavior for all SP combinations listed in Table 4. For S1P1, the shear scan displays shear-thinning behavior in the (0.001–5) 1/s shear rate range, with no apparent effect of shear above 5 1/s. The data was fit to the Carreau-Yasuda model, and the zero-shear viscosity was found to be 35.6 cp at the given temperature and salinity. On the other hand, the shear scan for S2P1 exhibits the same shear-thinning behavior in the initial part and then reaches a plateau. The data was fit to the Carreau-Yasuda model, and the zero-shear viscosity estimation was 52.8 cp. The same trend was observed for S1P2 and S2P2, except the zero-shear viscosity extracted by fitting the data to the Carreau-Yasuda model gives 124 cp and 23.5 cp, respectively. It is evident that the presence of surfactant does not affect rheology in the (3–100) 1/s shear rate range because, for the same polymer, the two curves with different surfactants overlapped, but there is a difference in the first range, which is either minor, as in P1, or significant, as in P2. The disparity in P2 suggests that P2 performs better with S1 than with S2.

Fig. 5
figure 5

The effect of chemicals on rheology at 85 °C with seawater

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Contact angle

Contact angle measurements were conducted on two distinct types of rocks with varying aging times. The first rock sample was an outcrop rock that consisted of pure calcite and had been aged for a week. The second sample was an Indiana limestone rock that had been aged for two weeks. Both rocks were anticipated to have oil-wet properties, making them ideal for exploring the impact of aging on wettability. The one-week-aged outcrop rock was utilized to examine the impact of four distinct chemical formulations on wettability in comparison to seawater wettability without any chemical treatments.The contact angle for the seawater stabilized at 129° which means the rock is water wet as in Fig. 6e. The contact angle for S1P1 stabilized at 52° as shown in Fig. 6e showing weakly oil-wet rock. While S2P1 is 34° indicating an oil-wet rock more than S1P1 as shown in Fig. 6b. On the other hand, both of the forthcoming solutions consist of P2, the former one containing the S1 has a contact angle of 38° as plotted in Fig. 6c. But the latter one containing S2 exhibited a contact angle of 70° indicating a water-wet rock Fig. 6d. On the other hand, the two weeks-aged Indiana limestone was used in this set of experiments to study the effect of the four different chemicals on the wettability taking the seawater contact angle as a benchmark. The seawater contact angle stabilized at 4° indicating the original oil-wet rock as shown in Fig. 7e. Comparing this result to the previous rock with seawater we can say that 1 week is not enough to restore the native state wettability on the disc samples. The contact angle for S1P1 spread to the rock surface after 50 s showing strongly oil-wet rock as shown in Fig. 7a. While the contact angle for S2P1 stabilized at 12° for more than 500 s measured through the oil phase indicating a strongly oil-wet rock as in Fig. 7b. Investigating the contact angle for P2 solutions with S1 and S2 Fig. 7c and d respectively resulted in extremely oil-wetness for S1P2. The S2P2 solution maintained a contact angle of 22° for over 1000 s during oil wetting, indicating strong oil-wet properties. Seawater has a benchmark contact angle of 4°. Therefore, mixtures containing SS-885 can shift the wettability of the rock from oil-wetness to water-wetness, ranging from 4 degrees to 12° when combined with ATBS/AM and to 22° when combined with TVP. In contrast, other surfactant mixtures increased oil-wetness to the maximum limit, causing the oil droplet to spread across the rock surface.

Fig. 6
figure 6

Contact angles for crude oil droplet in contact with calcite outcrop discs with the bulk fluid of a S1P1, b S2P1, c S1P2, d S2P2, e seawater (SW)

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Fig. 7
figure 7

Contact angles for crude oil droplet in contact with Indiana limestone disc with the bulk fluid of a S1P1, b S2P1, c S1P2, d S2P2, e seawater (SW)

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Core-flooding results

The effectiveness of the selected chemicals in releasing residual oil trapped by capillary forces or bypassed by water-flooding through fingering was assessed through core-flooding experiments. Additionally, the optimal combination of the four chemical formulations, along with the appropriate slug size and sequence, was determined.

The effect of chemicals

In the S1P1 core-flooding experiment, water-flooding resulted in the recovery of 62.8% of the oil initially in place (OIIP). Chemical flooding was able to recover 31.29% of the residual oil saturation (ROS), which corresponds to 11.63% of the OIIP. Once 5 pore volumes (PV) of seawater had been injected, the pressure drop stabilized as no more oil was produced. However, when SP injection began, the pressure drop increased dramatically due to the high polymer viscosity. For the S2P1 experiment, 7 PVs of seawater injection resulted in an oil recovery of 57.7% of the OIIP. Subsequently, a 2.7 PV slug of S2P1 was injected, which extracted 14.87% of the ROS, representing 6.285% of the OIIP. After 4 PVs of seawater injection, no more oil was produced, and water injection continued up to 7 PV for consistency with other core floods.

