100 Most asked questions by Chemical Engineers

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Wednesday, April 29, 2020

Wednesday, April 15, 2020

Video #2 - Measuring Draft

During this time of safe distancing, I'm providing you a series of short seminars. Please take a moment to view the video "Adjusting PumpAround Duty" by clicking on or copying and pasting into your web browser my YouTube or LinkedIn links below.

I will be happy to answer any questions you may have. You can reach me at:

1+ (504) 887-7714

Sunday, April 12, 2020

Adjusting PumpAround Duty

During this time of safe distancing, I'm providing you a series of short seminars. Please take a moment to view the video "Adjusting PumpAround Duty" by clicking on or copying and pasting into your web browser my YouTube or LinkedIn links below.

Saturday, May 4, 2019

Refinery Safety Failures – Attitude or Engineering?

IN 1976, I was the supervisor of the world’s largest alkylation unit. My plant, No. 2 alky in Texas City, had a capacity of 26,000 bbl/d. In mid-June, an explosion that originated on my unit, badly damaged both No. 2 alky and No. 3 FCU (the world’s’ largest, 120,000 bbl/d fluid catalytic cracking Unit). Fortunately, no-one was hurt. Given the argument that we all are obliged to share our safety-related experiences, 42 years on, let me describe what caused this costly incident, and how proper design could have prevented this explosion.

Safety – attitude or engineering

There is a misconception in the process and refining industry that the key to safety is:
  • awareness
  • alertness
  • attitude
Safety meetings often do not deal with actual safety issues on refinery units. Everyone I have ever met in a refinery wants the facility to operate without death and disaster. But only too often, this desire is frustrated by engineering design errors. The 1976 propane explosion at the Amoco Refinery in Texas City, US is an illustration of a failure in applied technology.

Sulfuric acid alkylation

The Stratco Alkylation process (licensed by DuPont) was developed during World War II by CW Stratford and Ward Graham. Butylene and isobutane are reacted to make iso-octane at a temperature of about 10°C. The exothermic heat of reaction is removed by an effluent refrigeration loop with a typical composition of:
  • 80% Isobutane
  • 10% normal butane
  • 10% propane
The propane is continuously purged from the circulating refrigerant in a depropaniser tower. The overhead propane product from this tower contains an acid ester – a hydrocarbon molecule combined with a sulfur trioxide group (SO3). This acid ester is entirely non-corrosive as long as it is water free or dry. But, if it accidentally gets wet, then the acid ester will dissociate into hydrocarbon and weak sulfuric acid. Strong sulfuric acid (90%+) is not corrosive to carbon steel. Weak sulfuric acid (10–20%) is tremendously corrosive to carbon steel piping. I have personally seen weak acid eat through welds of 6” piping over a weekend.

Wet vs dry

According to my Alky mentor, Ward Graham (who passed away in 1980), corrosion in an alkylation unit depropaniser may be entirely suppressed if the depropaniser feed is kept dry (free of both dissolved and entrained water). During normal operations, this would be the case – except on startup of the depropaniser. 
I was in charge of the operation of No. 2 Alky from April 1974 through mid-1976. During this period, the alkylation reaction section was operated without interruption. After all, we produced 0.6% of the total gasoline consumed in the US. But, the unit’s depropanizer was shut down on several occasions to fix tube leaks in the water-cooled overhead condensers. To operate without the depropaniser for a few days was not a problem. Propane accumulated in the circulating isobutane refrigerant stream. After a few days, we could then vent off non-condensables from the refrigerant accumulator drum to fuel gas. The vent gas had 50% butane, as compared to 2% butane in the depropaniser overhead LPG product. So, isobutane consumption was high while the depropaniser was out of service. But, that was the normal operating procedure followed while the depropaniser was off-line for condenser tube repairs. However, on re-commissioning the depropaniser, this practice had the potential to introduce corrosive moisture into the tower.

Depropaniser startup procedure

A leaking tube in the depropaniser overhead water-cooled condensers could not introduce water into the tower. The depropaniser operated at 20 bar. Cooling water pressure was 2 bar. The problem of moisture introduction into the tower occurred after we shut the tower down to repair or replace the leaking tube bundle in the overhead condenser. Moisture could then be introduced into the depropaniser in a variety of ways:
  1. The tower was steamed-out to hydrocarbon free it prior to blinding-off (ie, “spading”) the shell side of the condenser; 
  2. The tower was depressured below the circulating cooling water supply pressure; or 
  1. When the tower was re-streamed, wet field butanes (which contained about 2–5% propane) was used to start-up the tower to establish a reflux flow at normal 300 psig (20 BAR) operating pressure.

