Larry Lukens - July 9, 2005 - copied from spentshaler's Journal
Larry Lukens is one of the most knowledgeable energy business veterans pursuing the goal of developing a healthy shale oil industry. A 20 year Navy veteran whose career includes a variety of top-level positions in the federal government's energy programs, Larry headed the Paraho Corporation in the 1980s. He is now consulting for the Queensland Energy group as they determine appropriate steps for development of the Stuart project in Australia.
The mere mention of oil shale to the uninformed often provokes a knee-jerk reaction and litany of reasons as to why the commercial development of this massive resource is a bad idea. Here, the most often cited reasons are lack of sufficient water supplies, energy inefficiency, uncontrollable adverse environmental impacts, and the so-called "popcorn effect". Like most myths, these never had any basis in fact, once did but no longer do, or have been embellished over the years to the point of absurdity.
Before we examine each of these myths, it is important to understand that the various methods for the conversion of oil shale to shale oil vary markedly and, as such, do not conform to a "one size fits all" labeling. This fact more often than not either gets overlooked or is not known, resulting in sweeping generalizations and precipitously false conclusions. I'll provide examples of this pitfall later on.
In addition, some of these myths have their genesis in studies that go back more than 25 years and ignore the fact that, yes, some things actually have changed since. Advances in best available control technologies for the mitigation of environmental impacts and improvements in energy conversion efficiencies are but two examples of why some of the more dated concerns over oil shale development no longer apply... but they seem to persist nonetheless. Here it is important to recognize that, while there may have been little in the way of U.S. oil shale development over the past several years, an oil shale conversion plant has many close cousins in other mining, minerals processing and petrochemical refining industries. These industries have not been standing still, rather they have been advancing technological improvements that are directly applicable to oil shale.
In 1980, the Office of Technology Assessment (OTA) issued a report on its assessment of oil shale technologies1. Chapter 9 of this report was devoted to the question of water availability. Based on their analysis of what the OTA investigators deemed the six most advanced retorting technologies at that moment in time (1980), it was reported that net water requirements, in terms of the number of barrels of water consumed for each barrel of oil produced, would range from a low of 2.1 to a high of 5.2. These net water requirements then were compared to OTA's analysis of the availability of water in the oil shale regions of Colorado, Utah and Wyoming, leading the investigators to conclude that the maximum production capacity of an oil shale industry in this region would be limited to between 500,000 to 2,000,000 barrels per day, depending on the mix of technologies deployed, the volume of new water storage facilities constructed, and the average annual flows in the Colorado River combined with other demands on the same. These numbers (read "limitations") have been thrown around with reckless abandon ever since.
Now let's take a look at the facts. In 1980, none of the six technologies examined by OTA had progressed beyond the pilot plant or semi-works plant level of development (i.e., R&D at the field level). More importantly, detailed engineering designs of the deployment of these technologies on a full commercial scale had not been performed at that time. As such, a more detailed understanding of the water balance (i.e., water production versus usage) for these plants - an understanding that cannot be gained absent an engineering analysis of a fully integrated commercial facility - was not available to OTA at the time the study was conducted.
Now, if we fast-forward to the late 80s and early 90s, we find a quite different result. Take the Paraho process for example. The 1980 OTA report shows that the direct-heated Paraho process would consume between 2.27 and 2.71 barrels of water for each barrel of oil produced. These were early estimates based on the results from Paraho's pilot plant and semi-works plants (i.e., R&D plants). Subsequently, Paraho initiated and completed a detailed engineering design for a full-scale, commercial project, which design included a complete water balance for the plant. This water balance resulted in a net requirement of 1.3 barrels of water for each barrel of oil produced. Thus, and assuming that OTA's assessment of water availability remains valid, at 1.3 barrels of water per barrel of oil produced, OTA's upper limit of 2 million barrels per day increases to over 3 million barrels per day.
Examining the actual water usage experience of the Unocal commercial demonstration plant makes an even more compelling argument. This plant, which was constructed in the Colorado Piceance Creek Basin in the mid 1980's, was (and remains) the largest oil shale processing facility ever constructed and operated in the U.S. With a design plate capacity of 10,000 barrels per day, this plant was intended to provide a demonstration of the Unocal B retorting technology at a commercially representative scale. While the plant failed to operate for extended periods of time at its design rate, it did operate for several years (it was shut down in 1993) and, as such, provided a significant advancement of understanding with respect to many issues, including those associated with water usage. Over the period of its operation, this plant actually produced more water than it consumed. This statement is based on my conversations with engineering personnel who worked for Unocal and is further supported by the fact that Unocal was forced to construct several evaporation ponds in order to dispose of excess water. Here, it should be pointed out that the amount of water that this plant actually used was less than the design rate, owing to the fact that the retorted shale disposal area contained shale that was not fully retorted and therefore absorbed a lesser percentage of water than would otherwise be the case. Even if this had not been the case, however, it is highly unlikely that continued operation of this plant would have resulted in a net water usage. It is interesting to note, in this regard, that the 1980 OTA report shows net water consumption for the Unocal process of 2.77 barrels of water for each barrel of oil produced.
