Wellbore (in)stability while drilling shales is a major problem for the petroleum industry. The drilling of a hole into a formation in equilibrium induces stress concentration around the borehole. A physiochemical interaction occurs if parameters like hydraulic and chemical potential of the water-basedrilling fluid (WBM) and shale formation fluid are not in equilibrium. Differences in these parameters influence the borehole stress-state and shale mechanical strength. This work presents the results of a laboratory study conducted to observe changes in pore pressure and acoustic and dynamic mechanical properties of Pierre II shale exposed to WBMs under simulated geo-static stress conditions. The experiments show that shale pore pressure is altered as a function of WBM exposure. These alterations can also be observed with simultaneous measurements of shale acoustic velocities. Results from such tests will aid in the diagnosis of logging-whiledrilling (LWD) wellbore (in)stability problems, which is the long-term objective.
Shales are fine-grained sedimentary rocks composed of clay, silt and in some cases fine sands. In the hydrocarbon drilling industry and for the purpose of this discussion, shale will be termed as an ill-defined heterogeneous argillaceous material ranging from the relatively weak clay-rich gumbo to highly cemented shaly siltstone, with the common characteristic being of formations with extremely low permeability that contain clay minerals.
Shales make up over 75 percent of drilled formations and cause over 90 percent of wellbore instability problems. The drilling of shale can result in a variety of problems ranging from washout to complete collapse of hole. More typically, drilling problems in shales are experienced as bit bailing, sloughing, or creep. (In)stability in shales is a continuing problem that results in substantial annual expenditure by the petroleum industry -half a billion dollars per year according to conservativestimates.
A drilling fluid system (drilling mud) consists of different solid and fluid components, with different components added to the fluid to improve performance. Main functions of a drilling fluid include the removal of rock material during drilling, imparting hydraulic support to the borehole to ensure stability, providing lubrication to reduce friction between the borehole surface and drillpipe, cooling the drill bit, etc. In the past, oil-based drilling muds (OBM) have been the system of choice for difficult drilling. Their application has been typically justified on the basis of borehole stability, thermal stability, fluid loss, lubricity, etc. As environmental concerns restrict the use of oil-based muds, the petroleum-service industry must provide innovative means to obtain OBM performance without negatively impacting the environment. Water-based drilling fluids (WBM) are attractive replacements from a direct cost viewpoint. But, conventional WBM systems have failed to meet key performance measures met with OBMs, especially while drilling high-angle, extended-reach well trajectories going through water-sensitive shale formations.
Past efforts to develop improved WBM for shale drilling have been hampered by a limited understanding of the drilling fluid/shale interaction phenomenon. This limited understanding has resulted in drilling fluids designed with inadequately optimized properties that are required to preventhe onset of borehole instability problems. Historically, wellbore (in)stability problems have been approached on a trial-and-error basis, going through a costly multiwell learning curve before arriving at reasonable solutions for optimized operations and systems. Recent studies (Mody & Hale 19
