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Refining 201: The Assay Essay
Posted by Robert Rapier on May 29, 2008 - 9:30am
There have been several refining questions lately that were topical to this essay, originally posted in January 2007. Here I have updated it to reflect more recent prices.
When a refinery purchases crude oil, the key piece of information they need to know about that crude, besides price, is what the crude oil assay looks like. There has been a lot of discussion here at various times about “light sweet”, or “heavy sour”, and how these qualifiers affect the ability of a refiner to turn these crudes into products. So, I thought it would be good to devote an essay to this subject, and discuss how different types of crude can affect a refiner’s bottom line.
Let's compare light sweet oil to heavy sour oil by looking at a pair of assays:
| Liquid Volume % | Generic Light Sweet | Generic Heavy Sour |
|---|---|---|
| Gas (Boiling Point to 99°F) | 4.40 | 3.40 |
| Straight Run (99 to 210°F) | 6.50 | 4.10 |
| Naphtha (210 to 380°F) | 18.60 | 9.10 |
| Kerosene (380 to 510°F) | 13.80 | 9.20 |
| Distillate (510 to 725°F) | 32.40 | 19.30 |
| Gas Oil (725 to 1050°F) | 19.60 | 26.50 |
| 1050+ Residuals | 4.70 | 28.40 |
| Sulfur % | 0.30 | 4.90 |
| API | 34.80 | 22.00 |
Table 1. Comparison Between Assays of Light and Heavy Crudes
Note that for this essay we are only concerned with a portion of the assay. The full assay would have information on metals concentration, salt concentration, vapor pressure, etc. What the two assays above tell us is that one is light (the higher the API gravity – a measure of density – the lighter the crude) and one is heavy. It also tells us that one is sweet (low sulfur %) and one is sour. Now, to be clear, a heavy crude can be sweet and a light crude can be sour. But refiners that are equipped to handle heavy crudes are generally also equipped to handle sour crudes, so that’s what they buy. Heavy sour is cheaper than light sweet, and there is more money to be made with heavy sour crudes as long as a refinery is configured to handle them. Gasoline doesn’t care whether it came from cheap heavy sour or more expensive light sweet; the product price will be the same in either case.
Now, back to the assay, and what the various categories mean. The way the assay is done is that the crude oil is boiled, and the amount boiled off at various temperatures is measured. This defines the various products, or cuts. When 99°F has been reached, the gases have been boiled off. This is the dissolved methane, ethane, propane, some butane, and some trace higher gases. This cut can end up being purified for sales, or it can end up as fuel gas to help satisfy a refinery’s need for steam.
The next cut is straight run, or natural gasoline. Gasoline is a mixture of hydrocarbons that are characterized by the boiling point, and the gasoline you purchase at the gas station will contain many different blending components. One of these will usually be light straight run gasoline. This cut will contain things like butane, octane, and every manner of branched and cyclic hydrocarbon that boils in a specific range. Most gasoline has been subject to additional processing (more on that later). The straight run gasoline is what can be expected to be distilled from the crude oil with no additional processing. Typically, straight run gasoline has pretty low octane, so refiners are limited in how much can be added to the gasoline pool. However, lower octane blends will probably contain some portion of straight run gasoline.
The next cut is naphtha. You can do a couple of things with naphtha. You can blend it into gasoline, but the octane is even worse than for light straight run. Therefore, you are seriously limited on how much can be blended. More commonly, naphtha is fed to a catalytic reformer, which processes the naphtha into reformate and boosts the octane from less than 40 in the naphtha to greater than 90 in the reformate. Reformate is then a very desirable gasoline blending component.
We then come to kerosene (also called “jet”), which starts to get into the range of diesel components. This cut also has more energy content per gallon than the earlier cuts, but is too heavy (less volatile) to be blended into gasoline. The sulfur components start to become more concentrated in these heavier cuts, so kerosene is typically subject to hydrotreating. In this step, hydrogen is added to the kerosene in a reactor to convert sulfur components into hydrogen sulfide, which is then removed. Kerosene has a number of uses. It is used as fuel for jet engines, and it is also blended into diesel. It is also used in some portable heating and lighting applications.