Before leaving this myth, perhaps I should mention the sources of the water that are produced and/or collected by these plants. Colorado oil shale contains, on average, 2-5% by weight of a combination of surface and mineral bound water, which water is liberated and collected during the retorting process. In addition, and for those retorting processes that combust the residual carbon that remains on the shale after the shale has been retorted, water is produced as a product of this combustion. Other sources of water in the plant include collected surface water run-off and sanitary wastewater, along with water condensates from various processing systems.
The message here is quite clear. Considerably more is known today about the water usage requirements of oil shale plants than was the case when the OTA report was issued in 1980... and yet this report still is cited as the quintessential authority on this matter. Advanced engineering designs combined with actual operating experience now show that an oil shale industry with a capacity well in excess of 3 million barrels per day can be achieved, provided the more water conserving technologies are employed.
I'm not certain how this myth got started; however it is patently ridiculous that is at least for the technologies with which I am familiar and have the energy balance data to back it up. More specifically, I cannot comment on certain of the in-situ approaches for I am not privy to the energy balance data from the same. On the other hand, I can comment on certain of the surface processing technologies, particularly the Paraho process.
To begin with, it is important to understand that in an oil shale thermal recovery process (i.e., retort), the organic material (kerogen) in the rock decomposes upon heating to form a hydrocarbon vapor (i.e., vaporized liquid) and a hydrocarbon gas. The vapor then is subsequently condensed into the liquid form we call shale oil. Moreover - and this is a very important point - that isn't the end of the story - at least for some processes. Once the retorting process is complete - that is, once all of the kerogen in the rock has been decomposed - there remains on the rock a significant amount of carbon, which carbon represents a significant source of fuel. Several of the surface retorting processes make use of this residual carbon to provide the source of heat required for the retorting process, to produce steam for use in other areas of the plant and to produce electrical power.
Let's use the Paraho process again as our example, since it is the one for which I have access to detailed engineering data. This process uses the residual carbon mentioned above to provide the energy required to carryout the retorting process (i.e., to produce the shale oil and the hydrocarbon gas). Once that energy requirement is satisfied, there remains sufficient residual carbon on the retorted shale to fuel other requirements in the plant... plus some. For example, in the case of a plant producing 100,000 barrels per day of shale oil (actually, upgraded shale oil, or syncrude), and after satisfying all of the energy requirements for the entire process, there remains sufficient energy in the form of carbon to produce 500 megawatts of electrical power for export. In other words, this plant would provide a net production (i.e., over-the-fence sales) of 100,000 barrels per day of syncrude plus 500 megawatts of electricity. So much for the myth that an oil shale industry would consume more energy than it produces.
Before leaving this myth, I should point out that, in recent years, this myth has been tied to the greenhouse gas issue, as well. Here, the argument is that the development of oil shale is "greenhouse unfriendly" since it consumes more energy than it produces, with this net energy deficit most likely being supplied by a fossil fuel burning power station. Well, and as the example cited above so clearly demonstrates, this claim is utter nonsense. In fact, quite the opposite is true, at least for oil shale plants that make maximum and productive use of all of the energy content of oil shale. That is not to say that the conversion of oil shale will not produce greenhouse gases (i.e., CO2), for it will. What it does say, however, is that with the application of prudent first law (i.e., conservation of energy) principles, the oil shale industry can provide a greenhouse gas offset by producing electricity that would otherwise be produced in fossil fuel power plants.
This myth is considerably more difficult to address for it depends on one's definition of "acceptability". Moreover, I have found that the question of environmental acceptability more often than not gets confused with the question of social acceptability... and then it becomes even more difficult to define.
Having said that, let's start with something that we can define. From an engineering perspective, environmental acceptability simply means whether or not the appropriate application of best available control technologies and practices will be sufficient to meet or beat the applicable environmental regulatory requirements for air emissions, water discharges, and the like. Under this definition of environmental acceptability, oil shale plants will either be acceptable or not, depending on whether the developers of these plants are successful in convincing the government regulators that they should be issued the necessary permits to practice. Under current law, I see no reason why an oil shale plant can't meet these requirements, for the nature of the emissions and the technologies for controlling the same are well known and in common practice in other industries. Using this as our metric for measuring environmental acceptability, therefore, this myth is just that... a myth.
The more nebulous - but nonetheless real - metric, however, is the one that actually relates more to the question of "social acceptability". Here, and to be certain, there are many groups " some organized, some not - that will be vehemently opposed to the development of an oil shale industry. As they have in the past, they will argue that this pristine area of the West (although it's becoming less so with all of the gas development activity) must remain unspoiled, that development will destroy certain habitat, that it will add to the greenhouse gas problem, etc., etc., etc. Now of course, the development of an oil shale industry will result in adverse environmental impacts when compared to the status quo. The question, therefore, becomes one of whether society is willing to accept these impacts or whether it prefers to maintain the status quo.
