An electrospinning process was successfully used to fabricate polyethylene oxide/cellulose nanocrystal (PEO/CNC) composite nanofibrous mats. Transition of homogeneous to heterogeneous microstructures was achieved by tailoring the concentration of PEO/CNC mixture in the solution from 5 to 7 wt %. Morphology investigation of the obtained nanofibers demonstrated that rod-shaped CNCs were well-dispersed in the as-spun nanofibers and highly aligned along the nanofiber long-axis. PEO/CNC nanofibers became more uniform and smaller in diameter with increased CNC-loading level. The heterogeneous composite mats were composed of rigid-flexible bimodal nanofibers. Results of structure characterization indicated that the incorporated CNCs interacted strongly with the PEO matrix through hydrogen bonding. Mechanical properties of both types of mats were effectively improved by using CNCs, with heterogeneous mats being stronger than their homogeneous counterparts for all compositions (0-20 wt % CNC contents). When a smaller diameter needle was used to form homogeneous mats, enhanced thermal and mechanical properties were obtained.

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.

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.

Increased drilling of infill wells in the Bakken has led to growing concern over the effects of frac or fracture hits between parent and infill wells. Fracture hits can cause decreased production in a parent well, as well as other negative effects such as wellbore sanding, casing damage, and reduced production performance from the infill well. An operator had an objective to maximize production of infill wells and decrease the frequency and severity of frac hits to parent wells. The goal was to maintain production of the parent wells and avoid sanding, which had the potential to cause cleanouts. Infill well completion technologies were successfully implemented on multiwell pads in Mountrail County, Williston basin, to minimize parent-child well interference or negative frac hits on parent wells for optimized production. Four infill (child) wells were landed in the Three Forks formation directly below a group of six parent wells landed in the Middle Bakken. The infill well completion technologies used in this project to mitigate frac hits included far-field diverter, near-wellbore diverter, and real-time pressure monitoring. The far-field diverter design includes a blend of multimodal particles to bridge the fracture tip, preventing excessive fracture length and height growth. The near-wellbore diverter consists of a proprietary blend of degradable particles with a tetra modal size distribution and fibers used to achieve sequential stimulation of perforated clusters to maximize wellbore coverage. Hydraulic fracture modeling with a unique advanced particle transport model was used to predict the impact of the far-field diverter design on fracture geometry. Real-time pressure monitoring allowed acquisition of parent well pressure data to identify pressure communication or lack of communication and implement mitigation and contingency procedures as necessary. Real-time pressure monitoring was also used to optimize and validate the far-field diversion design during the job execution. The parent well monitored was 800 ft away from the closest infill well and at high risk for frac hits due to both the proximity to the infill well and depletion. In the early stages of the infill well stimulation, an increase in pressure up to 600 psi was observed in the parent well. The far-field diverter design was modified to combat the observed frac hit, after which a noticeable drop in both frequency and magnitude of frac hits was observed on the parent well. This is the first time the far-field diverter design optimization process was done in real time. After the infill wells stimulation treatment, production results showed a positive uplift in oil production for all parent wells at an average of 118%. Also, only two out of seven parent wells required a full cleanout, resulting in savings in well cleanup costs. Infill well production data was compared with the closest parent well landed in the same formation (Three Forks). At about a year, the best infill well production was only 10% less than the parent well with similar completion design and the average infill well production approximately 18% less than the parent well. Considering the depletion surrounding the infill wells, production performance exceeded expectations.