[Editor's note: A version of this story appears in the December 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]
The idea of a successful oilfield development program has not changed over the 150-plus years of hydrocarbon exploration, but the tools used and the knowledge required that provide the means to the end continue to evolve. The goal remains to drain the highest percentage of oil and gas with the least amount of capital investment. Striking a balance between financial outlay and recoverable resource is an ongoing battle. Spend too little and you’re likely to catch criticism for leaving oil in the ground. Spend too much and investors will question your efficiency. The emergence of the development phase in many U.S. unconventional plays has operators still searching for the sweet spot.
In the Permian Basin, operators are challenging the complex geology of West Texas and southeastern New Mexico with aggressive drilling programs designed to find the balance between dollars and volumes—pushing the well spacing envelope in the name of enhanced ultimate recovery and its favorable impact on the bottom line.
Results, however, have not been kind.
The highest profile project testing downspacing limits has been Concho Resources Inc.’s Dominator pad in Lea County, N.M. Instead of the typical 600- to 700-foot well spacing used by many operators in the region, Concho would drill a series of wells with an average horizontal spacing of just 230 feet. The operator lined up seven rigs from a half-dozen different contractors, five frack crews and a big pile of cash across a 1-mile tract targeting the upper Wolfcamp to conduct the experiment. It failed.
Concho drilled and completed 23 wells on Dominator—an estimated $250 million investment. While initial rates were solid, later performance data indicated that the chosen well spacing was simply too dense. The company told investors in August that it would revert to wider spacing for future projects in the area. The news crushed the operator’s stock price. Concho shares sank 22% to close at $75.97, for the company’s biggest one-day drop since 2008, wiping out almost $4.4 billion of market value. Had it been successful, Dominator could have unlocked a significant amount of new drilling locations, boosting inventories already in-house by as much as 50%, by some estimations.
“That was a test both of the intensity of activity with seven rigs and then five frack crews operating simultaneously in a square mile, but then it was also testing a density at that 150% of our resource that’s greater than we’ve ever done,” Concho chairman and CEO Tim Leach told investors in July.
“And so we’ve certainly learned some things about the impact of the inner well communication and spacing. I think, as we have said, from an operational standpoint, the team did a fantastic job executing the project with it all brought on safely as planned and ahead of schedule.
“Clearly, the 30- and 60-day production rates were consistent with our other projects in that area, but the performance has declined, and that’s been clear. It’s just too tight.”
A parent-child relationship
While the full postmortem on Dominator has yet to be written, it is clear that Concho incurred unexpected well interference due to the proximity of the wells themselves—something industry calls the parent-child relationship or, more recently, fracture-driven interactions (FDIs).
Fracked wells in close proximity can impact production volumes as both are ultimately pulling resource from the same reservoir. If the fractures themselves encounter one another, it could prove a boost to one well but a bust for the other. Fractures in a child or infill well will usually follow the path of least resistance—or toward the pressure sink caused by fractures in the parent or primary well, which inherently lowers the volume of unstimulated rock by the infill well’s frack job.
Ironically, the aggressive frack jobs—longer laterals, higher proppant loads and more frack stages—that the industry has favored and resulted in higher IP figures from primary wells could be playing a lead role in the production decline.
Pioneer Natural Resources Co. has been in the Permian for more than a decade and saw the FDI issue crop up when it tested downspacing to around 400 feet back in 2013.
“At that time we were still pretty early in horizontal shale development, but we actually did see the negative impacts of parent-child relationships back then,” said Michael McNamara, Pioneer’s investor relations supervisor, who came from the engineering side of the business. “We jumped quickly back to 800- to 850-feet spacing rather than the 400 feet we tested back then to really mitigate and manage that relationship between parent and child wells. From our perspective, I think that is just one component that needs to be minded when trying to manage parent-child relationships. I think another important component that we have taken a very technical approach on is completion design.”
Using its 6,000 vertical wells in the Midland Basin, Pioneer has gathered logs and seismic data into an impressive database of subsurface information. It considers the data set a differentiator and a strategic advantage over its peers in the region. Learnings have dictated a more controlled approach to completions.
