For as long as hydraulic fracturing, or fracing, has existed, the story goes the same way.
A well is drilled, cased, completed, and put on production. And the story always ends the same way too – eventually the well runs dry. Companies move on to tap new wells because the play is played out.
Right? Well, maybe not. Since the start of the downturn two years ago, more and more companies are evaluating the idea of trying to pump some new life into old wells.
Enter refracing (or hydraulic refracturing), and enter the industry’s latest attempt to stay alive in a low price environment.
By refracturing old shale wells, operators have revived the viability and profitability of entire fields, including areas in the Bakken, Eagle Ford and Barnett. Better yet, work in those areas shows that even relatively new-but-underperforming wells can be refractured to boost production and output.
The technique represents a potential windfall for a fossil fuel industry tested by the current price correction and the costs of creating new wells, and could position operators with a relatively cost-efficient source of additional production for years to come.
Why Refracing? Why Now?
Refracing technology isn’t new. It’s been around for years, probably since the 1950s when fracing itself was first getting off (or under, rather) the ground.
When petroleum engineers come up against old or under-performing wells, they would re-enter the wells and fracture them with a mixture of sand and water, looking to release new geological avenues to get the crude flowing again.
So what made engineers and operators decide to try fracing horizontal wells the same way? In a word: economics.
We’re a couple years into a downturn in prices and a shift in demand. The majors have been warned to get busy evolving their business models forward or to get busy dying.
Like any born engineer would do, operators for various companies took a look at the situation: it costs nearly $6 million to drill and complete a new well. We have a lot of existing wells either under-performing projections or supposedly tapped out. So how much does it cost to try to squeeze oil out of a stone again?
The answer: anywhere from half to a quarter of what it costs to drill and complete a new well. The early innovators in the refracing game like Marathon Oil Corp. were hooked on the idea – and they wasted no time testing it out on their Bakken wells.
How Many Wells Could a Refracer Refrac If A Refracer Refraced Wells?
If the theory of refracing horizontal wells to re-induce output is inspired, then the results so far are downright tantalizing.
In 2015, a joint study from Baker Hughes Inc. and the Society of Petroleum Engineers (SPE) looked at wells in the Bakken and Eagle Ford fields after refracing. All the wells in the study showed prime potential for increased production after refracturing, even the Eagle Ford wells that averaged only 19 months since the initial completion.
Of course, as with any industry-pushing innovation, refracturing old wells comes with risks. There’s a chance that over-pumping could result in ruining a reservoir or some unintended consequence like pushing too far into a neighboring well (which results in any new output in your refraced well simply representing oil siphoned from next door).
Some experts worry that refracing doesn’t actually extend the life of the well in terms of total output – that rather the process of forcing the frac fluid into existing and reopened fissures simply accelerates the flow.
There’s also been some discussion about whether refracing truly represents a cheaper alternative, or whether the outsized cost of completion compared with drilling eats up any potential gains.
But more companies are jumping on board every month, and as the sample size grows, technologies related to refracing will get tested and refined. More companies involved in refracing should also close any real or illusory gap between the costs of a new well v. refracing an existing one.
All of the approximately 100,000 horizontal wells in the U.S. represent potential refracturing candidates, and the refracing of vertical wells has increased as well (in 2015, Devon Energy saw a 700% production increase after refracing 150 vertical wells in Barnett).
Refracing has moved beyond a shot in the dark and represents a major emerging technology in the shale fields.
What Fracing 2.0 Means For You
As much as any innovation in completion technology lifts all boats, and as much as refracing methods kickstart recovery in traditional resources, shale operators especially can’t afford to be asleep on the growth of refracing.
While it may seem like one of a dozen industry adjustments to stem narrowing margins due to a depressed global oil market, the routine 30% boost in production from a refracture well represents a potential major shift for shale that operators can hardly ignore.
Even calls to start working on the “fraclog,” or the 4,000 wells that are drilled but not completed (DUC) to increase overall output would require companies to pony up the costs of completion, which are significantly higher – double, really – the costs of drilling a new well. Refracing eliminates that outlay in the short term.
Refracing technology is also ripe for innovation, the bread-and-butter of engineering. IHS Inc. predicts that nearly 11% of all hydraulic fracturing activity in the U.S. will be refracing by 2020.
Refracing has been around for a long time. In its current iteration, it could be around for a lot longer, powering shale operators into the future and extending the life of shale plays all over the country.
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