Stressed Shale Drilling Strategy—Water Activity Design Improves Drilling Performance

Abstract Non-aqueous drilling fluids are often chosen to drill troublesome shale formations in an effort to minimize wellbore instability problems. However, Gulf of Mexico (GoM) experience has indicated that when drilling in highly faulted areas, oil- and synthetic-based fluids do not always prevent wellbore destabilization. This is evidenced by wellbore collapse, and the resulting difficulty with holecleaning, tripping, logging and casing running. It is known that the chemical, physical, and mechanical effects resulting from the interaction between the drilling fluid and the formation may degrade the stability of the borehole in the already weakened and stressed fault interval. Commonly, the practice has been to increase the drilling fluid salt content to enhance the borehole stability. The perception that low drilling fluid water activity is beneficial to wellbore stability is one that lends itself to a needed revision. A detailed laboratory investigation using preserved shale core and drilling information have confirmed that the water activity of drilling fluids is often much lower than necessary. This study has shown that when drilling faulted or fractured shale, the correct, not higher salt content in drilling fluids will reduce wellbore collapse problems and improve drilling performance. A laboratory method, which allows the quantitative measurement of water and ion movement during shale/mud interactions, combined with geological information, optimizes the salinity design of drilling fluid, which controls water and ion movement. Laboratory data and field cases from GoM drilling support the concept of optimum salinity to enhance borehole stability in naturally fractured formations as part of the stressed shale drilling strategy to improve drilling performance.