Treating Oil, Gas, and Water - More on GOSPs
Posted by Heading Out on December 27, 2009 - 10:10am
This is another in my series of Sunday tech talks. At the end of the last tech talk, I was commenting on the amount of water that usually comes out of the ground whenever we extract fossil fuels. Once it gets to the surface the questions become two-fold:
(1) How do we separate the different components of the fluid, so we can separate out what we would like to have (the fuel/fuels)?
(2) What do we with the parts of the mix we don't want?
The simple answer (as in easy to write) to the separation of the different components of the fluid is the Gas Oil Separation Plant. However, as you can imagine, if you are tasked with separating, for the sake of example, the liquids and hydrogen sulphide from a gas flow of 1.5 billion cf/day, which is coming from some 87 wells that concurrently produce some 300,000 bd of Arabian Light crude, the actual design of such a plant is anything but trivial. Even the sulfur that is drawn off, at some 90 tons/day, needs to be provided for in the design of the plant.
First, as the gas is produced from the wells, it must be collected into a common feed line, through a connector, called a manifold, that takes in the various smaller pipes from the individual wells, and feeds the result out in a larger pipe to the GOSP. Because the pressure that the fluid retains is useful as part of the separation process, we don’t want to lose any more of it than we have to in overcoming the friction in the pipes that it is passing through. (I have a couple of horror stories from my past about occasions when folk who should have known better used pipes that were too small, and ended up reducing both the flow rate and available pressure at the delivery end of the line). The pipes that carry the flow must, therefore, be large enough to carry the flows, through many miles of pipe to the GOSP. Thus we find, at Haradh, that the initial flows were collected into three different manifolds, and that they in turn carried the mix to the GOSP through five pipes which are, depending on flow, either 20 or 30-inches in diameter. (Different pipes are needed to continue to separate the sour (hydrogen sulphide containing) gases from the sweet before it gets to the GOSP.)
To construct the plant required at Haradh:
The main plant is made up of 100,000m3 of concrete, 22,000t of structural steel, 410,000 welded joints, 4,000km of cabling, 540km of plant piping, 1,400 items of engineered equipment and 750km of line piping, ranging from 18in to 56in in diameter.
The construction was also expensive of manpower:
For the construction of the facilities, the companies used 32,000m² of office and workshop space, a residence camp for 1,000 men and supporting facilities and a Boeing 737-qualified airstrip, 8,000ft in length with day and night operations. Support systems included 2,500 telephone exchange lines and video conferencing, data networks for 470 users, ground-to-air radio, 306km of fibre-optics and five communications towers.
It cost $2 billion and at peak construction had some 10,600 men working. It took 3 years to build (coming on stream in January 2004).
To sweeten the gas (get rid of the sulfur), it is generally bubbled through columns containing an absorbent liquid (typically sulfur-attracting amines) which remove the sulfur (which can then be recovered by heat in a stripping column, while the amine is then recycled).
The recent Khurais addition added 1.2 mbd of Arabian Light crude and GOSPs to support the new capacity. In the new GOSP construction which came onstream this year, there was an additional consideration. In order to help get the oil out, Aramco is simultaneously injecting 4.5 million bd of treated seawater. The main treatment plant at Qurayyah can process more than 13 million bd. The treatment involves removing particulate solids, ensuring that the oxygen content is below detection (this is needed to prevent corrosion), that there be no scaling products in the water and that there is a minimum amount of microbial content that could lead to biofouling of both the distribution pipeline and the injection wells. (Note that many of these concerns also relate to cleaning up the produced water from the wells before it is re-injected. ) The volumes that are treated are expensive, and thus there has been a recent move to simplify this treatment. Getting the solids out is relatively straightforward. Horizontal sand filters (albeit some 11 ft in diameter, 40 ft long) can treat up to 125,000 barrels of water a day bringing the particulate matter down below 0.2 mg/L. (On a personal note, again, sand filters work very well as long as there is no clay in the water--it takes just a few minutes for clay to coat and plug the top of the filter and make life really, really interesting).
