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President Bush has said that to achieve energy independence for the United States, we need to quickly build new receiving terminals for liquefied natural gas (LNG). The new terminals will enable us to import more natural gas to compensate for our own flagging production. Leaving aside the president’s, er, interesting conception of energy independence, what actually are the prospects for importing enough gas to make up for declining production in North America? Is it possible that supply constraints will promptly reduce the new and very costly LNG receiving terminals to white elephants?
The Hope for LNG
The desire to build new LNG receiving terminals is understandable. There’s been a persistent 2:1 price differential, roughly, over the last few years between spot prices for natural gas in US markets and the contract price for delivered LNG. In that period, importing LNG has been highly profitable for the companies involved. However, its scope has been limited by an acute shortage of capacity to receive LNG shipments in the US. Although 2004 was a record year for it, LNG still supplied only 2.9% of the US natural gas market. The hope of many in the utility business is that new terminals will enable LNG to be imported at a rate that will finally ease the protracted crisis in natural gas supplies that has been forcing up prices over the last few years. If prices come down, then investments made in gas-fired generating capacity from the waning Clinton administration years might at long last begin to pay off.
Two recent articles in this forum, make it clear that the utilities’ hopes for cheaper natural gas are most likely in vain—at least over the next few years. The problem, as both Murray Duffin and Andrew Weissman have pointed out, is that current supplies of LNG, as well as the tanker capacity to carry it, are fully committed in service to existing markets. There’s no spare LNG production capacity sitting around, looking for new markets to supply. We can build all the receiving terminals we want, but LNG tankers will not simply come, like baseball players in a scene from “Field of Dreams”.
If we are to import substantially more LNG, then two other things must happen. First, the fleet of LNG tankers must be greatly expanded, and second, producers will have to build new gas liquefaction plants and loading terminals. There is some activity on both those fronts, and nobody doubts that LNG imports will indeed be rising over the coming years. But it is not happening at the rate at which it would need to happen in order to meet the EIA’s optimistic forecasts for LNG imports. And with the U.S. coming into the market, competition for available supplies is bound to raise prices considerably.
Economics to the Rescue?
There’s a saying in economics that “the cure for higher prices is higher prices.” In theory, a period of high LNG prices should stimulate investment in new production facilities, which will eventually bring prices back in line to something more consistent with real production costs. Production costs for LNG should be low, since the source gas is most often a byproduct of oil production. Worldwide, there is still a great deal of co-produced natural gas that is simply flared, for lack of infrastructure for getting it to market. Does that mean that we can eventually hope to see a return to lower natural gas prices, once investments in facilities for gas liquefaction and shipping have picked up? It may not be happening as fast as the EIA has predicted, but isn’t that where market economics should eventually take us?
Don’t count on it.
The Pesky Alternative: GTL
The problem is that cryogenic liquefaction of natural gas for export as LNG is not the only way to make use of so-called “stranded” natural gas. Nor is it always the best way, from a producer’s point of view.
An alternative is to process natural gas to first make what’s known as “synthesis gas”—a mixture of hydrogen and carbon monoxide—and then use Fischer-Tropsch synthesis and downstream processing to produce premium sulfur-free diesel and jet fuels. If the price of LNG is low relative to diesel, it is more profitable for producers to employ this gas-to-liquids technology (GTL) to make diesel and jet fuel, rather than exporting the gas in the form of LNG.
The tradeoff between the two options is not simple and straightforward. In both cases, the capital investment in facilities is large. Lead times for construction can be several years. LNG has the advantage that, relative to the input gas volume, the capital cost for LNG facilities is much lower than for GTL. But the facilities must normally be sited near a deep-water port; its cryogenic temperature prevents sending LNG any distance by pipeline. Insulated storage facilities at the shipping port are costly and hazardous. GTL output, by contrast, is easy to store, and can be shipped by barge, rail, or truck, if needed. It commands a market premium for its high quality. It also involves the producer in a larger piece of the “value chain” of refinery products and petrochemicals. That often accords with a producer’s long-term economic plans.
Ultimately, the choice of whether to invest in LNG or GTL production will depend on the price that LNG commands relative middle distillates from the GTL process. Or, from a different perspective, the availability of the two investment options defines a long-term relationship between the price of LNG and the price of middle distillates. If LNG prices are not high enough, producers will find it more profitable to invest in new GTL facilities, rather than LNG. So the obvious question becomes, what is “high enough” to encourage increases in LNG production over GTL?
