Shale Well Interference: Spaced Out

[Editor's note: A version of this story appears in the November 2020 issue of Oil and Gas Investor magazine. Subscribe to the magazine here.]

The near-mythic status of the U.S. shale revolution has long been rooted in the premise that North America’s huge arsenal of wells could sway the world’s markets and break the rules set by the all-powerful OPEC pact.

The truth is that shale inventories are already beginning to shrink. The persistent pounding of E&Ps by the market and the ongoing frailty of commodity prices have cut economic support out from under drilling programs that were designed to pack as many wells as possible into a section.

Along with economics, the irreconcilable estrangement of primary and infill—or parent and child—wells in the field continues to be the difficult reality crashing into shale dogma. For years companies have worked at achieving tighter spacing while, if not overcoming well interference, at least mitigating it.

Results vary by basin and geology, but in general the more densely drilled a section is— at, for instance, 500-ft intervals—the worse the child wells and the possible degradation of the parent wells.

“From what we’ve observed, a lot of the industry is not accounting for flow regime changes, and we’re seeing that be more and more of a problem,” said Thad Toups, president with Haas Petroleum Engineering Services Inc. in Dallas. In late September, Toups presented a case study to the Petroleum Engineer’s Club of Dallas that zeroed in on deterioration of parent and child wells in New Mexico.

“Our worst clustering includes the tightly spaced child wells. This is going to be greater than eight wells per section (in the same zone) drilled mostly as child or co-completed wells,” he said. “And then our optimistic and our best clusterings are going to include the widespaced parents and stand-alone wells.”

Toups said that while some companies may not have publicly recognized the magnitude of well interference, which presents a sometimes greater than 30% reduction in EUR, “If you’re in the technical reserves [area], I think it’s understood.”

The repercussions of 2020’s great energy famine have reached a point of no return, in some respects, for shale players. Some public E&Ps have abandoned their furious drives to squeezing as many wells as possible into drilling sections. Others are capitulating. E&Ps have sought bankruptcy protection in 2020 for $53.7 billion—a value greater than the past three years combined.

Concho Resources Inc. has already started to transition to a wider well spacing program compared to 2019 and is now more in-line with 2018 and 2017, according to a September report by Barclays analysts. (Concho has since agreed to be acquired by ConocoPhillips.)

Cimarex Energy Co. likewise signaled a pullback in spacing, with Simmons senior research analyst Mark A. Lear likening the spacing decision to owning up to “past sins.”

Simmons data analysis had confirmed performance degradation across the company’s asset base in 2019, which coincided with increased well density and small completions.

With wider spacing and increased completion intensity in the Delaware Wolfcamp, Cimarex will likely see better well performance, Lear said in an August commentary.

“With eight to 10 wells per section resulting in some overcapitalization of its assets, [Cimarex] … expects to recover the same amount of resource moving to seven to nine wells per section,” Lear said.

Other companies are already making tough choices as the price of a barrel of oil remains in the $40 range.

Ryan Keys, president of Permian Basin operator Triple Crown Resources LLC, said potential for interference is a 3D problem in stacked plays. Without enough vertical space, the need for economic performance overrides conversing inventory.

In the Wolfcamp, at current prices, that means focusing on one or two benches instead of five.

“Unless oil prices double, you’re basically sacrificing that inventory forever,” Keys said.

Infinite reservoir

During his well-spacing presentation, Toups quoted astrophysicist Neil DeGrasse Tyson regarding the “good thing about science.

“It’s true whether or not you believe in it.”

And it’s in cosmic terms that Toups describes wells.

“When you first drill a well, it’s going to feel like it’s in an infinite reservoir. It feels like it’s drilling the whole universe,” he said.

Well production spikes up, accelerating like a racecar on the first straight of a track. But then the well reaches a “boundary,” usually the individual stages that begin to communicate. At this point the well has reached the End of Linear Flow regime, and the decline rates increase. Inevitably, things begin to interfere. In the case of wells drilled too closely together, the inference is literal. The wells began to compete underground for the same molecules, pulling them in different directions.

Finally, the well begins to “feel all of its boundaries,” Toups said, and begins to produce down like a conventional reservoir. The tighter the wells are spaced, the sooner the well reaches this Boundary Dominated Flow regime.

“The key point here is production forecasting accuracy improves when you honor these flow regimes that are changing over a well’s life,” Toups said.

It wasn’t until additional data began to appear that the realization struck petroleum engineers that “We’re getting the PDP [proved developed producing] forecast wrong a lot. So, let’s go back and try to understand how to do that better.”

However, the science behind shale reservoirs and the economic potential of concentrated well density began with more assumptions than evidence.

Scott Rees, chairman and CEO of Netherland, Sewell & Associates Inc. (NSAI), said that early on, wells were drilled primarily to hold acreage, which provided large amounts of data for isolated parent wells.