At the same time, to ensure that there is no corrosion in the pipelines that carry the water (perhaps over 150 miles to a well in a journey that might take 36 hours) the pipes themselves are given a special internal coating to try and retain water quality integrity and to ensure that the injection wells do not become plugged. The pumps and equipment are powered by gas turbines.
And speaking of gas, the recovery of the oil at Khurais is also expected to generate some 0.3 bcf of a sour natural gas that will be sent to Shedgum to have the sulfur removed, and 70,000 bpd of NGL.
Getting the gas out of the oil occurs very easily (as both Darwinian and idontno commented after my last post appeared on The Oil Drum):
Very basic, the oil, gas, water, and sometimes sand enter a hydrotreater. The flash gas compressor takes suction from the hydrotreater to remove the gas. The hydrotreater normally will have an electric grid that helps to corral the gas at the top of the hydrotreater. The gas is drawn off and flows to the flash gas compressor. The water and oil separate in the hydrotreater. There’s usually two hydrotreaters and sometimes three to separate the oil from the gas. The velocity of the fluid as it passes through the treaters is critical since if flow is too high there will not be enough time for the oil and water to separate. The water is drawn off for further processing. The sand is separated in the sand separators and bagged for deposit ashore. The oil is processed to get the salt down to specification. Nalco, one manufacturer who fabricates different kinds of production equipment, has a very good web site to visit. They include flow diagrams.
Depending on the gas and oil mix the process of getting the gas out can pass through more than one stage where the pressure in the vessel is dropped, and at the lower pressure the gas bubbles out of the oil. (As noted, just as carbon dioxide bubbles out of soda when the can is opened).
In order to accelerate the separation of the water from the oil (remembering that oil floats on water), the vessel is often now heated, so as to speed the process up. Sand in the fluid is going to be an increasing problem as wells get deeper and more of them are horizontal, but separation can be accomplished as exemplified by the way in which the oil and sand are separated up at Fort McMurray. For that, there is a video.
This is part of a series, and I am grateful for the help that is given both by those asking questions, and those with practical experience that help with replies.
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Thanks, Dave, for your series!
It would seem like a GOSP would be needed wherever oil is produced--for example on an oil platform, out in the ocean. I know there are often separate pipes returning the oil and natural gas from the platform. Where does the excess salt water go? Directly back in the ocean, or is it reinjected deeper?
There are also huge numbers of individual stripper wells around. Where is the GOSP function handled for these wells?
Gail – There’s an equivalent system used to handle offshore processing requirements. These are floating production, storage and offloading (FPSO) ships. Most are converted oil tankers. Certainly the most scary field operation I’ve ever seen. When working in Deep Water Equatorial Guinea the porthole in my office on the production platform looked directly out to the FPSO about 3000’ away. Processed about 2 million bo per week. Besides the fact that you’re essentially living on a floating refinery, what made it so scary was that 20 million cf of NG was flared of the stern daily. The operator had offered to lay a NG pipeline to the shore for free but the gov’t turned them down. Didn’t want to spend any money for a local NG distribution system. I never spent time there but would land on the chopper pad dropping off hands. Just the radiant heat coming off the flare (at the opposite end of the ship) was uncomfortable. Chatted with some of the hands manning the FPSO. One of those “hell on earth” tales. Always hot and noisy. Most wore fireproof clothing and carried EBD’s (emergency breathing devices). And when alarms would go off (every few days) they would jump out of bed, throw their FP clothing on and go back to bed. And always carried their EBD’s with them even in the showers and head.
Made life living on the production platform seem like a visit to a Hilton by comparison.
Doesn't this contribute to carbon emissions and global warming? Is this taken into account when oil products are compared to alternative fuels? And is the energy lost in flaring counted in the EROEI/Net Energy calculations we so often read about?
You sometimes see Nigeria with higher emissions relating to oil than other countries, because of the natural gas flaring.
If the natural gas is burned later (benefiting mankind instead of just being burned off), it seems like the emissions would be about the same, assuming all of the natural gas gets burned, rather than escaping. It is just the benefit to mankind is a lot less.
All of the global warming gas discussions are based on the country of production. Since Nigeria is not one of the developed nations (and doesn't have an active Greenpeace organization), we don't hear much about its issues.
