Bye Bye Tamoil Refining

Hmmmm,

It seems that I am writing about nothing but refinery closures and even that in the past tense. Anyway, here's what I think is the real truth about what happened with the Tamoil Switzerland organisation that "required" them to close the Collombey (Valais) Refinery this year (2015).

This is all hearsay, and in any case, is almost too stupid to believe it is real, but here goes.

The story is, that the Tamoil marketing group got super-enthralled with their trading successes in writing spot deals (that means individual sales that are not related in price or conditions to any other sales or purchase committments) in 2012 and 2013. The result was the thinking that "when a little bit is good, more has to be better!" So they went to the extreme in 2014 and decided to sell all their products from the refinery in Collombey on a spot basis. This is probably okay when there is a market stabilising effect from other term sales contracts in the area - like from other refineries. But there are no other operating refineries in Switzerland, and moving product from outside Switzerland to inside or vice versa is difficult and expensive - it requires either rail or barge transport for large volumes and truck transport for smaller volumes plus small imports (only) from southern France on the pipeline that feeds to Geneva. This is not a large enough traffic pattern to stabilise the Swiss market.

What happened then? Well, the Swiss marketers (we are not talking about Tamoil here, let's call them the "Traders") are isolated but they still are not stupid. They started timing their purchases - all spot sales now, so at current prices as negotiated right then - for when the Tamoil refinery tanks were full to over-flowing. What happens then? Well, Tamoil has the choice of (1) selling product to buyers outside Switzerland (at a low net price because of transportation costs) or (2) reducing refinery throughput and make less product (also expensive because the fixed costs of running the refinery are a major factor and the minimum turndown for the refinery is probably around 60-65 percent of full capacity - it is expensive to run a refinery at low throughput rates, but it is even more expensive to shut it down) or (3) reduce the product prices until somebody buys the products. Guess which choice Tamoil made? I don't know, but as far as I can see, probably a combination of options 2 and 3. If this happens once or twice a year, it is not a big deal, but when it happens continuously all year long, it means MAJOR losses for the organisation as a whole. Marketing loses money (big time!), refining loses money because it is forced to run a low rates and even shut down some equipment, and even crude purchasing loses money because they probably made annual contracts for specific volumes of crude oil, and when they cannot absorb all that crude oil, they will either have to sell it (probably at a loss since it is "distress" crude that is not planned for sale) or pay a penalty to the crude supplier.

All of this means that a company that was making money before, now is losing large amounts of money under essentially the same market conditions as it made money in the years before.

What ways does Tamoil have out of this situation? That depends on whether they recognise what the problem was to start with.

My recomendation would have been - at the appropriate time - to fill the product tanks, shut down the refinery for at least two months, DO NOT SELL TO THE TRADERS, and buy excess supplies from outside the country as necessary. That would be painful for Tamoil, but the Swiss Traders will suffer even more than Tamoil because Tamoil will still have the cushion of their own supplies in storage. After 6 weeks or so of having to buy all their product from outside Switzerland, the Swiss Traders will be ready to make a deal that will save their own bacon. To add a little insult to the injury, Tamoil could also make an announcement that the shutdown is being made to reduce the capacity of the refinery to fit the Tamoil captive sales quantities - this announcement to be made at the time of the shutdown.

I think the Traders would have caved in and made arrangements for term deals in the following year, and maybe even starting in advance of the new year. When the first one caves in, the rest will follow quickly.

That's what I think. Now, what did Tamoil do?

Tamoil waited as long as they could, and then shut down the refinery and announced that it was for sale. All the refinery people were laid off and the refinery was (I think) slowly mothballed for long term storage.

Since then, there have been rumours of up to about eight different interested parties to buy the refinery. None of the bidders has been accepted and the Canton is now looking at requiring Tamoil to clean up all the spills and contaminations on the refinery site. THIS is a MAJOR project and there will be some serious negotiating about whether the refinery is still operating if it is being used as a terminal. Tamoil is on weak ground here since the main refinery rail and truck loading takes place on the other side of the Rhone River in Canton Vaud.

Now, if you were in charge of Tamoil, what would you do to the management team that so poorly managed the whole situation? Fire the whole team, right? So would I. What has happened? Not one person has been fired - all the responsible idiots are still pushing their desks!

Like I said at the beginning, "Hmmmm"

Post Mortem PetroPlus

Now it has been a full half year since the last time I wrote about PetroPlus. In the mean time, various pieces of the "empire" have been sold off, the Swiss refinery has been leased for 6 months, etc.

For me, the whole thing was a planned gimmick - a way that the PetroPlus management could get out of a bind (a company that did not have a chance of surviving the next 6 months, not to mention the next 6 years). They managed to duck the personnel bullet in every location, the environmentla headaches, and most if not all of the other social and legal responsibilities as well.