In cases where a second well had been drilled, the wells might show little to no signs of early interference, but with only two wells in a section, they were likely not representative of results if the area were more fully developed at that spacing, and this still reflected very limited data for conclusions on spacing.

“You had very limited data for the second, the children, wells,” he said. “With such limited data, we all had to extrapolate a bit, but we could see evidence through the child well performance that those wells would have less total recovery than its offsetting parent well.”

There was, particularly for smaller operators, what Rees called “technical tension” between what Netherland Sewell considered proved and what companies thought they could produce. Netherland Sewell’s primary job was to assess the proved, or most certain, reserves, taking into account the company’s development plan. However, the company’s business plan normally incorporates its most likely expectation of recovery per well, which is more equivalent to the proved plus probable categories.

Telling a company “No, the data only has proven this, not proven that yet” happened. “It made for some interesting conversations,” Rees said.

“Luckily in the early days, because of the immaturity of the unconventional plays, the proven undeveloped locations and reserves were, by definition, conservative. Whereas the clients’ and the public stock market’s valuations were more based on an expected case as set out in PowerPoint [presentations] than on the proved reserves,” Rees said.

In retrospect, those disagreements weren’t “the end of the world if we said, ‘For this pilot, these locations, we think your proved reserves could be 20%, 30%, less than what you’re saying publicly as of right now,’” he said. “At the time, increased horizontal well lengths and improved completion design from year to year were allowing companies to have realistic expectations they could achieve better per-well ultimate recoveries.”

Company presentations stated the most likely business case. What companies actually put on the books was proven and reasonable, Rees said.

Companies and NSAI looked for “analogies of tighter spacing” to support their reserves case, with the recognition that local geology in a play can vary widely even when separated by a few miles.

The challenge was and is to incorporate and understand the impact of the changing horizontal lengths, completion practices, well spacing, producing practices and geology across different areas and benches. Rees said their role was to determine what had been proven in this area and zone and what could be included by analogy as clients surveyed nearby wells and surmised, “that should work really well in our area.”

As basins were explored, oil and gas companies in every basin conducted or closely observed neighboring downspacing tests. Rees said that companies are driven by economics to determine optimal spacing. Besides recovery per well, the pricing outlook has a major impact on well economics. “If prices had stayed where they were, that was probably not a bad thing to drill more wells,” he said.

In 2016, Devon Energy’s Thistle spacing pilot tested 400-ft vertical spacing in the Leonard Shale. Throughout the history of the STACK, operators plowed through eight to 14 wells in the Meramec Formation.

But perhaps the most infamous spacing test was Concho’s Dominator Project, a $250 million boondoggle in Lea County, N.M., that was bent on cramming in wells with horizontal spacing of about 230 ft between wells. Most wells in the area, at the time, were drilled 600 ft to 700 ft apart. After solid initial rates, the Dominator’s 23 wells petered out. Bernstein’s Bob Brackett, writing about the 2019 Dominator, said Concho took a risk that, at the time, caused the market to shave $4 billion off the company’s value.

“Moonshots are expensive. If successful, Dominator had the potential to ‘unlock’ 50% incremental locations,” Brackett said. “Moonshots are risky. But we argue that the moonshot is behind us and the conventional development ahead.”

Keys, whose acreage is on the Midland Basin side of the Permian, was initially shocked by the results and the closeness of the wells Concho drilled.

“I was like, ‘My god, you just broke the Wolfcamp,’” he said.

But the tests were also valuable to other operators.

“There are some very high-profile tests that are failures. And thank goodness. Because we would have destroyed a lot of capital if we all tried it,” he said. “So, we never got that aggressive. But we are grateful to Concho for providing the industry a useful bookend.”

Space economics

Christopher Kalnin, CEO of BKV Corp. and Kalnin Ventures, with operations in the Marcellus and Barnett shales, said well spacing has the potential to rewrite assumptions about natural gas prices.

Partly, he said, that’s because of diminished oil well inventory in the Permian Basin, resulting in less production of associated gas.

“I think that’s been the cause for the rally, honestly, in the gas markets for the last couple of months, from where we were early in the year,” Kalnin said.

Kalnin Ventures has analyzed the relationship between oil and gas prices in domestic onshore. “What you see is that in order for associated gas to really grow, for example, in the Permian, you need $50-plus per WTI barrel of oil to start adding associated gas into the system,” he said. “And then on top of that you need pipelines.”

Kalnin also said gas plays may have to reckon with their own spacing problems.

“This issue of overspacing wells, stealing gas from each other’s wells and overstatement of reserves, is quite significant,” he said, adding that Appalachian producers inventory appears to be “hugely” overstated at current prices.

“We could make this work with higher prices,” he added. “But at the current price, we’re just not going to bring on these wells.”