When one thinks about the situation in a country like Nigeria, one can understand why the government might be reluctant to put in natural gas pipelines. Individual residents are so poor that at best they might be able to afford the simplest cooking stove fired by natural gas--probably not hot water heating, and indoor plumbing. Pipelines to homes that each use a tiny amount of natural gas would be hugely expensive. If the pipelines are from the offshore fields, and they deplete in a few years, the cost of the whole system could be very high relative to the benefit.
"If the natural gas is burned later (benefiting mankind instead of just being burned off), it seems like the emissions would be about the same, assuming all of the natural gas gets burned, rather than escaping. It is just the benefit to mankind is a lot less."
The harmful CO2 contibution man makes is time dependent. If the amount of CO2 per year is increased due to nat. gas flaring, that amount is not naturally absorbed by the earth's ecosystems. Capturing this gas and not flaring it would reduce annual CO2 emissions and not boost the earth's atmospheric content. Saving it for later makes sense from a peak energy standpoint and AGW standpoint.
I am not a pipeline engineer, but have worked for an energy distribution company. My impression from seeing pipelines built on land is that building a shallow water pipeline is much less costly than onshore pipeline.
Secondly, the gas does not have to be put in a distrubution system, just sent to a power plant. Or if a compression/liquifaction plant were built, the gas could be shipped anywhere in the world. Problem is most of the governments in sub Saharan Africa have no long term view, nor are they acting in the best interest of their citizens.
I would agree that you could burn the gas in a electricity generation plant, and distribute the electricity. Building the infrastructure for electricity would still be somewhat expensive for a poor country, but perhaps it could be done. There would still be the problem of what to do, when the natural gas from the offshore wells runs out in a few years, and people are accustomed to electricity.
You also say the following.
I am not really sure what you are talking about when you say we should capture the natural gas and not flare it.
If you take the oil out, you have to do something with the natural gas. One choice is vent it (let it go without setting fire). This is a terrible choice, since methane is a green house gas. Another choice is to burn it near where it is extracted. This is flaring. A third choice is to pipe it somewhere, and burn in there. The timing of burning the gas where it is extracted and burning it after it is piped somewhere is pretty much the same. If takes a few days (or a few months at the outside) for the shipping to happen, so the timing of the burning is not very different.
A fourth choice is to reinject the natural gas, to help with well pressure. This seems to be what several poorer countries do with the natural gas. It is one of the reasons that natural gas is not very plentiful in the middle east. I suppose this might be what you mean. I don't really think of this as storing the natural gas for later.
Rich countries set aside a few locations (like salt caverns) for natural gas storage, so as to have sufficient natural gas for heating in winter. This storage is fairly expensive, and only time shifts the use of the natural gas by a few months. I don't see that as a long term option for storing natural gas, because of the cost and limited availability.
Gail:
In much of the Middle East the gas that used to be flared is now captured and used as a domestic fuel source.
Yes, that is the case in much of the Middle East but not all. The oil fields in the northern section of the Persion Gulf lie half in the Saudi section and half in the Iranian section. You can tell where the border is by the flaring. All the Iranian platforms flare but none of the Saudi platforms flare.
Mbnewtrain wrote:
No, it makes no difference whatsoever. The C02 stays in the atmosphere for about 800 years so burn it now or burn it later it still has the same effect. Anyway this flaring is only a very tiny percentage of the total amount of fossil fuel burnt daily. Just one coal fired power plant probably produces more C02 than a dozen or more gas flares. China is building two new ones per week.
Ron P.
A country with significant oil resources that cant afford to build an electricity grid is not poor, its being looted.
Sad but true magnus. The EG ogv't makes billions from the oil production and spends vitually nothing on its citizens. Even worse then that, some time ago the president-for-life dismantled a malaria spraying program which had eradicated the disease from this island nation. He figured out it would be easier to control the locals if they were sick and weak.
Never did care for "nation building" especially the way the US approached it but if there was one spot on the global where I could support such a US effort it would be EG. Would cost very little and risk none of our military. I suspect when TSHTF EG will be "controlled" by one of the big energy importers. But who ever might take charge it will be a better deal then the folks have now.
