Modeling shale gas production—bonanza or bust?

Editor Neil McNaughton, with help from Kappa Engineering CEO Olivier Houzé, takes a skeptical look at shale gas. Behind the ‘game changer’ for world energy headlines is a complex picture of price and reserves. Anyone for a million year buildup test?

It usually takes a while for ideas to enter the public consciousness—but once they are there, they become immovable objects. Where I live in France, shale gas exploration is invariably associated with damage to the environment. Its exploitation has been banned under moratoriums from both right and left wing governments. But that is not the immovable idea I want to explore in this editorial.

The other universally accepted truth relating to shale gas is that it is a game changer for world energy. The US is going to be self sufficient in gas (and maybe oil) at some not too distant date. Cheniere’s LNG import facilities planned for the southern US are now being turned into LNG export terminals. At least one major conventional gas project has been canceled (Shtokman). And as natural gas is perceived as environmentally green, there are moves to replace coal and diesel fired electricity generating plants.

The problem with this rosy scenario is that there are two big unanswered questions. One is the amount of gas that these new-type wells will deliver in the mid to long term. The other is the price at which such can be said to be economic.

Let’s deal with the second question first. At the 2010 AAPG, Chesapeake’s Aubrey McClendon stated that money could be made at $5/mcf but McClendon may be seen as something of an optimist. In 2011, BG Group’s Malcolm Brown stated that natural gas was ‘developable’ at $5.

Given the propensity for oil and gas folks to paint a rosy picture and present something nearer to a best case than an average, I suggest that we retain $10 as a price that would bring a significant portion of the promised reserves into play.

Natural gas is currently selling for around $2 in what is clearly an unsustainable situation. A glut of production has hit the market, and as ExxonMobil CEO Rex Tillerson said recently, ‘We are all losing our shirts.’ For those of you who are more comfortable with crude oil prices, think of how things were when crude was at $20 compared to today’s $100.

Given that the wheels should have come off the shale gas game in North America, what is sustaining the activity? One factor is that in Europe, the natural gas price is around $11 and in Japan, nearly $17. So those folks at Cheniere are probably on the right track. Another factor is momentum, as industry drills its obligation wells.

To return to the first question as to ‘how much’ shale gas will be produced I bring in my first and only witness, Olivier Houzé, who is CEO of Kappa Engineering, a vendor of well test software that it used, inter alia, to evaluate shale gas wells. Houzé, speaking at a recent gathering of the French oil and gas technologists’ association (AFTP), provided an insight into the state of the art of evaluating shale gas wells. We summarize his conclusions as follows.

The shale gas boom presents an interesting problem to the reservoir engineer. There is a lot of science that has the potential for useful application. But the ‘factory drilling’ paradigm means that little money is devoted to research and there is no prior experience of how these novel reservoirs will perform. A ten year period from first production is required before we have the good data we need for a proper evaluation.

What we do know is that there are multiple modes of production and different scales of gas diffusion including desorption, flow through micro-pores and the fracture network itself. The concept of a ‘virtual’ well test is instructive. Calculations show that it might take a million years to reach pseudo-steady state in the reservoir itself! Even attaining pseudo radial flow may take 100 thousand days. In the early days of unconventional production, various decline curve models were tried. Although wells were far from the terminal decline phase, such calculations were accepted by the SEC and booked as ‘reserves.’

What should be used for a twenty year plus evaluation? Working from a straight line flow regime, the ‘ad-hoc’ Arps decline curve has begotten thousands of publications and various fiddle factors. But the problem is that 2-3 years of data is too short a time frame to evaluate such methods.

Analytical models suggest a less optimistic picture than decline curves, but they may be ‘right,’ or at least less wrong. Such models can be very complex including, for instance, fractal diffusion. Tools are being built today in anticipation of possible ‘bad news’ when the decline curve approach no longer works. These include numerical models with unstructured gridding and dynamic refinement. Some models may need millimeter cells!

Despite these sophisticated models we still lack data. Model water flow back studies and stress analysis may be tried in the face of an unwelcome productivity drop. But here, empirical pressure-to-productivity relationships may be used to ‘explain’ just about anything.

All the models can match sub 10k hour data. One early study was recently updated with an extra ten months of data. Rerunning the model showed that the old straight line proxy was extremely optimistic and missed the fact that fractures see’ each other. The analytical model turned out to be pessimistic, failing to account for formation compressibility. While an ‘improved’ numerical model was OK, this does not say much/anything about the next 5-10 years.

For both shale gas and shale oil the problem is that all kinds of curves can match the first three years of data. But what happens over the longer term? Several industry consortiums have been initiated to try to understand the problem.

So there you have it. A game changer for world energy that is predicated on a significant hike in US natural gas prices and whose capacity to deliver the promised reserves is the subject of under-funded research as industry ‘factory drills’ ahead!

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