Q&A

(2011) Question 76: What can cause exothermic reactions in propylene driers and guard beds and how can these reactions be prevented?

As introduction, Propylene Recovery Units downstream of FCC units typically consist of a C3/C4 Splitter, a Deethanizer and a C3 Splitter in series.

(2011) Question 77: How prevalent is the use of low slide valve dP override control in modern FCCU DCS systems and can the over-ride be considered an "independent protection layer" (IPL) when conducting a layer of protection analysis (LOPA) to protect against a pressure reversal scenario?

The panel concluded that 100% of the FCC units in their respective companies used the low slide valve dP over-ride to protect against reversals.

(2011) Question 78: What are the locations, formation mechanisms, mitigations and removal methods for coke deposition in the riser, reactor, reactor vapor line and main column inlet nozzle?

There are two ways that coke forms in FCC reactors. These are incomplete vaporization in the feed injection zone of the riser and HC vapor condensation of high boiling point species on cooler surfaces. In both cases the hydrocarbon liquid wetted on a surface has essentially infinite residence time at elevated temperature, resulting in thermal degradation reactions that create solid coke deposits.

(2011) Question 79: What procedures do you use to overcome chloride fouling problems in FCC fractionators? What is the contribution of chloride from the catalyst?

Overcoming or preventing chloride fouling problems in FCC fractionators is a primary responsibility of the unit engineer. There are several tools that can be used to monitor an operating unit.

(2011) Question 80: Does silica entering with the FCC feed have a negative impact on the performance of the catalyst or the product slate? Does the silica source matter? Does it matter if originated from crude oil production, antifoam injection in coker units, or from the crude itself? What proportion of the silica entering the FCC leaves with the product?

I did not find any internally reported issues involving silica in FCC feed as a catalyst poison or as having negatively impacted product qualities. As a result, there have not been any attempts within BP to track silica in FCC feedstocks and in FCC products therefore I don’t have a basis for responding to the portions of this question requiring this kind of analysis.

(2011) Question 81: What are the potential impacts on FCC LPG and FCC gasoline properties from a) processing coker off-gas into the FCC gas plant and b) processing coker naphtha in the FCC riser?

Coker products are known to contain more sulfur, H2S, di-olefins and mercaptans than FCC products. Care should be taken not to overburden the LGP sulfur extraction unit or send an excessive amount of diolefins to the Alky. One of our refineries experienced excessive mercaptan sulfur in the Light Cat Naphtha when a coker light ends stream was routed to the FCC gas plant.

(2011) Question 1: Do any of you place an alarm or upper limit on the operating pressure drop (dP) through a hydrotreater reactor circuit (preheat exchangers to High Pressure Separator)? If yes, what is the basis for the maximum dP?

One of our refineries has developed limits for pressure drop through the reactor circuit. The maximum allowable pressure drop is determined by the difference between the upstream reactor or heat exchanger design pressure and the set pressure of the relief valve on the high-pressure separator. The purpose of the alarm is to ensure that the upstream vessel’s design pressure will not be exceeded before the pressure at the downstream relief valve reaches the set pressure.

(2011) Question 2: In hydrocrackers, how are your sampling systems designed to safely obtain inter-reactor / reactor effluent samples?

Inter-reactor sampling can be important for monitoring catalyst performance, troubleshooting, and measuring yields. In a hydrocracker, such a sampling system allows measurement of nitrogen slip from the pre-treat section into the hydrocracking stage.

(2011) Question 3: How are you managing your units to mitigate risk of HTHA (High Temperature Hydrogen Attack)? What are monitoring best practices? Should we be concerned about short term operating periods such as startup, shutdown, hot stripping, etc.?

HTHA is a form of degradation of metal caused by hydrogen reacting with carbon in the metal to form methane in a high temperature environment, typically above 400 deg F and 50 psia H2 partial pressure.

(2011) Question 4: How reliable are the dry gas seals on hydroprocessing recycle gas compressors? What are the system components put in place to enhance the reliability?

Dry gas seals have been used for compressors for many years. The feedback was mixed in its infancy, and there were teething problems. External factors such as the contamination of the sealing gas, insufficient sealing gas pressure and process gas leak onto the seal ring surfaces have been the main reasons for seal degradation.

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