A distribution system wouldn't have been necessary. A pipeline to shore and a station where CNG bottles are filled for free would probably have bought quite a bit of goodwill from the locals. Free clean cooking fuel, free motor fuel... that would have gone a long way in lots of people's lives. And as long as you're burning NG to run your compressor, generate electricity and charge batteries for free too.
Unfortunately x, yes, in a very wasteful way. Some days the smoke would stretch from horizon to horizon. In the mean time the vast majority of the EG folks suffered extreme poverty. As someone who has always taken pride in doing my little part to feed economies the sight of such waste was very depressing. The view of the EG people as I rode from the airport to the chopper base didn't help. Eventually I covered my porthole. That got some strange looks from other hands: a view of the water was a rare and coveted perk.
Re: Gail's comment...even when I worked on the other side of the platform it wasn't any better. I was close to the Nigerian border and at night it was easy to see dozens of NG flares from their offshore fields. With that background in mind it shouldn't be much of a surprise how the rhetoric regarding controlling GHG's impresses me very little.
Someone please help. I've posted this question in 2 separate threads, and have received no definite and precise answers:
Can NGL's be refined into diesel, gasoline and jet fuels, and if so, what percentage of NGL's are used to this end?
shox -- saw your answer a couple of times. From westexas and maj I think. The short answer: yes. Not so much turned into such products but used in the process. Basicly breaking down hydrocabon chains and rebuilding them as needed. Perhaps the smarter folks can toss you some more details.
Google yields few specific answers about NGL processing. This is what I've sifted out: There is such a thing as natural gasoline which is refined from NGL, and then further refined to make stable gasoline. I haven't seen anything about diesel or jet fuel being refined from NGL.
One of the reasons I ask about NGL's is that whenever I see the NGL portion of the oil production curve, I wonder if any of it is refined into transportation fuels. Conventional and heavy crude appear to be going into decline already, but the addition of NGL's yields the "plateau." So I wonder if NGL's are worth paying attention to when projecting the short term future of transportation fuels.
Natural gasoline was a light condensate from an oil or gas well. Condensates were included in oil production numbers, while NGL's were a seperate entitity. Propane is a commonly recognized NGL. Transportation may be propelled by natural gas or propane without the high expense of converting it to gasoline.
There are facilities in Qatar to convert natural gas to liquids similar to diesel.
Another off topic question please anybody, thanks.
Why is the state of the art siesmic technology so expensive?
My first guess is that it has a lot to do with patents and very high profits but maybe the process also requires more manpower and equipment than one might think.
It's not, at least compared to the cost of drilling a well - a hole in the ground is one of the most expensive things you can buy. However, here are some typical seismic costs:
Recording Equipment - The cost is dependent on the number of channels. Systems record 12,24,48,60,96, or 120 channels. A general estimate is $1000 per channel. Thus, a 24 channel system costs $24,000, and a 48 channel system costs $48,000.
Cable - Seismic cables cost $50/channel.
Geophones - Geophones cost $100/geophone. You can get away with 1 per channel, but its more efficient to have more so you can lay them out in recording groups rather than moving them all the time.
Time - It takes 90 minutes to initially lay out the cable, geophones, and test the electronics. If your spread requires geophones to be moved, it takes an additional 30 minutes every time you have to move them.
Explosives - Explosives must be detonated in holes approximately five feet deep. Portable drilling rigs cost $7,000. Explosives cost $100 per charge.
Explosives crew - It takes 30 minutes to drill and load each shot hole, and requires a crew of two. The explosives handler makes twice as much as the field hands. Liability insurance costs $100/day.
Acquisition crew - Minimum of three. The acquisition crew can not acquire seismic data while the drilling crew is drilling, and vice-versa, but they all get paid for an 8-hour day regardless.
Processors, interpreters, and report writers - They use as many person-hours as people in the field, but make twice as much money.
Subsistence and travel expenses - $100/person/ day while doing the field work,
Vehicle depreciation - $50/day,
Fringe benefits for employees - 25% of salary,
Overhead - 100% of total direct cost.
So, as you can see, the costs add up.
