The US oil and gas landscape is always shifting, but today’s tectonic forces are markedly different, potentially heralding a new energy era as outlined by Enverus Intelligence Research (EIR) in its 2024 outlook.
From last year’s flurry of shale sector mergers and acquisitions to the success of a new breed of geothermal wells in Nevada and the still-emerging lithium extraction technologies deployed in Arkansas, each trend highlighted by EIR shows that as the US shale sector matures there remain big opportunities for those who can stick around.
To unpack it all a bit more, we selected five of the biggest developments EIR said are reshaping the US energy market and discussed them with the experts who made the predictions. This is what they told us.
1. Tight Oil Running Low on Good Rock
The biggest theme dominating the US shale sector in recent months has centered around a series of blockbuster mergers and acquisitions.
Since October, major industry players Hess Corp., Pioneer Natural Resources, and CrownRock all decided to sell out to larger rivals Chevron, ExxonMobil, and Occidental Petroleum (Oxy), respectively. Pending approval, these three deals represent more than $125 billion in cash and stock exchanging hands.
But that such big names are motioning for the exit suggests to some that the sector has turned into a high-stakes game of musical chairs.
“High-quality resource scarcity is a very real issue and it's evident from both the numbers involved with the deals we saw in the Permian and in the messaging which for almost every single deal has been related to improving the inventory outlook for the buyer," said Steve Diederichs, senior vice president of oil and gas research at EIR.
In other words, those doing the buying at this point are more than likely not looking to parlay their holdings, but are signaling their intent to be one of the last shale companies standing. The sellers, meanwhile, may be tipping their hand in revealing that the US shale sector is entering into its late innings.
While consolidation is expected to march ahead despite all this, Diederichs explained that there are not many companies left that can pack the punch of a Hess or a Pioneer, which until closing will hold claim to being the largest Permian producer.
"Most of what is still held by potential targets, namely the private operators, is going to be of lower quality than what the public companies already own, which doesn’t really tick the box of inventory quality accretion that the buyers are looking for today," he said.
2. The 3-Mile Standard Is Coming
As both the number of players and future well locations continue to dwindle in the US shale sector, one thing on track to grow is the number of new shale wells being drilled in the Permian Basin with 3-mile-long lateral sections.
The trends go hand-in-hand, according to Diederichs, who said the economics of the longer wells are so good that the prospect of drilling more of them through acquisition is driving up the price of Permian deals involving large swaths of contiguous acreage.
“Three-mile wells are going to become the standard in a few years, and certainly today, every opportunity that a company has to drill them, we are seeing them act on that,” said Diederichs.
The move toward longer wells has been taking place for several years with the average lateral length in the US growing from just about 5,000 ft in 2013 to 10,000 ft in 2022. And just as before, the driver is not about well productivity—it’s about getting more out of each dollar.
Diederichs noted that while there is a substantial drop in per-foot productivity when comparing 1-mile laterals to 2-mile laterals, the cost savings far outweighs the performance degradation. He added that the per-foot losses become marginal, and thus even more palatable, as the laterals extend from 2 to 3 miles.
Combine this with operator reports of a per-foot capital savings of 15%, and the case for drilling a 3-mile lateral becomes hard for shale producers to ignore.
The next step out is already underway with several companies testing 4-mile laterals in the Permian. Notably, such wells likely meet the industry’s definition of extended-reach drilling (i.e., a 2:1 ratio between lateral and vertical section length) which has traditionally been reserved for only the most complex upstream developments.
It’s too early for EIR to make a definitive call on the future of the Permian's 4-mile laterals, but companies including ExxonMobil are betting big on it. When the US supermajor announced its $59.5 billion megadeal to acquire Pioneer last year, it cited the ability to drill more 4-mile wells as a top driver for its decision to combine the companies’ massive holdings in west Texas.
