Injection Water Compatibility Study and Scale Prediction Analysis for a Low-Permeability Carbonate Reservoir Development Optimization

Abstract

Injection water-induced formation damage evaluation is considered critical in a low-permeability (2 md) oil reservoir development because of the potential bridging of narrow pore throats by in-situ scale precipitates. This problem can be mitigated with processed low-salinity water, albeit at significantly high capital expenditure associated with water processing facility that could erode the economic margin of the project. Laboratory fluid compatibility tests and software simulation were therefore conducted to appraise the risk of inorganic scale deposition during water injection in an undeveloped carbonate reservoir with high-salinity formation brine (TDS ~205 g/L). The laboratory experiments were initially carried out with both synthetic and actual field samples including formation water extracted from pressurized downhole fluid tester. Coreflood and fluid-fluid compatibility tests were carried out at estimated bottom-hole temperature of 150 °F and pressure of 1,000 psi. Comprehensive mixed-brine simulation software was also used to determine the inorganic scaling tendency expected with the use of seawater, produced water and diluted produced water for the planned injectors. The study identified an inherently high calcium sulfate risk associated with the planned seawater injection in the new reservoir while the highest combined inorganic scale precipitation was observed at approximately 1:1 ratio for the formation brine-seawater mixture. This paper discusses the laboratory fluid compatibility experiments and scale prediction analysis for different injection water utilization while providing an insight into the potential impact of scale risks associated with seawater injection in an onshore development reservoir with high divalent-salt content formation brine.

Mineral Scaling in Microchips: Effect of Substrate Wettability on CaCO3 Precipitation

“…Surface wettability plays an important role in the prevailing flow regimes during secondary flooding, affecting the displacement efficiency. , During oil recovery, enhanced oil recovery (EOR), CO 2 or gas storage, geothermal energy production, and membrane filtration processes, complex physicochemical processes take place including the deposition and growth of salts. In the case of oil production or gas storage, the insoluble salt-scale deposits may reduce local rock permeability or may result in tube clogging, − resulting in higher production costs or to the abandonment of drilled wells with large amounts of entrapped oil. When membranes are used for water and wastewater treatment, crystallization of CaCO 3 , phosphate, or other salts reduces their lifetime.…”