Even to the apparent theft in the main office in Zug - theoretically and curiously, only the board room furniture was stolen, but I strongly suspect that some incriminating documents disappeared at the same time, and that "theft" was never reported.

I don't know what has happened to all the executives involved in the debacle, but I suspect that they all came out "smelling like a rose." I seriously doubt that a single one of them was or will be called to stand for the responsibility that is supposed to go with corporate governance.

Shame on you people. You have made a mockery of the entire idea of clean business practices.

More About PetroPlus

It has been more than a month now since the banks pulled the plug on PetroPlus' credit line for crude oil purchases. During that time there has been a lot of hype about outside investors, mysterious bank connections providing more money, sales of refineries, permanent shutdowns of refineries, etc.

The apparent truth, to date, is that PetroPlus got some credit from one bank or another that allowed PetroPlus to keep the Coryton (UK) and Ingolstadt (Germany) refineries on line.

Recently there have been some articles in the Swiss newspapers that indicate that PetroPlus was never run by refinery people, but by investors and financial people with the idea of putting a "refining conglomerate" together and then flipping it to the highest (or maybe first) bidder. Sorry - "flipping" comes out of the Internet website business, it means selling a newly-made website quickly to earn some money - also quickly. In other words, to make a "quick buck."

Other articles are saying that the PetroPlus business model - trying to use the leverage of a refiner to be able to make use of arbitarage between crude oil and product prices - was a flop in the USA, and the continuing situation of excess and expensive refinery capacity in Europe was the final kiss of death for Petro Plus.

In any case, whatever the intentions were, the business model has proven itself to be a financial flop - for example, 11 losing quarters out of the last 12. Now, a consulting company is running the Coryton Refinery under the instructions of a British judge, and the Ingolstadt Refinery is running at about 50% of capacity using ??? for money. One has to wonder if this last stage in the process has not been a ruse to allow PetroPlus to close the unprofitable Antwerp (Belgium), Petite Couronne (France), and Cressier (Switzerland) refineries plus other lower level facilities (terminals) without having to pay up for the closure costs: personnel layoffs, ante up for the personnel pension funds, environmental cleanup costs, company closures, etc., not to mention avoiding much of the loan repayments due. It could be the icing on the cake for creating a "Petro Minus 3" with only two reasonably profitable refineries and minimum remaining debts.

What do you think? I would like to hear from you!

What Will Happen To PetroPlus?

If you have been following the financial news in Europe, you may have seen some articles about PetroPlus recently. PetroPlus is the largest independent petroleum refining company in Europe, and their refining capacity is around 4.5% of the total European refining capacity. The refineries are located in the UK, Belgium, Germany, France, and Switzerland.

The reason that PetroPlus has been in the news is that their consortium of banks that was financing the purchase of crude oil for PetroPlus's 5 refineries froze the revolving credit line about ten days ago. In effect, that is like freezing your credit card when you are on a business trip and didn't take much cash with you. If that happened to you, your trip would stop, and that is about the same as what is going to happen to PetroPlus's refineries in the coming week.

Why did the banks do that to PetroPlus? The answers are not very clear, but the basic reason (my guess) is that the European banks are scared to death of what is coming with the financial crisis in Europe. It is so bad, that the banks don't even trust each other, and would rather park their excess money in the European equivalent of the Federal Reserve Bank than trust it with another bank!

A second reason is that the European refining industry is suffering from over-capacity as the result of the economic slowdown that has been taking place over the past two years. The refineries that are owned by a company that also owns its own crude oil supplies can afford to continue on at close to maximum throughput - which is the most effcient operating mode for virtually every refinery. The excess products are sold by the umbrella company on the market, and this puts price pressure on the other refineries - like PetroPlus.

PetroPlus's refineries apparently have been operating at roughly 75-80 percent of capacity - and that has put the refineries in a perilous financial position. Proof of the pudding: PetroPlus has made operating losses for the past 8 quarters.

The question now is, how will PetroPlus come out of their own private financial crisis? There is some pressure being applied by the refinery labour unions to the governments in various countries. The idea is to force the banks to loosen up with the money so that something around 3000 people plus at least as many dependent employees in the support areas do not lose their jobs.

What other options does PetroPlus have?

• They could search for processing arrangements so that the crude oil and the products do not belong to PetroPlus, and thus the need for the revolving credit disappears. This will not happen immediately - most companies that want processing deals have them already, at least for 2012.
• They could try to sell the refineries, but this is already a buyer's market, and PetroPlus's refineries are not the most attractive in Europe
• They could just bite the bullet and shut down the entire operation, maybe retaining a few locations as terminals, and scale the company down to about 5-10% of what it is today. Scrapping the refineries will be an expensive procedure, since every refinery has its share of environmental problems that will have to be resolved - at a price.
• They might try to sell the refineries one-by-one to non-European crude oil producers so that the producers could process their own crude oil in Europe. This is not very attractive, because refining in Europe is expensive, but someone might bite on the option.
• The last option is to declare bankruptcy and let somebody else sort out the problems.

