E&P companies continued to tout the efficiencies and cost-slashing prowess of “pad” drilling and other savings measures undertaken during third-quarter earnings conference calls, highlighting a trend that has been especially notable this year as companies have stepped up activity across a growing number of unconventional fields.
Operators seemed particularly proud of snipping down the number of days needed to drill wells. For example, in South Texas’ prolific Eagle Ford Shale field, Forest Oil aims to migrate to pad drilling, which allows multiple wells to be drilled from a single site rather than moving the rig after each well, company CEO Patrick McDonald said during his company’s call last month.
“We’ve installed a rig walking system that will allow us to skid the rig over in a much shorter time period and allow us to drill four well pad locations in approximately 60 days — a significant time savings over current single-well style drilling,” McDonald said.
Continental Resources, an early mover in the prolific Bakken Shale oil play in North Dakota and Montana, has designed “larger and larger” multiwell pad drilling schemes, with up to 14 wells on a site, company chief operating officer Rick Bott said earlier this month in his company’s call.
“In the first quarter , 10% of our operated rigs were on multiwell pads; today 45% of our operated rigs are engaged in pad drilling, and that percentage will continue to grow,” Bott said. These wells are infill drilling that place wells in-between existing wells to drain more of the reservoir.
This saves Continental money on access and site building costs by extending existing roads and infrastructure built for the original wells, said Bott. “Incremental site construction costs from additional wells from an existing pad are much lower,” he said.
Pad drilling also minimizes rig moves, he added. “When we do move rigs, the average cost per rig move is lower – 17% this year,” he said. The company saves 10%/well on those that are pad-drilled.
Also, using newer, more capable rigs allow faster drilling times, even though the rigs cost more per day to lease. This results in a rise in average wells drilled by 33% to 1.2 wells per rig-month in the third quarter versus the first quarter, said Bott. And the average number of days to drill the well’s lateral–its horizontal leg, which he calls the “most critical part of the hole–dropped 18% through greater efficiencies and accuracy, said Bott.
“If you take our drilling cycle spud to spud, well costs are 25% lower in the third quarter versus the first quarter, in large part because of these drilling efficiencies,” he said. “And that’s on top of a 12% improvement in spud-to-spud we had last year.”
Bott also said the time to complete a well has dropped 25% for the number of days from rig release to first production — from an average 76 days last year to 57 days so far in 2012.
Also, the cost of proppants–substances such as ceramic and sand, that hold open a well’s fracture after hydraulic fracturing–have dropped as much as 40% over 2012, he said. This has reduced Continental’s stimulation cost per fracture “stage” or interval from $124,000/stage in fourth-quarter 2011 to $98,000/stage in third-quarter 2012.
Pad drilling is also a focus for big independent Chesapeake Energy, among the US’ most active upstream operators. The company is ramping up to what company chief operating officer Steve Dixon in early November called “full development mode” in several key plays.
As the company finishes drilling acreage and can hold it by production, “we can focus on pad drilling, our equipment mobilization times will compress, our water handling logistics will get simplified, road and pad construction costs will decline, and many other economies of scales will be realized,” Dixon said.
While difficult to precisely quantify, Chesapeake targets long-term capital efficiency improvements of at least 15% to 20% as it transitions to pad drilling, he said.
In addition, Southwestern Energy, which pioneered the natural gas-prone Fayetteville Shale in Arkansas and is now trying to explore for oil elsewhere, talked up its purchasing savings for oilfield service costs, William Way, the company’s chief operating officer, said.
“Our wells have come down in the quarter a lot due to reduced vendor” costs after the company consolidated vendors, he said. “We’re seeing some reductions in cost there.”
Also, pumping its own wells rather than contracting with an outside oilfield vendor saves about $150,000-$160,000 per well, he said, adding: “We’ll pump a large number of wells next year.”
One upstream operator that has lowered its sand costs even more in recent years is Pioneer Natural Resources, which has a sand mine that supplies sand for a large chunk of its well completions.
“We continue to push the envelope in terms of the use of white sand as opposed to more expensive ceramics” to keep the well fracture open, Pioneer chief operating officer Tim Dove said during a conference call earlier this month.
Dove has said the cost savings is “something like $700,000” per well by using white sand rather than ceramics.
Multi-pad drilling provides “tremendous” cost savings of perhaps $600,000-$700,000/well, said Dove, although he added that may be “somewhat” offset by the use of bigger fracs and longer laterals in the future.