Instead of setting up for the biggest completion for one of its infill wells, Pioneer opts to pump less fluid so that the fractures won’t propagate as far and put the primary well at risk. The operator stimulates closer to the infill wellbore instead of trying to get longer, propagating fractures.
“I think if you aren’t minding your spacing and you’re pumping very large jobs, you are going to see quick, negative impacts in your well performance,” added McNamara.
Time is also a contributing factor as operators march toward shale development. A Raymond James report recently hypothesized that the average infill well being drilled today is coming online at about a 30% lower production rate than the primary, and that the time delay between the parent completion and the infill completion seems to have a significant impact, with six-month delay infill well degradations in the 10% range, while two-year delay wells may suffer greater than 40% degradation.
It makes sense. The longer the primary well is online and actively draining the reservoir, the larger the pressure sink created, and the more likely an inappropriately spaced infill well will lead to a frack interaction (or hit).
All of this has the potential to skew estimated ultimate resource recovery if that number is based on the primary well. That impacts recovery volumes, which impacts return on investment, and ultimately impacts drilling location inventory, and that can result in tumbling valuations.
Seaport Global Securities LLC recently illustrated the impact of well interference on assigned net asset values. If a company has 77,000 acres and plans for 660-foot spacings, that results in 580 locations. Run a couple of rigs, and the present value of future cash flows at strip pricing comes out to $664 million, according to Seaport Global’s numbers. That’s a base case.
Now, if early wells show that well counts and spacing are too aggressive—dropping from eight wells to six per section at 880-foot spacing—the location count drops to 435. As a result, net asset value drops 22%. It can get worse.
If the base case EUR was 495,000 barrels of oil equivalent (boe) per well, upspacing will cause the EUR on the infill wells to take a hit. In full-field development, those EURs need to come down another 20%. That is another 38% hit to net asset value. In total, those two mistakes can cost around 60% of the value from what was originally thought.
Seaport Global analyst Mike Kelly confessed at the recent DUG Eagle Ford conference in San Antonio that Wall Street was seduced by inflated inventory counts, single-well economics and sexy IP rates, and did not fully understand the effects of FDIs.
“It’s been a rough go in the last five years in the space,” he told attendees. “In 2015, Wall Street would give you a valuation that was 8x EBITDA. Today, that’s 4.1x for my coverage universe. There has been massive value destruction here.”
Another problem? As the Permian moves toward a manufacturing operation, the dominant well in the region shifts from primary to infill. The impact on produced volumes could be significant. Bernstein estimates that starting in 2016, child wells drilled in Lea County, N.M., just northwest of Midland, Texas, suffered more from interference than they benefited from technology gains. The impact was roughly a 10% worsening in cumulative output. Researchers warn the impact could range up to 50%.
And it’s not just the Permian. Devon Energy Corp. conducted a spacing pilot in the Stack play of western Oklahoma during 2018. A denser 12-well per drilling unit program was conducted at the company’s Showboat project targeting the region’s overpressured oil window. While initial results were encouraging, the company told investors in July that the results did not meet expectations and that it would “quickly recalibrate” its completion designs and flowback strategy to improve results of future projects in the area. Devon added that its spacing plans on all go-forward activity would be sized at four to eight wells per section in the Stack.
Earlier in the same play, Continental Resources Inc. flowed a promising new Meramec density test, also in the overpressured oil window, at its Compton unit—a 10-well density unit, with five new wells in the upper Meramec and four new wells and one parent well in the lower Meramec. The 10 wells flowed at a combined peak 24-hour rate of 22,032 boe (75% oil) or 2,203 boe/d per well.
Average completed well cost for the nine new Compton wells was approximately $9.2 million, down approximately 28% from the cost of the primary well. Expectations led the operator to suggest EURs of 1.7 MMboe per well. All was fine after 30 days, but the following quarter Continental revealed it saw a rapid decline at Compton, prompting the producer to rein in its per-well EUR estimate to 1.2 MMboe and confess that 10 wells were too many for the unit. The downspacing exercise didn’t work, and the operator’s stock dove 11%.
Dominator, Showboat and Compton all have one thing in common beyond their production shortcomings: Each of these were tests to see if an aggressive well spacing array in developing shale resources could pay off big. While expectations were high across all parties, the results should be taken for what they were—the product of industry experiments.
