Refining 101: The Assay Essay
Posted by Robert Rapier on January 16, 2007 - 11:35am
Topic: Supply/Production
Tags: crude oil, economics, oil companies, refining [list all tags]
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 is 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)
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 $55 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 $80/bbl. They therefore grossed $80*0.909 - $55 (the purchase price of the barrel), or $17.72 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. 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 $1.40. Let’s value our gases at the value of propane (about $0.14/lb on the spot market), and we get a value of 300*.044*$0.14 = $1.85 for the propane. Our gross profit (before operating costs, taxes, etc. are considered) is then $17.72 + $1.40 + $1.85, or $20.97 per barrel for the light crude.
Now consider Refinery B. Instead of buying WTI at $55/bbl, they buy a heavy Canadian crude for $38/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 our coker, we 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, we grossed $80*0.906 - $38 = $34.48 a barrel on the heavy crude. This is almost double the profit of the light crude. We have slightly less propane yield than in our previous example. The value of propane is $1.43. Finally, we end up with 16.8 lbs of coke, which is worth only $0.015/lb (about $0.25 total). Our total gross profit then is $34.48 + $1.43 + $0.25 = $36.16.
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
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As coking becomes more common expect significant price increases in asphalt and heavy oils. This is one reason I'm so keen to get good numbers on these markets. They I think represent the move to coking heavy sour oils as light sweet declines. So I think they are the most sensitive barometer of the oil supply.
In the future this means ships may end up paying close to diesel prices for fuel oil or just burn diesel or convert to coke or cokes slurries.
As coking becomes more common expect significant price increases in asphalt and heavy oils.
It's already starting to happen. I knew that asphalt prices have been increasing, but I ran across a graph while I was working on this article that shows that prices have really skyrocketed. You can see a graph of the increase here:
http://www.techtransfer.berkeley.edu/newsletter/05-4/highprice.php
Now, the bulk of that rise goes along with the price of oil, but as oil prices go higher refiners will feed more asphalt to cokers when they can, causing an asphalt shortfall. This trend will get worse going forward, but at some point asphalt prices may be high enough to cause some refiners to reconsider installing that coker they have been thinking about. But we have a ways to go before that happens. Economics still strongly favor installing heavy oil processing facilities.
You can get an asphalt price index at this link.
http://www.acaf.org/asphalt_price_index.htm
Holy cow 1.35 a gallon for asphalt ?
From about .60 in 2002.
Also it seems that Asphalt prices trended upwards leading oil prices.
I mean that asphalt prices seems to have started going up back in 2002.
The recent correction seems larger for asphalt but I think this is the combination of the season oil prices and looming recession.
Asphalt prices look like a pretty good merged economic/oil price indicator.
Right now they say demand is dropping faster than per bbl prices signaling recession.
Thanks for the link !
This is great.
Now do you have one for the supply at these prices ?
You say both barrels weigh 300lb. I thought that barrels were a fixed volume, 42 US gallons. My calculations show the Heavy at 22API (density 0.9218 kg/litre) comes out at 330.44lb and the Light at 34.8API ( 0.9218 kg/litre) comes out at 305.03 lb. Have I misunderstood something?
No, the barrel weights were just approximate. As I said, the real economics are somewhat more complicated than what I have presented, but if you follow the example you have the big picture. The exact weight of the barrel doesn't change that big picture.
Very informative and nicely done.
Maybe you're planning on getting into this topic in one of your subsequent refinery essays, but I'd like to see some discussion on the final disposition of all the sulfur that is removed from the crude. Even at less than 1% of the crude, it has to be a truly huge amount of material, and will become even larger as more and more 3%-sulfur heavy crude is used.
If I recall correctly, there are several pathways for the sulfur that is removed: i) combustion of H2S and discharge of SO2 air emissions, ii) removal of SO2 from i) as calcium sulfate sludge, iii) conversion to sulfuric acid, and iv) removal as elemental sulfur. I'd be interested to know which is the most common pathway at present.
It would seem to me that if high-sulfur heavy crude is going to constitute an increasing fraction of a refinery's imput, then the disposition of the removed sulfur is going to become increasingly problematic, giving that there appears (last time I looked) to be a glut of byproduct sulfuric acid and elemental sulfur.
In at least some cases, it ends up as elemental sulphur. I saw a picture once of a giant yellow mountain of the stuff. Not sure, but I think it was next to the tar sands thing in Canada.
In at least some cases, it ends up as elemental sulphur.