The next cut is distillate (specifically, No. 2 Distillate; kerosene is sometimes called No. 1 Distillate). Like kerosene, this cut contains sulfur and must be treated (as do all the heavier cuts). Distillate has two major end uses: as diesel fuel and as home heating oil. In fact, as seen in the assays above, a substantial portion of a barrel of oil ends up as heavy distillate. For the light sweet crude assay above, 32.4% ended up as distillate, and for the heavy sour crude 19.3% ended up as distillate.
We then come to gas oil, which is also known as fuel oil or heavy gas oil (distillate also being known as light gas oil). This cut is typically processed in a catalytic cracker to make cracked gasoline. By the name, you might guess that cracking involves breaking these heavy, long-chain hydrocarbons down into shorter hydrocarbons that boil in the gasoline range. The cracked gas is then blended into the gasoline pool.
The final cut, residuals, or just plain “resid”, is the cut of greatest interest when we talk about the economics of heavy crudes versus light crudes. Note in the assay above, that less than 5% of the barrel of light crude ends up as resid. However, the heavy crude yields over 28% resid. Resid is sold as asphalt and roofing tar, and was historically not a very profitable end product. Therefore, more and more refiners are installing cokers to further process the resid. A coker can take that resid and turn it into additional gasoline, diesel, and gas oils. The economics of doing this are typically very attractive, given the historical price spread between light oil and heavy oil. A coker can turn over 80% of the resid from low-value asphalt into valuable products like diesel and gasoline. (The resid can also be processed by hydrocrackers, but this entails different economics because they require hydrogen.)
Examples (For Illustrative Purposes Only)
Light Crude Economics
Let’s compare two hypothetical refineries. Refinery A has no coker, and thus is restricted to either buying light crude, or buying heavy crude and selling a lot of low-value asphalt and roofing tar. So let’s say that Refinery A pays $125 a barrel for West Texas Intermediate. They will turn that barrel into 0.909 barrels of liquid fuel product (per the light assay above, 4.4% ends up as gas, 4.7% ends up as resid, and 90.9% ends up as liquid products), which let’s say has a value of $140/bbl. They therefore grossed $140*0.909 - $125 (the purchase price of the barrel), or $2.26 a barrel before we consider the value of the asphalt and the gases.
Historically, the value of asphalt has been very low – less than $0.10/lb. However, prices have risen along with the price of crude, and are now around $0.23/lb. Given that a barrel of crude weighs around 300 lbs, and we got a 4.7% asphalt yield, the barrel yielded 300*0.047 = 14.1 lbs of asphalt worth $3.24. Let’s value our gases at the current value of propane (about $0.40/lb on the spot market), and we get a value of 300*.044*$0.40 = $5.28 for the propane. Our gross profit (before operating costs, taxes, etc. are considered) is then $2.26 + $3.24 + $5.28, or $10.78 per barrel for the light crude.
Heavy Crude Economics
Now consider Refinery B. Instead of buying WTI at $125/bbl, they buy a heavy Canadian crude for $110/bbl (this is an actual recent price). Again, their barrel of oil weighs some 300 lbs, and as we can see from the assay above their resid yield may be in the range of 28%. So, of the 300 lbs, 84 lbs ends up as resid. But with their coker, they can turn 80% of that into high-value products, and only 20% (16.8 lbs) ends up as low-value coke (a coal substitute). Therefore, the overall yield from the heavy crude amounts to the sum of the cuts up to resid (71.6%), plus the resid that was turned into products (80% of 28%, or 22.4%) minus the gas cut (3.4%) for a total of 90.6%.
The overall liquid yield is almost the same as for the light crude, but much less was paid for the heavy crude. So, the economics look like this: For the liquid fuels, they grossed $140*0.906 - $110 = $16.84 a barrel on the heavy crude – much greater than the profit of the light crude. The propane yield is slightly less than in the previous example. The value of propane is $4.08. Finally, we end up with 16.8 lbs of coke, which is worth only $0.03/lb (about $0.50 total). The total gross profit then is $16.84 + $4.08 + $0.50 = $21.42 per barrel of heavy crude. (If you compare these numbers to the initial essay written in January 2007, you will see that margins have significantly worsened).
