Deepwater turbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sands vary in thickness from millimeter to meters in thickness. The reservoirs are highly permeable, but the silt and clay laminations affect the reservoir permeability in each layer, resulting in changes in the well productivity and sweep properties.

We illustrate the applications of NMR, borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology, the geometry, and the net producible fraction of these reservoirs:

  • We demonstrate that the partitioning of NMR T2 distribution is a robust method for calculating independent volumes of clay, silt and sand.

  • We present the experimental set-up and the application of a novel method to calculate the thin sand fraction of a laminated reservoir from NMR free fluid volume. The results of this method are compared to the sand counts from a high resolution borehole image and from core images. This comparison reveals the effect of the lamination geometry on the formation evaluation.

  • We illustrate the effects of thin silt and clay laminations on wireline formation tests, and on the productivity and flow profile of a production test. The dynamic reservoir information obtained from these measurements enables to understand the fluid flow behaviour and potential productivity in such a reservoir.

These techniques reduce the uncertainty of hydrocarbon volume and productivity computations in a highly laminated deepwater reservoir. The field example used in this paper is a turbidite sand from North West Borneo. The techniques demonstrated here are also applicable to the analysis of other categories of thinly bedded, shaly sand reservoirs.

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