[Editor's note: A version of this story appears in the November 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]
We can thank our lucky stars that the U.S. has become an energy powerhouse. This unforeseen event has changed the balance of payments via commodity exports and, in turn, altered the global geopolitical calculus (see the Saudi drone attacks). It is boosting oil town economies and creating jobs (Midland and Odessa perennially rank among the cities with the lowest unemployment rates in the U.S.).
But this lofty perch is beset with threats. These range from government intervention to changing consumer attitudes. Now, there are lawsuits against pipeline construction and against the big banks that fund oil and gas development. Combine all this with a perceived slowdown in oil demand growth, and E&P companies have a lot to think about—all while trying to make a buck and give half of that back to their investors before they bolt.
Here are a few comments we’ve gathered that provide insight. First, Ray Walker, the COO of Encino Energy LLC and former COO at Range Resources Corp., was a pioneer in the Marcellus Shale. At Hart Energy’s annual DUG East conference in Pittsburgh earlier this year, he reminded us of some central facts. “The rock rules, no matter how good you think you are as a frack engineer.
He also cited capital discipline that’s becoming the new norm throughout the upstream world. It has improved many an operator’s financial profile, but at the expense of the service companies’ margins. “You have to ask yourself, ‘How do I get more cash flow for the money I am putting in the ground?’”
Many of the early shale plays that caused so much excitement and hype are maturing. Some are in the deliberate manufacturing phase that will also lead to EOR, led by the majors’ increased commitment to unconventional plays.
For example, more than 27,000 wells have been drilled in the Eagle Ford since Petrohawk Energy Corp. unveiled it in 2008. Where does it stand today, now that it is one of the most mature of all U.S. shale plays? It’s turning out to be one of the most resilient.
Lately, operators have been applying for more drilling permits to the Austin Chalk Formation in the eastern portion of the play, which is keeping it relevant. Its proximity to the Texas coast for exports or petrochemical feedstock is another big plus. Technical progress continues as producers fine-tune operations and well spacing.
“We refer to the Eagle Ford as the ‘dark horse,’ because it remains one of the most economic basins in the country. We are getting the most questions about it and the Austin Chalk,” said Enverus analyst Bernadette Johnson, speaking at Hart Energy’s 10th annual DUG Eagle Ford conference recently.
“In general, downspacing has been successful here, and more so than in any other play.” The Eagle Ford’s drilling times have improved and are now nearing 1,400 feet per day per rig.
Enverus breaks this play into the western and eastern half, each with different characteristics. More than 80% of the wells being drilled today in the western Eagle Ford are child wells, which indicates just how mature the play is, Johnson said. She also cited a lack of core locations remaining in the east, especially in Karnes County, “although this is not concerning to us. This is a natural development for such a mature play.”
However, interest is shifting back to the east now as the Austin Chalk play in Washington County heats up, based on new drilling permits. There is interest north of the Karnes Trough in Wilson County.
“We’re watching it closely, and it’s very liquids-rich,” she said. “Although the eastern Eagle Ford type curves are lower than in the western part, the economics are actually better. The eastern part is not as mature.”
In the southwest portion of the play, the economics are driven largely by gas prices, with Enverus estimating operators need a breakeven price of at least $2 per thousand cubic feet. The average oil cut in the western portion is 61%, but clocks in at 82% in the eastern. Perforation intervals in the east have lengthened since 2014 to average 8,500 feet, which is longer than in the west.
The eastern portion has shown more well productivity improvement per foot drilled since 2018 while the heavily drilled west has been consistent, Johnson said. “Again, the geology really matters. It depends on where you are for what you’re able to do in terms of spacing and proppant.”
In most shale plays, the quality of previously unproductive, uneconomic or “un-sellable” acreage is being revealed with more clarity. Value is being turned around by using smarter drilling and completion practices, coupled with more precise well spacing.
So after a wild decade of exploration and outsized spending, the shale business has turned into a true business, with a long tail of cash generation ahead.
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