Stepping Off The Cliff

What does it take to make shale gas commercial?

That was one of the questions addressed by Adrian Topham, Product Line Manager for Reservoir Development Services at Baker Hughes in his presentation in a workshop day preceding the European Unconventional Gas Summit Paris 2011.

But in terms of reserves, he noted there were different degrees of them: proved, probable, possible. It was also a question of whether they were discovered or undiscovered.

“The reserves are in ‘this range’ when you’re probably thinking ‘just give me the answer.’

He said there was a range of outcomes.

“Reserves are quantities of petroleum anticipated to be commercially recoverable,” explained Topham. “They must be discovered, recoverable, commercial and remaining.”

He added, “Reserves are estimated because they’re always uncertain.”

Topham explained that contingent resources were a class of discovered recoverable resources.

“European shale gas sits in the resource category,” he said, “with some of it discovered, some undiscovered. It enters into the reserves category in 2014.”

In terms of the risk and uncertainty, he said: “I’m going to fall off this cliff but I don’t know how far it is to the bottom.”

“Considering the probability of finding hydrocarbons, the risk is less for shale gas,” Topham said, adding “the uncertainty is the full range of outcomes.”

For one, he highlighted the subsurface uncertainty.

“It is present but can it be economically recovered, and with how many wells? Wells make up an even larger proportion of the cost of shale gas. These costs are higher due to fewer services in Europe.”

As to when those services will show up, he addressed the looks out in the audience: “You’re looking at me and saying ‘you tell me’ as we’re one of the providers.”

He said that conventional gas fields had drainage, while shale gas reserves were bound by economic cutoff limits, adding, “There’s a limited understanding of the 10-30 year forecast well life, as most plays are less than 5 years old.”

Topham explained that there was a reserves booking dilemma in, for example, the Haynesville shale where uncertainties were apparent in the shale’s performance. “As we get more wells in different plays, we can establish that decline rate better.”

He spoke of ways to mitigate against the cost of wells, which made up 40-50% of the development cost, via increasing the length of horizontal wells and laterals, increasing the number of fractures along the well bore, and improving the frack design.

Considering his position at Baker Hughes, there was an idea he said he was not entirely sure he agreed with, “That the risk of overruns could be reduced by transferring risk to the drilling contractor, at a fixed sum per well, a fixed amount per meter drilled, and using light weight rigs.”

“Many wells mean many production systems, so their careful design, possibly modular, might be a way to reduce those risks,” Topham said, referring to how to reduce facilities costs.

He said there were major risk factors regarding the bankability of shale gas products, like resource titles, reserves adequacy and producibility.

The risk and uncertainties, he said, were variable and could be partially mitigated through exploration.

In terms of the economics, Topham gave a macro depiction of shale gas in North America.

“It’s very much in demand there, so rig count is not a problem – there’s plenty of capacity - but we’re talking about substantial amounts of capital.”

He said that with O&G prices being relatively tied to each other, the ratio was creeping up. Global oversupply was softening the shale gas market, Topham added.

“More operators are starting to buy their way into North America, which is being developed by small operators, so national and international companies are starting to buy their way into that market. There’s been a range of buy-ins, which have been quite varied. Some of that is following the liquids, where the value is stronger.”

“When projects mature they gain in value,” added Topham.

Regarding unconventional resource value progression, he presented a cost example.

A net production forecast showed two different approaches to shale gas production: a smaller firm versus a joint venture approach, which he said provided a much more manageable capital spend, compared to the other which had a much higher capital spend.

“The development pace is set by your capital abilities,” he added.

Topham questioned a seller’s rational: Why sell?

“If you want to reduce your risk, and get more capital as a smaller operator; also to mitigate against leases and commitments. It’s the ability to monetize some of the asset.”

Topham contended major operators would bring capital, and technological advances from other parts of the world (like horizontal drilling). He proceeded to show a huge list of recent US shale gas transactions.

In terms of development considerations, he mentioned water: “We know we need large amounts, so it depends on availability.”

The footprint, he said, involved reclamation and good neighbor policies.

He had a slide entitled “LNG helping to build a global gas market.”

“It’s likely to affect the speed at which shale gas gets developed, but has a fairly high transport cost,” Topham contended.

Key criteria for tech evaluating shale gas plays, according to him, included source rock quality, source maturity, gas quality, structural complexity, timing of burial/uplift, clay content and presence of water.

Development considerations include well performance, maximizing well drainage, pace of development and capital issues.

Addressing the concerns of the public regarding hydraulic fracturing was also important.

“It’s not a new technique, and has been proven for much of the last century,” explained Topham. “It’s application has changed, it’s success.”

“Regarding concerns about drinking water, most aquifers are much shallower than the shale gas resources we’re talking about.”

He said that the major message from a technology point of view was “all shale gas plays are all different.”

“The economics vary, exploitation costs vary on a rang of things, particularly well costs,” said Topham. “Prices are dictated by things like LNG, while future price of gas is unknown.”

In closing, he noted the numerous opportunities for shale gas development in places outside of Europe, like Asia.

On audience participant proposed the use of saline water in hydraulic fracturing.

“It’s a good idea,” commented Mr. Topham. “No one’s actually thinking that far ahead yet because we’re in the appraisal phase. It depends on the compatibility of the saline water - as long as it’s free of solids and inerts. Pumping out of saline aquifers might be easier. As an industry we should be promoting that to allay concerns.”

He added, “The industry is moving away from using lots of costly chemicals for cost savings as well as environmental reasons.”

In a query regarding eco-friendly fracking fluids, Topham replied: “We are developing those kinds of things in North America. I don’t know the timeframe offhand, but I’m sure it’s pretty quick.”