The Permian Gas Problem Is Just Getting Worse
Rachel Adams-Heard and Catherine Ngai December 24, 2019
(Bloomberg) -- America’s top shale field is becoming increasingly gassy as drilling slows down, undercutting profits for explorers at a time when investors are demanding better returns.
Natural gas has long been a nuisance in the Permian, where a massive glut weighs on prices, with crude producers sometimes having to pay to get it hauled away or burn it off in a controversial practice known as flaring. Now the problem is intensifying as wells age and fewer new wells are drilled.
Shale wells produce a spew of oil when they’re first fracked, but over time, production falls -- sometimes as much as 70% in the first year -- and gas becomes a bigger part of the mix.
“Activity levels are no longer what they were,” said Artem Abramov, head of shale research at Rystad Energy. “The oil ratio is no longer sufficient to offset gas in older wells, so we’re seeing some increase in basin-wide” gas-to-oil ratios.
In the Midland portion of the Permian, the average well produces about 2,000 cubic feet of gas for each barrel of oil in its first year, according to Tom Loughrey, a former hedge fund manager who started shale data company Friezo Loughrey Oil Well Partners LLC, or FLOW. Over the lifetime of those wells, about 30 years or so, that rises to an average of about 5,000. It can climb as high as 7,000 in the gassier Delaware.
What BloombergNEF Says:
“Shale wells are notorious for their steep output declines; however, that decline is more severe for oil than for gas and NGLs [natural gas liquids]. Gas and NGL production continues for much longer, increasing the gas-to-oil ratio (GOR) of most U.S. shale plays.”
It’s an issue that’s made worse when subsequent wells are drilled too close to the initial one, or when there’s interference from another producer’s neighboring wells.
Diamondback Energy Inc. emerged in November as a victim of this phenomenon when it reported third-quarter well results that were disappointingly gassy. The percentage of oil was 65%, the lowest since at least 2011, which it blamed on a nearby producer who took too long to frack its wells. The company also revised its expected crude ratio for 2019 to 66%-67% of production versus 68%-70% previously.
Then there’s the fact that in recent years investments have shifted to the Delaware, where output is much gassier than in the historic Midland portion of the Permian.
“Almost all, if not all, of the gas supply growth next year is coming from the Delaware Basin, whereas most other basins are staying flat or even decreasing,” said Ryan Luther, a senior research associate for RS Energy Group Inc. “It’s something that can be particularly challenging for the Permian operators because there is that pipeline constraint.”
In April, gas traded at the Waha hub in West Texas dropped to minus $4.63 per million British Thermal units. In other words, producers had to pay to get their gas taken away.
Smaller producers with rising gas ratios have taken the hardest hit as prices tanked. Over the last year, Approach Resources Inc. has reported oil production that was less than one quarter of its total output. The company filed for bankruptcy protection in November.
Producers in the Permian are already flaring record levels of natural gas. The Texas Railroad Commission, which oversees the oil and gas industry in the state, has granted nearly 6,000 permits allowing explorers to flare or vent natural gas this year. That’s more than 40 times as many permits granted at the start of the supply boom a decade ago.
While flaring gets rid of the methane, it still releases carbon dioxide and other particulates into the air. The agency’s tendency to approve all flaring permits is now the subject of a lawsuit brought by pipeline operator Williams Cos. The company recently lost a case in front of the commission, arguing that producer Exco Resources Inc. should use Williams’ pipeline system instead of burning off unwanted gas.
U.S. Energy Secretary Dan Brouillette put the Permian’s gas problem down to infrastructure.
“Even if we could capture the gas, it’s not clear we could get it to the marketplace,” he said in an interview in Washington last week. “We just need more pipeline capacity.”
Maybe I'm wrong, but I interpret this to mean that oil production is dropping and NG is increasing way, way too much. And if some of the Wall Street pundits are correct and if Opec continues to keep its thumb on oil production, then the price of oil could stabilize toward the upside. Could be that's why there's a bit of aciviity beginning to sneak into the leasing in LA per year's end, which is somewhat unusual, the way I read the tea leaves. It must be the operators are smelling higher oil prices and feel confident to drill some new oil wells. They can't be thinking about drilling new NG wells. In other words, with the price of NG cratering, along with this article's insight into even more NG coming out of the PB and with even more pipelines coming online in Texas, such seems to be the only thing that halfway makes any sense. So if this hypothesis is, indeed, correct, then us NG mineral owners are truly in for a very tough row to hoe, maybe for years to come. Personally, I don't see LNG being able to move the needle enough to change the rather bleak short-term future for NG. I only hope I'm missing something. And that something might be the quick depletion of so many shale wells in the HA, which might mean even more new horizontals will have to be drilled by BPX, etc., to uphold pipeline contracts.
I think we would do well to remember that the modern horizontal wells in the Permian are producing a majority of oil of a lighter API gravity than the standard, West Texas Intermediate (WTI). WTI is a light, sweet oil with a gravity of ~39.6. So much of current production is lighter so a new category has been created, "West Texas Light Sweet" from 44.1˚-49.9˚API gravity. This range covers the gravity range between WTI and "condensate" which is >50.0. Many here in NW LA and E TX are familiar with historic producing gasy formations which are classified as "wet gas", Hosston/Travis Peak, Cotton Valley, etc. The liquid production from those wells, condensate and Natural Gas Liquids (NGLs), declines much faster than the gas volume. After a number of months, the liquids are depleted but the gas production can go on for many years. This is similar to the production mix described in the article.
So, for those of us focused on the gas market, this is more negative news. It's not just the "associated gas" that comes with new oil wells but an observable trend of high gas oil ratios in those wells entering their second and subsequent years of productive life. If the OPEC+ reduction in production targets becomes a reality and supports the price of crude to the point that domestic US oil operators crank the rig count back up, the glut of natural gas that has persisted for the last few years will likely last well into the next decade. Also the request to flare Permian gas will continue to climb well past the 6,000 granted in 2019.
These days, I am more focused on the climate than the gas market. Are there no costs or penalties to these producers for dumping tons of carbon dioxide and methane into the atmosphere?
Not at the moment. Hopefully that will change in the near future. The methane gets burned off in flaring but the process does release CO2. Of course the entire system leaks methane at multiple points and excepting a few companies, there appears to be little in the way of efforts to cut fugitive emissions.