Parity for NG vs. Diesel
There is enough information publicly available to allow a rough estimation of what the natural parity between LNG and diesel prices would be, based on the current state of the technologies involved. The answer, unfortunately, is bad news for anyone hoping for the return of cheap natural gas.
According to a recent report from SRI, the cost breakdown for GTL product from the proven Shell process is $7.00 for capital and depreciation, $3.00 for catalysts and utilities, and $4.00 for labor, taxes, and plant overhead. That’s $14.00 per barrel of output, exclusive of the gas input. In newer plants, it appears to require about 10 MMBtu of gas to produce one barrel of GTL product. If a barrel of GTL product is valued at $80, the effective return to the producer on 10 MMBtu of gas is $66.
A valuation of $80 for a barrel of GTL product is certainly high by past standards for middle distillates. However, the past standard for crude oil was not $55 / bbl. In the world going forward, $80 / bbl is probably not unrealistic for the refinery price for premium diesel and jet fuels that are free of sulfur and PAH compounds.
A long-term LNG price of $6.60 / MMBtu (“plus shipping and handling”) would be disappointing, but not a total disaster. We’ve been living with natural gas at roughly that level for a couple of years now. It would mean that LNG imports would not bring the hoped for price relief, but at least they should allow demand for gas to be met and thereby prevent prices from rising still higher.
Unfortunately, the simple derivation that led to that $6.60 figure is not the whole story.
The Larger Story
The GTL process is not, by itself, terribly efficient. Figures for carbon efficiency and energy efficiency vary depending on the particular process and reporting source. Quotes for carbon efficiency range from 55 – 70%. That means that from 55 – 70% of the carbon molecules in the natural gas feedstock end up in the liquid product. Energy efficiency is more consistently cited at about 65%. I.e., the energy content of the GTL product represents only 65% of what was contained in the input gas.
On the face of it, that sounds pretty bad. However, another little saying is that “it’s only waste if it’s wasted”. As it happens, the waste heat and chemical byproducts of GTL synthesis are valuable products in their own right.
Most of the carbon loss in GTL processes comes from the partial combustion of some of the input gas to provide high temperature heat for the steam reforming step. That step produces synthesis gas for the subsequent FT synthesis step, and is endothermic. So while as much as 45% of the original carbon may be oxidized to CO2 in the reforming phase, the loss of chemical potential energy is much less. Much of the heat released in partial combustion of carbon ends up adding to the chemical potential energy in the reformed gasses. Also, the CO2 byproduct of partial combustion has its own market value. It’s fairly easy to separate from the other reforming gases, and it can be sold for injection into aging oil fields for enhanced oil recovery (EOR). According to an article in the July 2005 Scientific American, oil producers with access to CO2 have been paying from $10 – 20 per ton to use it in EOR operations. For perspective, $15 per ton of CO2 would equate to a “rebate” of roughly $1.00 / MCF of natural gas, for the CO2 byproduct of its combustion.
In contrast to the carbon loss in the reforming step, most of the energy loss in GTL processes occurs in the subsequent FT synthesis phase. FT synthesis is exothermic; the reaction vessels must be actively cooled to keep them at optimal temperature for the reaction. However, only a part of the difference in chemical potential energy between the input natural gas and the FT liquids is lost as heat. Much of it goes into chemical potential energy in the principle “waste” product of FT synthesis—which is hydrogen gas.
Since the ratio of hydrogen to carbon in natural gas is nearly double what it is in the heavier hydrocarbons of the GTL output, it should not be surprising that the GTL process produces hydrogen as a major byproduct stream. In fact, it produces almost half as much hydrogen as would be produced if the same amount of natural gas were processed by steam reforming to produce only hydrogen. So if a hypothetical Middle East producer happened to have, say, large reserves of heavy sour crude that required a lot of hydrogen to refine, a GTL facility could supply that hydrogen at no cost. Or, since it’s only a matter of internal accounting, the GTL output could be charged for only 60% of its NG input, with the other 40% charged to hydrogen production for the refinery. That would boost the accounted productivity of the GTL process by 66%.
