Thinly laminated and silty deep-water reservoirs of offshore Malaysia have historically posed difficulties in formation evaluation due to complex log responses causing uncertainties in key petrophysical properties like porosity, water saturation, net pay and productivity. Moreover, compartmentalization of the reservoirs due to extensive faulting in this area increases the evaluation challenges.
Generally, thinly laminated reservoirs are evaluated either by high-resolution methods, including borehole imaging and whole core analysis; or bulk volumetric approaches, which utilize nuclear magnetic resonance (NMR) and suitable shaly sand saturation equations. Adding silt as an additional component requires a cautious combination of these two approaches. Furthermore, linking the petrophysical evaluation with depositional processes and structural settings using borehole image, acoustic log and formation pressure is key to the future development of the field. Lastly, securing clean formation fluid samples is crucial to design the production strategy.
Aforesaid complete dataset was acquired in a deep-water well of offshore Malaysia to assess hydrocarbon potential. While relatively higher resistivity distinguished potential hydrocarbon bearing zones, NMR-based irreducible water saturation was a crucial indicator of possible water-free hydrocarbon production from the silty zones with high water content. Net sand was accurately calculated from the high-resolution borehole image and compared with the standard petrophysical approach. Then, a detail analysis of formation dip, facies and paleo-current direction was performed on borehole image to recognize different depositional processes and structural settings. Formation pressure data was collected extensively to understand reservoir compartmentalization. While the testing zones were selected based on higher free fluid and higher resistivity anisotropy; the precise testing depths on sand laminae were guided by high-resolution borehole image. Later, low contamination downhole fluid samples were collected using focused sampling technique. 2D NMR method and real-time downhole analysis of optical absorbance, refractive indices, fluorescence, density, viscosity and sound speed were used to differentiate formation fluid from the OBM filtrate. The reservoirs were then evaluated integrating the petrophysical properties with the depositional process and structural settings to understand their long-term production potential.
This paper represented a case study of an integrated workflow of optimum data acquisition and evaluation of the thinly laminated sand-silt-clay sequence of deep-water reservoirs of offshore Malaysia. Effective and optimum integration of NMR, high-resolution borehole images, formation testing and sampling data provides the robust framework of this formation evaluation workflow to solve the complex petrophysical and geological uncertainties of these reservoirs.