Great details Rocky. Another way to look at it is that current 3d acquisition in the Gulf Coast onshore is running about $35,000 to $50,000 per sq. mile. From a practical point it's not very efficient to shot less the 20 or 30 squares at once. Even more cost effective if you shoot at least 100 squares at once. Of course, cost can run up if you're shooting in Rocky's back yard or a swamp in S La.
But for many of us the costs are not a factor. We're buying Gulf Coast drilling deals right now. We won't even review a deal that doesn't have 3d coverage. And typically not just any 3d data. In many trends there are attributes in the 3d data set that can greatly increase the probability of success. So a 100 square shoot might cost $5 million but could save you from drilling an $8 million dry hole. But what's even more critical is that $5 million shoot might generate a dozen high quality prospects with a total potential target reserve worth $1 billion. In a month we'll begin drilling a series of 12 such prospects. Each wildcat has a potential to gross $150 million of oil/NG each. None of these prospects would exist had not the 3d been shot some years ago.
But there is trouble down the road. Folks that shoot 3d seismic are speculating on two critical factors. First, that they'll find enough viable prospects. Second, and more important, that there will be drilling capital to spend on those prospects. Right now we're taking advantage of the current low capex availability. Folks with a lot of money invested in 3d can't find buyers for their prospects. Obviously folks are not rushing out to acquire new 3d surveys either. In the example above we're not paying for any of the $8 million costs of the 3d used to generate those prospects. The folks that did will have to eat that cost themselves but are happy they found us to share the drilling costs. Had they not they would have lost their leasing dollars as well as a chance to make money drilling the prospects. These are high quality prospects in one of the hottest plays in Texas and yet they spent almost a year looking for a partner.
It gets a whole lot tougher offshore. When Shell was doing their Beaufort survey the lack of decent 3-5 day marine forecasts made it the whole process rather dicey, there are miles of floating gear that takes the best part of three days to pick up out of the water hopefully ahead of heavy weather.
Just to make those prospects more of a gamble a court injunction can stop the exploration process at about any point right up through drilling.
I don't know about the relative fractions of the different NGL compounds, but butane is the lightest NGL that can be blended into gasoline, and usually just for winter gasoline.
http://www.theoildrum.com/node/5858
Pentane and heavier NGLs can be refined into liquid fuels.
http://www.countyofsb.org/energy/mitigation/NGLTransportation.asp
I thought the main purpose of the GOSP was to remove condensate (NGLs) for safety reasons.
The fact that the Saudis are investing so heavily suggests some other factors.
For one thing Saudi Arabia is the world's largest exporter of LPG and they are expecting a big increase in the market price for LPG. I wonder about the charts TOD folks are posting showing NGL's increasing in the future as a portion of world liquid production.
30% of NGL is condensate from oil wells and if oil production are declining, shouldn't all projected NGLs?
Another could be that the Saudis want to recover other gases (or even steam via the Claus process) for use in tertiary EOR, as Saudi Arabia is not particularly rich in NG.
maj -- Part safety but mostly cash flow. Water removal is often a critical aspet also. As far as declining NGL's that's probably going to be difficult to relate to declining oil production. While oil production declines more NG fields are being produced via LPG sales. For many of these fields the NGL yields are a big factor in their development. I think I recall one Persian Gulf NG field will yield over 200 million bbl NGL. I suspect many LPG projects wouldn't be economic if not for the NGL yields.
BTW -- That big NG flare in EG also burned a good bit of NGL. Pure methane burns fairly smokeless. Some days that flare looked like burning car tires. All the more wasteful.
So everything depends on the mysterious undersea North Field/South Pars?
It is not in Saudi Arabia but is divided between Qatar and Iran.
http://en.wikipedia.org/wiki/South_Pars_/_North_Dome_Gas-Condensate_fiel...
It may be huge but development has been very slow.
Like Shtokman and Yamal, this gargantuan field seem mythical.
The main purpose of the GOSP is to separate oil from gas, water, and sand. They would normally separate out the NGL's from the gas stream at a gas plant, which is better suited for that kind of thing.
