| American Fuel & Petrochemical Manufacturers

Question 62: What criteria are used to evaluate the performance of crude pre-heat train exchangers to support a decision to clean any portion?

It is essential to keep crude pre-heat exchangers clean. Cleaning benefits are hard to justify if they negatively affect crude rate. The criteria we use are crude hydraulic throughput, heater firing limits, fuel gas savings, desalter temperature efficiency, or crude or vacuum tower heat balance if you have needs in that area to remove heat.

Question 61: What are some of the potential strategies to mitigate iron carryover from the desalter?

High iron content on desalted crude manifests itself in two main areas. These are inability to make anode-grade coke and as a FCC catalyst poison. The iron can be in many forms. Three of the most common forms of iron we see are iron oxide, which is rust; iron sulfide, which is corrosion; and, siderite, which is essentially crystalline iron carbonate that we are seeing more and more of in certain tight oils.

Question 60: What has been done to address corrosion problems either inside your desalter or in the brine handling circuit?

Some refiners have used acids in the desalter washwater as a means to assist in emulsion resolution. We always look for other solutions as this practice may present other challenges including operator exposure, corrosion to the desalter internals/water circuit, and additional acid load to the atmospheric tower.

Question 59: How does improper control of desalter washwater and brine affect crude unit overhead pH?

Guidelines around the addition of desalter washwater were historically 3 to 5% on volume based on crude charge. Some years back, with a shift towards heavy Venezuelan and unconventional crudes, the trend pushed up towards the 7 to 10% range or higher.

Question 58: What issues are experienced at the desalter and pre-heat train when recirculating brine at the desalter?

Before answering this question, I want to clarify that the panel has defined ‘recirculating brine’ as brine going back to the freshwater makeup.

Question 57: What problems are associated with processing crude with high solids content? What steps can be taken to reduce or remove these solids from the crude?

High solids crude processing presents some increasing challenges for refineries running conventional crudes, tight oil crudes, and heavy Canadian bitumens. As you can see in the graph, some of the heavy Canadian solids run as high as 300 ptb (pounds per 1000 barrels).

Question 56: With the current domestic conventional and unconventional crudes available, what incompatibility issues are observed from the tank farm through the crude unit? What mechanical, operational, and chemical strategies are employed to minimize these impacts?

Incompatibility issues are mostly observed in the desalter and downstream pre-heat train and heater as the asphaltenes precipitate and cause stabilized emulsions. Some of our observations include salted crude carryover from the desalter. The water and contaminants exit the desalter and foul all of your downstream pre-heat exchangers and heaters.

Question 55: In a recent turnaround, we successfully de-gassed and de-greased our crude tower but discovered residual mercury. What techniques have been used to mitigate this issue?

We recommend pre-turnaround development of a PPE matrix that can be used during the turnaround which outlines the PPE required should you discover mercury during the outage.

Question 54: Please comment on both personnel and process safety concerns when transporting and receiving crude via rail and truck. What laboratory analyses support this effort?

We receive crude by truck and rail at two of our seven refineries. I have prepared three slides to share with you: one for personnel, one for process, and one for sampling. Most of the tight oils we bring in are from under-developed fields that do not have proper gas plants; therefore, they come in fairly wild.

Question 53: With respect to hydrotreating, what is the typical (CO + CO2) impurity in hydrogen produced from pressure swing adsorption (PSA): 10 ppm or 50 ppm? What problems can be expected if the (CO + CO2) exceed this value? If the hydrotreaters can handle higher than (CO + CO2), is it possible to run the PSAs harder and produce more hydrogen?

UOP has designed around 1000 PSA units. For most of the refinery applications, the impurity limit has been set to less than 10 ppm. The table shows a comparison between specs when relaxed from 10 to 100 ppm. H2 recovery was also checked when specs were tightened from 10 ppm to 1 ppm.