Not a very encouraging picture, is it? I suspect that the actual resolution will end up being a little bit of everything mentioned above. The refineries are in separate companies, so each one can be handled independently. The German refinery is the best candidate to continue operations, due to configuration (it has conversion capacity) and location (Bavaria). The least promising is probably the French refinery, which has a large number of employees and is the oldest and technically the least sophisticated of the group. The UK refinery is facing a major turnaround (technical overhaul) in 2012, and this will be a big negative for either continued operations or a sales effort.

What will happen? Your guess is as good as mine! In any case, I wish all the colleagues at PetroPlus all the best for 2012, whatever that turns out to be!

Refinery Process Design

Recently, I received a question from a practicing chemical engineer. It was interesting, because it focused on one of the basic decisions involved in a new refinery: "What is the best oil refining process pattern if we want to produce a maximum amount of gasoline when refining a heavy crude oil." We all know that crude distillation is the first major process step that happens when crude is introduced into the refining process, but how do you decide what comes next?

The various licensing companies (UOP, IFP, Exxon Research, etc.) as well as most of the engineering and construction companies and many engineering consultants all have their own ideas, which (naturally) feature their own processing strengths and prejudices, and tend to ignore their weaknesses. All of them also have one or more computer programs that are supposed to determine the optimum refinery configuration for a given crude oil of combination or crude oils. They are even (supposedly) set to give the optimum return on investment using built-in investment costs that usually reflect the most recent projects attempted.

What you can do with the crude naturally depends upon what sort of crude you have. Responding to the question above, I assumed that it is not only heavy, but also contains a medium amount of sulphur (2-3%) and middle- to high-level of metals (particularly nickel and vanadium), and not an excessive level of organic nitrogen. In other words, nothing very exotic.

Gasoline Refinery

A more-or-less traditional flow scheme from the USA (which is where the gasoline refinery concept was born) for a medium to large gasoline refinery is shown below. This ignores the modifications necessary today to produce specialised gasoline.

Atmospheric distillation block

• Atmospheric distillation


• Full range naphtha HT => splitter => heavy naphtha to catalytic reforming and light naphtha directly or via C5/C6 isomerisation to gasoline


• Light distillate (kerosene) HT à burning kerosene and/or jet fuel


• Mid-distillate (gasoil) HT à Diesel fuel and light heating oil

Vacuum distillation block

• Vacuum distillation


• Delayed coker (a large one, so that essentially no vacuum residue remains)

Conversion block

• FCCU – feeding medium VGO and heavy VGO with a feed hydrotreater to reduce the sulphur and nitrogen contents


• The C3/C4 streams go to alkylation, catalytic polymerisation, and MTBE (except in places where MTBE is not allowed in gasoline)


• An AGO/LVGO hydrocracker (depends on the needs of the gasoline pool and the cost of hydrogen production) as a combined FCCU feed HT and a gasoline component producer (the economics should decide whether this is necessary or not)

Hydrogen production

• There will be a large volume of refinery gas and C3-C4's coming from the cracking units; these can be used for hydrogen production (steam-HC reforming), perhaps balancing gasoline component production against hydrogen requirements
  Another option, if there is not enough light material after fuel and LPG product needs for steam-HC reforming, is a partial oxidation unit, using vacuum residue as the feedstock (this is effective but capital-intensive) instead of or in addition to the steam-HC reformer, and partially replacing the coker

Other process and utility units

• Steam production for various usages, including utility, process, and power generation


• Sulphur recovery – there will be large amounts of sulphur, produced as H2S, that will have to be converted to sulphur for safe handling


• Coke handling – if the refinery coke is not burned in the power plant, it will need to be handled for export from the refinery – one option is to calcine the coke to make it a more valuable product

What you will note above is that virtually all products are hydrotreated at some stage of the process. This is to make the distillate fuels (gasoline, kerosene for jet or burning fuel, gasoil for heating oil and Diesel fuel) compatible with today's worldwide low sulphur environmental requirements. The product slate should be roughly 55-65% gasoline by weight, 25-15% light distillates by weight, with the remaining ±20% going to coke, sulphur, maybe propane/butane, and own consumption (including catalytic coke produced and consumed in the FCCU). The volume yield of gasoline can be almost 100% on crude, depending on specifications and the degree of cracking utilised.

If the refinery is to be a (relatively) small one, then the best solution may be to build the entire atmospheric distillation train, but only the vacuum distillation, the delayed coker, and the hydrocracker in the vacuum distillation train as a high-conversion unit (primarily gasoline components), and leave out the FCCU and its downstream units. The hydrogen production facilities will still be necessary unless H2 is available from outside the refinery. In the future, if the refinery is expanded, an FCCU plus its downstream units can be added, and the hydrocracker can be converted to an FCC feed pretreater with lower conversion (50-60 %) but with a much greater throughput (1,5 –2 times original).

