If it is relatively easy to capture the CO2 from an IGCC [Integrated Gasification and Combined Cycle coal-burning plant], why wouldn't we start working to prove that assumption by capturing the CO2 from at least several of the existing GTCC (gas turbine combined cycle) plants that use natural gas as their heat source?CO2 sequestration for coal-fired powerplants is held out as the major way that America will reduce it's CO2 emissions significantly over the next two decades. But, CO2 sequestration requires a lot of tinkering with the plant. An IGCC is nice for efficiency, but is not required. Several other really serious pieces of equipment are required, however:
- Sequestration costs big money. Since you really don't want to unnecessarily sequester 4 times as much nitrogen as CO2, you seperate that nitrogen and vent it. Since you don't want to seperate nitrogen from the exhaust gas (you'd have to cool it), you seperate it from the incoming airstream. Thus, the air filter on an ordinary plant is replaced with an expensive and energy-hungry plant with cryogenics, multiple turbines, and heat exchangers galore.
- The exhaust must be compressed and liquified to inject it into the ground. Most of the heat must be removed from the exhaust in order to compress it. In a normal coal-fired powerplant, a large fraction of the waste heat is rejected by simply venting the exhaust into the air. In a CO2 sequestrating facility, you need a big heat exchanger and a cooling tower to do that work. Oh, and a larger fresh water supply.
So, they talk about sequestration while they defer it as long as possible.
Interestingly, one of the side effects of concentrating the oxygen in the gas being burned is that the operating temperature increases, which could improve efficiency. Unfortunately, combustion turbines already run at temperatures higher than the melting point of the turbine blades... and probably cannot be run hotter. My guess is that exhaust CO2 will be cooled, recirculated and recompressed, and then used to dilute the oxygen in the incoming stream to lower flame temperature.
[Update: check the comments on this post. Harry Jaeger makes some nice points.]
It seems that there is a bit of confusion here in talking about CO2 removal and sequestration with both IGCC and so-called "oxy-combustion" at the same time.
ReplyDeleteFirst of all, IGCC is already proven, so there is no long "roll out" period for it. However, oxy-combustion, where near-pure oxygen would be used to burn fuel in a gas turbine (or in a conventional coal plant, for that matter) is still to be developed and demonstrated.
With IGCC, coal or some other carbon-rich feedstock is first gasified to produce a "synthetic" gas ("syngas") comprised mainly of hydrogen and carbon monoxide. This is a fully combustible gas and can be used in today's gas turbines with no problem.
However, the products of combustion would normally include CO2, which is the bad news.
The good news, as you say, is that removing the CO2 in IGCC is relatively simple, because it can be done from the syngas in a so-called "pre-combustion" process rather than from the exhaust of the power generating unit (i.e. post-combustion).
You refer to removing CO2 from an oxy-fired GTCC plant burning natural gas in oxygen.
Actually, burning natural gas produces relatively little CO2 (about 1/3) compared with burning high-carbon fuel such as coal. So it would not make much sense to add a lot of cost to add CCS to a gas-fired plant.
What could be demonstrated, however, is CCS applied to an existing IGCC plant.
But, since the chemical process used remove CO2 from syngas is fully commercial, there would not be so much learned by that demonstration. In chemical terms it is rather straightforward to add steam to the syngas to convert the CO to CO2, while producing additional hydrogen.
The CO2 could then be absorbed in a commercial acid-gas removal process and the hydrogen-rich syngas would be used to fuel the gas turbine.
The technology is all commercially available today, including the gas turbines to burn hydrogen-rich fuel gas, as long as the percent CO2 removal is not so great as to leave near-pure hydrogen for the turbine fuel.
The good news here too is that it would take "only" about 50% CO2 removal to make the CO2 emission from the IGCC plant roughly equivalent to burning natural gas in a combined cycle plant.
So, you ask "Why are there no GTCC plants doing CO2 sequestration?"
The answer is that it would not make sense to do that, while it would make sense to demonstrate CCS with an IGCC plant - especially at a CO2 capture level of around 50% to achieve "natural gas equivalence".
