Dynamics in the Permian Basin are changing as drillers turn their attention from acquisitions to drilling, with some concerns arising over the productivity of new wells, writes Ros Davidson
What: The land rush in the Permian has slowed and operators are focusing on drilling.
Why: Producers are learning how to maximise output at lower oil prices.
What next: There are concerns about the productivity of new wells as sweet spots are depleted.
The perception of the Permian Basin may have changed in the last few months, but activity in the play will not be tapering off any time soon. But “Permania” may have cooled a little as operators shift their sights from acquisitions to drilling.
In recent weeks, third-quarter results have included insight on the Permian. Super-majors ExxonMobil and Chevron have said they will continue to ramp up drilling in the basin, which straddles West Texas and New Mexico. This comes as WTI seems to be staying above US$55 per barrel.
In an earnings call on October 27. ExxonMobil said it would increase its rig fleet in the Permian by 50% by the end of 2018, up from 20 currently, and would extend the length of its horizontal laterals to up to 3 miles (5 km).
The same day, Chevron said it would raise spending in the Permian to US$4 billion for 2018. Chevron’s oil production in the play was up by 30% during the last 12 months, and the super-major now has 15 rigs working the region. “It’s a very good use of your money,” Chevron’s chairman and CEO, John Watson, said of his firm’s Permian investment.
Leading the charge
The Permian is by far the most productive oil region in the US, outpacing the Gulf by a comfortable margin, and this is not going to change. The Permian is currently estimated to be producing roughly 2.6 million bpd of both unconventional and conventional oil.
However, productivity per well is declining a little. Paris-based energy research firm Kayrros has found that production per completed well, adjusted for the total depth and length of that well, has tapered off since mid-2016 and may have even dropped a little this year. Kayrros’ president, Antoine Rostand, told NewsBase Intelligence (NBI) that this was because operators were now drilling outside the most productive areas of the basin. He said it was a trend that would continue.
“Yes, some operators are running out of ultra-premium locations,” a Wood Mackenzie principal analyst, Benjamin Shattuck, agreed. But he said it was also important to note when looking at production data that companies were not necessarily focusing on maximising production. Indeed, they may scale back as a well’s cost of drilling per barrel improves less quickly. “For example, if a 5,000-foot [1,524-metre] lateral will recover 500,000 boe and a 10,000-foot [3,048-metre] lateral recovers 850,000 boe, there is a fall in productivity per foot,” he told NBI.
“An operator can tolerate a little fall in production” if the length of well is a question of diminishing returns, said Shattuck. “It’s a balancing act with costs,” he said. Wood Mackenzie estimates that the average cost per barrel in the Permian has dropped by about US$2 from 2016 to 2017.
Weighing the numbers
Another way of viewing productivity is across the region’s entire rig fleet. In May 2016, there were about 136 rigs in the Permian on average, and now there are roughly 386 as the price of oil and confidence have picked up. With that many rigs, some are inevitably drilling acreage that is not as productive.
The US Energy Information Administration (EIA) tracks new well production per rig across the seven major shale regions in the US. And its latest new well production numbers for the Permian do indeed show a drop in output since mid-2016, when the region’s rig count started rising.
Another metric for production is per well, and as companies have become more adept at completing wells, shorter-term output per well has risen, but over the life of the well it has remained the same – it is just more front-loaded. Production can be 15% higher in the first 12 months compared with one year ago. Output declines are then steeper.
Comparing “like for like” wells takes into account geography and geology. “In 2017 we’ve seen a small increase in productivity in like for like wells, but not the 20-30% increases seen in 2015-16,” said Shattuck. This metric is also evidence of the activity moving out of the best of the core areas.
The land rush in the region has slowed, owing to inflated acreage prices and operators shifting their focus to drilling, while cash moves downstream. Earlier in October, Wood Mackenzie reported that drillers had invested US$35 billion in land deals for the region in the nine months ending in March.
Adding to the land rush was ExxonMobil, which announced a deal in January to double its holdings in the Permian to 6 billion barrels through its purchase of companies operated by BOPCO from the Bass family of Fort Worth for US$5.6 billion.
However, after the boom in mergers and acquisitions (M&As), the total collective value of land deals since March has dropped to under US$5 billion.
Investment in the Permian – specifically, upstream capital expenditure – has risen by about 80% just from 2016 to 2017, a faster increase than expected. Wood Mackenzie anticipates investment still growing next year, but at a more marginal rate.
The rush to build up acreage in the Permian has calmed down, but there will still be growth even as the path forward for new entrants becomes more challenging. The region’s rig count is predicted to rise by about 50 by the end of 2018, according to Shattuck, despite a slight pull-back in the first quarter of 2018 owing to lower oil prices in the second half of 2017 and to a growing inventory of wells needing to be completed.
Wood Mackenzie projects that the region’s production of tight oil will more than double to 5.1 million bpd in 2025. The basin is currently producing roughly 2.3 million bpd of unconventional oil, according to Wood Mackenzie analyst Edward Sherfey, who also spoke to NBI. This accounts for the majority of the region’s total production.
Nonetheless, there are geological challenges looming in the region, most noticeably the disparity in production between parent and child wells. The hyper-productive parent wells can produce 15-35% more oil than their offspring, which are infill wells.
There are not likely to be more parent wells in the region, compared with child wells, before the end of the decade. “But if there is not a technical or strategic response [to this], it will be difficult for the Permian to continue growing at that same rate,” said Shattuck. In that case, the region’s peak tight oil production could come as early as 2021.