- Peak Permian production could increase by 500,000 b/d over WoodMac's base case in a modelling scenario where new technology adoption accelerates more aggressively
- Long term reservoir performance presents bigger risks and may bring peak Permian production forward by 4 years– putting more than 1.5 million b/d of future production in question
- Both upside and downside scenarios have potentially significant implications for oil price and industry cash flow
Technology has played a huge role in the rapid rise of production in the Permian. Operators are bullish on the region's long-term potential and poised to exploit the Permian at an unparalleled pace over the next few years. However, according to a report by Wood Mackenzie, Geology vs. technology: how sustainable is Permian tight oil growth?, geological constraints that may arise as the play is aggressively developed could lead to production shortfalls, and in turn, higher prices early next decade.
In the report's reference case analysis, Wood Mackenzie forecasts Permian production to increase to more than 5 million b/d in 2025. Fully modelling the potential impact of the latest breakthrough technologies reveals measurable upside to Permian peak production; however, downside risks related to tighter well spacing and well-on-well interference, could bring peak Permian production forward by 4 years compared to the upside case – putting more than 1.5 million b/d of future production in question.
Robert Clarke, Research Director for Lower 48 Upstream at Wood Mackenzie, explains: "Technology gains in the past few years have propelled Permian well performance to new levels. However, industry is set up to develop the Permian region's shale zones at an unparalleled level, testing the geological limits of the play. It is very likely that the upcoming level of activity will introduce a new set of issues, particularly reservoir deliverability."
Countless other shale plays have proven that the first few years of growth are typically the easiest. Beyond that, producers require more breakthroughs to keep their barrels at the bottom of the cost curve. The Marcellus hit regulatory and midstream bottlenecks, the Bakken contended with huge differentials, the Haynesville dealt with a massive cyclical downturn, and the Eagle Ford sweet spots ended up being much smaller than originally modelled. In the Permian, the growth challenge could relate to the industry ultimately finding hard subsurface limits for tight oil recovery.
Wood Mackenzie assessed and quantified the unintended consequences of high-intensity, long-lateral, close-proximity drilling and fracking on reservoir deliverability. The analysis found that well interference during fracking events could reduce future estimated ultimate recovery (EUR) value by 30 percent compared with today. Clarke notes: "These reservoir issues could begin to manifest as sweet spots become exhausted. Taking into account some bearish assumptions, if future wells tap more difficult rocks, and are not offset by continued technology evolution, the Permian may peak in 2021."
The report looks in detail at one of the most prevalent reservoir risks, parent-child wells. Infill wells located next to older producers are routinely called 'child' wells, in reference to the older offset 'parent' producers. Only a small percentage of wells drilled today in the Permian are child wells but this will change in the coming years as operators ramp up production.
Report co-author, Alex Beeker, Senior Research Analyst at Wood Mackenzie explains: "When child wells are drilled, they are exposed to different reservoir conditions than the parent. Leaning on history again, we believe future child wells, because they're effectively drilled into pressure sinks, could have EURs 20-40 percent smaller than their parent producers. This would massively impact production growth and also limit the amount of cash flow available for reinvestment."
There is much at stake for operators in the Permian to get the technology vs. geology equation right.Under the conditions outlined in the report, the maximum range between the upside technology and downside reservoir risk cases is more than 1.5 million b/d in 2025. That's more production than the Bakken ever delivered on an annual basis.
"The ultimate outcome will be some combination of all the factors we modelled. Other risk factors will also come into play such as evolving gas to oil ratios and water-injection issues in adjacent zones that will impact pressure regimes and completion designs," Beeker adds.
A few things are clear from Woodmac's sensitivity analysis though. Permian production will grow aggressively for the next few years, technology advancements will quickly spread across all operators, and EURs for many parent wells should keep rising. Further into the future though, huge downside reservoir risks may quickly become a reality if technologies don't evolve to meet the geological challenges of the future.
"The technology vs. geology tug-of-war has the ability to profoundly alter the future production profile of the region, and ultimately oil price. Less Permian supply from 2021 onwards would exacerbate the global supply gap and effectively mean the US cannot deliver what the market believes it can. Other sources of higher cost, conventional production would be needed." Clarke concludes.