‘These interactions are unavoidable’
Well interference isn’t new. The issue has been around a long time, even with some of the early vertical wells drilled in tighter formations, like in East Texas. The nature of those wells allowed operators to keep returning to drill offset wells with little to no concern for adverse impact other than perhaps a smallish window of lower pressure.
With today’s horizontal wells, the frack becomes more difficult. The frack “wings” coming off the infill well will migrate toward the pressure sink created by the primary well, and instead of an evenly fracked wellbore, you get one weighted almost exclusive to one side.
“We see these [frack hits] at such distances from the parent well that there is probably no way to avoid them completely,” said MicroSeismic president and CEO Peter Duncan. “Instead, you manage, monitor and try and minimize the effects, but then model to see what the proximity of the wells is going to do for you economically.”
Ideally, operators want some level of frack interaction. After all, if you are pulling resource from adjacent wells that show no level of interaction, then you are likely leaving producible oil in the ground. It becomes a classic “bend but don’t break” scenario. Producers walk the fine line, pushing to free up as much oil and gas as possible with each well without jeopardizing the entire operation.
“That way you know you’re getting the best coverage you can,” explained Scott Rees, chairman and CEO at Netherland, Sewell & Associates. “Plus it’s different on horizontal vs. vertical downspacing if you come back when prices are better 10 years down the road. That’s what used to happen with vertical wells. They’d drill one well per section. Ten years later, when prices were better, they would come back and drill another well. Ten years after that they would come back again and drill. You’d get a little bit less per well, but they could still do it, from a drilling and completion perspective.
“Now with horizontals, if you wait 10 years for prices to get better to come back and drill your infill wells, it becomes mechanically very difficult to drill and complete because of the nearby pressure depletion. When you’re drilling that 2-mile horizontal, you’ve got pressure differential sticking to contend with so actually getting the well physically drilled is difficult. Plus most of the sand you pump during your infill well’s completion will go to the low pressure depleted reservoir rock rather than the new, unstimulated rock. So operators are trying to figure it out now,” said Rees.
Much of the problem might be traceable to the beginnings of land acquisition, when an operator secures an acreage position and soon shifts into getting that acreage HBP. Initially, companies need to determine if any given unit is going to be economic so the tendency has been to drill a big well, with a big frack job, to get the resource moving.
At this point, many would not be thinking ahead to well spacing. The only goal would be to prove the area will flow, from the bottom of the bore straight to the bottom line. These robust frack jobs can result in fractures extending out thousands of feet. So when an operator shifts into development of an area and starts talking about well spacing of 600 to 700 feet, or even 1,200 feet, the company can start to see where problems may arise.
“This is not rocket science,” added Duncan. “Fundamentally what is going on here is that we’re creating plumbing and when that plumbing connects up, fluid flows between the different devices connected to the pipes. We just need to learn how to control how we are building the plumbing and then how to control the pressures within the pipes.
“I think the biggest issue, from my point of view, is that our practice is really one of driving down the road with our eyes closed. That is just the way it is. When one fracks a well and doesn’t watch what’s happening with a sufficient granularity, then stuff happens. Then we’re left waving our arms at what it might be.”
The “plumbing,” as it were, can sometimes have a mind of its own. Subsurface conditions are rarely homogeneous when it comes to formation pressures, natural faulting and the like. It not only can vary wildly from play to play, but from field to field, and sometimes even pad to pad. The result can be a sort of Rube Goldberg-styled chaos of channels and fissures running away from the wellbore, sometimes at great distances and sometimes into each other, referred to as an inner-well interaction.
“With the present systems that we are using, these interactions are unavoidable,” explained Aly Daneshy, president of Daneshy Consultants. “If you want to produce these reservoirs economically, you have to accept that. And trying to fight it, you’re banging your head against a wall. These are unavoidable. The results can be positive or negative. Collection of frack interaction data can provide very important engineering data that we need to raise our fracturing treatments to a higher level.”
The industry has experimented with different ways to combat well interference across the shales. Field work has yielded mixed results at best, but a few options have emerged for operators looking to minimize the impact of completed infill wells on the producing primary well. The approaches vary and have run the gamut from abandoning the primary well altogether to pressuring up the parent to help move the infill fractures away from the original wellbore.
