Biocides: Typically, the upstream group wants to kill bugs and the downstream wastewater treatment plant wants to keep them alive. So, you have bacteria in light tight oils, as well as in the oil sands, during crude oil production. The upstream group uses a biocide to prevent the sulfide-reducing bacteria to produce H2S, and the dosage is usually between 25 to 500 parts per million.

Under normal operations, having a consistent crude slate and a washwater pH between the 5 and 9, acid addition is not normally required, despite what gravity of crude the refinery is using. There are three situations for having a good conversation with your chemical vendor, if you think you need acid addition. One is removal of tramp amines. The second is metal removal; specifically, calcium or iron.

This question is a compilation of several that were originally submitted. One of those questions focused on being able to put slop into a pumparound, so we are going to address that as well. But of course, the most important factor about running slops is knowing what it is: understanding whether it is wet or not, whether the quality is known, and whether the quality is consistent. 

The crude unit wants them out of the crude oil, and the wastewater treatment plant would prefer not to have them. So essentially, we are talking about wastewater treatment solids. Some people call it recovered oil; some people call it slop oil; and some people call it skimmed oil. So, if I interchange these definitions, what I mean is recovered oil from the wastewater treatment plant. 

The discussion of where to route the discharge of relief valves is always a great conversation, and we are going to talk a lot about what happens in the crude preheat train; and specifically, with desalter PSVs (pressure safety valves). We want to minimize the amount of liquids (especially water) sent to the fractionator whenever possible.

The biggest obstacle, in my mind, to gain entry a crude tank is the accumulated sludge and solids. There are several strategies operators can use to attack that issue. The first strategy is to keep the sludge from accumulating during normal operation. For most MPC refineries, we try to keep our crude tank mixers running as much as possible.

To reduce aromatic levels, we definitely need to assess the unit’s capabilities. Is it a high hydrogen partial pressure unit with psig greater than 800, and does it have a higher than 4.0 hydrogen availability ratio (HAR)? If both answers are greater than those reference points, then full loading of NiMo catalyst can be employed to give higher hydrogenation and very good aromatic saturation results.

We prefer not to use salt dryers in new ULSD designs. In recent ULSD designs, we will put in a vacuum dryer, or we will re-boil the stripper to meet the low water specs. If there are less stringent water specs, using a coalescer can be sufficient. One of our most recent new units will have a coalescer followed by a vacuum dryer.

Currently, our gasoline runs at 12 ppm sulfur. There are two sour components: our LSR (light straight-run) and butane. Some approaches we are contemplating for compliance are hydrotreating the LSR, reducing the sulfur via dilution, or restarting an out-of-service Merox unit.

Use of either oxidized or presulfided catalysts can work fine. It depends on safety approach, cost allowance, time goals, and handling the processing preference. The main point is safely carrying out this skimming operation, whether or not it is oxidized catalyst or presulfided catalyst.