If you are referring to American light crude oil grades such as WTI (West Texas Intermediate) that is not correct. That oil could be refined in California. It would have to come by tanker from the gulf coast through the Panama Canal to get there. Until recently it would have to come on a Jones Act US flagged tanker (expensive, scarce). That requirement has been temporarily waived.
The California Air Resource Board (CARB) has promulgated a revised Cap and Invest rule that threatens the viability of the remaining refineries. All the remaining California refineries have sent CARB, the Governor and the CA legislature letters pointing this out.
California is now a net importer of gasoline following these refinery closures.
The CO2 has to be scrubbed out. This is not necessarily all negative, since if the CO2 is injected underground for sequestration it makes biogas carbon negative.
“especially given that a net new refinery hasn't been built in the US in 50 years.”
Existing large refineries have done some massive expansion projects in the last couple of decades, adding the equivalent of a several new refineries. It is often easier to do this than build a new grass roots refinery.
Example projects:
MPC Garyville +180 MBD (2009)
Motiva Port Arthur +325 MBD (2012)
XOM Beaumont +250 MBD (2023)
A few corrections. Credentials: I am a Chemical Engineer in a Senior Tecnical Leadership position at a refinery with over thirty years of experience.
1) API gravity is the density of the crude oil. Higher API = lower density. We use this unit of measure because it magnifies the differences in densities vs. using conventional units of measure.
2) Refiners in the US mix different crude types to maximize the objective function ($) of a set of constraints including crude grade pricing and availability, product demand volume and pricing, refinery unit constraints and product quality specifications. This is done using a linear program model.
3) light and heavy crude contain the same molecules but in different ratios. For example they all contain gasoline, jet fuel, diesel boiling range material and all contain some amount of material that could be turned into ship fuel or asphalt for paving roads. Heavy crude tends to sell at a discount to light crude because of the laws of supply and demand - refiners will buy a mix of whatever makes them the most money.
4) “Most refineries in the US are very old and are very polluting”While US refineries sites are old - some site have been in operation for over 100 year, the units and configuration of the refineries has evolved continuously over the years. The technology used in the refining units has evolved as well - this is not a static industry. The pollution standard for refinery operations and fuel emissions have been raised multiple times. So “Very Polluting” vs. new refineries does not pass muster. US refineries have been retrofitting wet gas scrubbers and selective catalytic reduction units to reduce emissions of SOx and NOx for decades. These technologies reduce emissions of both pollutants by over 90%. Most of the emissions come from burning the fuel that refineries produce and both legacy US refineries and new ones have to meet the same fuel quality specifications and hence produce equivalent emissions.
5. “There are different blends of gasoline that the US produces. The biggest is so-called summer and winter blends. What's the differene? Additives are added to summer blends (in particular) to increase the boiling point so less of the gasoline is in gas form because that produces more smog;”
Summer gasoline contains less butane than winter gasoline. That is the main difference. Butane is added to winter gasoline so cars start in cold weather. There are no additives added to raise the boiling point in summer - just less volatile light material added.
As an aside, Mvodern gasoline vehicles have carbon canisters to capture vapors (such as butane) from the gas tank when not in service. These are then regenerated by sweeping air through them when the vehicles are running.
6. “ California uses their own blends so in 2021-2022 when CA gas went to $8+, it wasn't just "gouging". It doesn't really work that way. CA requires a particular blend that only CA refineries produce so it's simple supply and demand as no new capacity gets added to CA refineries and demand goes up with population growth.
The reason for the CA blend goes back to the 80s and 90s when smog was a much bigger problem. Better vehicle emissions standards since then as well as improvements in the blends the rest of the country uses have largely made the CA blend obsolete so CA is really paying $1+/gallon more for literally no reason;”
There is some out of date information here. California is a net importer of gasoline since refinery closures in California have outpaced reduced demand from increased fleet fuel efficiency / BEV adoption. There are refineries in Asia that export California and some other US refineries can also make California grade gasoline but this requires shipping via the Panama Canal on Jones act ships that are scarce and expensive.
P66 / Kinder Morgan are planning a pipeline / pipeline reversal that would bring refined product into California including California gasoline.
