The inventory of drilled but uncompleted wells (DUCs) has been growing steadily and will likely continue to increase through the remainder of the year. Any hopes for a quick recovery will need to take these ready-to-soar producers into account.

Jessica Pair, manager for upstream at Stratas Advisors, told Hart Energy’s Viewpoint Executive Breakfast Series April 21 in Houston that there were 8,150 DUCs in inventory in first-quarter 2016. “With the vast inventory of DUCs, operators could potentially bring online tremendous amounts of resources,” Pair said. “Operators could literally flood the markets once again and impact the price depression that we have all been monitoring so closely.”

Concurrent with that huge inventory of DUCs, operators will be testing new completion technologies and systems to optimize production, which could add to the increase in production and stunt any price rise.

Operators are focusing on increasing their DUC inventory in 2016. In the Bakken, for example, Continental Resources stated in its earnings release that it is expecting to have close to 200 wells in its inventory by year-end 2016, she continued.

“The DUC supply that we do have on hand allows production output to be very elastic, which could in turn suppress overall prices once the market has moved past the breakeven threshold if the shale industry reacts at the escalated pace that we’re anticipating,” Pair explained. “The largest factor upon which general market dynamics hinges is determining that trigger point where shale operators will begin to deplete their inventories or determine if they are going to be a little more conservative.”

The largest growth in the Stratas DUC inventory has been within the Appalachian region. Outside of that region the majority of DUCs are in the oil/liquids producing regions such as the Midcontinent, Gulf Coast and Permian Basin.

In 2012 a well remained a DUC for an average of 60 days. In 2014 the average increased to nearly 90 days. During the times of lowest oil prices, a single well could average more than 150 days as a DUC, she continued.

With high decline rates for unconventional wells, operators have to take a different approach to completions so that the wells can produce for more than 25 years to be useful wells, said Rob Fulks, director of completion optimization at Weatherford, speaking at the Hart Energy breakfast. It was always anticipated that these wells were going to need a booster shot.

If the wells had been stimulated every six, seven or eight years, “refracturing would be a much larger part of the business. It could be 25%, let’s say, of the overall pressure pumping business. That never transpired,” he added. Hans Christian (H.C.) Freitag, vice president of integrated technology, Global Products and Services at Baker Hughes, said, “Times are still tough now in spite of the oil price being at $44 per barrel [on April 21]. North America is where all unconventional technology is being developed. This is where the world looks for new technology. What we have that is unique to the U.S. is thousands of operators, which means we have a distributed risk.

“If each operator just did a stimulation treatment on one of their DUC wells at the cost of $2 million, $3 million or $4 million, we would learn from 3,000 treatments. The knowledge gained would be dramatic. The U.S. is in a unique situation when it comes to distributed risk of experimentation,” he emphasized. “This is where the industry has to rally and have a look at what we should be doing.”

What the DUCs represent are a huge number of wells awaiting completion. Even with the lower oil prices, operators continue to test new technologies and processes for reducing risk at the lowest cost.

Refracturing vs. restimulation
The word refracture is being abused because refracture really means the operator is pumping another proppant stimulation. “Even if you had initially used high-conductivity proppant and a scale inhibitor, sometimes you’re just rejuvenating the conductivity of your fractures with xylene, solvent squeezes or acid-for-acid soluble problems. There are some acid-fracture plays out in the field that obviously would restimulate with acid and solvents vs. pumping a proppant stimulation,” said Tim Leshchyshyn, president at FracKnowledge, at the Hart Energy industry breakfast on refracturing.

Those methods are restimulation, except that doesn’t sound as hard and solid as refracture, he explained. “There are other methods that involve treating the completion rather than the inside of the well.”

There is an old inventory of tens of thousands of wells that are refracture candidates that were not completed with the idea of refracturing. Some operators like BP plan to do a refracture within 18 months as it does infill drilling. BP plans refractures when it does the initial completion, which makes it a lot easier, he explained.

Well optimization
Talking about well optimization means figuring out how to complete and fracture these wells—what tools to use, how many stages to put in the well, how many clusters per stage, how much and what type of proppant, what type of fluid, etc., Leshchyshyn told E&P. “Those things go into what gets me my maximum profit, net present value [NPV] or EUR, depending on our client.”

Well optimization is usually an NPV calculation. “The most popular time period is a three-year NPV, which in conventional wells was 75% through the lifetime of the well. If you haven’t made your money back by then, it’s not a good well,” he explained.

For horizontal wells companies will do a profitability value for the 15- to 25-year mark of the well, the NPV for the life of the well or the EUR, which is a better way to go for big oil companies, he continued.

“If you’re raising capital to build a small oil company, your investors are looking for that three-year exit point, and you’re probably wanting to stick to the three-year mark,” he added.

People have shifted their mindset over the last five years from tougher conventional wells into unconventional wells. “You’ll find that people have arrived at a high number of stages, high proppant intensity numbers, larger proppant volumes per stage and larger fluid volumes. They arrived at these numbers at the end of the five-year learning cycle,” he emphasized.

