Laboratory measurements of the relative permeability of cataclastic fault rocks: An important consideration for production simulation modelling

It is becoming increasingly common practice to model the impact of faults on fluid flow within petroleum reservoirs by applying transmissibility multipliers, calculated from the single-phase permeability of fault rocks, to the grid-blocks adjacent to faults in production simulations. The multi-phase flow properties (e.g. relative permeability and capillary pressure) of fault rocks are not considered because special core analysis has never previously been conducted on fault rock samples. Here, we partially fill this knowledge gap by presenting data from the first experiments that have measured the gas relative permeability (krg) of cataclastic fault rocks. The cataclastic faults were collected from an outcrop of Permo-Triassic sandstone in the Moray Firth, Scotland; the fault rocks are similar to those found within Rotliegend gas reservoirs in the UK southern North Sea. The relative permeability measurements were made using a gas pulse-decay technique on samples whose water saturation was varied using vapour chambers. The measurements indicate that if the same fault rocks were present in gas reservoirs from the southern Permian Basin they would have krg values of <0.02. Failure to take into account relative permeability effects could therefore lead to an overestimation of the transmissibility of faults within gas reservoirs by several orders of magnitude. Incorporation of these new results into a simplified production simulation model can explain the pressure evolution from a compartmentalised Rotliegend gas reservoir from the southern North Sea, offshore Netherlands, which could not easily be explained using only single-phase permeability data from fault rocks.