As an oil shale developer, there are only a couple of ways one can go about addressing this issue of social acceptability. First and foremost, I believe it important to be as transparent as possible. By that I mean, be completely open, honest and proactive in the disclosure of your development plans, how the same will impact upon the environment and the local communities and what you are prepared to do to mitigate the same. Beyond that, you must then "walk-the-talk" by making good on your intentions and promises. At the end of the day, however, social acceptance really equates to political acceptance, at least as long as our elected officials speak for and act on the behalf of our society. As such, the metric by which we measure social acceptability now becomes definable, for the political process can choose to legislatively permit or prevent the development of the industry.
I intentionally left this myth for last for it is so silly that it hardly deserves any mention at all. Nonetheless, it's still around and often cited as yet another reason why an oil shale industry is infeasible.
I remember this one particularly well, for it brings to mind an incident that took place back in 1979 when I was instructed by my boss at the Pentagon to go meet with the President's chief science advisor. I did and soon discovered that the President's chief science advisor was of the opinion that a 1 million barrel per day oil shale industry would cover the entire state of Colorado in more than 6 feet of retorted shale waste... because of the dreaded "popcorn effect". I was never certain whether I managed to dispel his mistaken opinion.
The "popcorn effect" stems from the claim by some that oil shale rock expands during the retorting process (not unlike heating popcorn), resulting in huge volumes of material... so huge, in fact, that one could never put it all back in the same hole from whence it came. Well, that's partially true; however the "swelling" is due to a totally different cause and, moreover and unless you are strip mining, no one in his right mind would try to shove all of this waste material back into the hole from whence it came anyway.
The so-called "swelling" has absolutely nothing to do with the retorting process. Oil shale rock doesn't "explode" or swell like popcorn when heated. Rather, the bulk density (pounds per cubic feet) of this material does decrease - like it does for any solid material - when you remove the shale from the ground and then crush it in preparation for retorting. Thus, when you place crushed shale in a pile, the pile will occupy a greater volume (due to the presence of air voids) than the shale occupied before it was crushed. The same is true for any solid material whether it's oil shale rock, coal, bauxite, your office desk or a piece of celery - chop it up and it will occupy a greater volume than it did before you chopped it up. To quantify this effect, one ton of oil shale rock occupies about 14 cubic feet before it is removed from the ground. Remove that ton, crush it and place it in a pile and it will occupy about 26 cubic feet of space (note we haven't retorted it as yet). Now retort this ton of oil shale rock (during which about 20% of the weight of the rock is removed in the form of shale oil, gas and water) and then place the retorted shale in a pile - it now will occupy about 22 cubic feet of space. Now then, if we attempt to throw this pile back into the same hole from whence that ton of oil shale rock originated, we will have about 8 cubic feet of material left over after the hole is filled... all a result of nothing more than air voids between the particles of spent shale. On the other hand, if we were to choose to compact this material to the extent necessary to reduce the space occupied by the pile to 14 cubic feet, it would all fit very nicely back into the hole.
For surface mining operations, that is exactly what you would do so as to restore the ground back to the original contours (as is practiced all over the world for coal strip mines). For underground mining, however, back filling underground could be done, but not without some spent shale left over due to the impractical aspect of compacting the spent shale back to the in-situ density of the original rock. In this case, the excess material would be placed into surface impoundments, such as the one developed by Unocal during its period of operation.
So, the oil shale industry will be no different than any other minerals processing industry that produces a tailing after the removal of the desired product... and it will deal with the disposal of the spent material in much the same way. Here it is worthy of mention that spent shale can be and has been put to use as a soil stabilization and road base material. These applications, however, have not been proven practical, not from a technical point of view, but from an economic one. Transportation costs typically render use of this material for these applications noncompetitive with comparable materials located closer to the point of use.
Like all myths, those discussed here have persisted over the years irrespective of fact and irrespective of further developments that refute. Moreover, and when added to the arsenal of those who would argue that the commercial development of oil shale is not in our best national interest, I'm not certain whether facts or other irrefutable evidence matters much anyway.
On the other hand, and for those of us who believe the commercial development of oil shale is, in fact, in our nation's best interest, we are left with but little alternative than to get on with the business of gathering the facts and the irrefutable evidence in the hope that common sense will eventually prevail. I believe the best way to do this is through a program designed to demonstrate - at something less than full commercial scale - the core technologies associated with the conversion of oil shale to shale oil or syncrude. These so-called demo plants would be large enough to prove - or disprove - that we know how to deal with the water and other environmental impact issues - but not at a scale that would leave an indelible and undesirable mark in the event we are wrong. Absent such a program, the myths of oil shale will live on, and on, and on...
1. Office of Technology Assessment, "An Assessment of Oil Shale Technologies", Vol. I&II, June 1980.