[off topic] Given your background,I was wondering if you could offer some clarification if I'd read some Bs or just misunderstood. Long ago I had read something in a petrochemical book, maybe I got wrong, but one little section I skimmed over seemed to point out a modern refinery cracking plant could use vegetable input stock with I think was a caveat in regard to cleaning or addition by-products. Is this feasible or done, or was I reading a fluffy passage that wasn't fact checked properly?
Yes, Hydroprocessing units at refineries can either co-process vegetable oil with hydrocarbons or run 100% on vegetable oil after some modifications.
Vegetable oils are tri-glycerides. These molecules can be cracked into three long chain paraffins and a propane molecule by reacting them with hydrogen at high temperature and pressure over a catalyst. This makes a raw diesel fuel that then needs to be isomerized to lower the cloud point (basically when it begins to freeze). The end result is a drop in replacement for fossil diesel fuel that burns smoother and cleaner.
Two refineries in the SF Bay Area have converted from fossil fuel operation to manufacturing this renewable diesel.
Fun fact: over 70% of diesel sold in California is now renewable or bio diesel. Both types start with tri glycerides - either vegetable oil, waste cooking oil or animal fats.
Started my career working in AI for a company that had a couple large refineries (I didnt dare refer to what we were doing as statistics because those guys had all been fired a decade before after attempting to perform some back magic they called six sigma), pipelines, a fleet of ethanol plants (at the time) and a couple biodiesel bets, including one that attempted to convert corn oil into biodiesel.
I was blessed to have a leader who wanted us to spend a lot of time on the field, working turnarounds doing, whatever I could to be helpful, etc. to learn the business and build relationships.
Working around the refineries, especially during turnaround, was a crash course in constraint theory and economics.
Good times.
At any rate, all of that was to qualify that most people would not believe how much time and money has been wasted trying to find innovative new ways to serve and capitalize on the CA biodiesel market.
" ... most people would not believe how much time and money has been wasted trying to find innovative new ways to serve and capitalize on the CA biodiesel market"
I am curious as to what is meant. Refinery side innovation or marketing or other?
In Australia over the years there's been a heavy focus on bio fuels and not any mention of renewable diesel or jet fuel. News items focus on modern vehicles, and not older diesels that of course could run on peanut or coconut oil without any chemical modification.
My locale (Northern Central Queensland Aust) bio-diesel is often produced small scale by individuals and not enough to be a statistic that I can find as a percentage of use in the state. Scaling up shouldn't be a problem in itself, it's just reluctance to use the present food oils as stock.
Thank you so much for that. I had tried searches various times and got little information.
Bio fuel is what most people think of when it comes to renewable - though by way of proper refinery processes, none of the issues or perceived issues would exist especially for more modern fuel injection pumps.
This is the kind of top engineering tech info that you sometimes get on HN, but much more often in the field of software than the less-abstract types of projects being built.
I like to build laboratories that use research instruments and techniques to get engineers and traders the results they need.
I've seen a few misconceptions with more discussion of the oil crisis appearing lately and figured I would add something sooner or later myself.
Anyway I was the early adopter of digital densitometry all those decades ago, and this is one of those rare times when you see API it has nothing to do with software, it means the American Petroleum Institute :)
But turns out their gravity scale is far more abstract than most people imagine.
>We use this unit of measure because it magnifies the differences in densities vs. using conventional units of measure.
Exactly. I've had research people stumble over this.
Well for oils & fuels going in & out of the refinery, they naturally can be quite consistent but always have significant variations in density with each batch and this is normal. API gravity is an excellent measure of density for this reason above all, it depends completely on density (not viscosity at all [0]) and you want these everyday minor differences (in the same feedstock or product stream) to have their numerical density reading show more easily-noticeable meaningful variation than you get from plain kg/m3 or specific gravity numbers. Plus actually end up with two significant figures being adequate most of the time in the real world, and more memorable across a wider range compared to 3 or 4 figures using conventional units.
Now how did the API gravity number end up getting bigger when the density is less? What's up with that?
It's a physical workflow thing. Density of liquids has been measured using simple glass hydrometers since like forever. Same kind used by beermakers to estimate alcohol content based on density, using hydrometers calibrated against liquids having known specific gravity.