In the S1P2 experiment, 7 PVs of seawater injection resulted in an oil recovery of 80.3% of the OIIP, which is a remarkably high recovery for water flooding. However, Buckley et al. (1996). reported a similarly high water-flooding recovery rate of 80% after two weeks of aging. Later, a 2.7 PV slug of S1P2 was injected, which extracted 33.41% of the ROS, corresponding to 6.574% of the OIIP. In the S2P2 experiment, 7 PVs of seawater injection resulted in an oil recovery of 58.17% of the OIIP. A 2.7 PV slug of S2P2 was then injected and successfully extracted 9.07% of the ROS, representing 3.794% of the OIIP. The pressure drop stabilized at this stage, indicating negligible oil production. With SP injection, the pressure drop increased due to the high polymer viscosity, but it declined again after polymer breakthrough.

The combination S1P1 showed the most promising incremental recovery out of OIIP as can be seen in Fig. 8 and can be considered as the optimum combination above the other three. Figure 9 displays the resistance factor changes during the flooding process. Following the water flooding period, the resistance factor initially rises at the start of the chemical flooding process due to the formation of an oil bank ahead of the water. However, it subsequently declines once the water breaks through. As the process shifts to post-water injection, the resistance factor declines once more due to the reduced viscosity. Notably, S1P1 exhibits higher resistance compared to the other combinations on average, which may be attributed to the formation of micro gel at the inlet face. This micro gel can partially obstruct the pores, causing a reduction in permeability.

Fig. 8
figure 8

The effect of chemicals incremental recovery out of original oil in place (OIIP)

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Fig. 9
figure 9

The effect of the chemical resistance factor (The ratio of the chemical pressure drop to the last pre-water flooding pressure drop)

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Table 5 contains a detailed summary of this set of experiments. Figure 9 displays the resistance factor changes during the flooding process. Following the water flooding period, the resistance factor initially rises at the start of the chemical flooding process due to the formation of an oil bank ahead of the water. However, it subsequently declines once the water breaks through. As the process shifts to post-water injection, the resistance factor declines once more due to the reduced viscosity. Notably, S1P1 exhibits higher resistance compared to the other combinations on average, which may be attributed to the formation of micro gel at the inlet face. This micro gel can partially obstruct the pores, causing a reduction in permeability.

Table 5 Summary of the effect of chemicals core-flooding experiments
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The effect of slug size

To determine the most cost-effective size, three different sizes were tested: 1.7 PV, 2.7 PV, and 3.5 PV. The SP slug used for injection was selected based on the chemical experiments, with S1P1 being identified as the optimal choice due to the incremental recovery achieved, as presented in Fig. 8. The full summary of this set is elaborated in Table 6. Starting with a 1.7 PV slug size core-flooding experiment, the SP slug was injected after pre-water-flooding and post-water-flooding. For S1P1 flooding, no oil was produced after injecting 5 PV of seawater, resulting in an oil recovery of 56.76% of the OIIP. A 1.7 PV injection of the S1P1 slug extracted 26.24% of the ROS, which is equivalent to 11.34% of the OIIP. The 2.7 PV experiment involved injecting the SP slug between two water-flooding sessions. S1P1 flooding resulted in an oil recovery of 62.8% of the OIIP by pre-water flooding. The chemical flooding extracted 31.29% of the ROS, which represents 11.63% of the OIIP. For the final experiment of the set, a 3.5 PV slug size was used, with 5 PV of seawater injection recovering 50.16% of the OIIP. The chemical slug extracted 34.21% of the ROS, which represents 17.05% of the OIIP. It's worth noting that different plugs produced different recoveries, even when using the same slug size. The optimal slug size was determined by observing the general trend, whereby incremental recovery stabilized at 3 PV. Thus, the optimum slug size is 3 PV of S1P1, as explained in Fig. 10. Figure 11 illustrates the resistance factor, which indicates permeability reduction due to polymer retention at the end of chemical flooding. The resistance factor for the 2.7 PV slug size is higher post-flooding than pre-water flooding, indicating retention. Conversely, the 1.7 PV and 3.5 PV slug sizes have lower resistance after post-water flooding than pre-water flooding, indicating permeability enhancement.

