Pity the Permian Basin. Investors complain about disappointing returns from Permian production. Stockholders worry about the financial outlook for operators in the play. Lenders have started to cast a skeptical eye at the basin’s profit potential.
So it’s surprising to find that a data-derived solution for addressing the Permian Basin’s current challenges might be readily available.
And it’s somewhat startling to hear that, someday, unconventional resource plays in the United States could fly higher than ever.
Deloitte Consulting LLP discovered an interesting disconnect when it analyzed 10 years’ worth of data from thousands of wells in Permian Basin and Eagle Ford plays.
“We looked at 80,000-plus wells across several basins and we did a couple of things. First, we classified the rock quality itself” using standard industry evaluation, said Scott Sanderson, principal in Deloitte’s Oil and Gas Strategy and Operations practice in Houston.
“Then the other, bigger set of parameters we looked at was the intensity of the completions, and analyzed the correlation to well productivity,” Sanderson said.
Opportunity and Optimization
Deloitte’s analysis found that ramping up completion efforts led to better results and increased production year after year for most of the 10-year period. The industry moved up the unconventionals learning curve and made good progress, right up until two or three years ago.
After that, not so much.
“Increasing completion intensity increased well productivity up until the 2016-ish, 2017 timeframe. After that, there were diminishing results over the entire dataset,” Sanderson noted.
Optimized well designs could have allowed operators to generate capital efficiency gains of 23 percent in the Permian and 19 percent in the Eagle Ford, Deloitte found, with a potential for U.S. shale players to lower capital requirements by $24 billion.
The extensive well-data analysis produced some surprises, Sanderson said. For example, rock quality in the plays mattered, but wasn’t necessarily the main performance factor. According to Deloitte, rankings of acreage potential and prospectivity – play Tiers 1, 2 and 3 – don’t appear to predict well performance as much as once assumed.
“A main conclusion was that Tier 1 acreage isn’t as big an influence on productivity as the industry thought, or as the industry was communicating,” Sanderson observed.
He noted that some wells far outside Tier 1 zones had initial production rates of 2,500 barrels per day or more.
“There are some people who have figured out how to optimize even in Tier 2 or Tier 3 areas. That surprised me,” he said.
Also, Deloitte found that in the past three to four years, about 67 percent of Permian Basin wells ended up either over-engineered or under-engineered.
Over-engineering wells through excess proppant loading, excess fluid injection or too-long lateral lengths expended funds without improving results. Under-investment in completion engineering had the opposite effect of sacrificing available, economic production gains.
In many cases, operators could have cut costs substantially without a large production loss. In 1,480 over- or under-engineered wells in the Delaware Basin, optimizing well designs could have reduced well costs by an average of 39 percent with only a 16 percent hit on production, Deloitte found.
There appeared to be no just-right “Goldilocks scenario” across all the play areas. Deloitte analysts looking at the business side of the Permian and Eagle Ford shied away from saying there was an optimum overall approach in the plays, Sanderson said.
“Nothing is going to be ‘optimum’ across this breadth of wells and productivity drivers,” he noted.
“It was interesting that proppant load was a big driver in Delaware Tier 2, for example, while fluid loading was bigger in Midland Tier 1,” with perforated interval a key productivity driver in Midland Tier 2 and Tier 3 and Delaware Tier 1, Sanderson observed.
“We don’t prescribe what the Goldilocks scenario will be, but there are certainly cases where you can say, ‘I’m going to reduce my EUR in exchange for a lower financial requirement,’” he said.
The importance of fully evaluating the effect of design parameters on well optimization was a major take-away from the study’s findings, according to Sanderson.
“A headline conclusion is, a lot of the bigger companies are trying to standardize, standardize, standardize to reduce the AFE cost. But in standardizing, they can overlook the subtleties of different completion design parameters driving well productivity,” he said.
Some well-design inefficiency is probably inevitable, and Deloitte noted that the largest companies have a tendency to spend on experimentation and innovation as they sharpen their unconventional play skills.
Also, “there was some trial and error – there was some brute force, saying if we pushed this (completion approach) over 3,000 feet, why wouldn’t 10,000 feet be better?” Sanderson said.
Growing Importance of Data Analysis
For the geoscientist, a major message is that data and statistical analysis skills and related technology like machine learning couldn’t be more important in today’s operating environment. Deloitte opined that companies might want “to complement their sophisticated technical models with comprehensive analytical perspectives.”
“It’s mostly analyzing these large datasets that exist now and getting the performance information fed back into the well design,” Sanderson said.
“The challenge is to get the feedback of performance into well designs” through an effective feedback loop, he added.
In that view, finding out “What has worked?” is less important than discovering “What is working?” And then use that information to guide operations “in a timely fashion,” Sanderson said.
“It’s maybe a little easier when you’re drilling one well at a time than when you’re drilling 12 wells at a time,” he acknowledged.
Sanderson cited the significant capital savings opportunities available to shale drillers, the size of the remaining U.S. unconventional resource potential and the room for operating improvements and efficiencies as clearly indicating a promising future.
“I take issue with what some other observers are saying, talking about, ‘This shale revolution may be about over,’” he commented.
He said he recently heard a comment that shales are “in the seventh inning,” implying that shale plays are nearing the end of their run.
“There will be a second act in shale. I don’t know what it’s going to be. If I did, I’d go out and invest in it right now,” Sanderson said.
“The prize that’s being left behind is so big there’s a lot of value in cracking the code to what comes next in unlocking this,” he noted.
That points to the Importance of continued innovation, research and development efforts and academic research into shales, he said.
“Innovation in unconventionals is far from over,” Sanderson said. “The unrecovered resource is too large and there are just too many good geologists, geoscientists, engineers, involved in working on new ideas.”