I think their big problem is the sheer volume of water they are producing. It requires a huge plant to separate it from the oil, and the volumes are increasing. They would have a big problem with water disposal, and they would like to reinject it into the reservoir to maintain reservoir pressures.
The Saudis could reinject the NGL's to improve oil recovery in a miscible flood EOR project, but I don't think that they're to that stage yet.
I am having trouble with these two statements. While condensate is technically a natural gas liquid, it is not counted as such by the EIA and others who tally oil production. Condensate is a liquid, (at sea level pressure and room temperature), not a gas at all therefore would not be seperated in a GOSP which uses declining pressure to get the gas to bubble out.
An oil man please correct me if I am wrong but... Condensate, I thought, comes primarly from gas wells, not oil wells. It is a liquid that condenses out of the gas as the temperature is reduced. Any condensate in oil would simply be mixed in with the oil and could not be seperated by pressure reduction process of GOSPs.
The purpose of the GOSP is to remove the gas from the oil and seperate it into different catagories. The gas would bubble out anyway as the pressure is reduced and before the days of GOSPs it was simply flared. A GOSP is not necessary for safety reasons as long as it can be flared.
The reason Saudi uses GOSPs on ALL their oil wells is that they need the gas for generating power and desalinating water.
The EIA counts condensate as crude. (C+C) When the EIA and IEA counts NGLs they do not include condensate. NGLs are gasses such as propane and butane that can be liquids at relatively low pressures. So I am having trouble with your 30% statement. Do you have a source for that?
Ron P.
Edit: After rereading your post I think perhaps you are just using the word "condensate" incorrectly. Condensate, by defination, is a liquid reduced from a gas or vapor.
Ron -- I don't know if we've ever established a detailed definition of "condensate". But as you described it is the liquid that drops out of the gas phase as STP is reached. But we also tend to use condensate for very light oil also. I'll dig around and see if I can find some standard convention. Do you know how the EIA/IEA define these components? An oil well can have NG in solution which, when seperated, can have some liquids associated with it. But such yields tend to be small: 1 to 10 bbl/million cf. But NG reservoirs, especially the high pressured ones, can have huge yields: 100 - 400 bbl/million cf.
I think so. I believe that all fossil hydrocarbons that are liquid at normal temperature and peressure are included as C+C and all fossil hydrocarbons that are not are either natural gas of NGLs.
From the EIA's Glossary, bold mine:
From Wikipedia:
Ron P.
Condensate is the liquid that condenses out of the gas from a gas well when it is reduced to surface conditions.
It is chemically more or less identical to very light crude oil. If you blend it into crude oil, the mixture will be deemed to be crude oil. However, companies like to keep condensate separate because it typically trades at a different price. The gasoline cut is typically better than that from crude oil due to the lack of heavy ends, and it has some specialty uses.
NGL's are liquids extracted from natural gas at a gas plant and include ethane, propane, butane, and pentanes plus, in varying proportions. The gas plant doesn't care whether it's gas or liquid, it takes natural gas and condensate in the front end, fractionates it into its components and stores it in different tanks by component. The residue gas goes out via pipeline.
Just to keep things confusing, some gas wells produce oil rather than condensate, and some gas plants can also process oil. If you have a few oil wells, or gas wells producing oil, in a big gas field, you usually feed them into a gas plant rather than bothering to set up an oil battery. The gas plant fractionates the oil out and stores it in oil tanks.
Thanks Ron/Rocky. That's what my insticts told me but wasn't 100% sure. Given how those organizations tend to view the world differently I didn't want to take to much for granted.
In my mind you have oil wells and gas wells.
Oil wells produce associated gas which is separated for safety reasons. NGL, which are liquid, come from oil wells, wet gas wells and dry gas wells. 25% of US natural gas came from oil wells in 2006. Natural gas plants remove NGL which are not transported in gas pipelines.
http://www.epa.gov/climatechange/emissions/downloads/tsd/TSD%20Natural%2...
I read that 30% from a NGL supplied page a while ago.
My point is that Ace and other peak oil chartists show NGL 'filling the gap' but this is 'deceptive' (because LPG is less energy dense and is use for things other than transportation-Peak Oil)and because much gas comes from oil wells.