This explains why so many refiners are rushing to install cokers. This is also why I don’t get too excited when someone comments that the build in crude inventories could be a build in “undesirable” heavy sour. Refiners don’t buy what they don’t need, so if heavy sour inventories are increasing then this is primarily coming from refiners that can process heavy sour.
As light sweet supplies continue to deplete, refiners will increasingly turn to heavy sour crude. But not enough refiners yet have a demand for heavy sour, so it trades at a significant discount to light sweet. This will of course change as more cokers are installed. There will be a higher demand for heavy crudes, and the asphalt market will become more lucrative as the asphalt supply gets rerouted to cokers.
Of course the caveat is that a coker is a major capital expense (hundreds of millions of dollars), and it is only part of the equation. I have focused here on processing heavy crudes, but not at all on sour crudes. The story is similar to that for the heavy crudes. Sour crudes trade at a significant discount to sweet crudes, and the refiners need additional processing equipment to handle them. But the economics currently favor installing the cokers and hydrotreaters to handle the heavy sour crudes, and will continue to do so as long as they trade at a substantial discount to light sweet crudes.
As always, comments, corrections, and questions are encouraged. Do note that while the examples above are approximate, they are not exact. There is more to the economics than what I have presented, but for the purposes of understanding some basic refining economics, this should suffice.
Additional Reading
Refining 101 at Tesoro
Basic Refining Overview
Petroleum Refining and Processing from the EIA
What is the difference between gasoline, kerosene, diesel fuel, etc.?
How Oil Refining Works
Contact
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- Tech support: support at theoildrum dot com
License
This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License.
Thanks for the great explanation. I have tried in my own inept way to differentiate between Light Sweet and Heavy Sour grades for friends and family, and get met with blank stares. I will get them to read your version.
I do have a couple of questions.
Crude gatherers, in Oklahoma and Texas at least, buy different grades and blend them to 40 gravity, or more specifically in the 36.5 to 40.5 gravity, to minimize the penalty when they do a pipeline tender. In effect, they are blending condensate (for the most part) and heavy crude. Have you ever had any experience with this at the refining end, and what does this do to the refining process and to the assay? Is this specific to the final blended crude or is there a general result of about the same as the sample assay you show for Light Sweet?
As we import more finished product, would you anticipate asphalt becoming proportionately more expensive than other refinery products, or has this already happened?
Chuck
Have you ever had any experience with this at the refining end, and what does this do to the refining process and to the assay? Is this specific to the final blended crude or is there a general result of about the same as the sample assay you show for Light Sweet?
Two comments on this one. Yes, I have experience with some Canadian blends that they mix together from several fields to meet a gravity spec. The good thing about that is that you get a pretty consistent crude. This is one thing that makes operating a refinery more difficult - when you crude quality is swinging.
But, there are multiple ways to get to a certain gravity, as you indicate. And I have seen some of those middle cuts essentially missing. In that case, you know they did something like mix up condensate with very heavy stuff.
As we import more finished product, would you anticipate asphalt becoming proportionately more expensive than other refinery products, or has this already happened?
I don't know if it has been rising at the same rate, but asphalt prices have run up with crude oil. But what makes asphalt at risk of rising disproportionately is the fact that refiners are installing cokers, and taking asphalt off the market and turning it into gasoline.
My note on this is that as the industry shifts from light to heavy feedstocks, that is very bad news for propane customers. As I understand it, propane "is what it is", and there is no valve you can turn at the refinery that will change the percent that you can get out, so if there is less there to start with, less is what you will get. Thus, propane will get a double hit: first from declining petroleum production post peak, and second from the shift in that production from light to heavy crude.
Say it ain't so!
I do not have a link, but I would hazard to guess that the majority of the propane on the market is actually from the NGL's (ethane, propane and butane) that are removed from natural gas. Separating the heavier components from methane is much more profitable.
I believe Robert mentioned that a lot of the lights in the crude are used in the refinery as fuel gas to fire various heaters.
Yes, I do know that the propane we buy is a mix from petroleum and NG. NG is peaking too, unfortunately. However, I do wonder about all that stranded NG that is just being flared - might it not be possible and economic to separate out the propane first and ship that?
