Shale EOR Delivers, So Why Won’t the Sector Go Big?
- Trent Jacobs (JPT Digital Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 2019
- Document Type
- Journal Paper
- 37 - 41
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The oil is there. The gas is nearby. The process is proven.
But is there an appetite to put it all together and redefine what it means to be a shale producer? This is the key question looming over the future of enhanced oil recovery for tight shale reservoirs, or simply shale EOR.
To answer it, unconventional oil producers are trying to weigh the options from what amounts to a complicated pros-and-cons list.
Developing a shale EOR program may mean drawing resources away from new exploration projects that have quicker returns, the same conundrum that has stymied the US refracturing market. On the other hand, shale EOR boasts impressive economics for companies willing to reinvest in land and wells already paid for.
This financial tug-of-war has been playing out in the shale sector since the spring of 2016. That was when Houston-based EOG Resources let it be known that its shale EOR program was boosting production from vintage horizontal wells in its Eagle Ford Shale asset in south Texas.
News of the development quickly made the operator synonymous with shale EOR. It is now widely understood that all of these projects rely on the huff-and-puff injection process using natural gas as the special agent that can unlock those additional barrels. Other key details are coming to light as well—such as the expanding scope of success.
In a recent quarterly earnings statement, EOG said it continues to see “strong results” from around 150 EOR wells, more than a third of which were converted in 2018. Analysts and engineering consultants have found about 100 other wells in the Eagle Ford that several other operators have converted into huff-and-puff injectors.
“It’s kind of incredible to see the data,” said John Watson, the senior research analyst who put together a report late last year that highlighted production details of shale EOR projects. After physically combing through filings at the Texas Railroad Commission (since they are not available to download), he found dozens of pad wells that saw a combined 10-fold rise in production above their trough.
Among the standouts, a group of 11 wells that reached a combined peak production rate in December 2011 of about 90,000 bbl a month. By August 2017, these wells were pumping out only 5,000 bbl. After gas injections began, the group produced 40,000 bbl a month—an average increase from about 15 B/D to 117 B/D per well.
Another case involved 14 wells that peaked at 330,000 bbl a month in 2013, then dropped to 10,000 bbl. Post injection, output increased to 170,000 bbl a month.
Watson’s report covers more than two dozen other shale EOR projects, though most lacked production results, revealing only project cost estimates. As opaque as the shale EOR effort has been thus far—at least outside of academic research—operators have shared these eye-openers for one simple reason: they have to. That is, if they want to receive the tax credits eligible for all EOR projects.
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