Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs

Abstract

Enhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions. Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ions at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery. The objective of the work presented here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92 °C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO42− is lower in the smart water, the occurrence of SO42− as anhydrite in carbonates may be sufficient to stimulate a similar reaction between the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system. Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO42−, Mg2+ and Ca2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.

Carbonated Water Injection for Enhanced Oil Recovery and CO2 Geosequestration in Different CO2 Repositories: A Review of Physicochemical Processes and Recent Advances

“…Superscript “ α ”: Ultimate recovery factor; the incremental oil recovery presented is with reference to the ultimate recovery factor recorded for waterflooding. Superscripts “ β ”, “ γ ”, and “ ζ ”: Study adapted experimental conditions for simulation from refs , , and , respectively. CO 2 storage represents the percentage of the dissolved CO 2 in injected CW that was stored after CWI.…”

Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

“…This simulation study was based on a coreflooding experiment by Gachuz-Muro and Sohrabi [18]. Specifically, the numerical 1-dimensional model describes the limestone core, which was discretized into 20 grid blocks.…”

“…Historymatching was performed through CMOST to assess experimental oil production [18]. The injection scenario was designed with successive SWI following LSWI.…”

New Insights into the Application of a Magnetic Field to Enhance Oil Recovery from Oil-Wet Carbonate Reservoirs

“…This condition becomes worse if natural fractures exist in the rock system where water is diverted to the fractures, hence bypassing significant oil volumes behind the water front. To solve this issue, several EOR methods such as smart water flooding, low salinity water flooding, water-alternating gas injection, polymer flooding, surfactant flooding and the use of nanoparticles may be adopted to overcome problems of water imbibition into the rock matrix [6][7][8][9][10][11][12][13][14] . Long payback periods, costly water treatment, the compatibility of water with rock surfaces, and low injectivity are among the problems encountered when using these methods.…”