Wettability at the core and microscopic scales : alteration by low salinity brine and asphaltene




Chandrasekhar, Sriram

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Reservoir natural drive can recover about 10-20 % of the original oil in place (OOIP), after which waterflooding is implemented which itself recovers another 30-40 % of the oil. Thus, a large volume of oil is left behind to target with tertiary production strategies, but their efficiency strongly depends on reservoir wettability. Carbonate reservoirs hold approximately 60% of the world’s oil. Recent laboratory experiments have shown that specific injection brine compositions can recover extra oil by altering wettability of carbonate core samples. The mechanisms of this effect are investigated here at the core and microscopic scale. Single phase brine corefloods were conducted in reservoir limestone at high temperature, which reached steady state in 2 pore volumes of injection. Injecting seawater, sulfate-rich seawater, and ultra-dilute seawater showed preferential SO₄²⁻ retention. The limestone dissolved in all investigated brines, but to a larger extent during ultra-dilute seawater injection, though it was a slow process. Additional reactions were inferred from disproportional gas production compared to expected CO₂ (g) production from dissolution, and indicated the complexity of core mineralogy. The same brines were injected to measure oil recovery from the reservoir limestone, and also measure effluent ion concentrations. Formation brine produced 40 % OOIP and seawater recovered an incremental 7 % OOIP. Sulfate-rich seawater and ultra-dilute seawater showed higher oil recovery of 65-80 % OOIP in secondary and tertiary modes, but required many pore volumes injection (PVI). The experiments showed mild sulfate retention but mainly captured the dissolution effect, changing limestone from oil-wet to water-wet and recovering significant volumes of oil. The viability of the mechanism at distances far from the wellbore is questionable. Calcite plates were studied in different brine compositions using an Atomic Force Microscope (AFM), to understand carbonate surface reactivity and equilibrium adhesion force with an oil droplet. It was found that a combined dissolution/ion-exchange process controlled calcite wettability. Monitoring surface activity over a 25 μm² area showed equilibration times longer than 45 minutes between fresh calcite and calcite-equilibrated brine. The surface activity was significantly subdued under sulfate-rich seawater brine which was attributed to gypsum surface passivation, which partially explained the sulfate retention in corefloods. A colloidal probe functionalized with –COOH acid groups represented the oil droplet in adhesion tests. Adhesion forces were strong in high salinity brine because of thin electrical double layer and high charge screening. Adhesion was strongest in formation brine that contained divalent ions. Adhesion forces were significantly weaker for ultra-dilute brines, attributed to expanded electrical double layers and net negative calcite surface charge. Low adhesion was also observed for sulfate-rich seawater because of negative surface charge from gypsum passivation. High pH brine showed low adhesion if it was compositionally stable. At seawater ionic strength, varying the concentrations of potential determining ions, calcium and magnesium, did not produce low adhesion forces. This was because of an already thin electrical double layer due to higher ionic strength, and little surface charge change. Thus, calcite mineral wettability could be changed, from oil-wet to water-wet, using specific brine compositions. An adhesion force dataset was generated to validate calcite surface complexation models and show viability of the low salinity brine induced wettability alteration. About 30% of the global annual oil production comes from deep offshore reservoirs. Large overburden stresses, high pore pressures, and low rock permeability favor gas injection for tertiary oil recovery. However, injection of gases, e.g. CO₂, creates solubility issues with asphaltenes that cause chemical and mechanical problems in the formation. Precipitated asphaltene particles can adsorb on the rock and alter the wettability adversely for recovery efficiency. Plugging of some of the pore throats by precipitated asphaltenes can reduce permeability. Core wettability alteration was evaluated experimentally. CO₂ corefloods were conducted to displace dead and live oil and performance was analyzed by the oil recovery, effluent fluid density, near-infra red (NIR) spectroscopy, and gas chromatography profiles. The treated cores were subjected to Amott-Harvey wettability evaluation, and compared. CO₂ injection did not yield measureable changes because of asphaltene precipitation in limestone wettability or permeability for dead Middle East crude oil. Not all asphaltene precipitated out; experiments indicated presence of asphaltene even after gas mixture contact. Live GoM crude oil showed asphaltene phase instability between 5750 psi and 6400 psi for a GOR of 1200 scf/STB. Live GoM crude oil was immiscible with CO₂ for 5600 psi and below. Corefloods showed CO₂ miscibility at 6000 psi and higher pressure.


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