“Papers from BHP showed that they simply shut in the nearby well, but that didn’t work. They got wellbore damage,” said Duncan.
“They tried abandoning, not even bothering with the parent well and just letting it go. That is not a very productive strategy either. They tried keeping the parent well flowing while the child well was fracked to see if they could reduce the pressure—if they could suck hard enough on it to keep it from building up pressure and causing damage near the well. That didn’t help much either.
“They ended up with parent wells that were reduced in their production. They tried small pre-loads. We’re talking one day pumping 1,000 barrels or so and they found that the parent wells generally recovered but, generally speaking, did not recover the full production rate that they were expecting.
“They tried larger loads. Not large enough to cause fracking but bringing it up to two-thirds or three-fourths of original reservoir pressure, and they found that actually worked pretty well. It kept the child treatment from impinging on the parent most of time. They lost production temporarily, but tended to recover and get back to their original production level.”
The issues with all of these active solutions to mitigate well interference impact field economics. The added cost to minimize FDIs, which in some cases can be substantial, may result in driving some smaller players out of the more tenacious shales once the full-field development phase is reached, and in extreme cases could result in financial stresses leading to insolvency. Given the current state of affairs between Wall Street and the oil patch, access to capital is not as robust as it once was.
Other methods implemented included refracking, but that was found to create more frack communication and allowed more opportunity for well-to-well interaction. There was also the notion of co-development of the wells—completing all of the wells in a section at the same time using zipper fracks and offsetting clusters. This is expensive, but also an encouraging solution.
What has revealed itself as being the most effective method thus far, however, has been building pressure barriers between those wells that have already been completed and those wells that are about to be treated—a method developed in Martin County, Texas, by producer QEP Resources Inc., which it refers to as “tank development.”
For QEP, it is a systematic approach that optimizes both the subsurface and surface operations—a holistic process to develop all of the formations from top to bottom as well as vertically at one time in a specific section, or “tank” of rock.
“We are completing wells at the same time, both vertically and horizontally, and bringing them on systematically so that the wells rarely see any interaction with their offsets,” said Chris Buscemi, Permian reservoir engineering manager for QEP. “The goal is to essentially develop an entire section of rock in typewriter fashion and work through your leasehold systematically. This way we are able to optimize drilling/completion operations, facilities design and subsurface development at the optimum density.”
A trial of the tank development approach conducted in the Midland Basin in 2017 seemed to prove QEP’s theory—that this style of working within the subsurface using a “pressure wall” does minimize well interference while optimizing stimulation, production and operational efficiency. The pressure wall is achieved by having completed a lateral and vertical volume of the reservoir—and thus having “pressured up” the system—but not having turned it online for flowback. The reservoir within the pressure wall is above pore pressure, due to the completion energy, and acts as a barrier to frack hits for wells on either side that are completing or that have been recently been put on production.
A chief learning from field tests, according to QEP, was finding that the perfect recipe for tank development is spatially dependent. Since the first trial, the company has moved 13 miles to the east in an area with a higher number of economic formations, and the well count has increased.
“Through development in different areas, our technical team has learned that we need to adjust our pressure wall size accordingly,” said Jill Thompson, senior staff geologist at QEP. “The more total wells in the DSU, the larger the pressure wall needs to be to mitigate frack hits.
“Also, since the initial trials, we have increased our understanding of the rock using seismic and earth models. The original pressure wall on paper was sort of a perfect box. That is not the way we implement and think about it anymore. Some formations and their rock properties allow for frack hits to extend further than other zones, therefore the pressure walls in those locations need to be wider in a vertical sense.
“Our technical team has also highlighted vertical deformation zones from our seismic and microseismic that may influence communication while drilling and completing. We are now planning ahead when we are completing in zones that show these features, and we have implemented a set of rules for how to mitigate communication in the tank. To date, we have been successful with this method.”