That is the case with the plants I am familiar with. The removed H2S gets turned into elemental sulfur and sold. Emissions of things like SO2 are pretty strictly regulated in the U.S. (this wasn't always the case, though).
google Claus sulfur plants.
that's the typical refinery process.
http://www.ortloff.com/sulfur/claus.htm
Saudi was trying to use sulfur to make concrete like roads just to get rid of their huge excess.
First world refineries don't just put all the sulfur up the stacks as SOX.
What happens to the sulfur depends on economics. It's a pretty good bet that the price of elemental sulfur will continue to fall because sulfur is also piling up at coal-fired power plants while the demand for sulfur is not growing at anything like the same rate. In some cases, the sulfur can be made into sulfuric acid on site and sold as such, but in the long run that will just knock down the price of H2SO4. I expect elemental sulfur will eventual be treated as a waste.
When I was taking chemistry (about 3 decades ago), the professor mentioned that the price of H2SO4 as an industrial chemical was the cost of transportation from Texas Gulf Sulfur or wherever. The white vitriol in the lab was that price, plus the cost of the container.
I do recall seeing a picture of a sulfur mountain back then, produced by the Frasch Process. Is it even necessary to exploit sulfur deposits that way any more?
Bought some as soil adment spring 05. $5.50/50 lb sack. There are mountains of it off the AlCan, northern BC, back in late 90's.
According to legend, both rural and urban, there is a yellow pile in Khazahkstan that is visible from space, presumably with the naked eye, as the clothed one can see your lawn ornaments. Having seen trainloads of sulphur on their way from Alberta to Vancouver, I can imagine there are numerous piles there, too.
Apart from vulcanising rubber and such, I suspect the production vastly exceeds the demand. Sulphur burns all too well in a rather molten state, and was used to kindle coal fires, but that was before my time, or after, perhaps. I did get a lump fired up on my bench as a kid and it burned relentlessly, clear through two layers of 1/2" plywood before hitting the floor. I resolved to leave it alone, but all this sulphur must be going somewhere and the atmosphere is my guess.
It sure makes an impressive fuel, if no one is looking. Hot and cheap. Brimstone. Sulphur dioxide makes carbon dioxide look like a good guy. I would imagine that the shipping costs from the Caspian far exceed the value, but rolling it downhill from Alberta to a waiting barge should be about as cheap as rail maintenance. As to who gets the honor of 'utilising' it and how remains a mystery. I have often mused on this as the jaunty yellow trains roll by. And I remain fathful to the ph spelling 'cause it looks better, and mixed with water it has quite an effect on PH. Phew!
The US does not seem to have enough... we keep importing some:
http://minerals.usgs.gov/minerals/pubs/commodity/sulfur/640301.pdf
Most of the sufur probably ends up in the chemical industry first. Without sulfuric acid most basic synthesis chains would come to a halt. A lot, it seems, is needed in agriculture in fertilizers. I am not sure where it goes from there... in the end it will have to be bound in some organic or inorganic form and then be deposited geologically. I haven't been able to find out what the end products are... but it could very well be that the sulfur in coal and oil is an end product of a similar chemical reaction chain that produces current organic sediments.
One other product is modern soap, or SDS (sodium dodecyl sulfate). In this the two divorcees, petrol and sulfur, marry again...
Sulfur is not a long-term environmental problem. Though its compounds cause acute damage, being toxic, smelly, and corrosive in the immediate area of a spill, it will join the natural sulfur cycle fairly quickly. I'm not sure precisely how quickly, but the only sulfur compound I'm aware of that has a significant environmental half-life is SF6. Then there's acid rain — but that tends to stop when you stop emitting SO2. It isn't like heavy metals.
In an aerobic environment, it will exist as SO4-- ions, and in an anaerobic environment, it exists as S-- ions. Various wild sulfur-loving bacteria will perform the conversion for you. It also exists as biological sulfur; certain amino acids and small molecules present in living things everywhere contain sulfur atoms.
Bottom line is, your sulfur spill will find something to react with and become environmental sulfate. If it encounters calcium, you'll have gypsum. If it's in a stream it will end up in the ocean as sulfate. Since we aren't burning sulfur to keep warm (yet), not enough of it is being dumped/spilled/spewed to acidify the ocean.
A few years back when I was working at a Zinc Smelter that processed ZnS ores, we roasted the ZnS to make ZnO and SO2. The exhaust gases went through a series of cleanup steps followed by a series of 4 catalyst reactors(not cheap!) to turn to the SO2 into SO3. The SO3 was bubbled through H20 to make H2SO4.