Hydrogen and CO2 are not the only useful byproduct streams from the GTL process. The heat energy released in F-T synthesis is not at a high enough temperature to drive the production of synthesis gas, but at 200 – 350 degrees C it is adequate for power generation and for water desalination.
Back to the Future
When the efficiencies of integrating GTL with refining of heavy crude, enhanced oil recovery, power generation, and water desalination are all considered, the price needed to favor LNG production over GTL is upped considerably. If crude remains in the vicinity of $55 a barrel, it’s likely that LNG will need to fetch $10 / MMBtu or more to justify investments in LNG production over GTL. Producers will no doubt want to hedge their bets by building some of both, but a quick boom in LNG at today’s prices appears most unlikely.
That leaves utilities stuck with uneconomical gas-fired generating capacity with only one good option: the once and future technology of coal gasification. Tomorrow’s coal gasification plants will be a far cry from the dirty, smelly “town gas” plants from the turn of the last century. Hopefully, they will follow the lead of the Dakota Gasification Company in producing a pure CO2 waste stream that can be sold to nearby oil outfits for enhanced oil recovery. But however they’re built, it’s time to get moving on them. Anyone waiting for natural gas prices to return to historical levels will, I fear, be waiting for a very long time.
 A claim equivalent to just 8 MMBtu per barrel is asserted for Conoco’s GTL process, but that is out of line with most other data. It could be the result of different accounting methods. E.g., it might exclude that portion of the natural gas input that produces hydrogen that is not consumed in the synthesis step.
Thank you for your excellent elucidation of GTL technology and economics!
A quick Google check shows that Qatar, for one, is very active in GTL development. They have (at least) a $1billion project with Conoco coming on line end of this year, a $5 billion project with Shell on-line in 2009, and a $7 billion project with ExxonMobil on line in 2011. In comparison, the 6,000 MW of new nuclear power plants contemplated in the recent Energy Bill will require an investment of about $9 billion.
I would note that at least some of the stranded gas resources are non-associated, like the one off NW Australia., lessening demand for byproducts and hence shifting the economics towards LNG for those cases.
Also, the latest EIA publication notes that as of April 2005 (the latest tabulation), the US electric industry went from 809 gas-fueled generators in 4/04 to 958 gas-fueled generators on 4/05, an 18% increase. This is neither good news nor sound electric policy.
I will also note that the author's competitive estimate of landed LNG at $6.60/mmBTU agrees closely with my earlier estimate where I compared LNG-fueled electricity against new nuclear power plants: http://www.energypulse.net/centers/article/article_display.cfm?a_id=623
Len Gould 9.2.05
The question is, why didn't the EIA etc. produce this paper themselves back in 1995?
James Hopf 9.2.05
GTL will create greater linkage between gas and oil, making them more like one commodity, with a very similar (equivalent) price. The question is, what will the overall supply/demand balance look like for this combined "gas/oil" commodity, and what will be the resulting price?
Although I disagree with them, oil/gas "optimists" believe that the potential supply of GTL will be so great that it in itself will cause the market price for a barrel of oil to drop to much lower levels. This would have the secondary effect of making LNG look more attractive, and causing the world gas price to drop. In a sense, this was not addressed by the article, as it assumes a future world oil price w/o addressing the possible effect of GTL on that price.
If these stranded gas reserves had the potential to reduce world (or US) gas prices if they were all shipped as LNG, why wouldn't they also have the potential to reduce world oil prices if they were shipped as GTL? Don't get me wrong. I don't think those sources are sufficient to do either.
This much IS true. Oil will peak first, and customers for oil-like products (i.e., cars) are willing to pay a much higher price for their fuel than are gas-fired power plants. Thus, the future price outlook for the combined "oil/gas" commodity is clearly higher than the price outlook would be for gas if it remained a separate commodity. The question is how MUCH more?
Answering this requires an analyses of future overall gas+ oil supply and overall gas+oil demand. Neither can be analyzed separately (such as pegging a future oil price prediction by looking at the oil market separately).
Roger Arnold 9.3.05
I would not want to let the EIA off the hook for the disservice their projections for cheap and abundant NG supplies have done to the utilities sector. The data that would have shown North American gas production nearing its peak were there for anyone willing to look. And the linkage between oil and natural gas prices could and should have been foreseen. Nonetheless, given their optimistic projections for oil availability, the EIA's projections for natural gas prices were consistent. The GTL-based linkage between oil and gas prices really kicks in only at oil prices higher than anything the EIA was expecting.
