Barium sulfate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing waterflooding. Chemical enhanced oil recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulfate coproduction behavior, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer, surfactant, and surfactant/polymer (SP) flooding cEOR processes. To aid the cEOR economic decision, assessment of the impact of cEOR flooding type on both scale management and oil recovery is performed. Reservoir simulation has been used in this study, employing homogenous and heterogeneous two-dimensional (2D) areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of anionic surfactant and partially hydrolyzed polyacrylamide (HPAM) polymer [e.g., oil/water interfacial tension (IFT), IFT, polymer viscosity, and SP adsorption]. Assessment is made of the minimum inhibitor concentration (MIC) required to control the scale that is predicted to occur due to the changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor (SI) during squeeze treatments in the production wells is modeled. The high viscosity and more stable HPAM polymer slug reduces the mixing between the injected and the formation brines, especially with low-salinity low-sulfate (SO24- ) make-up brine, reducing BaSO4 scale precipitation in the formation, delaying and reducing the potential scale risk in the producer wellbore compared to normal waterflooding. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion (ME) phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the waterflooding case, depending on the IFT, ME phase type, the injected salinity, and sulfate concentration. In SP flooding, low-salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the injection brine salinity, SO24- concentration, and changing brine composition due to ion reactions affects the produced water rates, the number of required squeeze treatments and MIC values over time. This, then, impacts the inhibitor retention and release, which influences the treatment volumes and cost required to control scale over field life. Considering the economic impact of cEOR flood type on both oil recovery and scale management, low-salinity SP flooding is demonstrated to be the most viable option, showing the highest positive net present value (NPV). The study shows that barium and sulfate coproduction and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities) on the oil/water IFT, on the level of chemical adsorption, and on the selected brine salinity. The severity of the scale risk is also impacted by the flood techniques used, with the extent of reservoir reactions having an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.
ASJC Scopus subject areas
- Fuel Technology
- Energy Engineering and Power Technology