3. More Permian Barnett Wells on the Way
The Wolfcamp and Spraberry formations remain the rockstars of the Permian Basin but there is a new layer taking the stage—the Barnett Shale. Better known to most as a dry gas play in north Texas where the shale revolution began more than 20 years ago, in the Permian—particularly in the Midland sub-basin—the layer runs deep and is liquids rich.
Big name operators including Oxy and ConocoPhillips are among those drilling into the 11,500-ft-deep horizon and so far, their results are promising according to EIR.
“We’re definitely excited about it. I think that [the Barnett] is for real and that 2024 will be a big year in which more and more of these pads will be tested across a wider portion of the play,” said Diederichs.
Aside from the wells producing in line with the Permian’s two stalwart targets, EIR is bullish on the Barnett’s outlook in the Permian because of its depth. While deeper wells mean more-expensive wells, it is believed that the Barnett layer offers enough vertical distance from wells landed in shallower horizons to protect against the parent-child issues that are known across the shale sector for recalibrating high expectations to the downside.
If all this holds up, EIR believes it means the Barnett is poised to transition from the delineation stage to becoming a play representing meaningful new inventory for the companies working its fairways.
4. EGS Will Get Serious Attention
n November, Fervo Energy commissioned the first commercial enhanced geothermal system (EGS) project with internet giant Google. The three-well facility in rural Nevada is supplying about 3.5 MW of geothermal energy to the public grid along with plenty of optimism to industry observers.
“We think we will see more of those kinds of projects this year and likely a lot more investment into the space based on that success,” said Graham Bain, a vice president of energy transition intelligence at EIR.
EGS can be summed up as horizontal well pairs that use hydraulic fracturing techniques to create supercharged subsurface heat exchangers. Bain explained that because EGS leans so heavily on the “shale playbook,” there are few, if any, major technology gaps to clear.
However, there are a few major questions.
The first surrounds the geothermal sector’s ability to lower drilling costs, which should be surmountable given the precedent offered by the shale sector.
The other side of the equation depends on how EGS wells will perform over the long term. Whether the reservoirs and fracture networks can maintain high temperatures for years, or decades, to come remains one of the biggest unknowns.
Another potential hiccup Bain said must be considered involves the risk of preferential flow through a dominate fracture(s). "This is one aspect that makes me hesitant to say that EGS is an absolute slam dunk," shared Bain.
He explained that preferential channeling may not only result in cooler-than-expected water temperatures on surface, but it could also cause the rock to contract and create an even wider fracture. The result would be a negative feedback loop in which the fracture area grows to allow more and more cool water to flow from injector to producer.
5. Early, but Exciting Days for Lithium Extraction
Rising demand for grid-scale battery storage and electric vehicles in North America has sparked growing upstream involvement in direct lithium extraction (DLE) projects that use hot brine, and often oilfield wastewater, as their feedstock.
The biggest news on this front came last year when ExxonMobil made a $100 million acquisition of 120,000 acres of lithium-laden subsurface rights in the Smackover formation of southern Arkansas, which holds the most lithium rich deposits in the US.
“ExxonMobil entering the market is definitely going to be huge since prior to that the space only had small players. It’s going to give investors more confidence to think that this is not just a pipe dream,” said Bain, who added that Chevron and Oxy have also shown recent interest in the space.
These developments follow recent breakthroughs in DLE technology that aim to expand the application envelope to low-concentration brines, a threshold considered to be around 70–75 ppm of lithium.
If commodity prices can hold steady and some of the recent pilot projects prove successful, Bain predicts use of DLE technology will expand quickly beyond Arkansas.
Regions on the list including Texas, North Dakota, Ohio, and Pennsylvania offer even more opportunities for oil and gas crossover. Bain said it's also worth tracking what’s going on to the north in Alberta where a handful of locally based companies are at various stages of demonstrating the region’s lithium potential.
In particular, Bain said Calgary’s E3 Lithium has recently run a low-concentration field test that, if considered to be successful, “will really open up the viability of DLE to be done almost anywhere because just about every basin has at least one interval with a lithium content of at least above 70 ppm.”
