Jan-2008

Canadian crude processing challenges

Vacuum unit design influences liquid volume yields, run length, product yield and product quality when processing bitumen crude oils

Scott Golden, Process Consulting Services

Article Summary

The North American refining industry is building or planning upgrades to take advantage of lower costs and increasing supplies of heavy and extra-heavy Canadian crude oils, conventional heavy feeds like Cold Lake and Lloydminster, and oil sands bitumen crudes. Such projects include new coker capacity and new or revamped crude/vacuum units. Most heavy crude projects require a complete new vacuum unit because these feedstocks are extremely difficult to vapourise. Oil sands bitumen presents the greatest challenge by far. To realise heavy vacuum gas oil (HVGO) product TBP cutpoints of only 950°F and meet a probable four-to-six-year run length requires the best available vacuum unit technology when processing oil sands bitumen crudes. One thing is certain: low-capital-cost dry vacuum units will suffer poor reliability and extremely low HVGO cutpoints, and very likely both.

Production upgrader experience proves oil sand bitumen is even more difficult to refine than conventional heavy crudes. Only a few refiners currently processing large volumes of Cold Lake and Lloydminster are achieving moderately high cutpoints at or slightly above 1000°F. However, highlighting the industry’s casual attitude toward differences in crude characteristics, it is not unusual to hear: “It doesn’t matter which crudes will be processed. They all have about a 20 °API gravity.” What will be the outcome? On-stream factors of months versus years or a very low HVGO product yield, a much higher coker charge rate than expected and higher incremental coke production of 1 wt% or more on bitumen. Today, these major economic consequences tend to be ignored, as price discounts are high. Few refiners have any experience of processing high blend percentages of Canadian crudes and none are operating a deep-cut vacuum unit or have experienced the challenges of high percentages of oil sands bitumen. 

Once additional coker capacity comes on stream, Canadian heavy crude prices are likely to increase, as in previous refining industry expansions. Com-pounding this are tightening Middle Eastern crude supplies caused by the demand for future large grassroots construction in India and China. Furthermore, declining conventional heavy Canadian crude production and large future production increases in oil sands bitumen will radically change the Canadian supply situation. Oil sands bitumen crudes will dominate supply. But these crudes require special design considerations to maintain a reasonable run length without significant economic loss.
 
Not all crudes are equal
Industry experience shows that presuming all heavy crude processing characteristics are alike is a gross mistake. Refiners in certain regions such as the US began processing large amounts of Mexican Maya and Venezuelan crudes in the mid-1980s, and in the last ten years have begun processing even lower API gravity and Venezuelan upgrader bitumen-based crude oils. Initial experience with these crudes can be best described as mixed. The learning curve has been very steep and painful. At worst, several industry publications have documented run lengths of three to six months, a very low HVGO product yield or extremely poor HVGO product quality. Years of processing experience with Maya, BCF 22/24 and similar heavy crudes have driven home many lessons, especially the need for additional investment to deal with the realities of these feedstocks.

Since the late 1990s, high percentages of extra-heavy Merey, BCF 17 and other 16–17 °API crudes have been processed by a handful of US refiners. Each has had to invest in process and equipment design changes to improve product yields and meet original run length objectives. Interim shutdowns have been necessary to decoke heaters, remove salt from the atmospheric crude column, change coked packing in the vacuum column, correct poor exchanger network design and other problems. Only after startup did it become apparent that low-capital- cost vacuum unit designs will not meet a reasonable run length or HVGO product cutpoints. Only recently, one refiner had to decrease the vacuum unit heater’s outlet temperature to 690°F from its normal of 760°F when processing 30–40% conventional heavy Canadian with oil sands bitumen crudes, to prevent massive amounts of cracked gas production causing a loss of vacuum. This large reduction in vacuum heater outlet temperature dramatically increased the coker charge rate. However, the coker at this refinery is too small relative to the increased coker charge rate. This may still be profitable if the crude price is low enough, but only if the discounts remain very large.

Canadian crude supply will change over the next 10–15 years from conventional heavy to oil sands bitumen. Bitumen crudes are blends of upgrader synthetic crude or condensates and oil sands bitumen. Diluents are needed to reduce the viscosity for pipelining. The generic names are diluted bitumen (Dilbit) or synthetic bitumen (Synbit), albeit each will likely have its own name such as Albian Heavy.

Figure 1 represents a typical TBP distillation for whole oil sands bitumen (with some variability depending on production location). Excluding diluents, bitumen consists of 10–12 wt% distillates recoverable at near atmospheric pressure, with the remaining 88–90% feeding the vacuum unit. More than 55% of the bitumen is not distillable even under optimum vacuum unit design. A state-of-the-art crude and vacuum unit will reduce the coker feed to approximately 57 wt% of the whole bitumen, but not much lower. Poorly designed vacuum units will produce coker charge rates as high as 67% of whole bitumen and run lengths measured in months, not years. Poor vacuum unit performance will result in incremental coke production of 1–2 wt % of the whole bitumen. When crude oil costs are $50 per barrel, the economic loss can be very high.

HVGO product TBP cutpoint
The HVGO product cutpoint is used to assess vacuum unit performance, with 1050°F often cited as the benchmark or design basis for new units. In reality, actual vacuum unit cutpoints vary from below 900°F on extra-heavy crude to over 1100°F for light crudes, with the majority operating below 1000°F even on moderately heavy 26–28 °API gravity feeds. Feed characteristics control the potential cutpoint. The maximum is determined by vacuum unit type and design. In the last 20 years, large amounts of Maya have been processed by US refiners and it continues to be one of the design-marker heavy crudes for recently announced Gulf Coast expansions, even though production from the Mexican Cantarell field is in steep decline.