The impact of infill wells on the primary well would commonly be a factor intra-field; however, there are times where primary wells on one piece of acreage can be negatively impacted by a well fracked on an offset property, by a different operator. These instances are not a daily occurrence, but they do happen. In most cases, the nearby operator preparing to complete a well will give its neighbors sufficient warning that their wellbore could be impacted by the adjacent completion activity. The potentially affected operator can opt to pressure up its well to defend it against potential FDI from the neighbor’s well.
Communication is the name of the game for these instances, and while the effect on defended wells can be nominal, the fate of nondefended wells can be disastrous, ranging from temporary water production to loss of the bore altogether.
“Communicating with each other—company to company—and creating ways to ensure everybody knows what everybody is doing is important,” said Peter Bommer, CEO at Abraxas Petroleum Corp. “We did have a couple of examples early on where we got kind of ambushed by offset fracks. It wasn’t anything intentional by the offset operator, but both of those wells suffered some interactions that were very negative. Via email or online, anything we can do to communicate and give the opportunity to rig up and defend is desired.”
Abraxas’ active well defense morphed in 2010 when it initially did nothing and quickly learned it couldn’t stand on the sidelines. First, the company changed to just pulling the pumping equipment and shutting wells in or setting a bridge plug. In the Bakken, that method didn’t seem to work, and the operator still had wellbore invasion. Use of diverter material to block perforations worked better. The company found that indeed it could screen out 10,000-foot laterals, but it wasn’t consistent. The PLA (polylactic acid) would melt or dissolve, and the operator would lose its block.
“We finally settled on pushing back against hits by injecting water,” confirmed Bommer. “We pull our legacy wells and install pressure transducers that feed us one-second data in real time so we can watch these primary wells. We rig up horsepower so we can pump in and we monitor.
“When we start to see these interactions, especially the big ones, we pump against them so at least we can get fluid moving in the right direction. This is low rate treatment. We’re talking one to two barrels per minute perhaps. Rarely do we inject more than 20,000 barrels in an individually defended well. That has been successful for us. We’ve defended about 40 wells this way.”
Abraxas went from almost always having the wellbore fill to almost 100% in effectively defending. Of course, defending does come at a cost—about $262,000 on a six-well pad defense in the Bakken. Much of that cost is driven by horsepower. If you’ve got wells scattered across a field on one to two well pads, the cost goes up.
“We were happy to spend that money and avoid multi-hundred thousand dollar clean-outs on these legacy wells,” said Bommer.
ConocoPhillips Co. has successfully used refracks in the Eagle Ford Shale to defend its primary wells from possible infill intrusion.
“When we go in to drill infill wells, those closest to that parent well—if we don’t do anything about it—we distort our frack toward that pressure sink,” explained Erec Issacson, vice president of ConocoPhillips’ Gulf Coast Business Unit. “So we don’t get an effective frack on those nearby wells. What we’re doing, in that parent well, is a defensive refrack. Normalizing that pressure field when we go in and drill those infill wells and we stimulate those, we don’t have as much of an impact.”
The potential financial stresses have begged the question whether full participation in the development of the nation’s shale plays is a game best played by the largest companies with the deepest pockets. On the surface it would seem so.
Big operators like Exxon Mobil Corp., Chevron Corp., Royal Dutch Shell Plc, and BP Plc have all made substantial moves into Lower 48 unconventionals during the past few years via splashy acquisitions or more stealthy means. ExxonMobil alone is running more than 50 rigs across the Permian Basin. Chevron is one of the region’s largest leaseholders with over 2.2 million net acres. Smaller players were instrumental in cracking the shale code and innovating to produce the volumes that have vaulted U.S. daily oil production from around 6 million barrels per day (MMbbl/d) in 2012 to over 12 MMbbl/d in 2019. Yet, all but those with the firmest footing and a solid grasp of the FDI issue may be excluded from the next phase.
“The ones that are going to get damaged are the ones that have run too far down the road without realizing the problem was going to happen and maybe have drilled a whole bunch of wells that they will now have to go back and remediate,” said Duncan.
“Then there are those who have made certain commitments to the market about their reserves that are now going to have to be revised. Those that have done that and put themselves into a situation where they have a large amount of debt that they can’t service, those guys are going to go away or be bought.
“However, I think small start-up players that truly appreciate the problem and act accordingly can afford to play in this market. Absolutely.”
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