Thank you. That is very interesting. It helps me understand this stuff better.
So would it be correct to state that refining heavy crude is more energy intensive, and has a lower ERoEI? Would more of the gas produced end up not sold but fueling the processing of the later products?
So would it be correct to state that refining heavy crude is more energy intensive, and has a lower ERoEI?
Yes, I have calculated this before. For just the refining step - and counting all energy inputs, even those generated within the process and used to drive it - the EROEI is about 12/1 for light crude and 10/1 for heavy, sour crude. That is just the refining step. Numbers I have heard for the crude production step are in the range of a global average of 17/1, which puts your total EROEI in the 6/1 range.
Thanks, Robert, for taking the time to educate us. Very interesting. I should have stayed in organic chemistry!
Just read this article last week - spooky timing. It's curious how heavy crude can be more profitable now - I'm still baffled about refineries can make better margins with oil rising and gasoline selling for relatively lower prices.
Very well written, thank you. It would seem that coker installation may bump up asphalt recycle rates as well. Crack spreads do appear to be widening as of late.
http://www.oilintel.com/spothome.cfm?loc_id=7
Thanks for the explanation!
I don't know if this little diagram is helpful. It is one I have posted before:
Fractional Distillation (Diagram by The Institute of Petroleum, UK)
These units are percentages? If they are, what am I missing? Both columns add up to way over 100%.
If you dont add the API, the rest should add up to 100.
Don't add the sulfur % (as the sulfur compounds are already distributed in the various boiling fractions) nor the API gravity.
Slatz & Iconoclast: thanks you guys! I knew I was slippin' a cog someplace.
I guess I'm a little confused as to what a coker does. I have worked in cokers, repaired cokers, and specified cokers, etc. The cokers I have been associated with make coke. It collects in the drum and with a high pressure water cutter cuts the coke into blocks which drops out of the bottom of the drum and into a rail car. The derrick on top operates with a drill string with the cutter at on the bottom. As the jet is lowered into the drum the coke is cut into blocks.
Coke burns like the lobes of hell and was used in steel industry to melt steel.
http://en.wikipedia.org/wiki/Coker_unit
to put it into laymans terms, a coker unit boils the tar out of the heavy resid (literally and figuratively).
The resid is heated and then flashed into the coker drum, anything that will volatize goes off the top and solids (coke) is left in the drum. You continue to flash the heated resid into the drum until the drum is full of solids. The full drum is then cooled with steam and then water. The bottom head is removed and then the water jets you noted above are used to cut the coke out of the drum.
You always see at least two drums in a coker unit, one being filled and the other being cooled/emptied.
The one aspect missing from the above presentation is the hydrogen content of the crude, products, and major fractions. Products contain only carbon and hydrogen, with the hydrogen content ranging between 14 and 15 wt%. The hydrogen content of crudes varies approximately linearly from 14% at 40 API to about 10wt% at 10 deg API (oil sands).
Vacuum residue (5 API for heavy crude) has about 8-9% hydrogen. Coke has 3-4% hydrogen. Thus, the raw products from coking of a vacuum residue (38 wt% coke yield from heavy crude with 24% "Conradson Carbon" are very "hydrogen deficient" with respect to refinery products (11% vs 14%).
If you assume the net yield from heavy crude is the same as light crude, you need to add a lot of hydrogen which is an input from the energy in natural gas. About 2 wt % H2 net, based on products will be required for a 22 wt% heavy crude converted into products. Less than 0.5 wt% will be required for light crudes, which can be obtained from the reforming process, which, incidently causes a reduction in volume vs the heavy naphtha feed.
Bottom line is that processing heavy crudes is no piece of cake-- more NG is required to achieve the same volumetric yield, which implies more hydrogen capacity, more hydrotreating capacity, more sulfur recovery capacity, and more utilities capacity.
Correction--that would be 22 API heavy crude, not 22wt% heavy crude.
Use the "share this" applet included in the posts to reddit, digg, and share the post on other sites, etc. It's really easy (provided you have a login at those sites).
Robert - I'm in the market for a new car, and since plug in hybrids are not yet here I was considering an Audi 1.8 liter turbo diesel - likely 2nd hand since I now understand the concept of depreciation.
