While technology can now let companies go back to wells and further spur oil production, it remains a question whether refracs are the best option in the current crude price environment, as Starr Spencer explains in this week’s Oilgram News column, At the Wellhead.
Low oil prices present the shale industry with a problem: how to keep production up while trying to push costs down.
One possible solution is refracturing existing wells. It sounds simple, elegant and logical: if output is declining in an oil or natural gas well, and hydraulic fracturing the well prodded it to produce initially sizeable volumes, then operators should just refracture it, i.e. shale’s version of enhanced oil recovery.
Refractures, popularly known as “refracs,” have snagged industry’s interest recently as oil prices in the US — where the majority of shale wells are located — have stubbornly bobbed around the $50/barrel mark. The reasoning is that since the all-in cost of most horizontal wells sport price tags of $8 million and up, and refracs can run roughly 25% of that sum or about $2 million if done correctly, refracs make a lot of sense.
And since upwards of 100,000 oil wells have been fracked in North America during the last four years, according to some studies, a sizeable portion of those may be able to be refracked, proponents say.
The idea has had support from many parts of industry for years. For example, ExxonMobil’s US shale subsidiary XTO Energy, in a presentation to the North Dakota Petroleum Council annual meeting in 2011, said refracs in the Bakken Shale of North Dakota and Montana appeared “economically and operationally effective” and were especially successful in wells with inefficient completions.
“Ample opportunity exists for further development of refrac techniques,” the presentation stated.
Experts say refracking stimulates bypassed pay intervals, re-inflates natural fissures and often contacts “new” rock. They say only about 8% of a reservoir’s oil is recovered from shale wells the first time around, but claim refracking can boost output to or near original levels, although the decline rate is likely to remain high — from 40%-70% the first year for oil wells.
Even so, some fracking experts are not convinced the market is ripe for refracs.
“The technology is not ready for prime time,” said Chris Robart, a director at energy consultancy IHS. “The challenge is that identifying candidates for refracs, and deciding how to refrac the well, are not that simple. There’s a lot of gaps in data that need to be there to make good decisions about how to design” a refrac operation.
Robart said refrac operations can be “pricey” unless well bores are designed in a way to facilitate them. And refracking doesn’t fit the “highly efficient, manufacturing mobile factory model” of shale wells, he said.
Others say there is no easy way to ensure the refrac treatment will go to the left-behind parts of the reservoir when it is placed on a long lateral of, say, 6,000 or 7,000 feet. A lateral is the horizontal portion of a well.
“How do I actually get to the [areas] that don’t produce at all and crack those open?” said Richard Spears, vice president of oil services consultants Spears & Associates. “You can do it, but the challenge and cost of doing it can be big. It’s technically risky, economically expensive, and in the end, will you really get something out?”
Not all wells are refrac candidates and it is important to evaluate wells first — which is what oil services giant Halliburton does, said David Adams, the company’s vice president-operations technology in North America. Halliburton looks at numerous criteria, such as prior well treatment, well integrity, the type of proppant used to hold the fractures open.
The cost of the evaluation is minimal, Adams said — maybe “a couple of percent” of the overall cost of a refrac.
Once a well is deemed suitable, technologies exist to gauge how the well has produced at various points along the lateral during the prior month, he said.
“We have ways of diagnosing which portions of the reservoir need” a refrac the most, Adams said. “We can derive some information on how the well should be refracked, just by pumping pressure diagnostics into the fracs and watching how they react to that pressure.”
And to ensure the refrac treatment actually travels to the right area instead of going into already high-producing sites, the company uses an engineered diverting solution, Nick Gardiner, strategic business manager for Halliburton Production Enhancement, said.
“We have diagnostics on where to…block off better-stimulated areas so [the refrac] goes to lesser-stimulated areas,” Gardiner said.
But even if wells are good refrac candidates, oil prices may prove to be too low right now, even though refracs are relatively cheap, some experts say.
“If you’re a producer, would you rather produce more oil at $50/barrel, or just keep the lights on [flat output] until oil prices recover?” Daniel Choi, E&P analyst for Lux Research, said. “I suspect [refrac] candidates would change if oil prices recover to $70-$80/b.”
— Starr Spencer in Houston
|Request a free trial of: Oilgram News|
|Oilgram News brings fast-breaking global petroleum and gas news to your desktop every day. Our extensive global network of correspondents report on supply and demand trends, corporate news, government actions, exploration, technology, and much more.|