Problems in processing discounted crudes Part 1: definition and crude preheat
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. This two-part article details these changes.
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. Figure 1 shows the major CDU/VDU systems. So-called opportunity crudes can adversely affect all of these systems. In addition to the systems shown in Figure 1, new or revamped CDU/VDUs may include crude and vacuum preflash columns and their associated equipment, which are also potential problem areas.
Discounted crudes have above average concentrations of bad actors: solids, acids, salts, amines, phosphates, asphaltenes, waxes, sand, drilling compounds, CO2, nitrogen, calcium compounds, metals, production treating chemicals, polymers, and more. Moving the amount of discounted crude in a blend from 10-20% to 30-50% has major ramifications. One example is severe corrosion in the vacuum tower vessel top section, its internals, and external pumparound equipment (see Figure 2), as well as high chloride content in vacuum diesel or LVGO products feeding downstream hydrotreaters. Although this type of corrosion is strongly associated with discounted crudes, it is even occurring with historically benign Middle East crudes due to chemical treating related to secondary and tertiary production methods. The refining industry will confront more challenges as discounted crude production increases, conventional crude fields increase water injection with its associated amines and other treating compounds, and compatibility problems intensify.
Many discounted crudes exhibit blending incompatibility with blends containing high percentages of discounted crude generating complications not seen at lower ratios. In the US, despite being referred to as ‘crudes’, most fracked liquid hydrocarbons are condensates rather than conventionally defined crude oils, and are too light for most refiners to process in high percentages. Consequently, producers, oil traders or refiners blend these condensates with other crudes to create targeted API gravity refinery feeds. Blending West Texas Intermediate (WTI) or light fracked condensates with heavier crudes such as Doba, Western Canadian Select (WCS), Cold Lake, Lloydminster Heavy, Zuata Heavy, or Middle East Neutral Zone creates long term problems that may not be found until a shutdown.
In one example of the cascading problems that can result from blend incompatibility, desalter emulsions caused by asphaltene precipitation from an incompatible blend led to periodically or chronically high chlorides in the desalted crude. The refiner compensated by increasing caustic injection to manage the chlorides. A higher caustic injection rate led to increased preheat exchanger fouling which lowered crude heater inlet temperature and raised crude heater firing. Higher crude heater tube metal temperatures (TMT) ultimately lowered heater run length and increased the risk of tube failures. Furthermore, high desalted crude chlorides resulted in accelerated corrosion rates in the crude and vacuum towers and peripheral equipment.
Poor reliability, low product yield and longer turnaround outages
Table 1 shows a partial list of problems attributable to fracked condensates, heavy crudes, bitumen, crudes produced from secondary and tertiary recovery techniques, and poor compatibility blends. This list highlights some of the industry experience over the last few years and is not comprehensive. In this era of six to eight year targeted run lengths, refiners need to consider investment programmes to eliminate or mitigate the risk of these unwanted outcomes. If, as projected, conventional crude production plateaus or decreases, refiners will be forced to process more of these crudes in spite of inadequate CDU/VDU designs. The days of processing only two or three crude blends may be coming to an end.
Reliably processing discounted crudes
To justify an investment to eliminate existing unit shortcomings, actual reliability and operating costs – including product yield downgrades – must be analysed. In the case of poor reliability, especially loss of containment, eliminating certain problems may be an urgent matter. Product downgrades include the inability to undercut naphtha to jet fuel, poor recovery of jet fuel from diesel, excessive diesel in the FCC or hydrocracker feeds, and high vacuum gasoil (VGO) in the vacuum residue (VR) product. The economic penalties of these downgrades can be identified with an LP or process model. However, an LP or process model cannot identify the root cause(s) of process system inadequacies and equipment constraints that reduce profitability. More importantly, an LP or process model cannot determine where and how to invest to eliminate or minimise reliability and operational problems.
CDU/VDUs are highly integrated process systems with individual equipment performance influencing upstream and downstream components. A comprehensive unit performance analysis should include extensive test run data gathering that incorporates complete unit hydraulic and temperature profiles and a detailed review of all process systems (see Figure 1) and actual equipment performance. For example, low desalter inlet temperature is common, but the potential causes are complex and are not understood by simply evaluating raw crude exchanger fouling. Low desalter temperature can also result from low crude heater outlet temperature, below design product yields, insufficient flexibility to shift duty between upstream and downstream of desalters and crude preflash column, crude and vacuum tower heat balance constraints, and many other factors. Process models are essential engineering tools for unit evaluation and design, but additional tools and information are needed to identify unit shortcomings and define cost-effective investment opportunities.
Equipment performance matters
Table 2 shows the major equipment that is critical for unit reliability and operability. Poor performance of a single equipment system has cascading consequences that may not be obvious. For example, poor vacuum ejector performance is nearly universal. Poor vacuum causes reduced VGO product yield, lower crude preheat, decreased desalter inlet temperature, and so on. Furthermore, vacuum heater coil steam and/or vacuum tower stripping steam may be reduced in an effort to improve the vacuum. Evaluation of vacuum ejector performance requires a thorough understanding of ejector and condenser fundamentals and proprietary tools to assess individual components and overall ejector system performance. This is just one of many equipment performance problems that requires more than a process model to evaluate.
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