This Audi engine is one of the most efficient and rivals a hybrid. However, everyone in Europe is now wanting to own and drive a diesel which now costs significantly more than regular gas and it seems to run out at gas stations more regularly. The cost of the car / engine is also considerably higher.
So what do I do? I foresee the difference between diesel and gas prices widening and ultimately wiping out the energy efficiency gain - in financial terms.
Diesel is also the fuel most likely to be first rationed, to keep heavy goods vehicles and agriculture going.
Stick to a light-bodied petrol car, which if they don't manage to turn out enough EV's to satisfy demand you could possibly convert to be able to run it a few miles.
Not that in the UK we seem very likely to have any electricity, although Gordon has now decided that the precious Labour policy of no new nukes was wrong - shame they took 10 years to do so, as it might have stopped the lights going out.
I foresee the difference between diesel and gas prices widening and ultimately wiping out the energy efficiency gain - in financial terms.
Agree. I don't see that situation getting any better, especially since the U.S. went to ultra-low-sulfur-diesel specs. That's harder to make, takes more energy, takes more capital, and you lose some of your yield.
Dear Euan,
depending on your transportation needs, I would recommend the following:
If you have to drive your family around, get the Audi or a used gasoline four seater the same size with the smallest engine possible (1.4l, 1.6l). This will get you to about 5-7l/100km if you apply fuel saving driving tactics. Or get a used Audi A2 or Polo 3l. These have four seats as well and will suffice to transport 2 adults and two kids or 3 adults.
Do not waste money on a brand new hybrid.
Alternatively go for a new SMART Micro Hybrid or a used Diesel SMART. This will be the optimal solution if you are single (commuting) or your family can make most of their trips by bike or public tansport. Add a car sharing for greater flexibility: you can always rent a bigger car if you need to go to IKEA, haul something big or plan a family trip. That's the model after that I am living right now after being car free from 2005 to 2006.
I get by with 3.5 to 4.5l of diesel per 100km. The new SMART Hybrid will use a little more gasoline, but not much.
In any case: get a good bike in the 1000 to 2000 Euro range with a dyno hub, LED lighting, gear hub and high quality racks (i.e. Tubus) and bags (Ortlieb, Vaude). And a bike trailer too, preferrably dual use (transporting kids/hauling the weekly groceries). Avoid suspension forks and rear suspension, go for wide, flat protected tires instead. Get two decent bike locks, preferrably an ABUS Bordo and an ABUS Granit. Avoid Kryptonite. Always lock it to an immovable object in well lit places. Ride your bike as often as possible.
HTH,
J. Daehn
Thanks for the advice - if only our government had spent more money on cycle lanes. They have spent a lot of money painting lines down the side of heavily congested roads - but I will avoid a rant.
I will look into the SMART option for short local commutes.
Hi Euan,
I would recommend you look here for CO2 emissions - but they only give figures for new cars:-( Apart from not wanting to emit more CO2 than you have to (you do don't you) it will affect your annual "road" tax or Vehicle Excise Duty.
http://www.vcacarfueldata.org.uk/search/vedSearch.asp
You should consider how many miles a year you drive since if like me you only drive 2,400 miles/year the better mileage from diesel will be outweighed by the higher cost of the car and the fuel.
I have an old gas guzzler and I am trying to justify to myself why I should get a newer small car other than just because I want one:-( SMART have a new electric version but they won't sell me one. Petrol at £5/litre would probably also work but then I'd get a Porsche since the roads would be empty and driving fun.
Or you could move to London and join a car share scheme.
A priceless source of information for those of us that don't quite understand all the intricacies of the downstream.
With middle distillates driving the oil price, it's important to know how they're made.
I referenced you in my column today over at ASPO-USA, Robert.
best,
-- Dave
Are plastics made mostly from residuals?
As far as I know plastics are made primarily from NG and NGL feedstocks not oil. Although Aromatic and some of the lighter oil fractions might be used Naptha for example is a big feedstock and often comes from oil.
Almost all plastic manufacturing can be routed through something called syngas which is a mix of carbon monoxide and hydrogen from this you can make methanol, ethylene etc. Once you have say ethylene you can make anything. Peanut oil could be used for plastics.
http://en.wikipedia.org/wiki/George_Washington_Carver
I think Carver would not be surprised about our current situation.
