Recompleting wells isn't anything new. Operators routinely evaluate previously drilled leaseholds to see if more production can be pulled from a field. With better-than-ever technology, however, producers today are finding they can reduce their drilling costs and extract substantially more oil and gas than they did when a well was drilled originally.
Recompletions, often called restimulations, or refractures (refracks), make more sense in some cases than drilling a new well, according to Schlumberger Ltd.'s Robert Drummond, president of the North America division. He told a San Antonio crowd earlier in August that evolving drilling techniques offer producers an avenue to revive mature wells.
The model going forward, he said, "will challenge the economics of drilling new wells in some fields."
Schlumberger and its competitors, including Halliburton Co. and Baker Hughes Inc., offer technologies that open more channels of a rock, allowing sand to be pushed deeper into the fractures. Drummond said there were "tens of thousands of candidates throughout North America" for recompletions.
For instance, a typical well in the Eagle Ford Shale in South Texas produces about 500 boe/d, around the same level as a few years ago. That makes drilling in some areas uneconomic today. Recompleting a well with new techniques may address the decline curves.
The Railroad Commission of Texas in June alone issued 43 permits to re-enter existing well bores, and it issued 133 permits to recomplete some wells (see Shale Daily, July 30).
It's one of the challenges operators face "as we get into the extreme edges of the reservoir," Drummond said. "Once we drill the sweet spots and reservoir conditions become even more challenging, it's going to require more technology to make these plays economical."
Some experts consider the recompletions to be the second part of the North American unconventional drilling revolution. Wood Mackenzie energy researchers see it as the third phase.
"The unconventional sector in the U.S. has already gone through two distinct cycles and is now transitioning into its third phase," said Robert Clarke, head of unconventional upstream research. "The first chapter was built around a large group of highly productive shale gas assets and was defined largely by production growth. The second wave was defined by a smaller grouping of high-margin tight oil plays.”
Today, producers are shifting to the third phase, which Wood Mackenzie in a new report dubs "Unconventional 3.0." The report, issued on Wednesday, focuses on brownfield exploration, as operators reassess once marginal assets previously considered to be insufficiently permeable for commercial drilling.
“In this current phase, the most modern aspects of the two techniques that define unconventional projects -- long-lateral horizontal drilling and isolated multi-stage hydraulic fracturing -- are being used to exploit all types of rock volumes in mature basins,” Clarke said.
The brownfield exploration "signals a shift in the industry’s thinking about what constitutes a successful unconventional play." Wood Mackenzie researchers found that "3.0" projects have the combined potential to produce more than 1 million boe/d by the end of 2020.
During the recent second quarter conference calls, several producers highlighted their recompletion results. Encana Corp., for instance, reported that it's recovering 1-2 MMcf/d in the Haynesville Shale at a recompletion cost of about $1 million per well. There's not much of a market today for natural gas, but with new wells costing about $12 million each, recompletions offer a lifeline, said COO Mike McAllister.
"In the Haynesville, we have implemented a refrack program with excellent results on our first two wells completed to date," he told analysts during a July conference call. "Initial production rates from both wells are 100% higher than expectations.
"We are planning to refrack five more wells in the Haynesville in the third quarter, and our teams are evaluating hundreds of wells for refrack potential" also in the Denver-Julesburg Basin, and the Montney and Eagle Ford shales.
Smaller Independents in the Game
Smaller independents see the cost savings as instrumental in redoing older wells.
Consol Energy Inc. had done six recompletions in the Marcellus Shale as of late July, CEO Nick Deluliis said during a 2Q2014 conference call. The six wells are in Greene County, PA; they first were drilled in 2009 (see Shale Daily, July 15). When the six wells first were turned to sales, the wells flowed at less than 1 MMcf/d. Two of the recompletions resulted in 24-hour flow rates of 4 MMcf/d-plus.
"So far, the results are promising," Deluliis said. "We've seen initial rates between 3 MMcf/d and 6 MMcf/d," exceeding what was expected, like Encana. "We're seeing good pressure. It looks like we've contacted some new rock with the recompletions," confirming that resin coated sand and longer laterals are effective in bringing up more oil and gas.
Consol is evaluating about 200 more recompletions, expected to cost $1.8-2.2 million per completion, the CEO told analysts. "There's a range there because as we work through these efficiencies and we continue to get better at what we do, those costs will come down."
Linn Energy LLC is evaluating some recompletions across a swath of the gassy Hugoton formation in Kansas, where it is the top player. The company in early August already had identified 150 recompletion opportunities for wells that first were drilled by predecessor owners (see Shale Daily, Aug. 5).
Linn built its stake by acquiring producing leaseholds from BP plc, and more recently, ExxonMobil Corp., Devon Energy Corp. and Pioneer Natural Resources Inc.
"We've had a lot of success on the recompletion side," Linn COO Arden Walker said. "We've gone in...on close to 500 wells since 2012 when we took over the original BP properties. We think we'll have similar types of opportunities with both the Exxon assets, the Devon assets, and the Pioneer properties, as we do believe we'll have continuation of opportunities there."
Optimizing older wells offers all types of opportunities, said Walker. "We've been able to drive costs down, and I think that's where we get the leverage of being bigger in a particular area.”
Devon’s Barnett Strategy
Devon is planning to launch a refrack project in the Barnett Shale later this year. The pilot program plans to attempt to establish the best practices and target horizontals with wider-than-average perforation clusters, or frack zones. Devon was the first unconventional operator to delineate the play after acquiring a leasehold from George Mitchell's company in the early part of the decade.
The early laterals that were fracked by Devon had widely spaced perf clusters, according to the company. With years of understanding now in the books, Devon plans to narrow that cluster density.
Marathon Oil Co. plans to recomplete 20-24 net wells this year, management said during its 2Q2014 call. And BP has begun restimulating wells in the Woodford Shale of Oklahoma.
BP completed a five-well refrack pilot in 2013 that averaged a twofold increase in sustained gas production on wells originally drilled by Chesapeake Energy Corp. BP engineers found that the incremental gas rate and reserves "can be economically added by the refracturing of horizontal shale gas wells" without "significantly damaging the baseline production rates," a case study reported.
Taking into account that the wells already had been cased and drilled, the refrack costs could be 50-100% of the original completion costs, BP said.
According to Wood Mackenzie, "the brownfield exploration phase that is quickly unfolding in the U.S. will redefine what international unconventional projects could look like," Clarke said. "Projects may not need massive operational scale, nor will they need to be drilled at an aggressive pace. Investors and operators need to be abreast of the specifics around what is unfolding in the Lower 48 and use that as a new template for project design abroad."