A design error

The Alky Unit had not been designed to start-up the depropaniser separately, while the rest of the unit was in operation. As it was possible to operate the unit without the depropaniser running, this should have been considered during the design phase of the project. As a consequence of this omission, in practice, refrigerant isobutane, that contained acid esters, was introduced into the depropaniser while the tower’s reflux was saturated with water. The acidic water circulated with the reflux. A rapid rate of corrosion, due to weak sulfuric acid, caused the 4” elbow on the suction of the reflux pump to fail. I climbed up to inspect the elbow a week after the failure. It looked like an evil person had taken a can opener, and peeled back the elbow, which was no thicker than a lid on a soup can.
The entire contents of the 4’-0” ID x 15’-0” T-T reflux drum had emptied. A huge white cloud of LGP vapours drifted across No. 2 alky, over to the No. 3 FCU. The cloud ignited off of the CO boiler on the FCU and detonated, blowing in the roof of the FCU control room. The shift foreman had everyone take cover beneath desks and tables, and thankfully, no one was injured. However, the entire East Plant of the world’s largest refinery was shut down for several months.

Corrective design change

After this incident, the unit was retrofitted with a caustic wash (10% NaOH) upstream of the depropaniser, to remove all traces of acid esters from the tower’s feed. This, I believe was a correct decision by the Amoco management. However, in the interval before the new caustic wash was installed, I instituted an alternate mode of operations. That was:
  • Step 1 – steam-out tower prior to start-up.
  • Step 2 – bring in mixed butane feed for a few hours to establish a reflux drum level and reflux flow using the tower reboiler to vaporize the reflux.
  • Step 3 – stop bringing in all the wet feed and run only on total reflux for X-hours.
By X-hours, I mean until I personally checked to see that the water draw-off boot on the depropaniser reflux drum was utterly free of water. Then, I would wait another shift, before allowing the acidic isobutane refrigerant recycle to be reintroduced to the alky depropaniser.


The original design error assumed that someone would use a significant degree of engineering insight to realise that the depropaniser must be completely dehydrated before the refrigerant recycle was reintroduced back into the tower. That, I believe, was an unreasonable expectation. Especially, since this requirement  was never specified in the unit’s original operating instructions.
The management decision to install the 10% caustic wash on the depropaniser feed, which I did not consider necessary at that time, (because with proper operation, the depropaniser on startup would preclude corrosive moisture) was, I now believe in retrospect, the correct engineering decision.    
As long as the alkylation unit was operated in a normal, steady state mode of operation, the depropaniser would remain in a dry, and hence a non-corrosive state. However, there were in practice, a number of circumstances that could inadvertently introduce moisture into the tower. The caustic wash was a relatively inexpensive option to enhance the unit safety by extracting acid esters from the depropaniser feed.
My own attitude towards safe plant design was greatly influenced by this incident. I now try to include provisions in my process design work for safe shutdowns, startups, and response to upsets and equipment failures. Especially if water can mix with acidic components.
The lesson to be learned from this incident is that process operations of refinery units are inherently hazardous. That just because correct operating instructions, to avoid a dangerous situation exist on paper, does not preclude the potential hazard. The use of a caustic wash on the feed to the depropaniser tower would have added to the intrinsic safety of the Alkylation Unit.
After reading this article, ask yourself this question: "Is my unit intrinsically safe, or am I relying on my field operators to always exercise good judgement, and invariably follow written procedures?"

Sunday, September 23, 2018

Norm Lieberman Receives Lifetime Achievement Award from Hydrocarbon Processing


Norman Lieberman accepts 'Lifetime Achievement' Award at the 2018 HP Awards

August 30, 2018, HOUSTON-Nearly 150 of the midstream and downstream oil and gas industry's brightest minds gathered Thursday to find out, and celebrate, the winners of the 2018 HP Awards. The awards ceremony seeks to recognize and honor the midstream and downstream processing industry's top innovations and innovators.
Honorees took home awards in 12 categories-10 encompassing the latest technological advances in the hydrocarbon processing industry and two people awards - fr om the gala event in Houston, Texas. These innovations are enabling refinery, petrochemical and gas processing/LNG operators to optimize their operations.
In this year's 'Lifetime Achievement' category, Norman Lieberman was awarded for his lifetime work in the downstream processing industry. Mr. Lieberman began his career in 1965 with Amoco Oil, where he designed the first complex fractionator using a computer simulation. He has authored more than 100 articles, as well as 11 technical engineering books that are focused on solving processing problems. His continuing education courses on troubleshooting process operations have been attended by more than 18,000 engineers and technicians since 1983. Mr. Lieberman specializes in the retrofit design of crude units, FCU fractionators, delayed cokers, sulfuric acid and alkylation plants, and sulfur recovery units.
The 2018 HP Awards were generously sponsored by: AspenTech, Eni, Fluor and KBR.