One of the sources I reviewed when I was researching this article was a report by A. M. S. Bakhtiari that was titled "Gas-to-liquids: much smoke, little fire". The following is its opening sentence:
"The initial gas-to-liquids (GTL) complexes implemented in the 1980s and early 1990s were not commercially successful for a number of reasons – the main one was that they were far too expensive"
There had been a lot of premature hype about the potential of GTL technology, based on underestimates of its capital costs, or overestimates of how quickly those costs could be brought down. Bakhtiari's report was detailing why GTL technology had largely fizzled. It was written in late 2001, and published in 2002. Ironically, however, the same data that Bakhtiari presented to show that GTL plants were a marginal investment with oil at $25 a barrel show that they are a very good investment with oil at $40 a barrel (and up).
Joseph makes a very good point about non-associated gas production. It does indeed shift the economics toward LNG over GTL. Particularly if it's off-shore production. The same applies for gas that is produced at or piped to a remote location where the infrastructure to support and exploit the more complex GTL system does not exist, and would be uneconomical to build. (I'm thinking of Sakhalin Island.) That's one of the reasons I'm certain that LNG production will be increasing. I just don't see it increasing fast enough to make much of a dent in natural gas prices.
I also agree with James that GTL production won't be large enough to significantly restrain oil prices. Not directly, anyway. However, the immediate supply crisis that is driving oil prices up is the shortage of light sweet crude. There seems to be enough heavy sour crude still available. The problem is lack of appropriate refinery capacity. GTL offers an economically efficient way to provide the hydrogen and thermal energy required for refining heavy sour crude. In that sense, it will serve to delay and soften the production declines that we will inevitably be facing.
Len Gould 9.3.05
It is interesting to read this CERI report on Oilsands production, though fairly outdaed now. http://www.ceri.ca/Publications/OilSandsSupplyOutlookPresentation.pdf
Some points: 1) They hoped that oil at Oklahoma Cushing might stay well above US$25/bbl (2003$) to enable further development. 2) If so, anticipate 3.5 million bpd by 2017. 3) "Gas consumption under this case could rise to as much as 3.7 Bcf/d by 2017. However, please recognize that this is a high-side outlook. A more reasonable outlook would see gas demand by 2017 in the range 1.5 to 2.5 Bcf/d. These are still very big numbers and represent more gas than is expected to be brought to Southern markets from Canada’s McKenzie Delta/Beaufort Sea region."
My own observation is, with oil going where it has been lately, what effect then on gas useage? Sure to put a bigger dent in available Cdn exports. Maybe Alaska gas could serve to provide the H2, and they could figure out a way to use the crude for the requred heat. Or a few small nuclear reactors?
Len Gould 9.4.05
Also interesting is this slide set from Cdn Assoc. Petroleum Producers http://www.capp.ca/raw.asp?x=1&dt=PDF&dn=85172
Here is documented a few interesting items.
1) Oilsands production current technology uses 0.45 mcf gas per bbl oil, though they indicate research is underway to reduce that.
2) WCSB (Western Canada Sedimentary Basin, essentially all of Alberta and BC gas production) is assigned a concensus "ultimate production estimate" which is less than double the amount already produced, eg. it has already peaked and is on a downward trend.
3) No other alternative (Artic Islands, McKenzie Delta, Coal Beds, Offshore west or east) is estimated to provide even a fraction of what WCSB provided.
4) Cdn coalbeds are huge relative US, so i'd guess US coalbed methane will not be very significant going forward.
Murray Duffin 9.4.05
Roger, Dr. Banks recently noted that a pipeline can transport a lot more energy as GTL liquid than as gaseous NG. For NG that is stranded inland, far from the coast. there is an added economic benefit to put the GTL plant at the well-head and pipe the liquid, rather than piping the gas and putting the LNG plant on the coast. Do you have the data to quantify this advantage? Murray
Roger Arnold 9.4.05
I don't have specific data on that, but you've tweaked my curiousity. I'll try to run some calculations.
