Processing TIPS

Integration of Delayed Coker and Hydrocracker


In order to reduce fuel oil, natural gas, and fuel gas consumption along with a reduction in CO2 emissions, some refiners are investigating the integrated operations of delayed cokers with hydrocracking units. The integration of delayed cokers and hydrocrackers has been common for 20 years in the refining sector as delayed coking has become the primary low cost resid upgrading unit for most new grassroots refineries. Hydrocracking of the coker gas oil will increase light product yield as well as aid the economy of scale for the hydrocracker. New coker designs are being optimized for the production of feed material to the hydrocracker so diesel and middle distillate products are maximized. This optimized coker design includes operating with low to ultra-low recycle rates and high recycle cut points. These optimized designs will lead to very high liquid yields of heavy coker gas oil (HCGO) which contains high levels of polycyclic aromatic compounds and other contaminants. The contaminants in the HCGO will rapidly deactivate the hydrocracking catalyst and reduce the catalyst cycle time. Several refiners have begun to filter the HCGO before it is passed to the hydrocracker to prevent fouling of the hydrocracker catalyst bed. This optimized scheme may also adversely affect hydrogen consumption in these units. Coker operating conditions may also need to be adjusted to meet diesel specifications relating to metals, Conradson carbon, and heptane insolubles in the hydrocracker feed. Processing CGO feeds may also lead to problems relating to crude compatibility in this feedstream and the hydrocracker feedstream that contains CGO will need to be filtered to prevent fouling in the hydrocracker catalyst bed.

Licensers of hydrocracking technology have responded to these challenges by lowering the HCGO TBP end point, asphaltenes, Conradson Carbon, and metals contents. Operators of hydrocrackers will also need to account for drum swings from the coker, which will greatly vary the quality of CGO feeds. This requires refiners to constantly monitor the quality of the CGO feed being sent to the hydrocracker and adjust any operating parameters accordingly to ensure that catalyst activities are maintained for a given run length and product specifications are met. The optimized coker/hydrocracker configurations will be designed to balance the overall liquid yield against total capital and operating costs for the integrated units.

UOP offers an integrated scheme that combines its Uniflex slurry hydrocracking process with a delayed coking unit. Vacuum residue is fed to both the Uniflex and delayed coking units, with pitch from the Uniflex process being fed to the delayed coker to increase its available feed material while the HCGO from the delayed coker is fed to the Uniflex unit to increase the yield of middle distillates. This integrated design will not only increase the yield of high-quality diesel and naphtha products but also help to debottleneck the delayed coker.

Chevron Lummus Global also notes that a delayed coking unit may be installed downstream of a hydrocracker to process the unconverted oil (UCO) from the hydrocracker into middle distillates and anode grade coke. Chevron states that the UCO from a hydrocracker typically was utilized as fuel oil, but the low value of fuel oil could allow refineries with existing delayed coking capacity to convert this UCO into higher-value products.1

Axens has presented three separate case studies involving the addition of a 54.4K-b/d ebullated-bed hydrocracker upstream of a 27.2K-b/d delayed coker. In case 1, a 200K-b/d refinery is processing 100% Arabian Heavy crude. For case 1, the ebullated-bed hydrocracking reactor is a single-train, single-reactor plant that operates at 60% conversion of 975°F+ (524°C+) resid material to distillates. For case 2, the conversion level is increased to 70% and the unit is reconfigured to employ two reactors in series with inter-stage separation in place of the single reactor of case 1. The expanded conversion level allows refinery throughput to be raised to 300K b/d. For case 3, the Arabian Heavy feed is replaced with Athabasca bitumen and the two reactors in series with inter-stage separation hydrocracker configuration utilized in case 2 is maintained. As a result of the higher vacuum resid content of the Athabasca bitumen, the overall refinery capacity in case 3 is halved from case 2 to 150K b/d with a 975°F+ (524°C+) resid material to distillates conversion level of 68%. A comparison between the Arabian Heavy and Athabasca bitumen feeds is provided in Table 1. Please note that for all three cases the catalyst cycle length was set at 30 months.


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For case 1, the entire unconverted residue (21,922 b/d) is routed to the delayed coker. The overall liquid yield from this configuration is 192.6K b/d which equates to 96.3 vol% of the total crude throughput. Like case 1, the uncovered bottoms (24,503 b/d) from the hydrocracker are also routed to the delayed coker in case 2. Overall liquid yield is raised (292.3K b/d) due to the increase in refinery feedrate though overall conversion is also raised to 97.4 vol% of the total crude throughput after raising the ebullated-bed hydrocracker conversion level to 70%. For the final case where Athabasca bitumen replaces Arabian Heavy, overall liquid yields are reduced due to the refinery throughput being only 150K b/d as a result of the higher vacuum resid content of the Athabasca bitumen compared to Arabian Heavy though overall conversion is increased to 101.53 vol% of total crude throughput as the feed to the delayed coker in this case is 27,221 b/d. Case 3 also provided the highest amount of diesel relative to the amount of crude processed. Overall results from the three cases are provided in Table 2. In all three cases, the product naphtha is routed to a cat reformer or isomerization unit, the diesel is blended to the ULSD pool, and the VGO is feed to a FCCU for upgrading to gasoline.


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In terms of process economics, the investment costs for each case ranged from $14.8-22.4K b/d with case 1 representing the lowest investment cost of the three cases. Investment costs included the new ebullated-bed hydrocracker; new crude and vacuum units; a steam methane reformer for H2 production; diesel, naphtha, and VGO hydrotreaters; sulfur plant, amine regenerator; gas recovery unit; sour water stripper; and corresponding utilities and offsite facilities. Operating costs for the three cases varied from $4.42/bbl for case 1 to $7.98/bbl for case 3. The higher operating cost for case is related to the drastic rise in H2 consumption due to the heavier nature of the Athabasca bitumen feed. Assuming a crude price of $92.48/bbl for Arabian Heavy, $67.85/bbl for Athabasca bitumen, $109/bbl for gasoline, and $114/bbl for diesel case 2 would provide the highest total net annual revenue of $932MM. All three cases were found to be economical so long as the price of Brent is over $55/bbl. Furthermore, the authors added that diesel yield in all three cases could be increased should the VGO hydrotreating capacity be replaced with VGHO hydrocracking capacity though this could raise total investment costs.2

Source: 2Q2015 issue of Worldwide Refinery Processing Review
  1. Arora, A.; Mukherjee, U.K. Refinery Configurations for Maximum Conversion to Middle Distillates. In 2011 NPRA Annual Meeting, San Antonio, TX, March 20 22, 2011 [CD ROM]; National Petrochemical and Refiners Assoc.: Washington, D.C., 2011.
  2. Wisdom, L.; Duddy, J.; Morel, F. Consider new technologies to increase diesel yield from bottom of the barrel products. Hydrocarbon Process. 2012. 91 (Nov.), 61.


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