Is the catalytic cracking of the gas oil a tunable process? One would think gasoline weights would come from one set of temperatures and pressures, while diesel might come from different settings. Is this not the case?
If there are a lot of cokers being installed presumably we're going to see a flip at some point - the heavier crudes will become more desirable. I watch the noisy, daily price information from upstreamonline.com when I'm not sufficiently depressed, but I've never looked at the trends. Is it possible to see when major facilities come online by looking at historic prices? Or will we see a big pulse of them coming on all at once as refinery managers make that move?
I wonder about the cost of methane generated hydrogen vs. electrolyzer hydrogen. There will come a time where packaging the methane for sale is better than using it in an SMR for hydrogen production, but I'm only up on the economics of such things at the far end of the value chain. This would depend on available hydroelectic or other inexpensive electricity sources at the processing point ...
Robert,
You're the shezz.
Very helpful article.
A catalytic cracker can break long chains down into smaller chains, is there a converse process that allows you to convert two shorter C5 to C10 chains, by addition, to make longer chained fuels, such as diesel?
Yes - Fischer-Tropsch. It's the basis behind GTL and CTL.
Wrong Answer. Fischer-Tropsch is never used in a refinery. What is used is Catalytic Condensation and Alkylation to make polymer gasoline and alkylate, respectively. For more information on this and other refining processes, go to the UOP website.
http://www.uop.com/refining/1052.html
It's not the wrong answer, in that it is factual. But it is also true that refineries don't employ FT to build chains, as it is not economical to do so from crude oil. If, however, there was a huge delta between the lower chain hydrocarbons and the higher chain hydrocarbons, you would see FT units being built.
It was the wrong answer to the question which queried about the linking together of smaller chains to form larger ones, not the building of chains, carbon-by-carbon.
There is a huge "delta" between lower carbon-chain hydrocarbons and higher carbon-chained ones in areas of "stranded gas" such as Alaska. I don't yet see any rush to build F-T plants at a location anywhere in the state, even though a large refinery exists at North Pole, located near the center of the state on the TAP, not far from Fairbanks.
My point is that, if F-T synthesis were economic, there would be no reason to confine the synthesis plants to "petroleum" refineries.
Great stuff, Robert, most helpful and way overdue!
This leaves me with a puzzling question though: why aren't the independent heavy sour refiners like Valero and Tesoro able to make more profit if their feedstocks come at such a discount? Both of us predicted $4 gas by this time this year, but I expected the heavy sour refiners' margins to recover along with it, and that doesn't seem to have happened yet.
This leaves me with a puzzling question though: why aren't the independent heavy sour refiners like Valero and Tesoro able to make more profit if their feedstocks come at such a discount?
Because in reality, the heavy crudes have gotten much more expensive, and the big delta between refining light crude and refining heavy crude has evaporated.
By the way, I have finished your book, and have been trying to finish the review. And I did have a comment on your prediction in the book on refiners. :-)
Thanks, Robert!
You said in your third last paragraph
As the crude oil production rate declines, not only will airlines continue going bankrupt, refineries will either turn to heavy sour crude or also go bankrupt. As Saudi Arabia is increasing their heavy crude refining capacity, other older simple refineries will have to decide whether to install expensive cokers/crackers or close down. Many will simply close down as crude feedstock supplies dwindle.
The table below is from page 46 of the IEA's May 2008 Oil Market Report. It shows that there was a recent peak refinery crude throughput of 75.5 mbd in December 2007. The footnote strangely states that forecast crude throughput is based on IEA's demand rather than supply. This implies that if crude production falls then refineries will draw on crude stocks to make up the difference.
source IEA May 2008 OMR http://omrpublic.iea.org/archiveresults.asp?formsection=full+issue&formd...
click to enlarge
Page 47 the IEA May 2008 OMR states that OECD refinery utilisation was 84% in March 2008, down from 85% in March 2007. As the utilisation rate is likely to decrease further as post peak crude production decreases, there will be further downward pressure on refining margins (full cost basis).