I'd be surprised, though, if pipeline transport efficiency of gas vs. liquids turned out to be a significant issue favoring GTL. This big issue with any pipeline always seems to be capital cost; there has to be a sufficiently large and reliable source to justify the large up-front cost of pipeline construction. The difference in relative transport efficiencies would have to be awfully large to overcome the 35% of the original energy in the gas that is converted to heat and hydrogen in the GTL process.
More significant than pipeline transport efficiency for gas vs. liquids is the fact that for gas, pipeline transport is virtually the only option; for liquids, OTOH, options include tanker trucks, rail cars, or river barges. So GTL can (theoretically) be applied to sources that are too small or temporary to justify a pipeline.
The extent to which GTL facilities can be economically scaled down is controversial. Shell is on record as saying that only large plants are economically viable. They would need to be fed by an extended supply network comparable to that needed for LNG. Syntroleum, though, is actively promoting small barge-mounted plants that can be taken to sources for which pipeline construction is not justified. There was also talk at one time of complete GTL conversion plants fitted into trailers that could be trucked to the well head. I didn't find anything happening on that front when I was researching this article, however.
Roger Arnold 9.5.05
After a little time to think about it, I realized that my answer above is inadequate. I realized when I answered it that Murray had framed the question in terms of transport capacity, whereas I answered in terms of transport efficiency. I did that because capacity and efficiency trade off; if pumping losses from a given size of pipeline would be too high, then use a larger diameter pipe pumping at a lower speed.
The problem with that model is that I had been thinking of pipeline cost as being dominated by the fixed costs per mile for right-of-way and access roads. It's not. The cost is surprisingly close to linear with pipeline cross section. So Dr. Banks point about pipeline capacity for liquids vs. the equivalent amount of gas is both valid and significant: for a given capital budget, more energy can be transported when pumping GTL liquids rather than gas.
I can't yet quantify that, and I think it remains true that in general, the availability of other storage and transport options is a more significant consideration motivating GTL than lower pipeline costs. But in particular cases, the pipeline cost could end up being the dominant consideration.
I also have an update to my end note , regarding the claim of only 8 MMBtu per barrel for Conoco's GTL process. The claim is probably valid. Both the carbon and energy efficiency for the process would be substantially higher than for the other processes I was citing. The tradeoff is that there's no hydrogen byproduct stream. The excess hydrogen from the FT synthesis step is fed back to the reforming step, where it increases the output of synthesis gas and reduces the output of CO2.
Joseph Somsel 9.6.05
Note only has the EIA been painting too rosy a picture, the USGS has been even worst.
It definitely looks like US natural gas production has peaked and probably Canada too.
Bruce Oliver 9.6.05
Don't worry about letting EIA off the hook for poor estimates. Anyone who invests in energy facilities and does have enough understanding of the industry to know not to rely on EIA forecasts deserves what they get.
The fact is many owners of gas-fired electric generating facilities have had numerous warnings in the trade press and other forums warning of tightening natural gas supplies and the potential for higher gas prices. Unfortunately, the comparatively low costs of installing gas-fired electric generating capacity, environmental impediments to building other types of generation, and the perceived potential for near term profits in deregulated markets often caused resulted in those warnings being ignored.
Although poor national energy policy has contributed to this problem, a lack of effort on the part of many industry participants to understand fully the fuels markets to which they were commiting themselves has also played an important role.
Mike Watkins 9.6.05
Roger, thanks for an excellent paper.
Regarding the 8-900 NG fired power plants you mentioned, a significant number of those can be fired with light distillates as easily as they can burn NG, be they combustion turbines or steam boilers. At $10/MM btu for NG (what utilities in my area were paying as of a week or so ago) and with coal gasification a long way off and capital intensive, those that are near enough to the necessary infrastructure (liquids pipelines, ship or barge offloading facilites, etc.) could be easily switched to light distillates with very little capital investment if they are not dual fuel capable already. A lot of "stranded" NG fired plants could suddenly have viability IF the owners of this "stranded" NG were willing to produce GTL at less than your indicated $66/bbl effective return.
After all, the whole concept of GTL is the utilization of an otherwise worthless asset. So to my way of thinking, to compete with other fuels; NG, LNG 6 oil, etc. it will have to be priced competitively, which is not at $80/bbl.
Can you give a comparative number to the $14/bbl production cost on a MM btu basis for the cost to produce a MM btu of LNG? I have read conflicting information as to which is more energy efficient, LNG of GTL on a "well to wheel" basis.