In this way, IGCC would even meet the CO2 emission criteria (1100 lb CO2 per MWhr) set for any new power generation to be built in California (or from which power many be supplied to California from out of state).
For more, visit our blog at:
Gasification & IGCC Forum - http://gasification-igcc.blogspot.com/
Harry Jaeger
Gasification Editor
Gas Turbine World Magazine
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Iain:
ReplyDeleteAs you know, I am a bit of a cynic when it comes to the efforts of sales people, including those that sell expensive power plant equipment but most especially those who sell fossil fuels.
It is SOOO much easier to make the sale of a new coal fired power plant if the marketers can convince all of the decision makers, including the public, that a solution to the major problem of carbon dioxide emissions is right around the corner. If they can just get the plant built, they will ensure a long term market for their profitable product.
If, after a number of years of operation - all the time adding to the total greenhouse gas concentration - someone requires them to add all of that additional complex equipment that you mention, the coal marketers will not cry.
Every process that you mentioned will require an additional energy input - the most recent IGCC report on sequestration indicates that a plant actually performing the capture and storage will consume between 10 and 40% more BTU's per kilowatt hour of output. My envelope computation indicates that the probability of 40% is much greater than that of 10%.
Of course, the power plant vendors will also be happy. Most of the companies that make the equipment for the coal gasification plant also will happily make the turbines, compressors, heat exchangers and control systems required to make it all work.
In the end, what you would get is a very complicated and expensive way to spin a turbine with something like 90% of the carbon dioxide captured.
For 1000 MWe output, including the 40% increase in energy input for the capture and storage system, that still leaves about 6300 tons per day going up the stack, and 57,000 tons stored underground with no real experience to tell us how long it will stay there. You also have to supply that plant with about 15,000 tons of coal per day.
Hmm - anyone wonder why I think nuclear plants are a simpler, less costly, and more environmentally friendly way to produce electricity?
We don't need no stinking capture system!
Harry:
ReplyDeleteI am confused. You wrote:
The good news, as you say, is that removing the CO2 in IGCC is relatively simple, because it can be done from the syngas in a so-called "pre-combustion" process rather than from the exhaust of the power generating unit (i.e. post-combustion).
As you said earlier, the syngas is mostly hydrogen and CO. It burns (oxidizes) along with intake air in the combustor of a conventional gas turbine, producing CO2, H2O, and heat. The N2 that is 78% of the intake air is also mixed in as part of the hot gas mixture that spins the turbine.
The CO2 is thus only available post combustion. The reason that people are talking about oxy-combustion is to separate the N2 out of the stream before it gets hot, but you still have the challenge of separating the CO2 from the H2O. That gas still must be compressed and cooled before storage.
I think that setting the bar at a standard of 1100 lb of CO2 per MWhr is fine, but it still begs the question - what should the operator be charged for the waste service being provided by the common atmosphere?
Harry,
ReplyDeleteThanks! I really appreciate you clearing me up on the oxy-combustion thing. I hadn't realized that removing CO2 before combustion was considered easier than removing N2.
I do see your point on sequestering half the carbon as a good first step, and actually, I agree... presuming that coal has to be in the mix. But I also think burning carbon is a fundamentally losing idea, and we already have a domestic, commercially proven solution in the form of nukes.
Since we aren't going to be retrofitting old coal plants for sequestration, the question is really, what are we going to replace them with? My sense is that we're better off spending money on nukes with an unproven but physically small geological sequestration problem, rather than spending money on new and different coal plants with a physically large geological sequestration problem. I don't think the political pendulum has swung far enough back yet, however, so maybe IGCC plants sited near empty gas salt domes make sense for now.
So, why are there no GTCC plants doing CO2 sequestration? A: Because GTCC plants produce less CO2 than coal plants, so it makes more sense to add the CO2 sequestering cost to a coal plant.
I don't think that's right. First, the metric that ought to matter in a public policy debate is how much CO2 can be sequestered per dollar, not how much CO2/MWh the plants produce. If it's cheaper to add sequestration to a gas turbine, let's do that. Gas turbines have much lower capital costs than coal plants of any kind, so they make more sense for a trial facility, because you tie up less capital when the newfangled gizmos break.
