Investigation of the effect of adding alkali (Na2CO3) on the adsorption of an anionic surfactant on the carbonate surface was also targeted. The optimum alkali concentration and engineered water (EW) salinity were adjusted for the alkali/surfactant solution and crude oil, which provides the desirable mid-phase microemulsion. After selecting the best chemical/EW combination, four chemical EOR core floods were designed to study the effect of the hybrid method on oil displacement and to investigate the effect of a negative salinity gradient design.
Background
Water flooding with low salinity can change the wettability of carbonates to the water-wet state through proposed mechanisms such as multicomponent ionic exchange (MIE) and bilayer expansion (Zhang & Morrow, 2006; Fathi et al., 2011; Esene et al., 2018). 2015) reported an increase in incremental oil recovery by more than 10% after the injection of LSS into carbonate core samples (Alameri et al., 2015). By applying alkali and shifting the pH to values above 9, the surface charge of carbonates' surface can change (Zhang et al., 2006), and the adsorption is controlled.
Literature Review
- Wettability in carbonates
- Mechanisms of Low Salinity Water Flooding in carbonates
- Surfactant characteristics
- Surfactants retention
- Hybrid EOR Method: Surfactant/LSW Flooding
- Negative salinity gradient
The mechanism depends on the integrity of the water film, which occurs between the rock surface and the fluid. The salinity of the water influences the phase behavior of the surfactant solution. The surfactant can adsorb to the rock surface due to the electrostatic interaction between the surfactant and the rock (Kamal et al. 2017).
Retention leads to high IFT and a reduction in chemical sludge efficiency (Kamal et al., 2017). The experiment conducted by Khanamiri et al. 2016) in sand cores resulted in 2-6% of additional oil production.
Problem definition
Objectives of the Thesis
Main Objectives
Thesis Structure
Furthermore, Chapter 2 presents the details and sequence of the procedures performed to achieve the objectives of this dissertation. Solution preparation, basic measurements of rock and fluid properties, water stability, phase behavior, static adsorption tests, and step-by-step instructions for coreflooding experiments explained. This section summarizes the most optimal alkali/surfactant formulation in terms of phase behavior, water stability, and static adsorption tests.
The main objective is to design several hybrid EOR coreflooding experiments to analyze the oil displacement performance and oil/brine/chemicals/LSW interactions during the EOR process. Previous research results (Sekerbayeva et. al., 2020) were used as a basis for hybrid EW/surfactant CEOR in this study. Experiments were conducted to show the effect of adding alkali (Na2CO3) to the CEOR slug on the adsorption of an anionic surfactant on the carbonate surface and oil recovery.
The injection sequence scheme was also analyzed to investigate the effect of a negative salinity gradient on oil displacement and recovery during EW/surfactant CEOR. First, aqueous stability and phase behavior tests were performed to measure oil/brine/chemical properties and interactions at operating temperature. Baseline measurements of rock and fluid properties were performed to perform intermediate calculations and to check the compatibility of the crude oil-brine-rock system.
Conduct core flooding experiments to analyze the oil recovery and fluid flow for different CEOR designs.
Materials
- Core Samples
- Brine
- Crude oil
- Surfactant
- Alkali
The core sample powder was analyzed by XRD (X-ray diffraction) to determine the mineralogical composition. Primarily, the formation water was prepared based on the composition of the formation water in the field in West Kazakhstan. Thus, the combination of optimized engineering water with anionic surfactant was used to study the effect on capillary number and oil recovery.
Two core flood experiments were designed to study the effect of negative salinity gradient on surface active flood performance. The surfactant concentration decreases during propagation through the core sample due to the dilution and adsorption, thus lowering the optimal salinity (Glover et. al., 1979). Therefore, the optimal salinity as measured by phase behavior can be changed and lowered in the porous media, leading to modification of the salinity and generation of Winsor Type III microemulsion in the porous media.
Using a negative salinity gradient injection scheme, the salinity changes the optimal condition in the porous medium to maintain the presence of the microemulsion phase as long as possible. Following this line of investigation, we studied the effect of a negative salinity gradient scheme and compared it with conventional surfactant flooding at optimal salinity. The crude oil used in this study was taken from a carbonate oil field in the Aktobe region of Western Kazakhstan.
To control the adsorption of anionic surfactant on the carbonate surface and to study the effect of ASP on oil recovery, an alkali (Na2CO3) was used.