And, last point/question, I understood from earlier research I did that water itself was a by product of the GTL process apart from any water produced via desalination using waste heat from the process.
Paul Roberts 9.6.05
Your article makes some very good points. Regardless of the level of LNG imports, natural gas prices and oil prices have historically been well correlated. (See Stephen P.A. Brown's article at http://www.dallasfed.org/research/swe/2005/swe0504c.pdf.) The correlation changes from time to time due to the economics of utilization and environmental constraints.
Since natural gas is sold in some markets (especially Europe) at prices determined by oil prices, it's likely that the price relationship will continue. Therefore, it's unlikely that LNG would significantly reduce natural gas prices. As the author noted, recent high prices for natural gas haven't led to high utilization rates for the existing terminals. And the Excelerate terminal has been substantially underutilized.
Dale Nesbitt 9.6.05
Very nice article. I came into the energy market modeling and consulting business in 1974 when many of today’s hydrocarbons were probably “source rock.” My first half dozen projects were synfuels projects—coal to liquids, coal to gas, shale to liquids, gas to liquids, shale to liquids, tar sands to liquids, and (amazingly) liquids to gas. Here we are 30 years later with many of the same issues. The first two facts that were impressed on me back in those days were that sticking hydrogen atoms onto carbon atoms was (a.) expensive, (b.) valuable, and (c.) endothermic and that liquid fuel pipelines and tankers are very inexpensive relative to gas. Your article is the first replay of the former I have seen in 30 years, and a nice articulation at that.
Having worked the LNG and world resource business, there is one extension to your discussion that would seem to me to merit thought. It was mentioned in a previous comment, but I want to underscore it. Gas near the ocean has competitive advantage as LNG. Gas not near the ocean has no competitive advantage and is more suited to GTL given the low cost of liquid fuel transportation and the substantial cost of gas pipelines from landlocked source basin to the ocean. As you correctly point out, GTL is endothermic, and there will be strong incentives by GTL owners to procure feedstock gas as inexpensively as possible. Every penny they save in gas procurement is a penny of margin capture. That tends to point them inland toward low gas prices. One can foresee a scenario in which landlocked gas such as West Siberia, East Siberia, Prudhoe Bay, Kazakhstan, the Russian Arctic, etc. far from the ocean will be differentially economically more suited to GTL while coastal onshore and offshore gas such as Qatar, Saudi Arabia, Iran, UAE, Northwest Shelf will be differentially economically more suited to LNG. This of course depends on the full life cycle cost of GTL (including losses), which is uncertain at present. We find in our World Gas Trade Model work these days that there is a significant economic difference between landlocked gas and coastal or near-coastal gas. It is clear as you point out that increased demand against regional gas resource bases worldwide will elevate located wellhead prices of that gas resource base relative to letting it continue to sit there as has occurred for the past few decades.
R George 9.7.05
Mr. Mike Watkins (9/6/05) comments on reducing the risk of stranded NG fired plants by using light distillates are worthwhile and should be examined closely. I see some major challenges though: a) price of light distillates would most likely track that of natural gas, so the benefit of economically switching back and forth may be constrained. b) air quality regulations in metrolopolitan areas, such as Los Angeles, may prevent, or at least constraint, such as switching. Additional exhaust controls may be needed. c) possible increase in global warming pollutants. Has someone calculated the impact on global warming pollutants when switching to light distillates - to what degree will these increase in a dual fired plant?
Ranji George (these views are mine, and not necessarily those of my employer, a public agency that regulates natural gas plants)
Joseph Somsel 9.7.05
As to fuel switching from NG to distillates, here on the North Coast of California, all the older formerly dual fueled plants (Moss Landing, Morro Bay, Hunters Point, etc) have had their hardware for oil storage and burning removed. The newer CCGTs like Metcalf can only use gas.
Not much chance for alternate fuels in my neck of the woods.
As to management's ability to predict the future, I remember raising the objection of limited domestic gas supply to a senior VP of my utility in 1991. He shrugged and then the company went bankrupt 10 years later.
Mike Watkins 9.7.05
The gas turbines that are the basis for the modern CCGT plants come in a variety of fuel options, and many are dual fuel from the factory. Those that are not can be retrofitted to dual fuel capability with relative ease. This would, of course, involve building some tanks and associated piping in addition to actual burner modifications to the GT's.