This effectively reduced the stack SO2 from 7% to 150ppm, but the acid was basically sold at cost +/- a few $/MT. This was in Clarksville, TN.
IIRC we made ~250,000 MT /yr of 93-98% sulferic (about 20 semis full per day).
RR,
Thank-you for this informative post. I would be interested to know how much hydrogen a hydro-treater and hydro-coker require to upgrade heavy sour. More to the point, given a kg of non-fossil hydrogen, how much of a profit can be made using it to upgrade heavy sour or Alberta/Venezuela bitumen instead of using it in a fuel cell. My guess is that upgraders, coal-to-liquids, biomass-to-liquids, and waste-to-liquids all present a "deal to good to refuse" to hydrogen suppliers for many years to come, and we will not see hydrogen-powered cars until every tonne of carbon is airborne. Thanks for any figures you can provide
I would be interested to know how much hydrogen a hydro-treater and hydro-coker require to upgrade heavy sour.
The coker doesn't use any hydrogen. In fact, it produces light gases which can then be used to produce hydrogen. Hydrotreaters and hydrocrackers do use hydrogen, but I will have to find you a public source on how much they use. I did read a report recently that to upgrade 1 barrel of bitumen takes about 1,000 cubic feet of hydrogen. That's probably a good approximate number to use for a hydrocracker requirement.
I get 59.18 kg bitumen / kg H2. Is that to make syn-crude or finised products?
If I recall correctly, that was for syncrude. I have some real numbers for hydrotreaters, but none that I can share. However, the actual requirements will be highly variable based on 1). The amount of sulfur in the initial crude; 2). The degree of processing (hydrotreating or hydrocracking); and 3). The finished product. Ultra-low sulfur diesel and gasoline requires quite a bit more hydrogen to produce than the higher sulfur versions.
A coker is basically doing destructive distillation ?
Basically your heating the bejezus out of the oil in a reducing environment with c-c c=c bond formation resulting in the coke and reactive free hydrogen that reacts with double bonds on the lighter products as the distill over. Or do you get a hydrogen/unsaturated carbon mix that needs to go through a catalyst ?
The reason I guess for this approach is that the carbon chains in the residue are much longer and don't boil any longer but thermally decompose below their boiling point. If you can't boil them you can run then through a hydro cracker.
Its interesting that the tar sands seem to use a steam cracking process for upgrading while refineries go with coking. I don't understand why different processes are used for such heavy oils. But I also did not find any clear explanation for the upgrade process of tar sands. Maybe they are the same.
I find references to coking as a step in tar sand upgrading. I'd love to learn more about both processes if someone can explain or provide links.
It hard to actually find out why certain processes are used and what competitive routes where.
Whats interesting is that the residual coke is not converted to syngas and used as a feedstock this show that syngas is still not a cost effective route to oil production. I'd have to guess that NG would have to get a lot more expensive and then the syngas would probably be more useful as a hydrogen source. Makes me wonder at the economics of CTL processes if they don't work now at oil refineries.
except around Houston where there are merchant hydrogen supplies, the refiner is his own hydrogen supplier. If you dig into the DOE's refinery capacity/equipment tables, you'll see that most big refineries have hydrogen plants (steam hydrocarbon reformers or Partial oxidation plants) to make hydrogen. There isn't a lot of non-fossil hydrogen about except as surplus from the chemical industry (where it is probably fossil sourced in the first place).
The naphtha reforming process makes a lot of hydrogen but not enough to run a heavy, sour upgrading refinery. So refiners have to make more. These plants are energy hogs. Great big furnaces needed to create the high temps necessary.
the lighter products from a coker are also hydrogen deficient (many double bonds) as a result of the thermal cracker process. Those require H2 to saturate them as well or your gasoline is gummy.
Typically the hydrogen in a hydrocracker goes to reactions in this order:
saturate double bonds (very fast and hot)
Metals removal (they crust out and block things up if you don't design your catalyst beds correctly)
Sulfur removal
Cracking large hydrocarbons into smaller ones
nitrogen removal
Saturate aromatics
Obviously all of these reactions are taking place at the same time but this is what I remember as the basic order of difficulty. Been 2 decades so don't hang me if I'm off a little.
Last time I discussed the situation with my old refinery design colleagues, the cheapest way to make hydrogen was still steam reforming so a hydrogen car is just a silly way to turn petroleum/nat gas into an auto fuel. Just go electric and cut out all the middle steps.