May well become more confusing (deceptive) over time maj. As others have pointed out a btu of oil won't be used the same as a but of NG or NGL. If in 20 years or so LPG becomes a major motor fuel then the cross link would be fair IMHO. OTOH if we start using much of our NG for motor fuel then we'll likely be substituting coal in some NG fired power plants. In one way or the other the mix will be there. But trying to put everything on a barrel basis doesn't do much justice to the situation. IOW, how much milage will you get from a pound of coal? If you're driving electric and buying your e from a coal fired plant then there has to be a conversion in there somewhere.
It's not so much deceptive, I guess, as just plain muddled.
This site, TOD is built on the premise that Peak Oil, in particular Peak Gasoline/Diesel (liquid fuel for cars)will be the End of Civilization. No more transit, no more mechanical power and it's back to the Dark Ages.
It's a fine premise but the charts are all for
C+C with biofuels, CTL,tar sands, NGL, etc.
Only about 70% of our petroleum goes for transport fuels.
I can't see LPG replacing oil because it costs more than oil and 30% of NGL comes from oil.It's a niche market. It's a good thing IMO, that NGL can be turned into poly-gasoline if necessary in the oil refinery but it is unlikely to happen.
Logically the next step should be watershifting all hydrocarbons(~60% efficient) to clean burning hydrogen and
burying the CO2, with the hydrogen being burnt in fuel cells at ~50% efficiency, more than double that of IC engines.
Peak Oil doctrine says we are running out of hydrocarbons( a varient of PO is that we are running out of cheap oil) and GW doctrine says that CO2 is overheating the Earth.
Clearly there are a lot more hydrocarbons geologically than cheap oil.
Tilton, the Colorado School of Mines boffin says there is 23,000 billion barrels of oil resource(counting heavy oil, tar and oil shale).
Then there's billion of tons of peat and 400,000 Tcf of methane hydrates, which the Japanese say will be commercial in 5 years.
The amount of carbon sequestration sites in the US exceeds 1000 Gt of CO2 and today the US produces 5.6 Gt of CO2.
The world seems to be heating faster than we are running out of fuel as of late and we are running out of cash faster than both.
Electric golf carts that go 40 miles are not cars, it's a different species--what's the mpg of a 200 cc moped?(who cares?). Fuel cell cars are similar enough to real cars to replace them.
Chevy Volt can go 40 miles on a 8.8 Kwh charge. 4.54 mpkwh x 33.4 kwh/gge = 152 mpg equivalent. Then a 37 mpg gasoline engine kicks in. If you go 100 miles you burn
40/152 +60/37 =100/x or 53 mpg.
http://en.wikipedia.org/wiki/Gasoline_gallon_equivalent
The Honda FCX fuel cell car gets 66 mpg and has a 350 mile range.
And a Happy New Year to you to maj. LOL. Frustration seems to be the order these days. More often then not I come to the conclusion that there are no "solutions" to be had. Just better and worse reactions to forth coming changes.
Totally delusional:
Efficiency of Hydrogen Fuel Cell, Diesel-SOFC-Hybrid and Battery Electric Vehicles
Ron P.
17%?
Not according to Ulf Bossel who gives gaseous hydrogen from electrolysis an efficiency of 23%.
http://www.efcf.com/reports/E21.pdf
I'm talking about steam reformating/water-shifting hydrocarbons
which is how almost all hydrogen is made in this country(USA).
Why is it that hydrogen 'skeptics' such as yourself trot out a method that is NOT used commercially make hydrogen to 'disprove'
the practicality of hydrogen fuel.
Electrolysis occurs at low pressures resulting in higher compression energy than
occur with reformatting.
About 2.5 tons of CO2 would be produced per ton of H2 so the equivalent of 150 billion gallons of gasoline would amount to 375 million tons of carbon dioxide to be sequestered, whereas 150 billion gallons of gasoline releases 1.5 billion tons of CO2;
20# x 150E9/2000 =1.5 billion tons.
The efficiency is ~70%(2010).
http://www.getenergysmart.org/files/hydrogeneducation/6hydrogenproductio...
