Application of Low Salinity Water Injection in Heavy Oil Carbonate Reservoirs

Abstract

Low Salinity Water Injection (LSWI) has received much attention recently as an Enhanced Oil Recovery (EOR) technique. Extensive research programs have been launched to investigate and identify positive effects of LSWI on oil recovery. Experiments have been performed on different formations and crude oils in order to identify the cause of wettability alteration, which is considered as the main reason for the observed additional oil recovery. The majority of the studies reported in the literature have been performed on light oils showing positive results, which represent a significant opportunity for these reservoirs. However, application of LSWI in heavy oils has received much less attention and poses a big challenge, especially in carbonate heavy oil reservoirs.Carbonate reservoirs are generally much more complex than their sandstone counterparts. Further difficulties arise when the reservoir is naturally fractured. These features as well as the oil-wet or mixed-wet conditions that dominate carbonate formations usually result in low recovery factors. The available data suggest that the ultimate recovery factor from these reservoirs is low and in the range of 25 to 45%, depending on the applied method. Although the most widely used method for heavy oil recovery is the thermal processes, non-thermal processes such as gas injection and smart fluids are gaining increasingly more interest amongst operators.In this paper, we present the results of an integrated experimental and simulation study performed in order to explore the potential of using low salinity water as an injection fluid for secondary and tertiary oil recovery from heavy oil carbonate reservoirs. Coreflood experiments were performed to derive measured relative permeability curves. This data were then used to numerically simulate the injection of low salinity water. A systematic sensitivity analysis was then performed to investigate the impact of reservoir parameters on the performance of LSWI in these reservoirs. The parameters considered included: reservoir thickness, well spacing, permeability, heterogeneity, and reservoir pressure. The numerical simulation results confirmed the high potential of LSWI for recovering heavy oils. Oil recoveries of up to 70% (OOIP) were predicted when LSWI was used as secondary recovery, which was consistent with the results from laboratory experiments. On the other hand, high salinity water injection just recovered less than 35%. LSWI as a tertiary recovery method also demonstrated high oil recovery which improves the economics of field applications of waterflooding as less water needs to be injected in the field for achieving the same oil recovery factor when low salinity water is used compared to high salinity water.

A review on low salinity waterflooding in carbonates: challenges and future perspective

“…Potential determining ions such as Ca 2+ , SO 4 2− and Mg 2+ have been demonstrated to have positive impact on final recovery of oil as these ions alter the surface chemistry of the carbonate surface and make it more water wet. In fact, injection of sulphate ions may result in scaling problems which is undesired (Romanuka et al 2012). Also, the size of Mg 2+ ions is much smaller compared to Ca 2+ ions, therefore substitution reaction may result in substantial reduction in mechanical strength of the rock.…”

“…Other ions such as borate (BO 3 3− ) and phosphate (PO 4 3− ) have been understood to have positive effect on final oil recovery and thus can be treated as PDIs. Only a few studies (Romanuka et al 2012;Webb et al 2005) have demonstrated the impact of using these ions as PDIs; however, more research needs to focus on other ions such borate and phosphate which can potentially be alternatives to calcium, sulphate, and magnesium ions.…”

“…Due to its reactive nature, SO 4 2− ions can result in scale precipitation. (Romanuka et al 2012) have rightly pointed out that injecting the low salinity brine with higher concentration of SO 4 2− ions in the formation that contains Barium and Strotium increases the potential of scale formation. This can result into plugging of pore spaces in the reservoir or plugging/choking inside a production tubing.…”

“…(Gomari et al 2006) studied the impact of potential determining ions, namely Mg 2+ and SO 4 2− , on calcite surface and found out that Mg 2+ has a greater impact on wettability alteration compared to SO 4 2− through mechanisms such as adsorption of magnesium as a hydrated ion on active site, and induction of surface reaction with surface Ca 2+ ions. (Romanuka et al 2012) suggested that high concentration of SO 4 2− ions in the injection brine can lead to potential scale formation in the production tubing, if the reservoir water contains barium and strontium. Thus, through imbibition studies they demonstrate that oil recovery can be increased through reducing the ionic strength of the injection brine.…”

“…Various mechanisms have been proposed which contribute to enhanced recovery from these rock types, which include wettability alteration, fines migration, pH change, interfacial tension (IFT) reduction, emulsion formation, electrostatic repulsion, etc. (Tang and Morrow 1999;Webb et al 2005;Strand et al 2006;Zhang and Morrow 2006a;Zhang et al 2007;Zhang et al 2007;Austad et al 2008;Ligthelm et al 2009;Hiorth et al 2010;Austad et al 2010;Yousef et al 2010;Romanuka et al 2012;Mahani et al2013;Al-Shalabi et al 2014;Heberling et al 2014;Mahani et al 2015;Jackson et al 2016;Alroudhan et al 2015). Although there are various mechanisms that have been researched to result in additional oil recovery, there has been a common understanding that the main mechanisms that contribute involve physical and chemical interactions between fluids and rock surface such as wettability alteration and/or IFT reduction.…”