The Great Shale Shut-In: Uncharted Territory for Technical Experts
As tight-oil producers move to curtail production, hard-to-answer questions are being raised about how shuttered wells will come back. The issue reveals key uncertainties about the delicate flow paths that define unconventional reservoirs.
Facing crippling crude prices and a historic supply overhang, the once-booming US shale sector is for the first time being forced to shut in thousands of wells across its most prolific tight-oil basins.
Accurate production data lags by months in the US, but analysts are reporting onshore shut in totals to be somewhere between 100,000 to 400,000 B/D. The largest cuts announced so far come from ConocoPhillips which said in addition to its Canadian oil sands projects that it is shutting in nearly the entirety of its US onshore position—some 2,400 wells, representing about 165,000 B/D.
A projection from commodity researchers at JP Morgan Chase suggests as others follow suit these curtailments may reach 1.5 million B/D may be shut in by June.
The business driver behind the so-far uncoordinated effort is crystal clear. Much less so is how the development will play out when prices bounce back up and the wells are turned back on.
That part is a subsurface mystery.
A new report by Wood Mackenzie published last week summarizes several factors shale producers are dealing with as they undertake painful but necessary shut-in campaigns. The chief risk listed for subsurface considerations was reservoir damage caused by a loss of relative permeability.
“Routine short-term shut ins—days to weeks—for maintenance or ‘frac hit’ avoidance seem to cause few reservoir problems,” the report reads. “But widespread shut in of tight-oil horizontal wells is rare, so the long-term reservoir response is uncertain.”
As the situation unfolds, many in the petroleum engineering community have taken to social media and online SPE forums to ask practical questions about how best to shut in wells, which ones to shut in, and how to restart them again. Some of the answers hinge on how long the shut-ins are meant to last; 2 months or 6 months could make a big difference.
“I don’t think anyone really knows for sure what will happen,” said Eric Gagen, who has spent more than a decade restoring shut-in wells offshore and in shale plays. The petroleum engineer served as a technical manager at a coiled-tubing company until industrywide staff reductions began this month. He said long-term shut-ins on the order of several months could introduce a range of issues that span surface equipment operations to “unexpected” downhole chemical reactions.
At a minimum, Gagen said operators shutting in for months should expect to see significantly higher water cuts upon restart. In most tight-rock reservoirs, especially those that are oil-wet, water becomes more mobilized than oil over time “and shut-in wells have a tendency to produce even more water as they are put back on production.”
Undulating wellbores—a common feature of horizontal wells—may exacerbate this issue. In the worst of outcomes, a water-loaded well produces such an excess of water that remediation efforts stop making economic sense. At that point, the well is a candidate for a plug and abandonment operation.
For the conventional world, decades of learnings on these matters are easily accessible via industry literature. Those working in the unconventional world are not as fortunate.
There are no established best practices. There is a dearth of case study and technical papers. All for the fact that the shale revolution has never seen such large-scale shut-ins.
In terms of candidate selection—which assumes an operator has the luxury of triaging its inventory—one bit of advice is to not overthink the problem. “Don’t try to be too clever,” said Lucas Bazan. “Just make decisions based on what you know and look at your data for that—this is the time do the homework.”
Bazan, the president of completions-focused Bazan Consulting, elaborated by saying he would first analyze how a well flowed back and then see how it responded during those routine, short-duration shut-ins to form a picture of the wells likely to best respond to a longer pause.
Lyle Lehman, an industry-recognized completions expert and founder of Frac Diagnostics, described the task of unraveling all the implications of unconventional shut-ins as “a can of worms.”
Unlike vertical well shut-ins, horizontal wells are too costly or technically challenging to isolate. Lehman pointed out that while their ability to expose thousands of feet of thin reservoir makes these wells economic, it also increases the effects of reservoir inconsistency, leading to an issue known as “crossflow” which will be amplified during an extended shut-in period.
“When you shut in, everything tends to crossflow,” along the lateral of the well, said Lehman. “Then, when you turn the well back on, that is going to change the stress on the propped fracture and this effect increases the potential for damage to the fracture conductivity.”
The crossflow effect is difficult to monitor but almost guaranteed to take place. As dictated by the third law of thermodynamics, fluids from higher-pressure fracture stages will migrate into a wellbore’s lower pressure stages until a state of equilibrium is achieved. On the upside, this rebalancing means a depleted fracture gets time to recharge—which may bode well for its odds of returning to trend later.
On the other hand, raising stress on the proppant pack in such a way becomes a bigger risk each time it is done, said Lehman, pointing out that economic-driven shut ins may happen more than once over the life of many existing shale wells.
Bottom line: “The opportunity for damage is very high.”
A production facility in the Permian Basin where production from dozens of mult-pad wells will be halted while crude prices remain lower than the region's break-even prices. Source: ConocoPhillips
Lower-Producing Wells Won’t Be The Only Ones
Of course, many tight-oil producers have no choice but to accept the risks involved.
