Dynamic reservoir simulation models are used to predict reservoir performance, and to forecast production and ultimate recovery. Such simulation models are also used to match historic production. The success of such models depends critically on optimal gridding, particularly vertical definition and the choice of rock parameters, especially relative permeability.

This paper compares simulation results as a function of utilising alternative relative permeability relationships as simulation input:

  1. Unaltered laboratory data

  2. Modified Brooks-Corey (MBC) relationships derived by fitting lab data (Lake,1989), including MBC and Sor extrapolation (Stiles, 1994)

  3. Relationships based on the more recently derived two-phase Modified Carman-Kozeny (2pMCK) formulation (Behrenbruch and Goda, 2006)

For maximum clarity, comparisons are made on a single layer basis but covering a range of permeability and porosity values, and capillary pressure relationships are based on modelled lab data using the Modified Carman-Kozeny Purcell (MCKP) model (Goda and Behrenbruch, 2011).

Study results show that very different production responses may be realised, depending on the validity of original lab data and choice of modelled relationships deployed. It is concluded that the use of the 2pMCK model in combination with auxiliary investigative tools is optimal in rationalising lab data. Some tested plugs show the influence of heterogeneity, as well as procedural shortcomings and even plug failure. It is shown how such test results can be identified by the 2pMCK model and then optimally modified. In comparison with the MBC model, it is also evident that the use of Corey coefficients may at times be too prescriptive, and even flawed when it is assumed that exponents are only a function of wettability rather than also considering plug heterogeneity and possible lab issues. Relative permeability and capillary pressure data sets are taken from lab results for the Laminaria and Corallina fields, Timor Sea.

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