Rain, rain, go away. So say service companies in the Bakken shale, where a much wetter-than-normal May in western North Dakota kept pressure pumping equipment — and well stimulation efforts — on the sidelines.

Activity will catch up as the Bakken serves up additional efficiencies in drilling and well completion in 2013. This is the year the play transitions to pad drilling, an important inflection point that shortens the cycle time on generating new wells in unconventional drilling.

A Hart Energy survey found two thirds of Bakken shale wells drilled on pads at the mid-point of 2013. Pad drilling share is expected to grow to 73% of all wells in 2014 as the play moves beyond lease capture and delineation into the resource harvest phase of the unconventional cycle.

Meanwhile the next round of delineation waits in the wings as operators eye the Three Forks Sanish member of Bakken group, which could boost original oil in place (OOIP) estimates for the Williston Basin above 4 billion barrels.

Companies like Continental Resources Inc. are embarking on delineation efforts currently in the Three Forks Sanish, which should lend itself to the same type of multi-well pad drilling that is being used on the middle Bakken member.

Currently, the number of wells per pad varies in the Bakken, but averages 4.3 based on operator responses to a Hart survey. The largest number of wells on a pad seems to top out at six, though most operators report a range of wells rather than a specific number when discussing pad drilling. The average number of wells per pad is a little lower than anticipated, particularly when compared to dry gas pad drilling, but reflects the oilier nature of the Bakken, where wells move to artificial lift quickly and, when rod pumping is used, are less tolerant of wellbore lateral gymnastics.

The technique of pad drilling varies among operators. Some drill two wells, then come back later and drill two more. Some drill each individual well sequentially. Other operators use batch drilling where wells are divided into segments and a rig drills surface on all pad wells, then comes back and drills the intermediate section on all wells, then finishes the laterals. The latter technique generates additional time savings and provides incremental efficiencies by allowing operators to drill vertical portions of the well with one set of fluids, then finish out the horizontal lateral with a different set. The result is less time cleaning tanks and switching over.

One of the more intriguing industry questions is how the transition to pad drilling impacts cycle time. It appears the initial savings involve the reduction of move time on each additional well. Previously, mobilization efforts could take up to seven days, or more, when transiting a rig from a single well location to the next single well location — worse when weather failed to cooperate. To date, those savings in move time have not only reduced truck traffic — some rig moves involved more than 40 truckloads — but also added to the number of wells each rig could complete in a year.

Reducing mobilization also reduces well costs. It may cost the same to drill a pad well as it does a single site well, but mobilization costs via elimination of trucking appear to provide an estimated 10% to 15% reduction in well costs.

One added advantage from the transition to pad drilling is that operators can move to batch completions, enabling the use of zipper fracs or other well stimulation techniques that appear to create a beneficial interaction between multiple well bores, creating greater reservoir “rubbleization” and increasing estimated ultimate recoveries (EURs). The latter is a qualitative impression among operators and not definitively quantified in the industry at this time in terms of actual production recovery versus standard completions.

The move to batch stimulation also reduces cycle time on the completion end, resulting in additional incremental cycle compression over and above pad drilling. Metrics for determining the impact of pad drilling include a mixture of rig count and well count. According to well count data released by Baker Hughes Inc., wells per rig in the Bakken grew from 2.46 on average in the first quarter 2012 to 3.25 for the second quarter 2013. At an average four wells per pad, operators were generating the equivalent of one more pad of completions at the midpoint of 2013, on an annualized run rate, than they were 18 months earlier.

Of note, the number of Williston Basin wells per quarter reached 609, according to Baker Hughes, exceeding the 603 drilled in third quarter 2012. Significantly, that output came despite a drop from an average 210 rigs working in the third quarter 2012 to just 187 in second quarter 2012. In other words, fewer active rigs were sustaining the same well count, implying an efficiency gain of 13% per rig in less than a year as operators embarked on the transition to pad drilling.

Despite the transition to fewer rigs, production continues to rise in the Bakken, topping 810,129 barrels of oil per day in May 2013, according to the Department of Mineral Resources at the North Dakota Industrial Commission (NDIC). The new high represented a 2.1% gain in monthly production on a sequential basis.

Further gains are likely, though they may be back-end loaded in 2013 as weather-inspired delays on moving heavy equipment resulted in an increase of wells waiting on completion to 500 as of mid-July. That number is up from roughly 350 as recently as the end of 2012. The expanded backlog of uncompleted wells points to a bifurcation in the market. Operators have reduced drilling time to fewer than 22 days, when measured by spud time to total measured depth, according to the NDIC. Separately, a study of horizontal wells by the oil services team at RBC Capital Markets found drilling days for horizontal wells dropping from an average 34 for the first half of 2011 to 26 on average in the first have of 2013. However, record rainfalls in May increased the time it takes to move from rig release to initial production as load restrictions restricted the movement of well stimulation fleets. According to the NDIC, it now takes 92 days to move from total depth to initial production.

One characteristic of pad drilling is that it alters the way traditional production grows. On single well pads, production is added steadily as each new well is completed. On multi-well pads, multiple wells are drilled and completed first. then all the wells are turned to sales, creating lumpiness in the production stream.

As the Bakken dries out, the volume of record-setting monthly production will see additional step level gains in the second half of 2013.

Contact the author, Richard Mason, at rmason@hartenergy.com