To address cratering demand caused by the COVID-19 pandemic and drive oil prices higher, the nations that form OPEC+ will begin shutting in their own wells in a coordinated cut of 9.7 million B/D on Friday, 1 May. The bulk of these reductions, a combined 7 million B/D, will come from conventional oil fields in Russia and Saudi Arabia.
But it will take an additional 10 to 20 million B/D of reductions from non-OPEC+ producers to keep the world’s storage tanks from topping out. This has turned the industry’s attention to US tight-oil producers to see how fast they can begin their share of the much-needed drawdown.
So far, only a handful have announced shut-ins but more are expected to be revealed as earnings reports are shared with investors in the coming weeks. One of the first to go public on this front was Permian Basin-focused Parsley Energy which said it shut in 400 low-producing wells in early April.
Wood Mackenzie estimated that on average, Parsley’s shut-ins involved wells producing under 6 B/D—qualifying them for what is known in the industry as stripper wells. Based on the firm’s analysis, it is a step in the right direction, but only a baby step.
“If all of the wells in the US making less than six barrels a day were shut in then it would only cut about 400,000 B/D of production,” said Julie Francis, a principal research analyst at Wood Mackenzie. A trained geologist, she also led the firm’s study into the various shut-in considerations.
Putting the 400,000 B/D figure into context, Francis said tanks in Cushing, Oklahoma—the biggest storage hub of US tight-oil—was filling at an average rate of 720,000 B/D earlier this month. If the inflow does not slow down, Wood Mackenzie projects Cushing will approach its operational limits by mid-May. The same will be true for the rest of US aboveground storage by mid-July.
“So, just shutting in low-rate wells does not remove enough oil from the system to fix the storage issue,” she said, underlining the inevitability that better-producing assets must soon be taken offline too.
Likely exceptions include the newest wells that are naturally flowing wells—the perceived reservoir risk of shutting in these wells is considered high by several experts.
Also not on the short list according to the Wood Mackenzie study are wells about 1-year old that are equipped with expensive electrical submersible pumps, which Francis noted are known to be “very finicky” and “difficult to shut down and then bring back again without risking damage.”
Better candidates include medium-aged wells that are on rod lift systems that involve some of the lowest costs and complexity to shut in.
What Is a “Good” Shut-In Candidate?
At first glance, it may seem like perfect business sense to focus shut-in campaigns on the least-profitable producers just as Parsley has begun. This way, operators can spare those wells that provide the lion’s share of the cash flow needed to cover overhead costs and pay down debts.
But, as mentioned, shutting in higher producers has a multiplier effect in removing excess barrels from the storage bottleneck. Engineering experts say these wells are the best candidates for other reasons.
Buddy Woodroof, a technical manager at Core Laboratories’ ProTechnics division in Houston, an industry-leading provider of fracture diagnostics, said companies must juggle different business needs vs. the subsurface conditions. The two will not always line up.
Giving an example of one trade-off likely to be commonplace, he shared that high-water-cut wells “are bad candidates from a restart perspective but good candidates because of the fact that you don’t have to cover the water disposal costs.”
Woodroof is in the camp that holds whenever a multiphase flow well—which all tight-oil wells are—is shut in there is risk of damaging the delicate, nanodarcy flow paths that define most unconventional reservoirs.
In his discussions with petroleum engineers, Woodroof said the conversations always return to which wells will have the best chance of restarting, regardless of what they are producing today. “Probably the most important point I can make is that good wells are the best ones to shut in. Bad wells, you may not get them back at all, so be cautious,” he advised.
Gagen is among the experts in agreement with this point. He said while in his line of work—workovers and interventions—he most often deals with “the weird ones,” there is one common thread connecting all the best-case scenarios.
“It may be an old truism that good wells are good wells, but when you close good wells they do tend to come back as good wells,” he said. “The things that made them good—high pressure support or low water production—make them easy to turn off and back again. The marginal wells are the ones that are toughest to bring back.”
George King, another completions engineering expert and advisor with Viking Engineering, has been studying the issue for his operator clients to quantify what a “good well” might look like in terms of bottomhole pressure.
“If you get down to 0.2 psi per foot of reservoir pressure, then there will be some problems getting that well back on,” he said, adding that, “you’re going to be swabbing for a long time, lifting it with nitrogen, or treating it.”
In conjunction with this report, JPT has published a synopsis of technical considerations coauthored by King. It covers dozens of nuances that include which kill fluids to use on the front end of the process and the possible effects of incompatible fluids mixing downhole for long periods.
The latter subject is relevant to stacked formations where it is common for wellbores and induced fractures to enable comingled production from multiple zones. Negative effects of this can be mitigated while flowing a well. Left to sit in the reservoir, the mixed fluids could lead to buildups of paraffin, asphaltene, or other emulsions both inside fractures and at the perforation.
King noted that due to the complexity of the topic, his list of technical considerations is not exhaustive.
He is working for operators to develop customized workflows based on their historical data, which then guides the process from candidate selection, monitoring during the shut-in, and finally to the restart phase.