Beyond the physical constraints below ground, money and economics are a primary motivator for how wells are spaced. Companies’ fidelity to investor cash flow demands is partly driving the down spacing of wells as commodity pricing remains essentially punch-drunk.

As Bernadette Johnson, vice president of market intelligence for Enverus, explained at Hart Energy’s DUG Permian conference, tighter well spacing draws out higher volumes. In the Permian, for instance, EUR data suggests that tightly spaced well programs generate about 60% more volume—but require 100% more wells.

But in the Permian, spacing between wells has steadily declined since 2019. Child wells at first showed higher productivity, likely because of advances in completion techniques.

A more detailed analysis, however, showed that as spacing got tighter between parent and children wells in the Wolfcamp, by 2017 hydraulic fracturing jobs were big enough to negatively impact child well initial production, Johnson said.

Even though spacing started to widen again in 2018 and 2019, productivity didn’t increase in the children wells, suggesting that operators are beginning to run dry of Tier 1 acreage.

Those details aside, the “cash-flow math” simply doesn’t work anymore, she said. Enverus found that wells spaced between 1,110 ft and 1,220 ft produced the highest EURs in the Permian.

Keys said well spacing is simply a function of price. But with current drilling, the economics aren’t going to be great even at higher oil prices because of the impact to reserves. As he thinks about his peers, it’s clear that, theoretically, many of the DUCs in the area work economically.

“There just aren’t many frac spreads out there completing the DUCs, so it looks like there isn’t going to be a wave of DUC completions,” he said.

Keys speculates that many of the DUCs, especially in the Permian, may never be completed. Wells drilled from 2016 to 2018 were perhaps drilled too tightly and, after the Dominator debacle, companies might conclude, “‘That’s not a great outcome. And it’s better sitting on the balance sheet as a DUC, as theoretical value, than actually turning it into a production,’” he said.

But the inventory drain is real. With Wolfcamp A and B locations separated by 300 ft vertically, there’s no way to conserve the inventory at current prices.

“We’re basically sacrificing all that [Wolfcamp] A inventory right now because we are focusing on the B, and we want to make sure we get good economics. It’s unlikely we’ll ever get back to that A inventory because of the parent/ child risk,” he said.

If prices scale up dramatically, it’s possible that some areas will eventually realize the hypothetical wells companies once promised.

But at $40/bbl oil, “You’d basically have to defy gravity in order to avoid destroying a lot of inventory. It’s not possible, so there will be a reckoning. There will be a scarcity of quality locations sooner than most expect.”

Had prices not dropped because of the pandemic, the previous spacing by companies probably would have supported many drilling programs.

However, at current prices, drilling fewer wells per section makes sense, Rees said. And if prices were to rise again, say over the next five years, to $100/bbl, economics improve for more tightly spaced wells. Companies would have to overcome more material depletion and interference issues for new infill wells than if they had drilled an area on tighter spacing all at the same time, Rees said.

Returning to those areas that have leaked off high pressures to offsetting producing wells is going to be something companies will have to optimize over time.

“No matter what you’re doing, you’re going to be wrong,” he said. “Prices go up, you should have drilled more wells. Prices go down, you should have drilled fewer. Given the price cycles we have seen and will see again, the oil and gas companies are going to get criticized either way.”

[SIDEBAR]

Inventory and Redeterminations

If a company’s well inventory shrinks, it usually follows that its borrowing base does as well. But scaling back well inventory doesn’t necessarily mean more pain during redetermination season.

Steve Hendrickson, president of Ralph E. Davis Associates, an Opportune LLP company, said he expects reduced drilling density assumptions to have a small impact on borrowing base redeterminations and that “They may actually generate a positive impact.”

While each borrower faces its own set of circumstances, Hendrickson notes that lenders give relatively little value to proved undeveloped reserves (PUDs) in their borrowing base calculations.

“It’s often the case that the borrowers’ undeveloped inventory isn’t all booked as proved. Changes to the probable undeveloped locations shouldn’t impact the borrowing base materially,” he said.

Reducing drilling density would reduce the remaining drilling inventory, but the reduction would occur at the end of the drilling schedule. “Due to discounting, the locations at the end of the drilling schedule have the least value,” he said.

And reducing the drilling density may result in wells with higher recoveries per well. Improved economics would be favorable for the remaining inventory and, if the results were as expected, could “lead to the replacement of production with fewer wells and less capex in the near-term. That could be a positive for the borrowing base in the future.”

Buddy Clark, co-chair for Haynes and Boone LLP’s Energy Practice Group, had a different take with the same result. Clark said that to the extent producers upsize from their well spacing due to well interference, the future value of PUDs could be reduced. However, Clark said that banks have already severely restricted any borrowing base credit for PUDs.

“The impact of increasing well spacing may not be as great as it would have been when banks were giving some [borrowing base] credit for future wells,” he said.