“Oil shale is the fuel of the future, and always will be.” But, as the tar sands have shown, changes in the economics of the industry coupled with technological developments can foster large scale production from previously inaccessible sources.
Second, the projection is based on expectations about both price and technology. Significantly, a recent survey of petroleum economists showed little consensus about future prices. The survey revealed two distinct camps -- those who think prices will remain high or increase and those who think they will fall substantially. Their take on prices is largely tied to their expectations about the impact of shale oil on the global market. One camp argues that the upside from shale oil supplies will be more than enough to meet demand growth. The other disputes that, saying the likely impact from shale is being exaggerated.
The role of technology is equally contentious. Some geologists point to the role of two technologies that have been central to the development of shale gas: hydraulic fracturing and horizontal drilling. Others emphasize the technologies present at Shell's Mahogany Ridge Project; a new, working, but small scale, oil shale demonstration technology that produced 1400 barrels of oil without mining. The traditional approach to oil shale -- which led to the bridesmaid label -- involved 'retorting,' a process that required mining the shale, hauling it to a processing facility that crushed the rock into small chunks, then extracted a petroleum substance called kerogen, then upgraded the kerogen through a process of hydrogenation (which requires lots of water) and refined it into gasoline or jet fuel. Here is a description of the Mahogany Ridge process from Shell's Terry O'Connor:
“Most of the petroleum products we consume today are derived from conventional oil fields that produce oil and gas that have been naturally matured in the subsurface by being subjected to heat and pressure over very long periods of time. In general terms, the In-situ Conversion Process (ICP) accelerates this natural process of oil and gas maturation by literally tens of millions of years. This is accomplished by slow sub-surface heating of petroleum source rock containing kerogen, the precursor to oil and gas. This acceleration of natural processes is achieved by drilling holes into the resource, inserting electric resistance heaters into those heater holes and heating the subsurface to around 650-700F, over a 3 to 4 year period.In short, the individual 'pieces' of a working approach have been demonstrated, but their viability as a systemic whole, particularly on a commercial scale, remain unproven.
“During this time, very dense oil and gas is expelled from the kerogen and undergoes a series of changes. These changes include the shearing of lighter components from the dense carbon compounds, concentration of available hydrogen into these lighter compounds, and changing of phase of those lighter, more hydrogen rich compounds from liquid to gas. In gaseous phase, these lighter fractions are now far more mobile and can move in the subsurface through existing or induced fractures to conventional producing wells from which they are brought to the surface. The process results in the production of about 65 to 70% of the original “carbon” in place in the subsurface.
“The ICP process is clearly energy-intensive, as its driving force is the injection of heat into the subsurface. However, for each unit of energy used to generate power to provide heat for the ICP process, when calculated on a life cycle basis, about 3.5 units of energy are produced and treated for sales to the consumer market. This energy efficiency compares favorably with many conventional heavy oil fields that for decades have used steam injection to help coax more oil out of the reservoir. The produced hydrocarbon mix is very different from traditional crude oils. It is much lighter and contains almost no heavy ends.
“However, because the ICP process occurs below ground, special care must be taken to keep the products of the process from escaping into groundwater flows. Shell has adapted a long recognized and established mining and construction ice wall technology to isolate the active ICP area and thus accomplish these objectives and to safe guard the environment. For years, freezing of groundwater to form a subsurface ice barrier has been used to isolate areas being tunneled and to reduce natural water flows into mines. Shell has successfully tested the freezing technology and determined that the development of a freeze wall prevents the loss of contaminants from the heated zone.”
It may seem, as O’Conner said, counter-intuitive to freeze the water around a shale deposit, and then heat up the contents within the deposit. It’s energy-intensive. And it’s a lot of work. What’s more, there’s no proof yet it can work on a commercial scale.
Yet both technologies, the freeze wall and the heating of shale, have been proven in the field to work. The freeze wall was used most recently in Boston’s Big Dig project. It was also used to prevent ground water from seeping into the salt caverns at the Strategic Petroleum reserve in Weeks Island, LA.
Third, a number of other factors have to be taken into account. The energy content of oil shale varies tremendously from region to region. Colorado shale is, by far, the most concentrated and, hence, most attractive. But, the process is both energy and water intensive, and water is at a premium in Colorado. Moreover, 72% of known US oil shale reserves are on government land. This is a fact that cuts both ways. On the one hand, this provides an economic lure; development of the lands could provide a significant revenue stream. On the other, as the case of drilling in the Alaska National Wildlife Refuge shows, exploitation of sensitive government lands can be a political hot potato. The Colorado reserves lie on land surrounded by National Parks and other sensitive areas. So, simply put, in addition to the economic and technology matters, there are also significant political considerations.
Finally, as my earlier research on the history of oil estimates showed, the current political economy of the oil industry accounts for the way assumptions underlying such projections are interpreted. In other words, while the projections are justified in terms of geology and technology, it is the current political economy of the industry which affects whether such estimates incorporate 'optimistic' or 'pessimistic' assumptions about the implications of those factors. Simply put, when there is lots of shut in short term capacity, the industry thinks that there is lots of energy available and opts for optimistic assumptions about future geology and technology. Alternatively, when demand outstrips supply, there is no shut in capacity, and the industry is doing everything it can to find new sources and get them on to the market, then pessimistic assumptions about future geology and technology become the order of the day. Thus, given the current glut of supply on the market, history suggests we would be wise to question the ultimate validity of these particular projections.