Faced with the challenge to generate relative permeability data for a complex reservoir management scenario in an unconsolidated heavy oil reservoir, a SCAL study was devised which focused on measurements that would provide tangible benefits to the operator. The initial guideline required oil-water-gas relative permeability on both oil leg and gas cap core, with no definition of the permutations possible within this remit. By analysis of the possible imbibition and drainage scenarios that might occur in the reservoir and the significance of these processes on final oil recovery, a focused workscope providing maximum value was developed. This saved the time and cost of measuring superfluous data and ensured that data relevant to field management decisions were not missed. Together with a description of the above analysis, this paper describes the experimental details of reservoir condition water and oil floods in oil leg and gas cap core, with in-situ saturation monitoring. The study used composite cores flooded to Swi against porous plates and with wettability restored in live oil. Water floods were conducted at reservoir advance rates and additional bumped rates. Systematic discrepancies between saturations derived from mass balance and in-situ saturation during water flood were seen. It is postulated that mass balance was erroneous due to hold up of oil in the rig pipework, an effect that would occur to some extent in all core floods, but accentuated by the high viscosity of the oil in this study. Capillary pressure end effects were identified from the in-situ data and proprietary core flood simulation methods were used to correct the relative permeabilities for such effects. Quite significant corrections were made to the relative permeability curves by core flood simulation compared to the JBN derived curves. Important reservoir management decisions are based on SCAL measurements. In this case water/oil relative permeability data had been measured on the same core in an earlier study eight years previously. This previous study did not benefit from in-situ saturation monitoring nor core flood simulation and so there was uncertainty in the measured relative permeability data. The present study, using “modern” techniques, has given the operator increased confidence in the relative permeability data underpinning reservoir management decisions, along with an associated reduction in risk.