The Edge

Questions of science – challenging our tight oil forecasts

1 minute read

Higher for longer – not the oil price but tight oil. The flow from these prolific US fields is unabated and the root cause of depressed oil prices.

We have raised our long-term estimates, now expecting volumes to rise from 4 million b/d currently to 10 million b/d by 2025 – 1.4 million b/d higher at peak than before. Two-thirds of the growth is from the Permian.

On our travels in North Asia, I quizzed Ben Shattuck, WoodMac’s Principal Analyst Lower 48, on the team’s upgrade.

Q.Why have we increased our tight oil forecasts?

A. We’ve seen productivity gains lowering breakevens, but availability of capital and more effective deployment of capital are two of the big factors.

The Permian is proving a gem, and there’s a structural shift in ownership in the basin. Deals like EOG acquiring Yates Petroleum in 2016 and ExxonMobil/Bass in 2017 give the operators a bigger spread of opportunities, on which they can high grade well inventory and put money to work in the best locations.

Tight oil is undergoing a shift from cottage industry, to a large-scale manufacturing process

Q. Is the build-up quicker too?

A. Much quicker. Improved efficiency means operators can do more with each rig. The rapid deployment of rigs underway will lead to tight oil production growing at 0.7 million b/d every year from in 2018 through 2023, reaching plateau only in 2025.

Q. Why did the Permian arrive on the scene so late?

A. The Permian is a big resource that’s produced from low-risk vertical wells for decades, and there was scepticism whether tight oil would deliver there.

Some operators, flush with success in the Eagle Ford, tried out the same techniques in the West Texas Midland Basin in 2012/13. Horizontal drilling and fracking worked immediately and oil production took off. By the mid-2020s the Permian will be producing over 5 million b/d on its own – that’s more than either Brazil or the North Sea!

Q. Are WoodMac’s tight oil forecasts the most bullish out there?

A. Absolutely not. We are very positive, but others are higher still. Just extrapolating some operators’ estimates of the potential they see in their inventory of wells suggests volumes could touch 12–14 million b/d in the middle of next decade.

Q. What do they see that we don’t?

A. There are lots of swing factors – the number of rigs deployed, wells drilled, speed of drilling and rig efficiencies, and the ultimate number of zones that will be fully developed.

But recovery factor is the biggest difference. It’s understandable that there will be a range of possible outcomes say for the Permian, still early in its development. And we know that geologically tight oil plays vary from well to well and zone to zone, proving up the Permian and other tight oil plays will throw up surprises over the next few years.

We'll start to appreciate more of the production nuances as projects mature. For now, we’re happy to be on the conservative side.

Q. Where else do we get challenged on our numbers?

A. We get push back that our IP (initial production) rates are low. There are a lot of good wells that flow prolifically but also disappointments. We're careful to look at the average rather than just the best wells in our modelling. We worry that high IP rates just accelerate production rather than add recoverable barrels, and may lead to steeper declines.

Production life may even be shorter, and operators will have to compensate by drilling more wells to sustain production or rely even more on artificial lift. The NPV benefit of high IP rates for every operator is doubtful in our view.

Q. How can outsiders get a piece of the action?

A. It’s a real challenge. The tight oil ‘haves’ hold all the aces – knowing the ‘lie of the land’ and the people network on the ground which are key.

The incumbents are also building on their advantage, acquiring contiguous acreage, high grading and transferring best practice across their portfolios. The ‘have nots’ have none of this.

It’s galling for new entrants to see deals costing US$40,000/acre and then playing catch-up from day one. One thing in their favour is many tight oil operators face rising costs and need capital to grow. Innovative farm-ins and partnerships could be a foot in the door.