Hydrocarbon Processing, the leading oil and gas trade journal for the hydrocarbon processing industry, has a worldwide circulation of more than 30,000 subscribers. Gulf Energy Information has published Hydrocarbon Processing for more than 96 years. Additional information on the HP Awards program can be found at www.HydrocarbonProcessing.com/Awards.                                                                                              ·

Press Contact:
Melissa Smith
Events Director, Downstream Gulf Energy Information

Sunday, March 26, 2017

Oil & Gas Journal: “Beyond Back-to-Basics: Process Principles & Concepts.”

Wednesday, October 28, 2015


Amine Circulation

Mr. Lieberman, which is a better amine – MEA, DEA, or MDEA – for use in a refinery?


MEA, without good reclaimer operation, in a plant with an FCU, is going to promote H2 assisted stress corrosion cracking. MDEA is used in concentrations of 45%, and hence tends to foam. In practice, I have found using 30 – 35 wt.% DEA is optimum – but occasional reclaiming to reduce heat stable salt accumulation is still required. If you have a sulfur plant tail gas scrubber, then a selective solvent, that rejects CO2 absorption, such as MDEA may be necessary.

Monday, October 26, 2015


Sulfuric Acid Alky

Our alky unit refrigeration compressor is limited by low suction pressure. The suction pressure gets down to one psig or less, but contactor temperature is 60°F or more. So, we slow down the compressor (turbine driver), to bring up the suction pressure, but then the contactors get hotter still. Any suggestions would be appreciated.


May I suggest you reduce your depropanizer bottoms temperature by 5°F. This will allow propane to build in your refrigerant recyle and raise compressor suction pressure, but without raising contactor temperature. You need to make moves on the depropanizer bottoms temperature slowly, as it will take several hours for the refrigerant recycle propane content to respond. Note, that if your compressor discharge pressure is at max, this will not work.



On our FCU wet gas compressor, we have an orifice plate that operates from 0” to 100” of water DP. The flow is typically high. The meter reads full scale – at an orifice plate DP of 95” H2O, or 3½ psi pressure drop. As the compressor suction pressure is only 3 psig, it seems to me that we are wasting a lot of compressor capacity on that orifice plate. What do you suggest? Also, high compressor suction pressure backs air out of the regenerator.


Eliminate the orifice plate. Use the vapor outlet nozzles of the upstream K.O. drum, as a restriction orifice. Measure the DP between the drum and the compressor suction. You can back-calculate the “orifice” coefficient based on the unit material balance. I’ll show you how to do this, if you send me the operating data. Looks like you can increase compressor capacity by about 10%, with zero investment cost.

Wednesday, October 7, 2015


Delayed Coker

My coker fractionation tower top pressure surges higher by 5 psi for a few hours. Tower top temperature jumps by 20°F - 40°F. The level in light gas oil pan drops. This occurs every few days. What’s happening?


You’re salting-up the top few trays. The top reflux can’t cool off the upper trays. They get hot, and sublime off the salts. A simple way to prevent the problem, is to periodically heat up the top of the tower, maybe for 30 minutes by 30°F, every few days. I’m not too sure about time and temperature factors. Periodic water washing is also possible, but a lot more complicated.


Vacuum Tower

In a vacuum tower, what parts of tower internals need to be designed for a large up-lift force, to prevent damage?


Only the over-flash chimney tray, if the chimneys are designed for a 0.5 – 1.0 mm Hg DP.



When I increased crude tower bottom stripping steam from 1,200 to 2,500 lbs/hr, I increased diesel yield by 1,000 BSD at the expense of LVGO. Vacuum, in the vacuum tower, improved from 25 to 18 mm Hg. Yet, vacuum resid yield failed to improve. Why not?

Reduction in vaporization of diesel in flash zone of vacuum tower, off-set reduction in pressure:

·       % vaporized prop. to  (V/1 • 1/P)