Secondary oil recovery projects in naturally fractured carbonate reservoirs (NFR) often introduce uncertainties and challenges that are not common to conventional waterflood. The recovery mechanism in NFRs relies on ability of fracture network to deliver enough injected fluid to the matrix, as well as rate and magnitude of capillary interactions within the matrix rock, during which hydrocarbon displacement occurs. The imbibition measurements can be performed in the lab using core samples, but due to reservoir heterogeneity, certain limitation of the lab equipment and quality of the core material, scalability of the core results to a reservoir model can be challenging.

This paper describes the design, execution and evaluation of the Log-Soak-Log (LSL) pilot test conducted in a giant naturally fractured carbonate reservoir with tight matrix in Western Kazakhstan, where repeatable and reliable measurements of water saturation change were achieved across large intervals (tens of meters) using a time-lapsed pulse neutron logging technique. Periodic measurements provided valuable observations of dynamic change of saturation and fluid level over time and allowed estimation of the rate and magnitude of imbibition in the slope margins, depositional settings and rock types of interest. Incorporation of the LSL results into reservoir models validated the ranges of water-oil relative permeability curves, residual oil saturation to water, irreducible water saturation, and capillary pressure assumptions. This validation constrained key subsurface uncertainty and updated oil recovery forecast in Improved Oil Recovery (IOR) waterflood project.


As part of the long-term strategy for Tengiz and Korolev fields, the IOR team has been evaluating alternatives to maximize recovery, considering that significant portion of the oil in place is stored in the tight carbonate matrix. These reserves cannot be accessed through primary depletion and require a different recovery mechanism. Preliminary simulations show waterflooding as a promising alternative, however, several key uncertainties and risks were identified.

While the fracture network is the dominant control on reservoir connectivity and well deliverability, the majority of hydrocarbon in place is stored in tight matrix rock. Incremental recovery from waterflooding an NFR will significantly depend on the rate and magnitude of water imbibition into the matrix. If it is found that injected water only displaces oil in the fractures and leaves matrix oil unrecovered, the value of the waterflood diminishes as incremental recovery is limited to a much smaller fracture pore volume. Therefore, oil recovery from the tight matrix has been identified as one of the key subsurface uncertainties that will drive economic performance of the IOR waterflood project.

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