One thing that makes GTL light distillates attractve over petroleum based distillates is their lack of sulfur, which is usually the bad actor in most oil firing.
Len Gould 9.8.05
Joseph: the line is so good it deserves a comment to commend you. " He shrugged and then the company went bankrupt"
Joseph Somsel 9.8.05
Thank you for the compliment.
You ain't gonna burn NO oil around here without an air quality discharge permit and for that you need to buy discharge allotments. Good luck. Plus, delivery over water to our coastal plants would face environmentalist opposition about the ports and terminals.
It's not the engineering, it's the government.
Agreed that GTL is low sulfur and a premium fuel but NOX can still be an issue - will it burn cooler? Gas-fired CCGTs here has trouble meeting NOX emissions.
Rodney Adams 9.17.05
Very interesting article, followed by some of the most educated commentary that I have seen on Energy Pulse. BZ to all. (That is Navy lingo for good job).
As a future purveyor of small nuclear gas turbine plants, my question relates to the possibility of using our waste heat as the heat source for the endothermic part of the Fischer-Tropsch process.
What is the temperature needed? Does anyone have a ballpark estimate of the total quantity of heat needed per unit capacity for a GTL plant? What are some typical plant capacities?
Rod Adams www.atomicengines.com
Roger Arnold 9.17.05
Thanks for the comment. The simple answer to your question about using the waste heat from a turbine as the heat source for production of synthesis gas is no. No source whose temperature is low enough for it to be labeled as "waste" heat is very useful for that purpose. The reactions that produces synthesis gas from steam and natural gas typically take place at around 800 degrees C--or higher.
The not-so-simple answer is that it's theoretically possible, and there's an outside chance that developments in nano-engineered catalysis might make it feasible at some point in the near future.
The reactions involved in making synthesis gas are equilibrium reactions. As such, they are driven by partial presures of reactant species, temperature, and pressure. The dominant net reaction is one methane molecule plus one steam molecule combining to yield one CO molecule and three H2 molecules. That reaction is endothermic, and by Le Chatelier's principle, the equilibrium will be driven toward the products on the right (H2 and CO) by high temperatures and low pressures. However, effect of temperature on equilibrium concentrations is not really very important. The partial pressures of the reactant gases are much more important in determining which way the reaction proceeds. High temperature is extremely important, however, to the speed at which the reaction proceeds. The molecular species present in the reaction--which include a lot more than just CH4, H2O, and CO--are individually pretty stable. It takes a good high temperature to supply enough energy to break and rearrange their molecular bonds.
A fundamental principle of chemistry is that catalysts affect reaction rates but don't shift equilibrium values. If you have a good catalyst for a reaction, you may not need high temperature to get a usable reaction rate. In theory, a properly designed catalyst could enable the production of synthesis gas at temperatures as low as 150 degrees C or so.
Anybody who manages to develop such a catalyst will become very wealthy; it would have tremendous commercial value.
Mike Watkins 9.20.05
My limited understanding of the syngas concept (I am a ME-not a ChE) comes from the ammonia industry in which I had some limited experience with the combustion/fuels/turbine/fan/Hx/condenser side before the majority of the industry was forced offshore due to high NG prices.
Based on that, I have a comment that you might want to pursue and research. The ammonia process begins with a reformer furnace where they burn fuel in order to start with the basic separations of steam and CH4 as described by Roger above. They then through some type of hokus pocus black magic not understandable to this ME, take the N2 out of compressed ambient air and recombine it all to make NH3 using the H2 from the reformer reaction. CO2 is a by-product, sometimes captured and used, often vented to the greenhouse.
That said, there are a couple of processes used in the (domestic USA) industry, and one of them is the Braun (sp?) process which has at its basis a GE Frame 5 GT that acted as a prime mover for some of the compression equipment required, as well as providing waste heat for steam generation and/or reformer combustion air (?). The Braun process is not nearly as prevalent as the big boy on the block, the Kellog process, so I may not have all those details exactly correct, Others can correct me if needed. Point I want to make is that a GT is used in the process, along with its waste heat.