You should be able to add hot steam to natural gas just as well as syngas, to get the water-gas shift that leads to CO2 + nH2. For coal, you end up with CO2 + 2H2, and with methane, you end up with CO2 + 4H2. Does acid-gas removal work well enough on these lower CO2 concentrations?
Rod's question needs someone willing to spend hundreds of millions of dollars to validate or disprove the assumption that CO2 sequestration can solve the environmental problems of burning coal. Who is that someone? What are the possible outcomes that would help that someone?
It sure as hell isn't the natural gas producers and operators. They are pushing the idea that CH4 is "green" -- that somehow it has little enough carbon. The last thing they'd want to do is associate themselves with sequestration in any way.
And I don't think it's the operators of coal-fired powerplants. If every new coal-fired plant has to explain where they are going to pipe their CO2, half will get hung up just trying to get right-of-way access to the sequestration field.
Rod,
ReplyDeleteTo be fair, a nuclear plant has a geological sequestration system too, because that's where your nuclear waste is going to go, eventually. The difference is that CO2 sequestration has a problem with the enormous tonnage and high pressure of the waste that must be moved. Nuclear doesn't have either of those, but the stuff is radioactive for the imaginable rest of history.
Of course, if one of those CO2 sequestration domes blows up (say, the wellhead explodes, which does happen from time to time), it's going to make an awfully big kill zone, like one of those anoxic lakes turning over. I'm pretty sure 2% CO2 is fatal to most mammals, and a year's worth of CO2 from a gigawatt plant would cover about 90 square kilometers at that concentration. That's a fairly big kill zone, and one that would blow around for a day or so before it mixed into the atmosphere enough to get the concentration down.
Rod,
ReplyDeleteAcid gas removal can strip CO2 out of a combination of CO, CO2, and H2. So, if you do a water gas shift reaction on the syngas, you end up with CO2 + 2H2 instead of CO + H2, so the CO2 is available pre-combustion. This is a second step of adding hot steam, and it happens at a different temperature than the coal + steam reaction, so there's at least one heat exchanger necessary to recover some efficiency.
You can then run acid gas removal to end up with H2 with some smaller amount of CO2. After the CO2 concentration has been reduced, they run this gas into what is now essentially a hydrogen-powered turbine.
Iain:
ReplyDeleteIf you just burn H2 in your turbine, don't you lose a good portion of the heating value of the input coal?
After all, the reason that we began creating CO2 in the first place was that the rapid oxidation of carbon as well as the rapid oxidation of H2 is an exothermic reaction that releases a large quantity of controllable energy.
Rod,
ReplyDeleteActually, burning those two H2 molecules releases more energy than burning that one carbon:
C + O2 => CO2 + 393.5 kJ/mol
2H2 + O2 => 2H2O + 483.7 kJ/mol
There is no trick here. Syngas formation is endothermic, which is why you typically have to use some oxygen to provide the extra energy. That oxygen will generate some CO2 which is the easy portion to recover with an IGCC.
C + H2O => CO + H2 - 131.33 kJ/mol
Water vapor has a Cp of about 2 J/K/gram, so if you wanted to supply that heat with just hot steam, you'd need input steam at about 4000 K, well past the melting point of nearly everything. Hence, extra oxygen. There is no required inefficiency yet since the heat released from burning C + O2 => CO2 goes into hydrogen generation.
The water/gas shift reaction is a little exothermic:
CO + H2O => CO2 + H2 + 41.17 kJ
This is actually a larger problem, since to get good efficiency you should be heating something that is at high pressure, so you have to run the water/gas shift, and subsequent CO2 removal, at high pressure and elevated temperatures. If undiluted, the water/gas shift heat release would increase the temperature of the gas by around 700 K. You actually need some of that nitrogen in the air just to dilute the reaction down enough to keep the temperature down.
Note that to avoid making a bunch of unnecessary entropy, the compressed air to which you add this hot hydrogen/CO2 mix should be equally hot. That puts a limit on how much you can intercool the combustion turbine intake charge, which together with the turbine maximum temperature limits puts a limit on your efficiency.