Core samples, drill cuttings, water analysis, and logging data are some of the first sources engineers should turn to for insights. “You have to look back at the rock fabric to see what's important,” he said. “There is no one component—there will be a bunch of them.”
Pressure, Stress, and Conductivity
For unconventional gas producers, the risks being discussed around shut-ins are considered to generally be the lowest—especially for dry-gas fields. Ample industry studies have shown that in shale gas plays in the US and Canada shut-ins can actually be beneficial. One of the most recent examples came from Apache’s Permian operations. The company shared details about a 60-day shut-in of gas and condensate wells that “surged” when production resumed.
The generalizations become less useful when the focus is placed on tight-oil reservoirs. Bazan pointed out that there are different views across the sector on the effects of shut-ins on the oil wells because each is based on experiences that apply to particular geologies.
“You have both cases. Operators will say you do lose reserves and then some will say you don’t—that a shut-in simply doesn’t matter,” he said. “But this is a case where wells that might have been flowing for 6 months, 1 year, or more than 2 years are going to be shut in for some percentage of their producing lives that’s not trivial. What does that do?”
An example of a formation where wells may better withstand a prolonged shut-in is the Wolfcamp Shale, the Permian’s most-prolific and -targeted horizon. The Wolfcamp is slightly overpressured compared with other formations, which means wells benefit from starting with higher pressures in the first place.
Pioneer Natural Resources, a pure-play Permian operator focused primarily on the Wolfcamp, has been outspoken on this issue. It reported to Texas regulators that the risk of shut-ins for its wells is low to nonexistent, even for a 6-month duration.
John Thompson noted that Pioneer have at least 800 wells with downhole pressure gauges in the Wolfcamp, which might place the firm in the best position to have such confidence.
Thompson, a specialist in rate-transient analysis, said the Wolfcamp represents an area where operators could shut in newly stimulated wells without risking much damage.
“What some are not recognizing is that when you shut in a well that’s naturally flowing and build its pressure back up, as you turn it back on it gives you a kick—so you produce at a higher rate than before for a period and yes, the odd one may be damaged,” said Thompson who is a co-founder of unconventional reservoir engineering training firm Saga Wisdom in Calgary.
The risk for the newest wells in overpressured formations is if they are brought back without a choke strategy the sudden pressure change could “hammer” the propped fractures, he said.
Regarding older assets, Thompson is optimistic that the majority of tight-oil wells on pump will prove to be resilient during this episode of mass shutdowns. He argues that the effective stresses have largely “played their role” for wells in a late-life production phase, limiting the potential for damage from geomechanical effects.
The damage mechanism of concern is known as stress cycling, which happens as a well goes from flowing to not flowing. While flowing, bottomhole pressures are relatively low compared to the sudden rise in pressure that comes as the wellhead is closed.
One way to assess the potential for stress-cycling-induced damage may be to look back at how a well was brought on line in the first place.
To promote initial production rates, many unconventional operators use open-choke strategies or “fast back” to allow horizontal wells to flow unconstrained during their first few weeks of life. Other companies have over the years adopted data-driven choke management strategies. Called “slow back,” these more conservative approaches are done in large part to prevent fractures from compressing too much and to keep proppant inside them during the flowback.
Nur Wijaya is studying the topic as part of his PhD program in reservoir engineering and geomechanics as a research fellow at Texas Tech University in Lubbock. Specifically, he is running a series of numerical simulations to understand the late-life effects of proppant conductivity based on the two flowback methods.
The work, based on field data and numerical simulations, is not published yet but Wijaya said it supports the idea that operators should consider those wells brought on gently as having the best protection against stress cycling, even in the middle of their productive life.
“If we slow-back the well, we see that it tends to preserve the conductivity of the fractures, especially the portion of the fractures that are closest to the perforation,” he explained. “If we fast-back the well, all of the fractures in the vicinity of the perforation will experience severe conductivity deprivation.”
Proppant conductivity is an important technical consideration for another reason. Since the last downturn in 2015, the US shale sector moved quickly to almost full adoption of in-basin mines that provided operators with cheaper but lower crush-strength sands. While in-basin sands have not been strongly linked to poorer well performance in various studies, some in the completions sector point out that the impact of long-term shut-ins and cycle stress on these proppants is not well understood.
“This is an opportunity to test all that,” said Lehman while making the point that cycle stress could compact a producing fracture slightly and lower its ability to contribute. If the stress is high enough, then the fracture will “pinch off,” blocking a large portion from ever producing into the wellbore again.
Lehman cited a study he completed while working with Halliburton years ago showing that in the Eagle Ford Shale proppant pack damage from cycle stress could be mitigated when a ceramic coating was used to strengthen the sand grains. “But nobody uses that coating anymore,” he said. “Everything in the unconventional world has to be cheap, which means you don’t have the luxury.”
More on JPT Online
In conjunction with this report, JPT has published a synopsis of technical considerations coauthored by George King (Managing Risk and Reducing Damage From Well Shut-Ins). It covers dozens of nuances that include which kill fluids to use on the front end of the process and the possible effects of incompatible fluids mixing downhole for long periods.