Procedures
- Brine, surfactant, alkali solutions preparation
- Rock and fluid properties measurements
- Aqueous stability and phase behavior tests
- Static adsorption test
- Coreflooding design
- Coreflooding
Length and diameter measurements were taken using a caliper to determine the bulk volume of the core samples. After determining the dry weight of the core samples, the porosity was measured using a helium porosimeter from Vinci-Technologies. After the injection test, the core samples were inserted into an aging cell filled with the oil, which was placed in the oven at 80⁰C for several days to change the wetting of the core sample towards the oil-wet state, as shown in Table 2.2.2. .
The salinity of the water has a significant influence on the phase behavior of the surfactant solution. As the salinity of the water phase increases, the solubility of anionic surfactants in the water phase decreases, expelling surfactants from the brine and contributing to the middle or upper phase and the transition from microemulsion from Type I to Type II to Type III. . Half of the solutions were ready to stand in the oven at 80⁰C for 6 days before the phase behavior study.
Some of the vials were placed in the oven at 80 ⁰C and the accompanying vials were stored at 25 ⁰C. The deceleration of the surfactant front caused by adsorption on the formation rock leads to an inefficient and economically challenging oil recovery process. Finally, the best alkali concentration in terms of static surfactant adsorption was identified.
This chapter presents the obtained results of experiments discussed in the method part of the research work.
Screening of Alkaline/Surfactant solution
The results obtained from the phase behavior and aqueous stability tests helped to adjust the concentration of EW and alkali to provide a medium phase microemulsion for better oil recovery and low IFT value. As a result, the best alkali concentration that provides the lowest surfactant adsorption on the limestone surface was identified. Therefore, it was decided to dilute the EW by 1.5 times to achieve the best phase behavior.
To study the effect of temperature, phase behavior of the 1.5 times diluted EW with different concentrations of alkali was investigated. It shows that when the alkali concentration is, the water solubility ratio is high and constant because all the water dissolves in the microemulsion, whereas the oil solubilization ratio is low. As the salt content increases, the solubilization ratio of the oil also increases, while the solubilization ratio of the water decreases.
The intersection of the oil-water solubilization ratio versus salinity curves is the optimal salinity and the optimal solubilization ratio. A water stability test is required to check the compatibility of surfactants with low salinity water and other chemicals. Similar aqueous stability tests were performed to study the effect of alkali on the stability of the surfactant solution when mixed with 1.5 times diluted denatured water.
One part of the bottles was placed in the oven at 80 ⁰C and the rest of the same solution was left at 25 ⁰C.
Static adsorption test
The trendline equation from Figure 35 was used to calculate the surfactant concentration after mixing these solutions with the rock. The selected adsorption wavelength was used to record the adsorption value after mixing the surfactant and alkali/surfactant solution with the limestone powder. According to Table 15, the surfactant solution with an initial concentration of 10000 ppm shows 9475 ppm after mixing with the rock.
The purpose of introducing alkali into the surfactant solution was to check to what extent the alkali will reduce the adsorption of the surfactant. However, phase behavior and aqueous stability tests show that a 1% alkali/surfactant solution provides better results. Based on the above screening tests, 1% alkali concentration was selected as the optimum value to control surfactant adsorption, microemulsion phase development and reduction of oil/brine IFT.
To study the effect of the selected alkaline/surfactant/LSW hybrid combination on the oil recovery, coreflooding tests were performed and analyzed.
Coreflooding tests
The first oil displacement test was conducted to check the effect of surfactant flooding combined with EW on oil recovery. EWSF differs from negative salinity flood designs by the salinity of the EW used. The oil recovery in this design was 66.40%, but this negative salinity gradient has a total incremental oil recovery of 25.13%, which is higher than the conventional EWSF case.
The hybrid CEOR that evolves the synergy of low salinity water flooding and surfactant flooding has proven its effectiveness in carbonate cores. Application of alkali was shown to reduce the adsorption of anionic surfactant on the carbonate surface and increase oil recovery. The EASF core flooding experiment revealed higher incremental oil recovery compared to the EWSF, which proves the benefit of applying alkali to the CEOR model in the hybrid scheme.
A three-stage design with a slightly inclined negative salinity gradient has shown higher incremental oil recovery compared to conventional EWSF injection. This study suggests that the injection schedule and salinity variation of the injected brines lead to better oil recovery due to the development of favorable phase behavior in the porous medium. Available at: https://www.intechopen.com/books/science-and-technology-behind-nanoemulsions/microemulsion-in-enhanced-oil-recovery.
Tang, G., & Morrow, N., (1999), Influence of brine composition and fine particle migration on crude oil/brine/rock interactions and oil recovery. Laboratory research into the impact of injection water salinity and ion content on oil recovery from carbonate reservoirs. Enhanced/enhanced oil recovery from carbonate reservoirs by tuning the salinity and ionic content of the injection water.
