Consider retrofits to handle high-viscosity crudes
In 2000, ConocoPhillips’ refinery in Sweeny, Texas, began processing 16° API gravity blends of extra-heavy crude oils, including Merey 16 and BCF 17
Scott Golden, Process Consulting Services
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Heavy crudes have higher viscosity, are harder to desalt, can have higher naphthenic acid content,1,2 and are more difficult to vapourise in the atmospheric and vacuum crude columns.3 Moreover, these crude oils have higher microcarbon residue (MCR) and asphaltenes, and many of them have extremely high levels of volatile metals that produce heavy vacuum gas oil (HVGO) products containing â€¨5-10 ppmw vanadium even at moderate cutpoints.4,5,6 Consequently, refiners that have lowered crude API gravities by 5-15° have experienced a common set of problems. To process these heavy crudes reliably for four-to-five-year runs, crude units need fundamentally sound process flow schemes and major equipment system designs. Otherwise, the units cannot meet their profitability targets. Figure 1 is a simplified process flow diagram of the crude unit in 2000.
After initial startup in 2000, the design basis crude charge rate and No. 2 oil product yield could not be met. Since the design crude charge rate was based in part on limited FCC feed hydrotreater capacity, reduced No. 2 oil product yield increased the volume of FCC feed from the crude and vacuum units per barrel of crude charge, thereby increasing the FCC hydrotreater feed rate at a crude throughput below the design basis. Any No. 2 oil product not recovered in the atmospheric column had to be processed through the FCC feed hydrotreater (see Figure 2).
Furthermore, as run length progressed, crude charge rate and No. 2 oil yield further degraded because of flooding in the top section of the atmospheric crude column. Amine chloride salt formed from the reaction of amines contained in the slop oil, and hydrogen chloride (HCl) plugged the atmospheric column trays. To avoid column flooding, operating pressure had to be raised, which further reduced the No. 2 oil yield and increased the FCC hydrotreater feed rate. A bypass line was installed around the plugged section, and the tower was operated for approximately four months with the bypass in service. This temporary fix allowed the unit to operate until the revamp was designed and ready for implementation.7
In 2001, the crude unit was revamped to meet the original design basis charge rate, increase No. 2 oil product yield and improve reliability. Following these changes, the crude unit capacity has consistently exceeded the design basis by as much as 6%. In addition, the No. 2 oil product yield has also been 2% higher than design on whole crude due to process and equipment modifications. Unit operability and reliability have been greatly improved. Yet there are still some problems with fouling in the top of the atmospheric crude column, but column internals design changes have allowed for effective water washing, with only a small loss in crude throughput.
ConocoPhillips implemented a major refinery upgrade with startup in 2000 that included installing new vacuum and delayed coker units (joint venture with PdVSA) capable of processing atmospheric reduced crude (ARC) and vacuum tower bottoms (VTB) from Merey and BCF 17 crudes. The crude unit was designed to produce ~67% ARC. Prior to the major upgrade, the crude unit processed low-to-mid 30° API gravity crude blends, with the ARC product fed to an atmospheric residual desulphuriser (ARDS) unit. Treated residue from the ARDS unit was charged to the FCC unit. During the upgrade project, the ARDS unit was converted to a FCC gas oil feed hydrotreater processing atmospheric column light gas oil (LGO) and vacuum unit LVGO and HVGO virgin gas oils, and delayed coker unit LCGO and HCGO.
Immediately following the 2000 startup, the crude charge rate was less than design and the ARC yield varied between 75-80% of whole crude. Additionally, No. 2 oil product was only 8-9% on whole crude versus a design of 16%. Due to the low No. 2 oil product yield, the FCC feed hydrotreater operated at maximum charge rate even though the crude rate was lower than the design. Thus, improving the No. 2 oil product yield was a key to meeting the design crude charge rate. Before the unit could be fixed, it was first necessary to determine the root cause problems.
Identifying root cause problems
Prior to beginning process and equipment modelling, ConocoPhillips and Process Consulting Services engineers conducted a thorough test run on both crude and vacuum units to gather the data needed to identify root cause problems. While symptoms such as low No. 2 oil product yield and low desalter inlet temperature were obvious, some of the problems were not as apparent because of a lack of data. Consequently, comprehensive measurement of pressures, temperatures and compositions were taken throughout both units. Much of the data had to be gathered through local measurements with single-gauge pressure surveys, portable calibrated thermocouples or high-accuracy electronic pressure instruments. For instance, while plant instruments measured a high pressure drop across the crude column, the exact location where the trays were fouling could only be found with local readings using two high-accuracy electronic gauges. Pressure readings were taken simultaneously to ensure column pressure variations would not influence the measured pressure drop (see Figure 3). Others findings required calibrated process flow and rigorous equipment models developed from the data gathered during the test run.
Based on test run data measurements and analysis with various computer simulation tools, the following root causes were identified for the low crude charge rate, reduced No. 2 oil product yield and poor reliability:
• Crude hydraulics High pressure drop through the hot train exchangers, incorrect relief valve location and inadequate pressure control scheme caused the low crude charge rate
• Desalter operation Low operating temperature contributed to poor desalting, the low crude charge rate and low No. 2 oil yield
• Low overhead temperature Low overhead temperature increased salt laydown on the trays in the top of the atmospheric column and contributed to the low No. 2 oil product yield
• Slop oil processing Charging slops containing several amine compounds caused salts to form in the top of the crude column when operating temperatures were below 270-280°F, thus the crude charge rate and No. 2 oil product yield were reduced
• Overhead condenser Capacity Insufficient condenser capacity required the stripping steam to be blocked to minimise column overhead pressure, thereby reducing the crude charge rate and No. 2 oil product yield
• ARC stripping Poor stripping section tray design caused low efficiency and the mechanical design was inadequate for this service, which contributed to the low crude charge rate and No. 2 oil recovery
• Pumparound heat level Pumparound locations and product specifications resulted in low draw temperatures that made heat recovery difficult, causing a low desalter inlet temperature; furthermore, the No. 2 oil/LGO reflux flow rate was low, contributing to poor No. 2 oil recovery
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