Not all companies are willing to take the time to learn how to be successful in refracturing. Some operators take their first guess on how to refracture and give up after a short while. There is a technology barrier to exact engineering and prediction for many styles of refracturing.

“I do know one or two operators who call them pump-and-prays. Statistically it takes up to five wells to get any new-play wells or refractures on existing wells figured out,” Leshchyshyn said.

“People who are just into the risk of trying it on one well and say, ‘Oh, that didn’t work; I’m stopping,’ are the operators for which refractures are not working,” he added.

BP pushed ahead with its refracturing. The company did its five or six failures, not total failures, and improved, understood, improved, understood and improved. “There were hundreds of wells that were tried before people figured out the slickwater and multistage fracture initial success that started off the unconventional industry,” he explained.

“People who are just into the risk of trying it on one well and say, ‘Oh, that didn’t work; I’m stopping,’ are the operators for which refractures are not working,” Leshchyshyn added.

Planning wells for future refracks
FracKnowledge tracks all fractures and refractures where people are trying to figure out if it works. “Operators can look at some history to de-risk their ideas for refracturing,” Leshchyshyn explained. “You always like to see how other people have tried it first and not start from ground zero in a vacuum.”

By tracking public information, the FracKnowledge website can show an operator that a particular technology or process works, and people can verify the data themselves. With the data they can learn how to do their first refracture and how they should calibrate their models. “People need to see that it works and how well it works. And, no matter how well you plan your refracture, refractures operationally need to be supervised minute by minute as the degree of predictability of field behavior is reduced. This is called satellite tracking,” he continued. Or one can be at the actual well site.

Current optimization is important to how to design a refracture. “You’re trying to turn your old well into your new well. Every well has a different situation depending on how badly it was fractured in year one compared to what you found out worked best in year five. It doesn’t matter which formation you look at.

“If you track year one to year five in any formation, the number of stages, amount of total proppant, and total fluid and production goes up dramatically,” he said.

“Similar to drilling new wells in the formation, you’re accessing new reservoir and new rock so that you get new production. Refracture challenges involve zonal isolation or diversion technologies,” he continued.

“Some conventional vertical wells have been refractured as many as six times. Horizontal wells haven’t been refractured more than twice yet. Most of industry is really copy-and-paste engineering, and they like to see other people succeed or fail,” he emphasized.

Developments that are needed
The industry is in an early stage when it comes to refracturing horizontal wells. “We have refractured vertical wells for the last three decades. We are also at an early stage when it comes to diagnosing where we want to refracture. The results of many wells have been somewhat disappointing when you go with a Hail Mary or pump-and-pray approach,” Freitag said. “There are more diagnostics that are needed.

“Once you’ve done the diagnostics and identified where you have some hydrocarbons behind the casing that haven’t been produced yet, then it would be ideal to be able to go in and be truly selective and just stimulate one individual zone,” he continued.

“The marriage of science, research and engineering through the pressure-pumping schedules that are needed to make this happen is still in its infancy. There’s still a lot more work that needs to happen before the second wave of the unconventionals goes across North America,” he emphasized.

For example, recently Pioneer Resources mentioned it was putting clusters every 4.6 m (15 ft) apart, believe it or not. When wells were originally completed they were perforated every 152 m (500 ft) or farther. “That shows how the industry has evolved. It also shows how we’re still very much in an experimentation stage. It’s all empirical knowledge so far,” Freitag explained.

“I think we are now at a point where we need to rethink our understanding of unconventionals. I think there is nothing to stop us from bringing the recovery up to 15% or 20% or even higher,” he added.

Baker Hughes has come out recently with a perforating gun that shoots a large charge into the high side of the wellbore and two smaller charges off to the sides, with nothing below. It is not the normal type of spiral shot distribution.

“We’re doing that to focus the fracture a lot more,” he continued. “At the end of the day it is geomechanics. We have to do everything we can from an engineering point of view to focus the fracture growth in the desired direction. We have 20 to 25 examples of doing high-side tracking with increased success in terms of EUR and production rate,” Freitag said.

Fulks pointed out that “there is an emerging class of new operators primarily funded by venture capital that is looking at this business in a whole different way. They want to go in and take over an unconventional field—whether it be the Haynesville or the Barnett or whatever—and rejuvenate it on several levels.

“The first thing they want to do is make sure that the artificial lift that is in place is absolutely the best because that’s a quick return on their dollars. The next thing they’re going to do is refracture the candidate wells, which will give them another quick return on their dollars. Then they’re going to rejuvenate that field to a certain extent and flip it again. They’re not going to stay with the field over its life,” he said.

Contact the author, Scott Weeden, at slweeden@hartenergy.com.

Read this month's other cover stories:

Centralizers benefit from optimization

Acoustic telemetry system helps reduce costs for complex wells

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