Distillate fuel refinery
But what to do if you want mostly distillate fuels instead of gasoline? Well, this is the "European solution" as opposed to the "American solution" for gasoline above. Typically, the distillate solution (high cetane number Diesel fuel, light heating oil, kerosene for household fuel and aviation turbine fuel) uses different choices of conversion equipment, in order to provide more middle distillates and less gasoline.


The earlier solution (1960's) was to use low severity FCC units, which produced more than 50% light cycle oil instead of a large volume of gasoline. Today, the light cycle oil is a problem because of it's aromatic and sulphur contents, not to mention stability.
The more current solution is a hydrocracker using (typically) one conversion stage to produce large amounts of desulphurised, low aromatic distillates (kerosene and Diesel fuel). Depending on catalyst type and feedstocks, the volumetric yield of distillates can be over 100%. Conversion of the vacuum residue to hydrogen and energy (steam and/or electricity) may take on a more important aspect, since the large hydrocracking process requires a lot of hydrogen. However, the steam reforming straight run naphtha to hydrogen is another H2 source, if gasoline is really unimportant. The refinery is somewhat less complicated than a gasoline refinery of the same size. The blocks below give an idea of what might be used in a distillate fuels refinery. The common components that remain more or less unchanged are shown in bold print.

Atmospheric distillation block

• Atmospheric distillation


• Medium + light naphtha HT à medium range naphtha to catalytic reforming and light naphtha directly or via C5/C6 isomerisation to gasoline


• Heavy naphtha / light distillate (kerosene) HT à burning kerosene and/or jet fuel


• Mid-distillate (gasoil) HT à Diesel fuel and light heating oil

Vacuum distillation block

• Vacuum distillation


• Delayed coker (a large one, so that essentially no vacuum residue remains)

Conversion block

• AGO/VGO hydrocracker optimised for distillate production


• HC medium naphtha to catalytic reforming (hydrogen production and gasoline octane), HC light naphtha to gasoline blending, naphtha sales, or H2 feedstock

Hydrogen production

• There will be a respectable volume of refinery gas and C3-C4's coming from the cracking units; these can be used for hydrogen production (steam-HC reforming), perhaps balancing LPG component production against hydrogen requirements
  Another option, if there is not enough light material for steam-HC reforming, is a partial oxidation unit, using vacuum residue as the feedstock (this is effective but capital-intensive) instead of or in addition to the steam-HC reformer, and partially replacing the coker

Other process and utility units (sizes may be different, but functions are essentially identical)

• Steam production for various usages, including utility, process, and power generation


• Sulphur recovery – there will be large amounts of sulphur, produced as H2S, that will have to be converted to sulphur for safe handling


• Coke handling – if the refinery coke is not burned in the power plant, it will need to be handled for transport – one option is to calcine the coke to make it a more valuable product

LPG Refinery
There is a third type variant, although it is relatively rare, and that is the LPG refinery. The objective of the LPG refinery is to optimise the production of propane and butanes in order to satisfy local market needs for LPG as fuel and as petrochemical feedstocks. Usually, these refineries are based on light crudes or condensates as a starting point, since there is a large potential for wasted energy when converting heavy oils to LPG.
The special process unit configurations that can be used here are

• hydrocracking units that are optimised for LPG production,


• catalytic reformers that run in what normally would be a stable but overchlorided catalyst condition (excessive hydrocracking), and


• FCC units trimmed for maximum LPG production (with ZSM-5 cracking additive).

Naturally, in every case, there will be a number of options to consider before the refinery's final process design is set, and special solutions for unusual problems or local conditions are the rule, rather than the exception, in refinery basic process flow design.

The selection of the optimum process flow scheme generally takes place by making runs with a refinery economics model. The objective of the model is to product the optimum profit, taking into consideration the base feedstock (crude), additional feedstocks, the product requirements, and the prices for feedstocks, products, and utilities. The first runs are with most, if not all of the process units in the model "open", i.e. the economic model is allowed to optimise without considering which of the process units will be built. This will probably give a refinery with a large number of process units, some of which will be uneconomically small from an operating point of view. Later, the least attractive processes will be eliminated, and the capital cost will be factored into the calculation (this may have already been done in the first step). Finally, other considerations (site requirements and limitations, transport considerations for feedstocks and products, transport considerations for refinery equipment delivery to the refinery, market limitations, process complexity, licensing considerations, political considerations, etc.) will finalise the refinery process design.

This should give you an overview of the process that is termed "refinery process design". Flexibility and an open mind are necessary in order to come up with a refinery configuration that fits all needs.

Questions are welcome!