It’s tempting to think that the industry is going to ride high on shale fever forever.
After all, it’s still a thrilling and often lucrative ride, at least for some folks.
But forever is such a long time.
In this notoriously cyclical industry, the savvy players recognize the need to look back often over their collective shoulders to be reminded of what has come before.
Granted, the last decade-plus has been awesome for U.S. energy production from shale plays.
Given all the success stories, it’s intriguing to realize these plays are still far from being a known – variability is indigenous. The players talk about “cracking the code,” but the “code” can differ even between adjacent wells.
A recent Bloomberg report noted that independent producers will spend $1.50 drilling this year for every $1 in return, and the International Energy Agency has reported that 2,500 new wells per year are necessary to maintain output of 1 MMbopd from the famed Bakken play.
Challenge may be the name of the game, but it’s not the end of the game.
“You can only win if you play,” noted AAPG member Luis Baez, North American manager at BG-Group and co-chair of the upcoming Unconventional Resources Technology Conference in Denver.
The myriad still-unanswered questions about shales tend to stir up memories of the once-booming Austin Chalk play in south Texas. The complex Chalk has challenged, and taunted, industry operators for decades.
The shale play staple technology, horizontal drilling, first became a household word on the brink of the 1980s when it became a kind of panacea to wrest production from the brittle, fractured chalk.
Industry veteran and AAPG member Nathan Meehan, senior executive adviser for advancing reservoir performance at Baker Hughes, has in-depth experience with these type plays and more.
Separating the Wheat From the Chaff
Meehan shared a bit of his considerable insight on shale issues:
“One of the things I’m concerned about is the ability for us to quickly identify what resource plays, or what portion of a resource play, are going to be commercial. If you examine the distribution of well performance even in commercial plays, a large fraction of the wells are uneconomical – like a third or more,” he said.
“And the people that have run production logs along the (shale) wells have identified that, typically, more than 30 percent of the frac stages in a good well have been unsuccessful – at least there’s been no significant contribution to production coming from them,” he said.
“If you look at every (shale) play in North America tested at any level, no one drilled something that had no chance whatever. They all had indicators of possible success.
“Yet a substantial number of those plays had gas results that would not be commercial at any foreseeable gas prices. Quite a few plays might be commercial at $8 to $10, but some not even at $12.
“To me those are the technically unfeasible plays, he said, and that’s a huge fraction of the total number of plays.”
Meehan emphasized how essential it is to understand the reservoirs via characterization. It’s a whole different game from playing the long-familiar conventionals. Hydraulic fracturing complicates the characterization process, which entails a number of factors having a complex relationship. Geomechanical values figure in significantly. Plus, it’s time to log areas further out in addition to those at the wellbore: “The technology solutions we’re looking for are ways to characterize the reservoirs and characterize those factors which drive production,” he explained.
“In conventional reservoirs, if you look at equations for Darcy’s Law and material balance, they’re full of variables that we sort of know how to measure, like porosity, permeability, viscosity. By characterizing those, we can predict how well the reservoir will perform to varying levels of success. Fundamentally, that’s what we do and what we’re kind of good at.
“The things people talk about for unconventionals, such as TOC (total organic carbon), how susceptible the reservoir is to hydraulic fracturing or, indeed, complex hydraulic fractures – those don’t show up in Darcy’s Law or material balance equation.
“The factors that do indeed contribute to some degree to success don’t have a simple relationship.
“So the things we’re trying to characterize are often geomechanical values, not only the distribution of natural fractures but the distribution of critically stressed fractures, detection of slowly slipping faults, characterizing the fractures away from the wellbore.
“We’re looking at trying to do more and more logs that will actually measure faults and fractures that don’t intersect the well. That’s a kind of technology we’re going to have to have to understand the reservoir. Just the ones at the wellbore are probably not enough.”
One Size Doesn’t Fit All
Hydraulic fracturing has proven to be an indispensable technology in the oil patch, but like any technology, there’s always room for improvement. Natural fractures need love, too.
“In hydraulic fracturing, we must do things that improve how we identify where to frac, as well as the designs. And we’re going to have to have a better understanding of where the frac jobs are going,” Meehan said.
“Right now one unconventionals operator might use lots of slick water fracs, one might decide to do hybrid fractures and another might do conventional fracs. But they typically do the same thing in every stage, like maybe 35 slick water jobs in a wellbore,” he said.
“If you look at how variable the wells are along the (well path), it might be that we need to do different types of frac jobs along the well,” he added. “We haven’t done a good job of elucidating what drives performance because all of it is mixed together. We have very few detailed predictive measurements that show response from a given well.”
Meehan said that the push to do factory drilling has led people to make fewer log measurements, take fewer cores and gather fewer reservoir characterization details.
“So,” he continued, “it would be easy to conclude that variability from well to well is somehow statistical in nature, because we’re not looking for and don’t have the tools to find factors that drive reservoir performance.”
