Capital efficiency: the big question for US unconventionals

Is US shale the paragon of upstream productivity it’s cracked up to be? As the marginal suppliers, shale gas and tight oil operators ought to be adept at managing for margin and all that’s about – understanding the supply chain; analysing individual well and asset performance and profitability; managing operations, processes and capital efficiently.

Unconventionals have come a long way in only a decade or so, and the downturn accelerated innovation and efficiencies. Paddrilling, longer lateral wells, targeted zone fracking and high volumes of proppant are today’s standard for leading tight oil operators, a world on from the primitive methods used to exploit the first shale gas plays. 

Tight oil break-evens have fallen by 35% from US$76 barrel WTI in 2014 to US$50 barrel (NPV,15) in 2018. Other key metrics such as IP (Initial Production) rates and Estimated Ultimate Recovery (EUR) testify to continuous improvement. The industry will argue that these efficiency gains are structural, reflecting the shift towards a factory approach to developing the plays. 

Our view is a little different. Yes, there has been structural progress. But much is cyclical, albeit in tandem with incremental improvement. Analysing the data in NAWAT (our North America Well Analysis Tool) raises the question of whether well production systems are as efficient and productive as they like to think they are. Two things stand out.

First, the variability in well performance of an operator

We examined the time elapsed during each stage of one company’s wells, from planning to permitting, pad construction, drilling, completion and finally production hook up. Drilling time averaged 48 days, but the standard deviation was 30 and the extremes ranged from just 10 days to 165 days for a well. That’s quite a difference. Geology and operational factors can affect wells and there will always be some variation. But unless the operator understands why it’s happening and addresses the problems, the result will be higher costs and inefficient use of capital. 

Second, the range of performance between operators

We looked at a sample set of operators in the Midland ‘Deep Basin’ subplay through 2015 to 2017 (see chart). The median time taken from the end of drilling and the end of completion was much of a muchness. There were though, on close inspection, big differences in the range of cycle times. Again, some variability can be a good thing, indicating design or operating changes that can be value adding. Too much variability suggests complexity in the well factory – inefficiency, higher costs and capital tied up unnecessarily. 

It can also free up a lot of capital. We’ve calculated that the current 8,000 DUCs (Drilled Uncompleted Wells) trap up to US$26 billion of capital. An effective, optimised Well Production System could free up 40%, or US$10 billion – money that could be recycled into the business or returned to shareholders. 

Tight oil and shale gas have become critical to the production outlook for Shell, Chevron, ExxonMobil, BP and Equinor into the medium term. The intensification of the  majors’ involvement will change the business model and accelerate the transformation from cottage industry to the factory model. 

Yet there are still over 200 operators of scale in unconventionals, with a wide range of performance in productivity and efficiency. Continuous improvement has to be the goal of all operators. Those failing to achieve best practice risk becoming prey as the sector consolidates.