To counter the consequences of the wellbore instability problems, a thorough analysis of the borehole conditions is performed throughout the entire life-cycle of a hydrocarbon well from planning during the early stages to completion and production. The analysis comprises the following: first, a rigorous understanding of the rock properties e.g. geochemistry and geomechanics mainly the stress magnitudes and rock strength. Second, the mud properties and the entailed interactions with the formation. For instance, numerous borehole failures in laminated rocks have been attributed to the interaction of the drilling/fracturing fluid with the layered-matrix e.g. interaction of water-based-mud with reactive clay minerals.
This paper focuses on the impacts of the pore fluids redistribution on wellbore stability in organic rich carbonate rocks. The experimental method consisted of measuring the Nuclear-Magnetic-Resonance transverse relaxation time (NMR T2) on samples saturated by spontaneous imbibition of oil and brine. The wellbore stability was investigated by analyzing the changes in the NMR T2 distribution of each sample after imbibition sequences. The obtained results demonstrated the elevated impacts the wettability and pore structure characteristics on the spatial distribution of the fluids in these rocks. The type of clay content in the bedding planes and its consequent interaction with the drilling mud was identified as a potential driver of the rock instability problems. The discrepancies in the wetting traits were magnified by the presence of fractures that enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space.