Abstract

Natural gas production from organic shale is one of the most rapidly expanding trends in North America's onshore oil and gas exploration and production today. In some areas, this has included bringing drilling and production to regions that have seen little or no activity in the past. Advances in horizontal drilling technology and hydraulic fracturing have made shale gas/oil production economically viable.

Haynesville and Marcellus shale plays are among the most active shale plays in the United States. The potential for production from these shale plays, coupled with other unconventional shale gas plays, is predicted to contribute significantly to North America's energy outlook. Although drilling experience has been gained since the development of these shale plays, we are still in the early stages of the learning curve for shale gas drilling. Due to its proven performance parametrics and advantages, invert emulsion drilling fluid, is often the preferred drilling fluid or "mud" used to drill the horizontal sections of the wells in Haynesville and Marcellus shale plays. However, water-based drilling fluid (WBM) has also been used and usage is increasing in horizontal sections of the Marcellus wells due to its technologically enhanced performance and environmental advantages. A comparative analysis was performed between invert-emulsion-based and water-based drilling fluids used in Haynesville and Marcellus shale plays to assess their performances and to identify the key challenges with both fluid types. The analyses include mud chemistry, drilling days, mud weight and well architectures such as hole sizes and casing sizes as well as depths of the casing shoe. A statistical analysis of drilling performance (P10, P50, and P90) was also performed to evaluate drilling days for wells of various depths of different operators over the past few years with different fluid types.

The analysis of 238 horizontal wells drilled in Haynesville shale play between 2006 and early 2011 shows that there is a continuous improvement in drilling performance over the years. This improvement is more pronounced in the wells drilled with oil-based drilling fluids (OBM). The analysis also shows that some operators drill the wells of similar depths much faster than others. Seepage losses and controllable kicks were also identified as some of the key issues in both Haynesville and Marcellus shale drilling. Although, laboratory results show that the clay content and reactivity of both Haynesville and Marcellus shale are very close to each other, the same WBM systems have shown much better performance in Marcellus shale drilling than in Haynesville shale play. The effects of high temperature and high pressure of the Haynesville shale formation on inhibition capabilities of water-based drilling fluids are among the key factors that have limited the performance of WBM in Haynesville shale drilling. Higher well depths and the increased drilling days in Haynesville shale play result in much more exposure time of the wellbores to drilling fluids, and are the key factors that resulted poor performance with WBM systems.

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