I'd guess the IGCC guys are thinking of absorbing the CO2 out of the syngas stream before they do the water/gas shift. I'm pretty sure the acid gas removal step has to happen at a lowish temperature, which isn't easy to get to from the result of a water/gas shift. So, they just absorb half the CO2.
Iain:
ReplyDeleteI think I get it, but I would really need to see the overall heat balances with real world efficiencies to understand the relationship between the heat value of the input fuel and the kilowatts of electricity out.
As you explain the reaction, some of the processes have to occur at elevated temperatures, which means that you need an energy source to provide the heat and you will have some losses of that heat during the cycle - there is no such thing as a perfect insulator.
For conventional plants, that heat rate is a very important measure of plant economy because you pay for BTUs on the input and sell electricity on the output.
For a plant that is required to capture and sequester some portion of the CO2 generated, another important economic measure would be the quantity of CO2 produced per unit of sellable electricity. A portion of the KW generated will have to be consumed in the process of capture and storage, so the amount of CO2 generated per net unit out would represent another cost per unit of electricity that needs to be considered in addition to fuel costs.
Please understand, I am not trying to argue that it is not possible to continue using coal as fuel even if society imposes requirements like capturing and storing carbon. (Although the storage part might be impossible to prove depending on the length of time chosen as required.)
What I do feel in my gut is that the process is far more complicated and expensive than the coal marketers portray. They toss off the terms "clean coal" and "carbon sequestration and storage" like they are a done deals and repeated say things like "this is a proven technology".
Those statements should be understood to be about as useful and credible as "the previous owner was a little old lady who only drove this car carefully on Sundays and changed the oil regularly."
Other interesting tidbits:
ReplyDeleteThe initial coal gasification pass happens at 800 C. This step all by itself is a pain in the ass, because you want to heat both coal and steam before mixing them. I'll bet that heating a powder is just too hard, and they just dump it in unheated and let the burning heat it up. If they do that, (a) the hot/cold mixing makes entropy and thus loses energy, and (b) they had better do it at elevated pressure or they'll lose even more recoverable energy. Remember that you can recover only the chemical energy released from burning C + O2 -> CO2 once you've gotten to the reaction temperature. Everything on the way up is just heat.
The water/gas shift happens at 400-500 C with iron and chromium oxide catalyst, or 200-400 C with copper, zinc oxide, and alumina. The fact that it's at a different temperature than the first reaction, and exothermic, means it pretty much has to happen at high pressure, as I said.
If I understand properly, when you have these temperature swings between the different stages of a reaction, you do them with heat exchangers to other steps in the system. So, the heat changes aren't a dead loss but as you know, no heat exchanger is perfect.
If you are trying to make an IGCC as clean as GTCC then why not just make Synthetic Natural Gas from the coal. This could then be piped from centralised coal gasification facilities to existing GTCC plant.
ReplyDeleteThe CO2 can be easily removed from the SNG to levels below those in many existing natural gaas supplies.
This technology was developed and demonstrated in the UK about 20 years ago.
Joe,
ReplyDeleteI think that you are on the right track, and would have a lot of support.
But you have to look into the chemistry of converting coal-derived syngas (CO + H2) to methane (CH4) - the so-called methanation process - to find your answer as to why it is not such a simple solution.
What you will find is that to get to methane from syngas is that there is a step where CO2 is produced as a waste product.
So, although it works, and the CO2 capture process is a built-in step, you still have the issue of sequestration to take care of.
There is a commercial SNG plant operating in Beulah, North Dakota that you should look into. Some time ago it was realized that there was a market for compressed CO2 in the oil fields across the Canadian border some 250 miles away. A pipeline was built and has now been in operation for some 10 years.
The CO2 is used for oil field pressurization to enhance production from "tired" oil wells.
So, you offer a very good solution, but it still requires CO2 capture (which is included in methanation)and sequestration - which could be done along with enhanced oil recovery. This form of sequestration is proven and commonly done, and adds a revenue stream to the SNG production that pays for the added compression and pipeline equipment.
Harry Jaeger