Waleed Alameri

Low-salinity Water-alternate-surfactant in Low-permeability Carbonate Reservoirs

Low-salinity water injected into carbonate cores, which have undergone sea-water injection, can produce additional oil more economically if a low-concentration non-ionic surfactant is added to the low-salinity water and injected as chase fluid. One major reason for the additional oil recovery is that low-concentration surfactant effectiveness favors the low-salinity environment. Several coreflooding, contact angle, and IFT experiments were performed to assess the proposed process. The core flooding sequence includes seawater, low-salinity water, and low-concentration non-ionic surfactant. However, for field application, we proposed low-salinity water-alternate-surfactant injection. The surfactant concentration in low-salinity water was 1,000 and 5,000 ppm. Phase behavior and cloud point measurements were conducted prior to surfactant injection. The core permeability is 0.5 to 1.5 md, and porosity ranges from 0.18 to 0.25. Cores were aged for eight weeks at reservoir pressure and temperature. The pendant drop oil-brine IFT and captive oil-droplet contact angle measurements were performed at variable brine salinity in the presence of surfactant. Seawater and low-salinity waterflooding corefloods yielded ultimate oil recoveries of up to 57 percent. Up to 10 percent additional oil recoveries was obtained from low-concentration non-ionic surfactant in low-salinity waterflood. With decreasing salinity, in presence of 1,000-ppm surfactant, favorable wettability alteration from intermediate-wet to water-wet was observed by contact angle measurements. Moreover, addition of small concentration of surfactant decreased the IFT and altered the wettability of several one-inch diameter, crude-aged, discs to water wet.

Matrix-Fracture Interface Cleanup Protocol for Tight Sandstone and Carbonate Reservoirs

In tight sandstone and carbonate reservoirs, the hydrocarbon recovery is mainly governed by the matrix- fracture interface mass transfer efficiency. To improve the matrix-fracture interface mass transfer in tight sandstone and carbonate reservoirs, we propose the following protocol to clean up the matrix-fracture interface and improve hydrocarbon production: (1) Inject one of the following – CO2 followed by anionic or non-ionic surfactant, Anionic or non-ionic surfactant followed by CO2, miscible or near miscible CO2 gas, low concentration anionic or non-ionic surfactant. (2) Repeat the process when another cycle of treatment is needed. The same procedure can be applied into injection well to improve injectivity. The proposed cleanup protocol improves production because – wettability alteration, reduction of IFT, swelling of the oil leading to lower viscosity, and molecular diffusion among other thermodynamic effects– all acting at the matrix-fracture interface. To assess the proposed matrix-facture interface clean up protocol, IFT and contact angle measurements that mimic the proposed processes were conducted. Favorable wettability alteration of tight carbonate and sandstone crude-aged cores and oil-brine IFT reduction were observed.

Experimental investigation of polymer flooding with low-salinity preconditioning of high temperature–high-salinity carbonate reservoir

Application of polymer flooding in high temperature–high salinity (HTHS) carbonate reservoirs is challenging due to lack of polymers that can withstand such harsh reservoir conditions. The traditional polymers are usually sensitive to high salinity, especially at high temperature. However, injection of low-salinity make-up brines may precondition high-salinity reservoirs before initiating polymer flooding which may reduce chemical degradation of polymer. This study aims to evaluate the effectiveness of a partially hydrolyzed polyacrylamide base polymer for mobility control application in a low-salinity preconditioned carbonate reservoir and hence on the improvement of oil recovery at HTHS carbonate reservoir. Core flooding experiments using unsteady-state technique were conducted on reservoir cores with permeability range of 10–100 mD. During each experiments, salinity of the make-up brines were changed to study the effect of preflush salinity and polymer flooding in HTHS reservoir. Oil production from water flooding for all the cases was found to be between 49 and 65%. Polymer helped to reduce the mobility ratio from 4.1 to less than 1 and additional 7–11% of oil was recovered from the remaining oil saturation after water flooding. Comparisons were also made between oil recovery results based on volumetric production and in situ saturation monitoring (ISSM) data, which were found to be matching. Additionally, the ISSM helped to understand the performances of fluids injected during oil recovery stages and captured front movement of the fluids at all time. Also, high capillary end effect was confirmed from the ISSM which may lead to underestimation of the oil recovery from water flooding in the absence of ISSM. Resistance factor and residual resistance factor were also calculated during all core flooding experiments and were found to be 7.0, 2.4, 36 and 3.7, 1.4, 8.9, respectively.