An Operation Support Center (OSC) was established in Colorado, USA to support clients drilling in the Pinedale Anticline in Wyoming as well as other operators throughout the onshore drilling market of the continental US. In the Pinedale Anticline region, operators plan to drill several hundred wells per year. The time to drill and complete a typical well stood at thirty-five days through 2007, and a target was set to reduce this to fifteen days. Achieving this target would result in a savings of approximately 2190 combined rig days a year thus saving the operator over $100mm.A strategy with 2 main elements was developed: a powered rotary steerable service for vertical drilling and remote optimization via the OSC. This approach allowed for no rotary steerable operations personnel to be based at the wellsite during drilling. The new OSC centric processes and procedures developed increased efficiency and allowed fast deployment across a fleet of rigs. The process included a rig-up crew that moved from rig to rig for BHA pick up or lay down.The remote operations team then monitored operations and began analysis to optimize performance. Using offset data and meanspecific-energy (MSE) techniques, drilling performance targets were set for each depth interval. OSC based drilling engineers alerted the rig when penetration rates were compromised by adverse drilling dynamics, or when input energy needed to be reduced to preserve bit life and minimize trips. The remote team also generated a daily report for each well that continuously compared penetration rates with expected performance targets and captured best practices. This process was used to communicate across the entire drilling organization.This method of challenging the target was complimented by the operator's ongoing optimization initiatives and resulted in an increased average ROP of 36% through February 2009. Average time to drill and complete these wells was substantially reduced from the original benchmark; with average drilling and completion time standing at seventeen days. This reduction in days has the potential of saving the operator an average of $900k per well.

In the quest to develop shale gas reservoirs, horizontal wells have emerged as the most prolific producers with lateral sections ranging from 3,000 ft to more than 10,000 ft in length in some plays. Even with substantial experience in planning and drilling in shale, borehole stability problems while drilling continue to occur, resulting in increased operating time and costs. Adding logging-while-drilling (LWD) tools to the drilling program can assist with identifying and mitigating such problems by providing valuable information on the condition of the wellbore. These measurements include ultrasonic and azimuthal calipers computed from density and photoelectric factor measurements. In this case study, time-lapse evaluation of these logs by logging on a trip out of the well revealed the presence of breakouts within the borehole and evidence of deterioration of borehole quality with time. Caliper measurements were integrated with other logs and regional tectonic information to construct a Mechanical Earth Model (MEM). The MEM consisted of estimates of rock mechanical properties, formation pressure, and in situ stresses. Using this data, a wellbore stability model was developed. The model provided insights into the stress regime and the mechanism of borehole failure. Drilling procedures to mitigate borehole breakout were consequently developed, thereby improving the efficiency of subsequent drilling in the same area.

An Operation Support Center (OSC) was established in Colorado, USA to support clients drilling in the Pinedale Anticline in Wyoming as well as other operators throughout the onshore drilling market of the continental US. In the Pinedale Anticline region, operators plan to drill several hundred wells per year. The time to drill and complete a typical well stood at thirty-five days through 2007, and a target was set to reduce this to fifteen days. Achieving this target would result in a savings of approximately 2190 combined rig days a year thus saving the operator over $100mm.A strategy with 2 main elements was developed: a powered rotary steerable service for vertical drilling and remote optimization via the OSC. This approach allowed for no rotary steerable operations personnel to be based at the wellsite during drilling. The new OSC centric processes and procedures developed increased efficiency and allowed fast deployment across a fleet of rigs. The process included a rig-up crew that moved from rig to rig for BHA pick up or lay down.The remote operations team then monitored operations and began analysis to optimize performance. Using offset data and meanspecific-energy (MSE) techniques, drilling performance targets were set for each depth interval. OSC based drilling engineers alerted the rig when penetration rates were compromised by adverse drilling dynamics, or when input energy needed to be reduced to preserve bit life and minimize trips. The remote team also generated a daily report for each well that continuously compared penetration rates with expected performance targets and captured best practices. This process was used to communicate across the entire drilling organization.This method of challenging the target was complimented by the operator's ongoing optimization initiatives and resulted in an increased average ROP of 36% through February 2009. Average time to drill and complete these wells was substantially reduced from the original benchmark; with average drilling and completion time standing at seventeen days. This reduction in days has the potential of saving the operator an average of $900k per well.