Operator Outputs from US Oil and Natural Gas Resource Plays Continues to Leapfrog

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Perhaps the most striking thing upstream companies revealed in their recent round of second quarter calls was the astounding production increases from US unconventional plays brought about by an array of tweaks to well drilling and completion techniques.

One tactic they’re using to eke more hydrocarbons from the ground is optimized well spacing — configuring wells as close as possible to best drain the reservoir without interference. Other techniques are placing hydraulic fracture sections or “stages” closer together and using more proppant to hold fractures open so oil and gas can flow more easily from the reservoir.

It’s taken a few years for operators to figure it all out, but about four years after they began widespread exploitation of unconventional oil plays, which are the current focus of most large companies, they are largely approaching full development mode.  In the meantime, they have seen staggering production growth, especially on the crude oil side.

For example:

  • Devon Energy, with five months of Eagle Ford operations under its belt after entering the South Texas play through its $6 billion buy of GeoSouthern Energy in late February, raised production there between March and June a whopping 57% by to 77,000 b/d of oil equivalent.
  • EOG Resources said its US crude and condensate production jumped 33% year-on-year to 274,600 b/d. Its crude/condensate output grew 52% in 2011, 39% in 2012, 40% in 2013 and it expects an estimated 29% of crude/condensate output growth in 2014.
  • Continental Resources, a pioneer in the giant Bakken Shale in North Dakota/Montana, reported company-wide production of 168,000 boe/d in Q2, most of it oil, up 24% year-on-year. Its Bakken production alone was 108,573 boe/d, up 23% year-on-year and 11% from Q1.
  • Pioneer Natural Resources, a first-mover in exploiting West Texas’ Permian Basin unconventionally, reported company-wide total sales volumes of 183,000 boe/d, up 12% year-on-year, and oil sales volumes of 79,780 b/d in Q2, up 15% from the year-before period.  From just two unconventional formations, the Spraberry and Wolfcamp in the Midland sub-basin, Pioneer expects to grow production 22%-27% in 2014 to 96,000-100,000 boe/d. Pioneer has estimated those formations alone contain 75 billion boe of recoverable resource.

In the Permian Basin, operators have found oil in the assorted “stacked” subsurface zones so prolific that they have about doubled basin production to over 1.7 million b/d currently from 868,000 b/d in mid-2007.

In the Bakken, operators have tinkered with optimal well drilling and enhanced completions for the last few years; as a result, production keeps ratcheting up and surpassing projections. Oil production in North Dakota topped 1 million b/d a few months ago—about 95% of the state’s output comes from the Bakken—and the Bakken itself is now at about the 1 million b/d level.  That is up from 205,000 in mid-2007, 484,000 in mid-2011 and 750,000 in mid-2012.  The play also produced its billionth barrel of oil in April.

Continental spent 2012 and most of 2013 standardizing its well drilling and completion methods in the Bakken and elsewhere, which lowered costs. Since late 2013, it has turned an eye to better recovery rates by enhancing its completion design.

Three recent optimalized Bakken wells generated early production 35% higher than the production trend for Continental’s 603,000 boe model for typical Bakken wells and 25% higher than nearby offset wells completed with the standard design.

“The end game is to determine the specific completion approach that is most cost-effective for each part of the play,” company Chief Operating Officer Rick Bott said in a quarterly conference call this week.

Meanwhile, Eagle Ford output was 1.4 million in July, a fast upward trajectory from 65,000 b/d of oil in mid-2010, 245,000 in mid-2011, 618,000 in mid-2012 and 1 million in mid-2013.

EOG said it is developing the Eagle Ford on 40-acre spacing, which is about 300 feet on average between wells. “Early results look good,” company CEO Bill Thomas said in his quarterly call.

The company, which also operates in the far western Permian’s Leonard Shale, is testing 300-foot spacing, down from 660 feet. And in the Bakken, EOG is now placing wells 1,300 feet apart but is testing a spacing pattern of 700 feet.

Devon also operates in the Anadarko Basin in Oklahoma, where its liquids production of about 41,800 b/d in Q2 increased 26% year-over-year. The company said the Cana Woodford play there was the strongest contributor to that growth.

In that field, Devon’s enhanced completion designs that doubled the number of “frac” stages to 20 and increased sand volumes used in fracturing to 6 million pounds/well from 3.5 million, helped drive up the company’s initial well production rates 35% against earlier averages, and increased ultimate estimated per-well recoveries by 15%, Devon said.

“These are among most productive wells ever drilled in Cana,” Devon Chief Operating Officer Dave Hager said.

And the production ramps aren’t stopping anytime soon. Devon estimates its Eagle Ford production of 49,000 boe/d in March should average 70-80,000 boe/d in 2014, up 63% from its starting gate, and ramp to more than 100,000 boe/d next year.

Marathon Oil, another big Eagle Ford player whose production there of 102,000 boe/d in Q2 grew 26% from a year ago, eyes more than 30% year-on-year growth in 2014 from its three large US unconventional US resource plays which also include the Bakken and assorted Oklahoma reservoirs.

And Pioneer plans to grow its total production 16-19% this year to 180,000-185,000 boe/d, with that same growth rate persisting though 2016 — which would double 2013 production within five years.

“Efficiencies in our completion design … are going to be driving us toward potential resource adds in the future,” Marathon CEO Lee Tillman said, adding some completion techniques such as extra fracture stages, will cost more.

Continental also said denser wells in the Bakken entail an incremental cost of $1.5-$2 million/well over the typical $7.5 million well cost.

“We have tested [enhanced completions] against the incremental value that it generates and absolutely see the return there for those incremental dollars,” Tillman said.

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