Using Bossel's numbers-
70% x 90% compression(too big) x 80% (?) x 50% x 90% = 23%
Compared to electricity from a grid coal plant
34% x 90% x 85%(too high) x 90% =23%
No difference.
Given the greater range of the fuel cell car, hydrogen beats batteries hands down.
http://www1.eere.energy.gov/hydrogenandfuelcells/production/natural_gas....
Hydrogen is already used to produce transportation fuels in refineries today--4% of US natural gas(~1 quad) is used to produce hydrogen for transportation fuels. This is bound to grow as heavy oil stocks increase.
http://www1.eere.energy.gov/hydrogenandfuelcells/production/natural_gas....
Hydrogen created by reformating hydrocarbons is quite practical combined with burying CO2 would be a clean fuel.
At this point the production of many quads of energy from renewable electricity strikes me as far more (totally)delusional than converting energy packed remaining hydrocarbons into hydrogen and CO2 to be buried.
Then you are talking about natural gas, a fossil fuel. It would be far more efficient just to burn the natural gas in cars. And the natural gas car would not cost half a million. And, if we started using natural gas for a transportation fuel, whether we turn it into hydrogen or not, then we would soon reach peak natural gas and we are right back to the same problem again.
Hydrogen cars are a hoax, a complete hoax.
The Hydrogen Hoax
Ron P.
Far more efficient?
It would also be far more efficient to burn cheap high sulfur coal.
Efficiency isn't everything.
William Stanley Jevons
Saying something is a hoax is easy.
Global Warming Hoax
If you are relying on Bossel's numbers without also acknowledging Bossel's conclusion (that hydrogen fuel cells running on renewable energy cannot compete with their own source of energy), you are delusional.
I can't use other people's data without drawing their wrong conclusions?
E-P = Insane cherry-picker par excellence.
Bossel's conclusions are faultless, you just don't understand them. You'd still use coal, eventually run out (doing a lot of environmental damage along the way), and be stuck with a hugely expensive system that collapses because it can't make efficient use of non-fossil energy.
Maybe my 2005 analysis of hydrogen's comparative advantage vs. its source will explain things to you, but given your record, I'm not sanguine.
Yes I'm afraid it is. The whole concept of running cars on hydrogen is a complete flight of fantasy. The availability of hydrogen is far worse than the shortage of oil. Sure it's the most common substance in outer space, but here on earth, molecular hydrogen is a very rare commodity. Hydrogen is also very expensive to manufacture, and the EROEI is abysmal. There ain't no such thing as free hydrogen, at least not on this planet.
If you did real-world economics on it, using realistic numbers rather than the ones bandied about by the hydrogen promoters, you would find the cost of running a car on hydrogen would be equivalent to running it on gasoline costing on the order of $100 per gallon.
Not many people can afford to pay $100 per gallon for gasoline, so they can't afford to run their cars on hydrogen, either.
There are a lot of cheaper alternatives, so they are the ones which will become the real-world solutions. We don't need any more of these ideas that only make sense if you live in outer space.
The price in 2006 for natural gas reformatted hydrogen was $3.10 per gallon of gasoline equivalent(gge) according to DOE.
http://hydrogen.energy.gov/pdfs/5038_h2_cost_competitive.pdf
Thank you for your 'expertise' in real-world economics (and wind powered trains!)instead of talking thru your posterior.
We have a bit of natural gas so driving around on it buys a bit of time, likely keeping us from actually developing a transport system that is long term sustainable. When the ng gets thin, then what. Of course the cost of converting the fleet to drive on hydrogen that comes from an energy source that won't be plentiful fifty years later if we start driving on it doesn't seem the best use of resources either. I'm sure numbers are out there for what that fleet conversion and subsequent retirement of same would burn up in resources. Could be why the smart money is on electric & electric/ICU combos for now and the long term thinkers want as much transport as possoble moved to rail, light and heavy, ASAP. Not an easy task with all the embedded subsidies that are in play, but something we still have the resources to do. Finding the will to do it is another story, which your posts demonstrate repeatedly.
Besides it would be much better long term, for those who don't want to see a sudden population crash that is, to save as much ng as possible for future fertilizer stocks, driving it to depletion on our roads--not a good idea.