Coupling Low Salinity Water Flooding and Preformed Particle Gel to Enhance Oil Recovery for Fractured Carbonate Reservoirs

Abstract

The recovery of oil from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPGs) control conformance are two novel technologies that have recently drawn great interest by the oil industry. We developed a cost-effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to test through laboratory experiments the extent to which the coupling method can improve oil recovery. The laboratory experiments showed that the optimum water salinity for the application of the coupled method was 0.1 wt. % NaCl under experimental conditions. The water residual resistance factor (Frrw) increased as the water salinity and the fracture width decreased. The oil-wet carbonate cores provided a higher improved oil recovery than a water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thus producing more oil from the matrix. Results also show that oil recovery increased by 10 % during LSWF after the second waterflooding. Additionally, when PPG was injected, another 8 % of oil recovery was gained. As a result, combined the LSWF and PPG increased oil recovery by 18%. LSWF can increase only displacement efficiency but has little or no effect on sweep efficiency, while particle gels can plug fractures or in high-permeable channels to improve sweep efficiency but have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improve both the displacement and the sweep efficiency.

Sequential injection mode of high-salinity/low-salinity water in sandstone reservoirs: oil recovery and surface reactivity tests

“…On the other hand, incremental oil recovery was ascribed to the decreasing injection water salinity. Alhuraishawy et al (2016) examined several LS water salinities (1, 0.1, and 0.01% NaCl), which produced oil recovery of 34, 40, and 45%, respectively. Brady et al (2015) classify the pH during LS flooding and the effect of low-salinity waterflooding into three categories: (1) pH < 5, because the low positive charge of oil to kaolinite means that the LSW can weaken oil's affinity toward kaolinite; (2) pH 5-6, which is the strongest LS water effect due to the ability of LS water to convert the interactional forces to cause repulsion between oil and kaolinite.…”

Determination of Swelling Behavior and Mechanical and Thermal Resistance of Acrylamide–Acrylic Acid Copolymers under High Pressures and Temperatures

“…Therefore, the major challenge in the gelant injection process is the uncertainty in its gelation time. The conversion of the gelant into the gel before it reaches target formation or gelant dilution in contact with water fails the gelant performance . Although the gelants have less mechanical strength, PPGs are resistant to all types of saline solutions with high concentrations and have good thermal and mechanical resistance. − Therefore, scientific research studies confirmed that the performance of PPGs was more prosperous than that of in situ gels in preventing excess water production from oil reservoirs. − …”