Experiments performed on core plugs and field tests that have been carried out during the last decade have demonstrated the impact of water chemistry on the final oil recovery. On the Norwegian Continental Shelf seawater is used in secondary recovery to displace oil from the reservoirs with temperatures of ~ 50-150°C. Most Norwegian reservoirs are initially hotter than 50°C, but portions of some of these reservoirs have been cooled down to 50°C or less due to water injection. In nature, fluids are in equilibrium with the rock if the temperature is above 70°C, and consequently, even if the pore water was originally sea water (usually it is more saline), the chemistry of the aqueous pore fluid in the reservoir (formation water) now differs from the chemical composition of seawater. When seawater, or any fluid with a different chemical composition than the formation water, is injected into the reservoir, the reservoir rock will be altered. The alteration will entail physical changes (dissolution/precipitation of minerals) and also change in surface chemistry (surface charge, zeta potential). These changes can affect the amount and rate of water imbibition (and oil expulsion), change the rate of compaction (e.g. Ekofisk and Valhall field), and exacerbate or moderate scaling problems in production wells.
In this project, we propose to quantify the impact of injected water chemistry on the recovery of oil by building a streamline model for the chemical changes that occur as the injected fluid moves from an injection to a production well. The main focus will be on fractured chalk reservoirs, such as the Ekofisk and Valhall reservoirs, however the methods developed will be general. The chemical changes will be calculated assuming that the flow occurs in flow zones (fractures or permeable strata). Along the flow zone the chemistry of the water changes when the chemical components diffuse into the surrounding matrix rock and react with the matrix rock minerals, or when chemicals in the matrix pores diffuse into the flow zone. The imbibition of water within the flow zone into the matrix, and the expulsion of oil from the matrix into the flow zone, will also be considered.
As the chemistry of the fluid in the matrix changes, wettability, mineral dissolution and precipitation, and the permeability of the matrix will change. Proposed pore-scale Lattice Boltzmann simulations will quantify these changes on the pore scale. The pore-scale results will then be incorporated into a core-scale model of the multiphase exchange between flow zone and matrix fluids. Finally the core-scale model will be incorporated into a streamline model. This coupled model will simulate the chemical evolution along the streamline as well as its evolving interaction with the matrix, and water imbibition from, and oil expulsion into, the flow zone. The pore models will be tested against the observed distribution of oil and water in pore structures from cryo SEM images. The core models will be tested against side 1/10 Optimizing Water Chemistry for Enhanced Oil Recovery spontaneous and forced imbibition experiments. The final product of the combined pore, core, and streamline model will be a set of theoretical streamline model capable of conducting predictions of how changes in injected water chemistry impacts oil recovery. In particular, the effect of adding sulfate to the injected water will be studied. The methods developed in this project will also give basic understanding of chemical water weakening and production well scaling.
