The ‘hottest shale play’ has been the media’s favorite cliché for the Permian Basin over the past year. And while cliché, the basin straddling West Texas and New Mexico has lived up to this description—its oil production, unlike that in other basins, did not fall off a cliff during the downturn, it recently beat its own record from the 1970s, and is expected to continue to increase production more than any other U.S. shale play and account for most of the American oil production growth.
The Permian has been pumping oil since the 1920s. Conventional oil production started to decline in the late 1970s, but the fracking boom revitalized the oil-producing region in the early 2010s, and as oil prices rose last year, the Permian beat its previous record for annual oil production dating back to 1973.
The Permian surge in oil production is also revitalizing other industries in small Texas towns, from frac sand trucking and oilfield services to overbooked hotels and full restaurants, as Robert Rapier wrote in Forbes about his recent visit to the Permian.
This shale basin will continue to drive the U.S. oil production growth in the short to medium term, forecasts suggest. But analysts have started to question just how long the Permian can keep pumping at this relentless pace before hitting geological or financial constraints.
The Permian is now nearing 2.8 million bpd of oil production, EIA data shows. To compare, in October 2013, before the oil price crash, Permian production was 1.29 million bpd. In January and February 2016, when oil prices dipped to below $30 a barrel, the Permian production was still ticking up and exceeded 2 million bpd, compared to drops in all other main producing shale regions, including the Eagle Ford and the Bakken. Related: Has Oil Become Overbought?
EIA’s latest Short-Term Energy Outlook (STEO) from January 2018 forecasts that higher production from the Permian will account for 800,000 bpd of the expected 1.2 million bpd of total U.S. crude oil production growth between December 2017 and December 2019. The Permian is seen producing 3.6 million bpd by the end of 2019, which would be a 900,000-bpd increase from estimated December 2017 levels and would account for some 32 percent of total U.S. crude oil production in 2019. The stacked plays and the large area allow drillers to continue to develop multiple tight oil layers and increase production, even with sustained prices lower than $50 a barrel, the EIA said. The Permian’s rig count is expected to increase from about 398 at end-2017 to 490 at the end of 2019, EIA has estimated.
So booming has been the Permian production that it has overheated property prices in West Texas, but it has also created a new Texas Gold rush, as the Wall Street Journal put it—a rush by service firms and Wall Street companies to buy patches of the Texas desert to mine sand and sell it to the drillers to use as proppant.
The use of more proppants—mostly sand—is one of the two primary methods of U.S. shale drillers to increase production, the other being drilling in top-tier acreages, McKinsey Energy Insights said in a report earlier this month.
While the Bakken proppant intensity is already close to optimal, the Permian still has room to grow. The Delaware-Wolfcamp sub-play has an average current proppant loading of nearly 2,000 lb/ ft, and yet it could realize up to a 35-percent increase in proppant intensity before approaching its sweet spot in proppant loading per foot, McKinsey says. The analysts expect Permian proppant demand to surge to 38 million tons in 2018 from 13 million tons in 2016.
According to Wood Mackenzie, however, signs have started to emerge that the relentless intensification of drilling leads to diminishing returns, and pumping twice as much sand as usual into Permian wells and drilling longer laterals doesn’t deliver commensurate volumes of oil. Still, WoodMac suggests that drillers could ‘change the laws of physics’ and that these signs of setbacks may actually be growing pains.
In addition, drillers may soon start to test the Permian region’s geological limits. And if E&P companies can’t overcome the geological constraints with tech breakthroughs, WoodMac has warned that Permian production could peak in 2021, putting more than 1.5 million bpd of future production in question, and potentially significantly influencing oil prices.
Then this year, U.S. drillers will have to contend with the drive in the shale patch to heed investor concerns and prioritize profits over production, and not “drill themselves into oblivion”, as oil tycoon Harold Hamm has warned.
Rising cost inflation in U.S. onshore also poses a question of how much increased service costs could offset production gains.
“The tension going forward will be between productivity gains (in our view, the greatest perhaps already realised) and resurgent cost inflation (still playing out),” Wood Mackenzie said in a December report on upstream costs.
The Permian will still be a growth story in coming years, but the combination of oil prices, capex discipline, cost curves, and geology will set the pace of that growth.
By Tsvetana Paraskova for Oilprice.com
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