Problems in processing discounted crudes Part 2: crude and vacuum columns
Project costs must be considered to fully understand whether or not an opportunity crude really does deliver on savings.
SCOTT GOLDEN, TONY BARLETTA and STEVE WHITE
Process Consulting Services, Inc.
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The term ‘opportunity crude’ has, for years, described crudes that refiners can purchase at steep discounts against typical crude. The term stems from the idea that processing these crudes represents a good profit opportunity for the refinery. However, refiners processing so-called opportunity crudes have experienced poor reliability, short run lengths, long turnarounds, reduced crude rates, decreased yields of high value products, and increased operating and maintenance costs. After accounting for the process and equipment consequences associated with these crudes, the proverbial ‘opportunity’ may not actually exist. Therefore, it may be more accurate to describe these feedstocks as ‘discounted crudes’. This change in convention should remind refiners that discounted crudes may come with more obstacles than opportunities. It is possible, however, for refiners to overcome many of these obstacles through process and equipment design changes that specifically account for the unique qualities of discounted crudes.
Most crude/vacuum units (CDU/VDU) were not designed to process discounted crudes or their blends, so operating problems such as severe exchanger fouling, desalting difficulties, crude tower plugging, vacuum unit corrosion and numerous others reduce unit profitability. Moreover, it is increasingly common to blend light and heavy crudes to create targeted gravity blends even though many of these crudes are incompatible. Blending incompatible crudes causes stable desalter rag layers, periodically high chloride carryover into desalted crude, poor brine quality, and other cascading processing challenges.
Part 1 (PTQ, Q1 2019) presented a definition of discounted crudes and explored problems in the crude preheat section of the CDU/VDU. Part 2 continues the discussion of potential CDU/VDU problem areas.
The crude column fractionates crude oil into naphtha, kerosene (jet fuel), diesel, and atmospheric gasoil (AGO) products for further processing and has six to nine different sections depending on complexity. Figure 1 shows a simplified crude column with two pumparounds and four distillate products. Some units have four or five pumparounds and additional products, depending on downstream processing and heat integration philosophy. Crude column top section fouling has historically been the most common crude column problem, followed by flash zone issues. Today, nearly every section of the crude column experiences fouling/corrosion depending on individual crudes and blend percentages, chemical treating, external feeds from downstream hydrotreating units, and operating conditions. Proper design of tower internals is becoming critical for mitigation of these issues and elimination of unscheduled outages. Trays with standard designs can no longer be tolerated where run length is important.
Crude column top sections have had problems with free water formation and laydown of nitrogen based chloride salts since the first units were built. Some refiners have tried to produce a heavy naphtha side draw which almost always leads to severe fouling and corrosion problems, even in the product rundown systems and heat exchanger services. Crude (and preflash) columns cannot reliably fractionate light naphtha from reformer feed without forming free water and amine chlorides that cause fouling and corrosion issues. Top sections have been lined with alloys like Monel, duplex stainless steels, Inconel, Hastelloy, and others to deal with the low pH environment, with varying success. Once operating temperatures are low enough to allow free water formation or amine chloride sublimation, corrosion always occurs. Today’s tower top sections can contain many different amine compounds, including H2S scavengers, fracked crude production chemicals, Canadian SAGD water treating compounds, and refinery steam system amines. Slop oils often contain amines from refinery treating sources and external feeds from hydrotreating unit stabilisers containing ammonia, H2S and other impurities that exacerbate corrosion and fouling.
Unit process design should ensure that tower top operating temperatures prevent formation of amine chlorides, with the specific amine type setting the minimum operating temperature. Ideally, amine chloride formation should occur in the overhead system where it can be removed with proper water wash rather than in the column. In addition to low column outlet temperature, low localised temperatures caused by cold column feeds – especially low flow rate pumparounds and reflux – must be avoided. Cold top pumparound return temperature from air coolers is especially problematic even when column top temperature is high enough to prevent amine chloride precipitation. Some compounds, like morpholine, can form very high melt point salts. Low localised temperatures can be avoided through good process design practices such as hot bypasses that allow for independent control of pumparound heat removal and return temperature.
Flash zone areas have experienced some fouling and coke formation related to crude type, blends, and/or poor equipment design. In the last 10 years, there has been a step change in the incidence of flash zone problems, which are appearing in an increasing number of locations. Discounted crudes have played a major role in this increase, causing rapid fouling and unscheduled shutdowns to remove solid material including drilling compounds, large quantities of asphaltenes, and tank bottoms accumulated sludge. Except in the most extreme cases, proper equipment design can eliminate these problems. In some cases, run lengths have increased from months to several years.
Fouling is occurring in new locations too. Synthetic crudes containing high percentages of coker products can cause diesel section fouling. Very high concentrations of coker products in Venezuelan synthetic crudes leads to diolefin polymerisation causing soft coke-like material on the top and underside of trays. A relatively new problem is kerosene fractionation and pumparound section fouling with phosphate compounds (see Figure 2) that are present either in the crude or the byproducts of some chemical vendor treating strategies. The phosphate problem is global with recent incidences in Indian, South African, and US sites.
Typical practice for tower internals design is to issue process datasheets with tower vapour/liquid loadings and allow the internals vendors to design the equipment, with selection based on low cost. Properly designed internals can eliminate problems throughout the column with a very modest cost increase. Best practice is to supply an equipment design that incorporates know-how depending on specific requirements. Some examples include eliminating stagnant zones, operating at high cross flow velocities where applicable, minimising weir height in selected services, operating at high downcomer velocities where necessary, having high fixed valve clearances to deal with fouling, and utilising push valves in potential stagnant zones. In many instances, the standard design approach has led to unscheduled outages or major operating changes that reduced high value product yields. In other instances, proprietary designs have created their own set of problems including plugging related to design features like truncated downcomers with dynamic seals. Replacing these trays with a plug flow sieve tray design (see Figure 3) has eliminated unscheduled outages in many refineries including several world class CDU/VDUs in India.
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