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Abstract
As an industry, we are still in the early stages of the learning curve for shale gas drilling although many shale gas wells have been drilled in recent years. Data from over one thousand wells drilled in the Maverick basin since 2003 were retrieved from an internal drilling database. Among them are over two hundred horizontal wells from the Eagle Ford shale play drilled by 31 different operators between 2008 and early 2011. The analyses of drilling performance data of these horizontal wells offer the establishment of general practice guidelines and recognition of opportunities for improvement in Eagle Ford shale drilling.

Oil-based drilling fluid, or “mud” (OBM) is a typical drilling fluid type currently used to drill from the surface casing shoe to the total depth (TD) in the Eagle Ford shale play. However, water-based mud (WBM) has also been used since the development of the Eagle Ford shale play. A comparative analysis was performed between oil-based and water-based drilling fluids to assess their performances and to identify the key challenges and potential areas for improvement when drilling in the Eagle Ford shale. The analyses included mud chemistry, drilling performance, mud weight and well architectures such as bit sizes, casing sizes and depths of the casing shoe, as well as lateral length. A statistical analysis (P10, P50, and P90) was also performed to evaluate industry-wide drilling performance such as drilling days for wells of various depths. Comparisons were made among different drilling fluid types and different operating companies.

The statistical analysis shows that although overall performance of water-based drilling fluids lags behind that of oil-base fluids in Eagle Ford shale drilling, a certain WBM system shows promising performance close to that of oil-based drilling fluids. The analysis shows that there is a general trend of decreased drilling days per footage over time and a large variation in total drilling days for similar well depths and trajectories. This indicates that although the drilling industry as a whole has improved drilling in the Eagle Ford shale over the years, there is still a large opportunity for improvement. One interesting finding is that some operators can drill wells in fewer days than the industry average even though their drilling fluid cost is slightly more expensive than the industry average. As a result of reduced drilling time, their overall drilling costs are reduced.

Lab test results with different fluid types show that the failure mechanism and shale-fluid interaction of the Eagle Ford shale is different from dispersion or swelling which are typical of traditional shales. The analyses and results of this study on drilling performance data provide lessons learned and general guidelines for current drilling practices and opportunities for improvement such as drilling fluid selections, mud weight, and well architectures in the Eagle Ford shale play.

Introduction
Natural gas production from hydrocarbon rich shale formations, known as “shale plays,” is one of the most rapidly growing areas of today’s onshore domestic oil and gas exploration and production. Natural gas has a key role in meeting the U.S. energy demands by supplying about 22% of the nation’s energy (NETL 2009; Sani and Ejefodomi, 2011). The potential for production from explored onshore shale plays, coupled with other unconventional resources, is predicted to contribute significantly to the U.S.’s domestic energy outlook. Ironically, the success from shale gas has played a major role in creating a natural gas supply surplus, thus lowering the price of natural gas.

The most active shale plays to date are Barnett, Haynesville, Fayetteville, Marcellus, and the Eagle Ford shale. Each of these shale plays has a unique set of drilling and operational challenges. 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 play drilling. These shales are very different from traditional reactive and swelling shales and create new challenges, in addition to the conventional shale instability issues that occur in the overburden formations.