I post this to add to the comment above in that a fuel has to be burned in order to provide the high temperatures necessary for the reformer furnace and the steam used in the process, so if your nuclear fueled engine can be the basis of this, while maybe not the complete source, but something that would enable less of the feedstock to be burned strictly for fuel gas, and more converted to GTL product, then your concept might still have merit. Others will have to comment as to whether the overall GTL syngas process could benefit from the addition of (any) heat or mechanical work to the process that would make your machine viable.
I only want to give you a path to wander down, not present this as a final technology. Since you are the purveyor of the nuclear gas turbine technology, if you choose to do the research you can let us know if you find any hopeful prospects therein.
Roger Arnold 9.21.05
Between you, you and Rod raise an intriguing line of thought.
There's been a lot of research aimed at production of hydrogen by two-stage thermo-chemical decomposition of water using heat from a high temperature gas-cooled nuclear reactor. But the heat from such a reactor could just as well be used to supply the energy for the endothermic formation of synthesis gas from steam and any source of carbon. The carbon source could be coal, natural gas, biomass, or oil shale. In fact, it could even be CO2 stripped from the atmosphere by "synthetic trees" of the sort proposed by Columbia physicist Klaus Lackner.
I would love to see a study on the economics of synthetic fuel production using nuclear energy. (Anyone from DOE reading?) It may be that the problems of trying to use hydrogen as a transportation fuel do not need to be solved. Synthetic gasoline, diesel, and jet fuel could end up being cheaper.
(A somewhat dated BBC news article on Dr. Lackner's work appears here (if I can get my embedded HTML to work right. Otherwise, you can Google "synthetic trees"). It recently appeared in Popular Science, but I haven't found an online copy.
Graham Cowan 9.21.05
"It may be that the problems of trying to use hydrogen as a transportation fuel do not need to be solved....", says Roger Arnold. No "may" about it, says Graham Cowan, perhaps first to utter the phrase, "nuclear gasoline" (but not an advocate of the thing, due to its troublesome nature in gigawatt-year outdoor heaps).
It is easier to create an artificial strewing of dust than an artificial tree of the kind mentioned in the BBC article. The energy cost of calcining a mole of limestone is a few percent of the energy that can then be stored by turning the CO2 into -CH2-. So you would strew the quicklime over a field and then, perhaps, harvest it a few weeks later when it had become lime again. Or quarry more limestone and calcine that, and let the CaO particles take all the time they need, wherever in the world they wander. Also see http://www.lanl.gov/worldview/news/releases/archive/02-028.shtml.
Thanks for the link Graham. That report, though, is from 2002, and seems to predate Lackner's work. Maybe they're related. In any case, while the system it proposes for taking CO2 from the atmosphere is CaO, I think it's in solution as CaOH. That would make it very similar to Dr. Lackner's.
I don't think one can just send clouds of powdered CaO wafting on the breeze; it latches on to any H2O in its vicinity to form caustic CaOH; if inhaled, it would burn the lungs. There are other minerals that react with CO2 to form carbonates, but I don't think any of them will react with gaseous CO2 directly. The reactions are always, AFAIK, mediated by water, with the CO2 disolved as weak carbonic acid. But we could--and may need--to dump CaO into the oceans to lower their pH. Rising CO2 levels have been acidifying the oceans, and neutralizing that acidity ought to increase the oceans' CO2 sequestering capability.
I'm not sure what you mean by "gigawatt-year outdoor heaps". Nuclear wastes?
Graham Cowan 9.23.05
A gigawatt-year outdoor heap is an unsheltered heap of an energy storage medium in an amount sufficient to take up or deliver one gigawatt-year. Perhaps you can imagine some difficulties with heaping up gasoline to that extent. Those damned NIMBYs may well have enough clout to prevent any actual coming-to-grips with those difficulties.
If carbon dioxide is to be taken from air for fuel-making purposes, the amounts will be ridiculously large. Despite the later date on Lackner's work, doesn't it seem a little odd to stand a filter like that up? Why wouldn't we first stand all the cornfields up?
I've been looking for an article like this, and this is the BEST I have seen. The response thread also contains great insite. One point I would like to make is that both GTL and LNG are endothermic. And even pipeline and LNG tanker manufacturing cost are endothermic after a fashion. BTU=$$$. The sunk cost associated with any energy production and trasport method needs to be considered as part of the total production cost.