Table 6 Summary of the effect of slug size core-flooding experiments
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Fig. 10
figure 10

Optimizing the slug size by injecting different slug sizes ranges from 1.7 to 3.5 PV presented in recovery out of residual oil saturation (ROS)

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Fig. 11
figure 11

The effect of slug size on the resistance factor

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The effect of the injection sequence

Four different sequences were tested to determine which one is the most effective in terms of oil recovery. The recovery percent of the residual oil was used as the deciding factor. The sequences tested were SW-SP-SW, SW-P-S-SW, SW-S-SW-P-SW, and SW-P-SW-S-SW. The SP slug used in the experiments was S1P1. The graph depicted in Fig. 13 displays the Resistance Factor profile for all tested sequences. It is important to note that the fluids containing polymer, whether combined with surfactant or used alone, exhibit higher resistance. Conversely, when surfactant was introduced after water flooding, the resistance factor was less than 1, indicating a lower pressure drop than water flooding. This can be attributed to the reduction in oil saturation, which subsequently increases the relative permeability of the water phase, leading to a decrease in pressure drop.

Table 7 summarizes the results of all the tests. In the SW-SP-SW sequence, injecting one pore volume (PV) of seawater resulted in oil recovery of 63.28% of the original oil in place (OIIP). Then, injecting 2.7 PV of the S1P1 slug successfully extracted 31.29% of the residual oil saturation (ROS), which represents 11.63% of the OIIP. The SW-P-S-SW sequence resulted in oil recovery of 55.7% of the OIIP by injecting 5 PVs of seawater. After that, 1.5 PV of the P1 slug was injected, followed by 1.5 PV of the S1 slug, then SW. This extraction process extracted 17.26% of the ROS, which represents 7.63% of the OIIP. The SW-S-SW-P-SW sequence showed water-flooding recovery of 52.78% of the OIIP by injecting 5 PVs of seawater. Injecting 1.5 PV of the S1 slug and then 1.5 PV of the P1 slug, followed by SW, resulted in an additional 12.08% of the ROS being extracted, which represents 5.702% of the OIIP. Lastly, the SW-P-SW-S-SW sequence showed oil recovery of 52.11% of the OIIP by injecting 5 PVs of seawater, followed by 1.5 PVs of the P1 slug, then SW, and 1.5 PVs of the S1 slug. In total, 25.52% of the ROS was extracted, which represents 12.24% of the OIIP. It is important to note that polymer flooding resulted in high recovery, with around 9% of the OIIP. Previous research has shown that polymer flooding can even reach 15% of the OIIP (Kamal, Sultan, Al-Mubaiyedh, Hussein et al. 2015). Based on the results depicted in Fig. 12, the sequence SW-S1P1-SW showed the highest ROS recovery. This is because it shows a synergistic effect that cannot be achieved by either surfactants or polymers alone. This result is similar to the findings of Felix et al. (2015), who showed that the SW-SP sequence is more effective than the SW-S-P sequence and polymer-augmented surfactant soaking. It is also worth noting that the recovery achieved by the polymer is much higher than that achieved by the surfactant, which supports the findings of Bataweel et al. (2012) that surfactants alone do not increase recovery unless there is a controlling agent for mobility. The graph depicted in Fig. 13 displays the Resistance Factor profile for all tested sequences. It is important to note that the fluids containing polymer, whether combined with surfactant or used alone, exhibit higher resistance. Conversely, when surfactant was introduced after water flooding, the resistance factor was less than 1, indicating a lower pressure drop than water flooding. This can be attributed to the reduction in oil saturation, which subsequently increases the relative permeability of the water phase, leading to a decrease in pressure drop.

Table 7 Summary of the effect of injection sequence core-flooding experiments
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Fig. 12
figure 12

The effect of sequence recovery out of the residual oil saturation (ROS)

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Fig. 13
figure 13

The effect of sequence resistance factor

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Conclusions

A comprehensive optimization study was conducted to identify the optimal formulation for enhanced oil recovery under harsh conditions that yields the highest recovery. The selected candidates were two amphoteric surfactants, SS-880 and SS-885, and two polymers, Acrylamido tertiary butyl sulfonate/acrylamide (ATBS/AM) and thermoviscofying polymer (TVP). The optimization involved investigating the surfactant polymer (SP) slug size, injection sequence, and their compatibility. The following observations were made:

  • The addition of surfactant did not affect the mixture's rheology at shear rates between 3–100 1/s.

  • TVP exhibited better compatibility with SS-880 than SS-885.

  • Thermal aging of calcite rock discs for two weeks was sufficient to restore wettability, while one week was not adequate.

  • The optimal chemical combination was carboxybetaine (0.05 wt%) and ATBS/AM (0.25 wt%), which resulted in 31.29% recovery of the Residual Oil Saturation (ROS), equivalent to 11.63% of the OIIP.

  • The optimal slug size was determined to be 3.5 PV, resulting in a ROS recovery of 34.21% and an OIIP recovery of 17.05%.

  • The optimal injection sequence involved co-injecting surfactant and polymer SW-S1P1-SW, yielding a ROS recovery of 31.29% and an OIIP recovery of 11.63%.