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.

One of the key objectives within the drilling industry is optimizing rate of penetration (ROP) and a major contributor to obtaining this objective is the PDC bit design. Whilst previous papers have proven that the PDC cutting structure geometry, particularly back rake and side rake angles, affect PDC bit performance when tested at atmospheric conditions, no information in the SPE literature exists for similar tests at confining pressures. The effect of side rake angle on cutter aggresiveness and cutter interaction at depths of cut (DOC) in excess of 0.04” are particularly unknown under confined pressure. The results of more than 150 tests show that back rake and side rake angles have substantial effects on Mechanical Specific Energy (MSE) and the aggressiveness of PDC cutters. Experiments with three different rock types; Carthage marble, Mancos shale, and Torrey Buff sandstone, revealed that at both atmospheric and elevated confining pressures, PDC cutters with 10 deg back rake angles require half the energy to cut the same volume of rock and produce higher cutting efficiency compared with cutters having 40 deg back rake angles. Possible reasons for this behavior are explained through the analysis of the cutting process. Results show that a cutter with low back rake requires less horizontal cutting force in order to cut the same volume of rock. This observation indicates that not only will a PDC bit with lower back rake angles, drill more efficiently, but it will also require less torque in order to drill at the same ROP. Other factors such as reduced durability of cutters at low back rake angles should also be considered while applying these results to PDC bit designs. Test results at both atmospheric and confining pressures revealed that MSE decreases with increasing DOC up to 0.08” on all three rock types. However, the tests also showed that MSE starts to increase slightly at DOCs above 0.08”, possibly suggesting an optimal minimum DOC. Experimental results also show that, whilst Mancos shale and Carthage marble have about the same compressive strength, Mancos shale requires three times less energy to cut compared to Carthage marble. This indicates that, compressive strength of some rocks such as shales cannot be used alone as a reference rock property for accurately evaluating and comparing drilling efficiency. A new 3D mechanistic PDC cutter-rock interaction model was also developed which incorporates the effects of both back rake and side rake angles, along with rock specific coefficient of friction. The results from this single-cutter model are encouraging as they are consistent with the experimental data.

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.