Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media.
A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F.
A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process.
In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study
Pore-Scale Simulation of Particle Flooding for Enhancing Oil Recovery