Page 45 of the IEA April 2008 gave a warning about refinery margins: "The poor state of hydroskimming refinery margins, estimated in this report to have averaged -$4/bbl on a full-cost basis for Urals crude in Europe during March, kept the pressure on less complex refiners to minimise crude throughputs. At this level even marginal economics do not support incremental crude runs by hydroskimming refineries."
The IEA May 2008 OMR Table 15 shows some refining margins for April 2008.
http://omrpublic.iea.org/omrarchive/13may08tab.pdf
US Gulf Coast Kern(Coking) refinery margins (full cost basis) for Apr 2008 was a very profitable $16.69/barrel. In contrast Mediterranean Urals (hydroskimming) margins were negative $4.97/barrel. All the hydroskimming refining margins on Table 15 were negative. This is not sustainable and some of these hydroskimming refineries will close down rather than converting to expensive upgrades for heavy sour crude.
What does the skyrocketing price of sulfur do to the margins? Is sulfur now expensive enough that a refiner might get a better margin from high sulfur feedstock? Is high price likely to increase the supply of sulfur?
What does the skyrocketing price of sulfur do to the margins?
For a long time, sulfur was pretty much a waste product that was hard to get rid of. I remember when I was interviewing out of college, I took a tour through one refinery and they had mountains of sulfur piled up. Now, the ones who end up with elemental sulfur are doing OK, as it does add to the bottom line.
Supply of sulfur from refineries will increase as the crude sours up, which is the trend.
your 34.8 degree api crude would weigh about 298 lbs/bbl, while the 22 gravity crude would weigh about 323 lbs/bbl. this shifts the profit even more to low gravity crude.
and could you give a little more detail on how a catalytic reformer works ?
maybe an explaination of what it does to raise the octane ?
and could you give a little more detail on how a catalytic reformer works ?
maybe an explaination of what it does to raise the octane ?
It's just a set of chemical reactions that turn low octane compounds like paraffins and naphthenes into higer octane compounds. For instance, something like heptane (C7) that has an octane rating of zero can be converted into toluene - which an octane of around 115. And octane is just a measure of the tendency to ignite prematurely.
The most important characteristics to know about the reactions are that they are endothermic, occur under a moderate hydrogen pressure to prevent coking of the catalyst, isomerize some linear chains to higher octane branched-chain alkanes, convert some linear chains to rings, and finally, dehydrogenate a portion (limited by equilibrium considerations) of the ringed (6C)compounds (called naphthenes) to stable aromatics (planar structures). Some 5-carbon naphthenic rings are converted to 6-carbon naphthenic rings before dehydrogenations.
Some hydroskimming refineries (used to) use hydrogen from reforming as their sole source of plant hydrogen. This would apply only to extremely sweet, high-gravity crudes. Since hydrogen is lost from each molecule that forms a ring and more from rings that are converted to aromatics, a significant amount of liquid volume is lost during the process, as I recall, in the order of 6-8% for every 20 to 30 octane points gained. Don't quote me on that, however.
And thus, Robert, you just have put your finger on the reason why I believe that "total liquids", and even just "C+C", are ultimately misleading statistics to be tracking. What we need to be tracking are the liquids net of those liquids used for production. Otherwise, we end up essentially "double counting", and inflating the figure to the point where it may appear that the supply of hydrocarbons is increasing when in fact for all practical purposes it may actually be decreasing. This in turn leads to the kind of clueless bewilderment and counterproductive blame-seeking and scapegoating that we are now seeing.
We should all be aware by now that the EROI for conventional petroleum has dropped substantially, and will drop still further as we move into tertiary recovery methods for existing fields and try to work challenging environments like deep offshore. This is not to mention the generally low EROI figures for tar sands (maybe around 5.0?) or oil shale (maybe barely more ant 1.0?). It has always taken energy to make energy, but it is now taking more and more. WE MUST FOCUS THE WORLD'S ATTENTION, AND ESPECIALLY THE ATTENTION OF POLICYMAKERS, ON NET RATHER THAN GROSS ENERGY PRODUCTION. Otherwise, people will have the false assurance that things are far better than they really are.
Fuel prices from around the world. Check out Veneuela.
http://news.yahoo.com/nphotos/Map-shows-price-gallon-gas-dollars-select-...