Abstract
Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.
Highlights
Reservoir rock in naturally fractured oil reservoirs consists of two regions with different permeabilities, namely matrix blocks and the fracture network
At each salinity level, with increasing concentration of divalent ions in the aqueous phase, the brine/oil interfacial tension (IFT) decreases. This IFT reduction could be attributed to the higher tendency of natural surfactant molecules in crude oil to transfer into the oil/brine interface at higher salinities and at higher concentrations of divalent ions when the total salinity is constant (Lashkarbolooki et al 2014a, b)
To discern the individual effect of Total dissolved solids (TDS) and brine composition on wettability alteration index (WAI), a factorial analysis of variance was performed. p values of 6.01 × 10−13 and 4.42 × 10−4 were obtained for the solution type and TDS, respectively
Summary
Reservoir rock in naturally fractured oil reservoirs consists of two regions with different permeabilities, namely matrix blocks and the fracture network Oil recovery in these reservoirs strongly depends on the interaction between high conductive fractures and low conductive matrix blocks (Nelson 2001; Haugen 2010; Sahimi 2011). Preferential flow of water through the fracture network causes a limited differential pressure across the reservoir that results in weak viscous forces for oil production. This leads to poor sweep efficiency and low oil recovery (Guo et al 1998; Narr et al 2006; Seyyedi and Sohrabi 2015). The two other forces, i.e., gravity and capillary, could be effective depending on the properties of the rock and fluids (i.e., the injection water and the reservoir oil) such as wettability of the rock, water/oil IFT, and the density difference between the displacing and displaced fluids
Sign-in/Register to view highlights & summary Talk to us
Join us for a 30 min session where you can share your feedback and ask us any queries you have
Schedule a callDisclaimer: All third-party content on this website/platform is and will remain the property of their respective owners and is provided on "as is" basis without any warranties, express or implied. Use of third-party content does not indicate any affiliation, sponsorship with or endorsement by them. Any references to third-party content is to identify the corresponding services and shall be considered fair use under The CopyrightLaw.