IOW, the lighter the density, the deeper the hydrometer sinks, then you take a reading from the unsubmerged portion of the stem. If the scale is calibrated in density or specific gravity, you read increasing numbers starting from the top of the calibrated glass stem. For oils & fuels you also need to know the temperature that the gravity reading was recorded at, so there's also a thermometer in the test sample along with the hydrometer. And people always read a thermometer from bottom-to-top as they count the little graduations in between numbered major divisions. "Everybody knows" the biggest numbers are at the top of the glassware, without any training. But as mentioned, you read a specific gravity hydrometer from top-to-bottom, where the smallest marked numbers are at the top of the glassware. Plus major divisions are fewer and further between than a thermometer. Ruh-roh. For busy people it's too easy to take both readings from bottom-to-top and get wildly or subtly incorrect results. But that's how you are supposed to read (the exact same glasssware) when calibrated using the API scale, which is mathematically inverted and expanded.
So you get °API where 10.0 is the gravity of water, and 100 is less density than you normally get without it being a pressurized product like LPG. 100 is not the limit, and negative °API is also meaningful but anything below 10 and it's usually the kind of tar or asphalt that sinks even in fresh water.
But that's not abstract enough yet. "Specific" gravity however, is basically a unitless number since it is always relative to something else, usually water. Which you are supposed to specify whether the reference material is water or not but it's so seldom documented that the only professional approach is to assume so without question. Provided that's as decent an assumption as it usually is, then for hydrocarbons the recorded specific gravity is supposed to also specify what temperatures both the test material and reference material values were obtained at. This qualification is not nearly as documented as often as it should be, then you pretty much have to assume it's 60 Fahrenheit for oils & fuels plus the reference water too. Looks like being unitless is supposed to carry a lot more metadata that it doesn't always show up with. Oh well. In petroleum it's still pretty strict about 60 F though, but the 15 C crowd has been on the rise for decades, from what I can tell it's because there is no metric integer equal to 60 F :\
The cool thing about specific gravity being unitless is that (considering temperature) you can use any accurate units of measure for weight and volume when taking raw density readings in the field. Grams, pounds, stones, liters, gallons, etc in any combination of weight per volume. Just has to be consistent between the test sample and reference material. So everything cancels and you get the same numerical rating from anywhere in the world at any time over the centuries. Once grams came along, and were standardized equal to one mL of water (under conditions!!) then it just so happens that specific gravity closely resembles the numerical density when the density is expressed in units of grams/mL. In these nearly-ideal metric units though the deceptively similar values are still significantly different from true specific gravity, and the differences often completely neglected along with the buoyancy of air. Which can have obvious significance if you're talking about a ship as big as a blimp.
So the density that the product actually behaves with in the real world, is imagined as if it were handled in a vacuum instead, while being held at some ideal well-known temperature, then converted to a unitless number, before being inverted and scaled to numerically better match the application.
Making the °API "almost like a bogus phenomenon", while still being based strictly on density, rather than °API being as much of a physical property itself.
But it works so much better than the real numbers the physical property is measured in, and the hydrometer does the same thing either way :)
Any more abstraction and the workflow could have gotten worse not better, you've got to stop as soon as you can or you could end up with no trail leading back to the underlying solution needed ;)
With digital densitometry you're not supposed to still need a plain old glass hydrometer, and naturally it's not so simple :0 Don't get me started on that ;)
[0] Although someone familiar with a particular oil field may accomplish some pretty good estimation of API gravity as a result of long term correlation between apparent visual thickness and measured density over the years.
The most commonly used process creates a mixture of steam, hydrogen and CO2. The water is condensed and the CO2 removed to purify the hydrogen product. The CO2 is a concentrated stream. This is sometimes captured and sold as a byproduct (eg food grade CO2 for beverages or dry ice).
Here is a commercial example of underground hydrogen storage that has been in service since 2007. It is a salt cavern in Texas. It is part of extensive hydrogen infrastructure connecting many industrial users (600 miles of pipeline)
For example crude oil is produced mid state in the San Joaquin valley and pumped by pipeline to the Bay Area and LA refineries.
Refined product from LA is delivered by pipeline from LA refineries as far east as Phoenix and up to Las Vegas.
Building new pipelines in California though is…challenging.
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