Wettability and Oil Recovery by Imbibition and Viscous Displacement from Fractured and Heterogeneous Carbonates

Abstract

About one-half of U.S. oil reserves are held in carbonate formations. The remaining oil in carbonate reservoirs is regarded as the major domestic target for improved oil recovery. Carbonate reservoirs are often fractured and have great complexity even at the core scale. Formation evaluation and prediction is often subject to great uncertainty. This study addresses quantification of crude oil/brine/rock interactions and the impact of reservoir heterogeneity on oil recovery by spontaneous imbibition and viscous displacement from pore to field scale.Wettability-alteration characteristics of crude oils were measured at calcite and dolomite surfaces and related to the properties of the crude oils through asphaltene content, acid and base numbers, and refractive index. Oil recovery was investigated for a selection of limestones and dolomites that cover over three orders of magnitude in permeability and a factor of four variation in porosity. Wettability control was achieved by adsorption from crude oils obtained from producing carbonate reservoirs. The induced wettability states were compared with those measured for reservoir cores. The prepared cores were used to investigate oil recovery by spontaneous imbibition and viscous displacement. The results of imbibition tests were used in wettability characterization and to develop mass transfer functions for application in reservoir simulation of fractured carbonates. Studies of viscous displacement in carbonates focused on the unexpected but repeatedly observed sensitivity of oil recovery to injection rate. The main variables were pore structure, mobility ratio, and wettability. The potential for improved oil recovery from rate-sensitive carbonate reservoirs by increased injection pressure, increased injectivity, decreased well spacing or reduction of interfacial tension was evaluated. Table A2. Contact angles on cleaved calcite after aging in crude oil (initially dry or wet with the same aqueous phase as that used to float off bulk oil)…………………………53 Table 2.1 Synthetic brine composition…………………………………………………..87 Table 2.2 Selected properties of crude oil samples………………………………………87 Table 2.3 Gambier and Edwards (GC) cores tested for the effect of initial water saturation. Table 2.4 Edwards (GC) cores tested for the effect of aging time for Cottonwood crude oil………………………………………………………………………………………...88 Table 2.5 Gambier and Edwards (GC) MXW-F cores tested for wetting stability and the effect of oil phase viscosity …………………………………………………………89 Table 3.1 Synthetic brine composition…………………………………………………104 Table 3.2 Edwards (GC) cores tested with different mineral oil viscosities…………...105 Table 3.3 Edwards (GC) cores tested for the effect of variation in core length (µ o = 3.8cP). Fig. 1.10 AFM image of calcite exposed first to (0.1M NaCl) brine then aged for 2 days and 21 days in E-1XD-00 crude oil (deflection image in water)………………………..37 Fig. 1.11 AFM image of calcite exposed first to (0.1M NaCl) brine then aged for 2 days and 21 days in Tensleep crude oil (deflection image...

Persistent Homology as a Heterogeneity Metric for Predicting Pore Size Change in Dissolving Carbonates

“…Much of the pore space is moldic, having formed through the preferential dissolution of fossil pieces. This contributes to the overall complexity of the pore network (Morrow & Buckley, 2006).…”

Impact of engineered water in modulating the wettability of oil–brine–rock system for improved oil recovery

“…McGuire et al [ 2 ] identified brine solutions with salt concentrations below 5000 ppm as optimal for achieving up to 19% additional oil recovery. Morrow and Buckley [ 3 ] experimented with using various crude oils acquired from different reservoirs, considering asphaltenes content and acidic/basic type to comprehend wettability alteration of the rock surface. The authors successfully controlled wettability through different crude oil compositions.…”