Any chance to improve efficiency by coupling these refineries to the waste heat of power plants or are the required temperatures too high?
many refineries already have combined heat/power generation facilities. There's no high potential heat being wasted in either location. Lots of money went into refineries and power plants in the 70's/80s to recover heat via heat exchange with cold feed stocks/steam generation etc. about all that's left is at levels perhaps suitable for home heating like European cities do. Except we hide refineries as far from people as possible.
I read this too (about steam reforming of methane). That 95% of the H2 currently produced is made this way, and that it is almost always used on site.
I have *never* found a review of all possible alternatives to oil that compared the pros/cons and concluded that H2 is clearly the best.
Hello R-squared,
Just a quick question: where do the heavy gear lubes and bearing greases come from?--the cokers, or a totally different refinery & chem-process?
Bob Shaw in Phx,Az Are Humans Smarter than Yeast?
Bob,
I believe those are just heavy to very heavy gas oil cuts that get taken off from the crude oil, probably from a vacuum tower after the initial light cuts are removed (gases, light straight run, naphtha, etc.). There would then be some sulfur removal process; possibly through hydrotreating. Beyond that, I am not sure what kind of additional processing they might get. I don't have direct experience with these gear lubes and bearing greases, so anyone who knows more can correct me if this information is incorrect.
Typically lube is produced from specific crudes that have high paraffin content. The Pennsylvania and Ohio source crudes have these qualities as well as some from Oklahoma. At one point the old Sunray-DX company refinery in western Oklahoma was shipping a complete train loads of 30 SAE oil to New Orleans for sale to Japan. Heavier lube grades, some of which are called Railway Cylinder Stock come from the same crudes. Greases while very thick are not necessarly very heavy. They are often mid range lube stock mixed with a soap or have been saponified. Additives such as molybdenum are added to give needed properties. Sodium and potassium based greases are water soluble, while lithium are insoluble.
Lubricating base oil stocks mostly come from Nigeria these days due to - wait for it - depletion of the Pennsylvania wells of Pennzoil and Quaker State fame. Both of these brands are now owned by Shell who also seem to have the lion's share of Nigeria. Attempts to upgrade the usual oil to a lubricating base by hydrogenation, as was being done in a Gulf/Petrocanada operation in Sarnia Ontario, met with less than stellar product, in my experience and opinion. I'm not sure if they stopped doing it, or fixed the process, or shortages of good base stocks made doing it better economical, but there are ways to 'parrafinise' base oils, plus the option of the totally synthetic, build it up from esters and such, process and so on.
When one figures in the drag reduction of synthetic lubricants versus their cost disadvantage, we are throwing away money and fuel by not using them. If we had to pedal those pistons up and down those holes, we'd all switch tomorrow.
Are you sure about Nigeria? IIRC Nigeria imports Arab light to make lube in their Kaduna refinery. Dumbest thing I ever saw in the oil biz. Building a lube refinery way inland with no local lube crudes.
Arab light is a good lube crude. Very popular around the globe for that purpose.
I'm going to guess most lube oils these days are being made by hydrocracking/treating Vacuum gasoils of whatever crude is available. Chevron went that route in the 80's. Ditto Exxon IIRC.
I hear that base oils for lubricants etc is one of the products from the GTL projects that are ramping up in the middle east (particularly in Qatar).
This is correct. I ran a GTL lab for a couple of years, and we had a group devoted to the lubricants that you get from the process.
RR
Your example and the distilates you get. Because we have more heavy sour on the market (?) does this explain why diesel prices are so high at the pump. Less qty, higher distilling heating requirements, and greater fuel(energy) content?
The move to ultra low sulfur diesel (ULSD) has put pressure on diesel prices, as there are more processing requirements and the ultimate diesel yield is lower. But a bigger reason is that Europe has a high demand for diesel, and so they don't ship it over here like they do gasoline. Some of our gasoline demand gets satisfied by imports, but the situation with diesel is different because 1). The demand in other countries is high; and 2). A lot of other countries can't meet our new ULSD specs.
Europeans went to USLD before we did. That's why they have the super efficient diesel engines available and we don't just yet.
Their gasoline surplus (running refineries to meet diesel demand if you look at it very simplistically) has indeed been exported to the US for the past few decades. Our new, tighter gasoline specs made that difficult for some of the traditional European export refiners.
my guess is the reason our pump prices for diesel are so high is demand is low so retailers don't get the same turnover on stock. They demand a larger markup and also don't feel the need to compete aggressively on price. Same deal as with premium gasoline. the market price spread may be a nickel but you see 20 cts on the pumps.