Increasing energy demand coupled with the production decline in traditional hydrocarbon resources poses one of the main challenges for the oil industry. There are not many feasible solutions with current technologies to meet the energy demand. One of the proven technologies to increase the recovery is the gas injection EOR (enhanced oil recovery/enhanced gas recovery. During the last decade there is definitely an upward trend in gas injection processes (Oil&Gas Journal, 2014). As we are facing more and more complex reservoir-fluid systems, there is an increasing requirement for new, generally more complex, dynamic modelling capabilities. Several simplifying assumptions that were appropriate for the modelling of conventional oil and gas reservoirs are not always valid for the more complex fields. One of these assumptions is the absence of component transfer between the aqueous phase and the hydrocarbon phases. A related assumption is the absence of chemical interactions between fluids and reservoir rock.

This paper shows how these complex processes have been included in a general purpose reservoir simulator in a robust and numerically efficient way. Currently, there are two approaches, (1) sequential calls to the flow solver and the geochemical solver (i.e. explicit coupling); (2) incorporation of the geochemical equations into the flow solver (i.e. fully implicit coupling). However, the first approach has an intrinsic drawback of not guaranteeing consistency of calculated dissolved gas between the flow part and the geochemical reaction part. The second approach is inherently too computationally expensive, limiting the number of reactions and number of species that can be part of the simulations.

Our new approach is to ensure consistency of the calculated gas solubility between flow and geochemical solvers as in a fully implicit scheme while achieving computational efficiency as in the explicit coupling scheme. The coupling scheme to the geochemical solver (for which the open source code PHREEQC is used) is explicit, but by extracting suitable parameters after every timestep, the partitioning of components between the aqueous phase and gas/oil phase(s), including evaporation of H2O, can be handled fully implicitly within the flow solver. The simulator runs in Equation of State mode for gas and oil components that can transfer between the gas/oil and the brine. Chemical components that can only reside in the brine (or the reservoir rock) are transported explicitly. In this way the number of components that need to be solved fully implicitly during one timestep is kept low. The approach is applicable not only to gas-water systems but also to oil-water (and gas-oil-water) systems. We show how the phase partitioning results compare favourably against experimental data, and illustrate the dynamic modelling approach on a case example.

The potential application area of this new methodology is very broad, and includes modelling of EOR methods (e.g. water-oil-rock partitioning of chemicals); CO2 and sour gas sequestration (e.g. solubility and mineral trapping; dry out problems); screening the unexpected scenario of leakage of gas components into groundwater (e.g. in the context of shale gas development); and some aspects of water flooding (e.g. reservoir souring; water flooding in a sour oil reservoir).

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