Nine capillary constrained pore facies have been used to characterize the static rock types of the Minagish Oolite reservoir. However, this classification resulted poor history match on dynamic platform. An in-depth review indicated that two representative textural facies - connected vuggy limestone and fractured limestone - were not captured in the model due to either non-availability of suitable plug samples or respective bed thickness below log resolution. To resolve this issue, high resolution X-ray tomographic whole core data was generated in order to capture continuous pore network records along a 337ft core section.

Using CT based pore typing, six representative dynamic rock types were created with 10 cm vertical resolution. Out of these, two are vug/fracture dominated high permeability type and three are matrix pore dominated rock types. One is tight and non-reservoir facies. The high-permeability connected vuggy or fractured limestone samples show a wide range of pore size. Under weakly oil-wet conditions, the relative permeabilities of these rock types indicate unfavorable waterflood performance and only the oil from the vugs or fractures could be recovered in a full field dynamic setting.

In case of grainstones with separate vug porosity, the non-connected vugs are connected through the macropore system. After drainage of the macropore and vugs, the micropores get invaded, which contributes well to the changes in saturation profile. In fractured limestone, in particular, the connected fractures control the fluid flow behavior, which has extremely low waterflood relative permeability cross-over saturation of 0.11. This indicates a very unfavorable oil recovery where essentially only the oil in the fractures can be displaced.

Wettability variations from strongly oil-wet to mixed-wet conditions had little impact on likely recovery and the overall assessment of waterflood behavior. The scanning curves, representing waterflooding a transition zone, again displayed similar behavior, in that the flow was still controlled by the preferential displacement of oil from the larger connected pore space.

High permeability vuggy limestones and low permeability mudstones, when captured within the dynamic model provide better history match for the last 60 years of production and thus, improved production forecasts for upcoming wells. Identification of perforation intervals avoiding the high permeability zones, selective plug back, choke back in production wells and deciding the rate and suitable intervals for injection are some of the important tools used for well-based production optimization.

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