Direct Strength Measurements of Shale Interaction with Drilling Fluids

Abstract Athough a crucial factor in drilling, the effects of the interaction between drilling fluids and shales on rock strength have not been directly studied in a laboratory setting. Instead, indirect methods, such as monitoring of shale swelling behavior, penetrometer tests, shale dispersion tests, etc., have commonly been used to gauge "relative" shale strength. In the results presented here, fluid interaction with two very different shales is reported and interpreted. One shale, from deepwater offshore West Africa, was tested with invert emulsion fluids (IEF) having varying water phase salinities. The second shale, taken from land drilling in Oklahoma, was tested with IEF and brine-based drilling fluids. The shale strengths were directly measured as functions of fluid chemistry and exposure volume using a specially-designed testing device located at the Poromechanics Institute (PMI) of the University of Oklahoma. IEF having differing water phase salinity levels (ranging from 50,000 to 350,000 ppm calcium chloride) were first tested to determine changes in rock strength with exposure volume. Rock cohesive strengths and internal friction angles were then calculated, and the results showed changes in rock strength as a function of water phase salinity and exposure time. Additionally, the Oklahoma shale samples were exposed to calcium chloride brines having the same salinity levels (50,000 and 350,000 ppm) as the IEF, and the resulting effects on rock strength as a function of fluid chemistry and time were measured and compared to the IEF results. The results clearly show that drilling fluid chemistry and exposure time have direct bearing on shale strength. This study should be interpreted as only the beginning of study of fluid interaction with shale: there is much to be learned here, yet much more in the future. Introduction Most of the formations drilled for oil and gas are clay-bearing shales, and problems in these formations account for the bulk of wellbore instability problems. When exposed to drilling fluids, formation shales can become unstable, a process that if left unchecked can lead to wellbore failure. Failure mechanisms generally fall into the following categories:MechanicalChemicalHydraulic Formation failure can lead to significant expense in the loss of a well or an interval, in time, and in materials used to correct or deal with ongoing wellbore stability issues. Several researchers have described these processes in general 1–3. In particular, some researchers have studied the transport of water in shales 4–6 as a key factor in producing mechanical failure. Similarly, many wellbore stability models have been constructed in which the key failure mechanisms of shale have been coupled to give predictions for compressive shear as well as tensile failure 7–10. Most recently, the complete models taking into account the three-dimensional wellbore geometry and the effects of time have also been coupled with earlier models 11 to give a poromechanical analysis of the generation/diffusion of pore pressure in shales in contact with drilling fluids 12,13. The constant development of increasingly sophisticated wellbore stability models promises to further expand and deepen our understanding of shale instability problems 14.