People familiar with the energy business know that most existing vertical wells produce little oil or gas. They might be surprised how many horizontal wells fall into the same category. Under the right circumstances, this growing number of wells in decline could represent an investment opportunity.
Or, it might become a giant abandonment headache for the oil industry.
In 2020, about 78 percent of the more than 936,000 oil and gas wells in the United States produced less than 15 barrels of oil equivalent per day, according to a study updated earlier this year by the U.S. Energy Information Agency.
Out of approximately 159,000 U.S. horizontal wells surveyed by the EIA that year, around 50 percent produced 50 boe/d or less and almost a quarter produced 20 boe/d or less.
Laura Freeman called this surfeit of low-production wells one of the “uncomfortable truths” of the oil industry.
“We’re aging out horizontal wells through much of the U.S. and the question comes up, ‘What do you do with those wells?’ Once you’re down to 50 barrels (a day of production) or lower, it’s a huge problem,” she noted.
“I think it’s an interesting topic that people aren’t talking about, where the waters are muddy,” she said.
A managing director and founder of energy advisory and consulting firm Highpoint Global Capital, Freeman is a recognized expert in mergers and acquisitions and oil-industry financing. She’s been directly involved in more than $5 billion in acquisitions and divestitures.
At the upcoming International Meeting for Applied Geoscience and Energy in Houston this month, she will discuss the low-production wells situation as the featured speaker for the topical luncheon, “Aging U.S. Shale Wells: Years of Remaining Opportunities or Growing Asset Retirement Obligations?” on Tuesday, Aug. 30.
Understanding Decline Curves
Freeman said she became interested in low-volume U.S. wells when clients asked her to analyze properties as potential acquisitions. Most depleting wells simply didn’t fit her clients’ requirements in terms of conventional production, cash flow or risk.
“They wanted conventional wells but they didn’t want stripper wells. You can do asset screening and it eliminates every well,” Freeman said.
“There are places where you can have a whole basin or a whole state and everything screens out,” she added.
She then took a closer look at horizontal wells as a distinct category of recently drilled wells. Freeman conceded that horizontal wells in unconventional plays can be attractive investments, especially with high initial production rates and at currently high oil and gas prices.
“But if you really start looking at it, by three years, three-to-five years in, the wells are out of fracture flow,” she noted.
“There’s an interesting situation where under a little lower pricing, a lot of these wells don’t work. You don’t have to go too far down to get these inflection points,” she said.
Shale wells and other types of unconventional wells have notoriously steep and rapid decline curves, not because they are horizontal wells but because they’re hydraulically fractured wells. Also, horizontal wells are more expensive to operate, Freeman observed.
She said older horizontal wells in the Delaware Basin can absorb $5,000-$8,000 per month per in base operating expenses, and compared that to $2,500/month for a vertical well “just to keep it pumping, to keep the lights on.”
That reflects, in part, the higher operating costs for horizontal wells from the start of production. In the Delaware Basin, “it can be $25,000 a well in (operating expenses). You tell that to people and they think you’re crazy,” she said.
The economics and operational difficulties of declining wells haven’t been completely appreciated by investors, and neither have their operational challenges, according to Freeman, who had an earlier career as a petroleum engineer.
“Private equity and hedge fund investors don’t understand how complicated operating really Is,” she said.
One approach to reviving older, fractured, unconventional wells has been refracturing – adding a second round of hydraulic fracturing and completion per well. But Freeman said refracs to date have a mixed history of success.
“Do refracs really help? Refrac you can do some places, but in other places it doesn’t work. There are just mixed results. It’s worked for some people in some places but it hasn’t worked for a lot of people in a lot of other places,” she said.
Recompletion costs also can be brutal, especially in deeper horizontal wells with long laterals, she observed. Freeman has noted that the commonly used 6:1 gas/oil energy value ratio can distort the economics of older shale gas wells. At July 2022 prices of $98/barrel for oil and $7/million Btu for natural gas, it takes about 14 Mcf of natural gas revenues to equal 1 gallon of oil, a ratio of 14:1.
Freeman said she focused her research on the Delaware Basin area in the Permian, which includes a fairly low percentage of horizontal wells producing 50 boe/d or less, around 22 percent in her latest published overview. But in the Bakken and Eagle Ford play areas “there’s a lot of barrels in this boat,” she observed.
“You start to see things that the general public and even the general industry might see, but they just don’t understand how bad it is,” she said.
After getting her undergraduate degree in physics, Freeman added a master’s degree in petroleum engineering and took a job in the oil industry. She then earned an MBA at the Anderson School of Management at the University of California, Los Angeles, while working at Occidental Petroleum.
That UCLA business degree paved the way for her later career in financial and energy analysis, but Freeman said she might not recommend the management-degree path for younger people today.
“I’m not sure that’s a good idea now. You could pay hundreds of thousands of dollars and not be any better off,” she said.
Demystifying the Economics
Freeman’s research on declining wells has been featured in the Society of Petroleum Engineers’ Journal of Petroleum Technology. Some online criticism of her work appeared to stem from a misreading of her message: She isn’t arguing against unconventional resources development, but analyzing the status of fractured horizontal wells three years into production or more.
And it doesn’t indicate questionable economics for unconventionals. In a survey conducted by the Federal Reserve Bank of Dallas earlier this year and reported in July, operators said they needed a WTI oil price from $48/barrel (Eagle Ford) to $54/barrel (Permian Basin) to drill a new well profitably.
In some other U.S. shale areas, operators said they needed a price closer to $70/barrel to drill.
Asked what per-barrel WTI oil price was needed to cover operating expenses for existing wells, responses ranged from $23 (Eagle Ford), $28 (Permian/Delaware) and $29 (Permian/Midland) to $38 for U.S. non-shale plays.
The aging-wells presentation at IMAGE ’22 is also billed as the AAPG Women’s Network Luncheon, but Freeman she isn’t going to dwell on the women-in-industry theme – while still noting the shortage of female representation in energy industry operational/management and financial analyst positions.
“It’s usually all men in every meeting, except for me,” she noted.
Freeman said she mostly hopes to “demystify” the economics of the low-volume U.S. wells situation. While understanding the financial side is important, even essential, “it’s not rocket science,” she said.