There’s still a debate as to how significant the natural fractures in a reservoir that slip and shear are to production, as compared to the surface area created by the hydraulic fractures.
“There are people who believe that the major contribution to production is these natural fractures that slip and shear as a result of strain associated with hydraulic fracturing, and that improves the permeability and connectivity away from the fractures. So much so that that’s what drives the commercial production,” Meehan said.
“There are others who model the reservoir with no change in permeability. They just model with complex hydraulic fracturing,” he said.
“It’s likely a mixed answer,” he concluded, “with some reservoirs leaning toward one and some toward the other.”
Help Wanted
Yes, microseismic is a cool technology, but it needs help to identify what’s going on, as Meehan explained:
“We do a very poor job, even with microseismic, of identifying quantitatively what changes there are in permeability away from the hydraulic frac; we don’t know how to quantify that.
“My guess is that’s a key driver to what constitutes a sweet spot,” he added. “It’s the potential to increase the permeability in the matrix as a result of hydraulic fracturing. We have to integrate reservoir characterization at the wellbore, away from the wellbore and through microseismic before we have a chance of understanding what these wells do.
“The problem, of course, is everyone has so many rigs going that no one wants to study and slow the process down, he said. “If you’re having success in developing wells, you don’t necessarily stop to figure out why – that’s led to the factory drilling campaign.”
Pad drilling is a relatively new kid on the drilling block, where multiple wells can go down in close proximity.
That can be a blessing and a curse.
“Another technology we have to do better on is related to pad drilling,” Meehan said, because “we all want a smaller footprint.
“There are a lot of places where we’ll have to drill dozens of wells from drilling pads,” he said. “Ultimately, for oil reservoirs, they’ll all need artificial lift, and you can’t put a dozen or more sucker rod pumps with surface pumping units all together where people can see them.
“We’re going to have to change how we do artificial lift (and) hydraulic fracturing – and we have to dramatically change how we do reservoir characterization so we can then do real reservoir understanding instead of just statistical correlations,” he said.
“There’s a remarkable number of very simplistic analyses done just sort of by cross-plotting things in Excel,” he added. “The amount of noise there and the lack of ties to fundamental physics gives these pseudo-correlations that kind of look like a visible correlation – but when you look and see R-squared is .4, you know there’s essentially no predictive power.”
Upgrading Water Usage
Water used for hydraulic fracturing can vary – it can be fresh, produced, flowback.
The latter two are preferred, and are more plentiful where the wells are close together.
Water usage overall can be reduced with seemingly little, yet concentrated effort.
“Another thing that needs a technology boost is the water usage problem, Meehan said. “We use a great amount of water and must figure out a way to use otherwise non-usable water.
“With produced or flowback water, that’s facilitated with more wells from a drill pad,” he explained.
To minimize the amount of water used, Meehan said, we should:
- Stop drilling the really poor unconventional wells, “which would take out 30 to 40 percent of the wells,” he said.
- Stop fracing the parts of the wellbore that won’t contribute to production – “there’s another 30 to 40 percent,” he said.
“It’s understanding the reservoir, the completions,” he added, “eliminating the poor wells.”
Sweet Spots, Sour Spots
The widely touted sweet spots are good. Zeroing in on sour spots may be preferable.
“People talk about sweet spots as if by seismic or mapping we can find the very best parts of the reservoir,” Meehan elaborated.
“One exercise I do in all the big plays is to look at a couple of simple things: How much production is there? How many operators are in the field and how many does it take to produce half of the production of the field?”
Meehan explained that there are typically about 100 operators at a play, but only a handful of them – maybe around six – produce fully half of all production from that play.
For the rest – the bottom 80 percent or so – production is, on average, very poor.
“If people were able to find the sweet spots, the place where the best wells are, the average would be much higher,” he said. “There’s some sort of variability that’s difficult for us to quantify from seismic.
“I believe we can find the sour spots, or poor areas, maybe easier from seismic and logging,” he said. “If it’s like anywhere else in the entire oil industry, you will get this sort of log normal distribution of quality.
“’Sweet spots sort of suggests we can just find the right hand of that tail,” he continued, “but I don’t think we can do that consistently – no one has. I do think we can differentiate what that big fat left side of that tail is, the distribution that’s uneconomic. I think there are some seismic indicators and some things that suggest it.
“One is when we see big faults that cut through the higher zones or down into water,” he continued. “Those areas tend to be poor; they tend to suck up a lot of the fracture and put it out of zone – or worse, put it into a water-bearing zone.”
You can detect that by way of geoscience and geophysics, he said.
You also can also find some areas that have a very poor likelihood of natural fractures – but you must then understand if natural fractures are contributing in a meaningful way to production.
“A lot of people write a lot of stuff about finding sweet spots,” Meehan added. “I think one of the technologies where we will be more successful going forward is avoiding sour spots.
“That’s probably not a real name, but (it works) just because it’s the opposite of sweet,” he said. “I haven’t read any papers about avoiding sour spots.”