Jun-2016

The outlook for transport fuels: Part 2

As demand evolves, as specifications change, and as new fuel opportunities arise, what are the implications for refiners up to mid-century?

GAUTAM KALGHATGI, Saudi Aramco
CHRIS GOSLING and MARY JO WIER, UOP

Article Summary

Global transport will continue to be powered largely by petroleum based liquid fuels in the next few decades due to their vast production and distribution infrastructure, high energy density and portability. The growth in transport fuel will not be constrained by the supply of oil over this period. The increase in demand will be mostly in the commercial transport sector and the world will need much more diesel and jet fuel in the future compared to gasoline. Moreover, gasoline octane quality needs to increase to enable more efficient spark ignition engines.

This poses significant challenges to the refining industry and is likely to increase the availability of low octane components in the gasoline boiling range. The main challenge for diesel engines is to control particulates and nitrogen oxides (NOx) at reasonable cost without compromising efficiency. This challenge is much easier to meet if diesel engines are run on fuels that do not ignite as easily as diesel fuel, allowing more time for fuel and air to mix before combustion starts. There is great potential to develop Gasoline Compression Ignition (GCI) engines that are at least as efficient, possibly cleaner and cheaper compared to today’s diesel engines, but which run on low octane gasoline rather than diesel.

This two-part article investigates the petroleum refining implications of two scenarios. Here, the second part addresses the possibility of using a low octane ‘New Fuel’ in new engine combustion systems, such as GCI engines (Scenario 2). The first part (see PTQ Q1 2016) dealt with a scenario based on current fuel and engine technology (Scenario 1), while a comparison of refinery operations and performance under the two scenarios is addressed here.

The numbers quoted are projections based on the assumptions made. The results suggest that the availability of such new engine technology might enable refiners to reduce capital investments and increase profit margins through better asset utilisation. 

Scenario 2: base refinery configuration with New Fuel introduced
The refinery flow scheme for Scenario 2 is the same as the base refinery configuration in Scenario 1, except that unit capacities are different. The blend stocks that are available for New Fuel blending are the isomerate, reformate, FCC naphtha, heavy CDU naphtha, CDU kerosene, and C4s. The crude slate consists of Brent and Arab Heavy, the same as in Scenario 1. The refinery configuration used in Scenario 2 for the LP evaluation is shown in Figure 1.

New Fuel specifications
The required RON specification for the New Fuel was set at 70. The other specifications for New Fuel were assumed to be similar to gasoline, as the distillation range will be closer to gasoline than diesel as summarised in Table 1. The final boiling point can be higher for the New Fuel at 250°C, compared to 200°C for European specification gasoline. A minimum specific 
gravity of 0.72 g/cc was specified to provide similar heating value to gasoline.

Refinery configuration changes in Scenario 2
The refinery configuration and expansion planning is the same as the Scenario 1 refinery except that New Fuel is introduced in 2030, displacing some of the diesel demand. The changes in the Scenario 2 refinery unit capacities are summarised in Table 2. The changes in configuration from 2010 through 2050 were assumed as follows:
2010: The configuration and production requirements are the same as in Scenario 1
2020: The configuration and production requirements are the same as in Scenario 1.
2030: New Fuel has been introduced to the market and production is 8000 b/d, reducing diesel production from 90 000 b/d to 82 000 b/d. The feed rate to the FCC was similar for Cases 2 and 3 at 26 000 b/d.

An increase in the hydrocracking (HC) unit capacity from 13 000 b/d to 22 000 b/d was required to meet the distillate demand, but less than the HC unit capacity increase to 
31 000 b/d in Scenario 1.

2040: Production of New Fuel increased to 26000 b/d, with increasing penetration of GCI engines replacing 20% of diesel product requirements. This reduces diesel production from 133 000 b/d to 107 000 b/d. The HC unit expansion in Scenario 2 is reduced from 53 000 b/d in Scenario 1 to 28 000 b/d.

The FCC is fully utilised in Scenario 2, while minimising the capital required for increased HC unit capacity and is the low capital option.

2050: The diesel-to-gasoline ratio increases to 1.7 with all of the gasoline at 100 RON. Production of New Fuel is 42 000 b/d as penetration of GCI engines gradually increases, displacing 30% of diesel fuel demand. Diesel production decreases from 139000 b/d to 
97 000 b/d as a result. The FCC unit feed rate increases to 55 000 b/d, requiring a 14% capacity increase over the base case unit. The HC unit capacity is decreased from 28 000 b/d to 18 000 b/d. The CNR reformate is 104 RON, isomerate at 89 RON, with MTBE blended to increase RON and dilute aromatics.

LP evaluation summary for Scenario 2
The refinery linear program (LP) simulation was used to evaluate the impact of future fuel demands for each configuration. Figure 2 shows the product slate for the initial 
refinery configuration and the revamp configuration changes assumed to meet the future demands.
Table 3 summarises the LP simulation for Scenarios 1 and 2.

Petrochemical naphtha production in years subsequent to 2030 was eliminated in Scenario 2, increasing the yield of higher value products.

The refinery unit capacities as a function of time in the Scenario 2 analysis are compared to Scenario 1 in Figure 3. Similar to Scenario 1, the largest process unit is the DHT, with approximately 100000 b/d capacity in both scenarios. The CU for vacuum residue conversion, and the naphtha complex NHT, CNR and isomerisation units also are similar in capacity. The key difference in capacities is between the HC and FCC units. In Scenario 2, the production of New Fuel allows for the FCC unit to be fully utilised, requiring a much smaller HC unit, at 18 000 b/d compared to 61000 b/d in Scenario 1. The conversion unit capacities are contrasted in Figure 4 for Scenario 1 and Scenario 2.

The blend stocks required for the 100 RON gasoline product for Scenarios 1 and 2 are compared in Figure 5. Since there is a higher feed rate to the FCC in the New Fuel scenario, more alkylate is produced, and the higher FCC conversion also increases MTBE production, minimising the amount of MTBE to be purchased. The decrease in imported high octane blend stocks increases profitability.

A key benefit of producing New Fuel is the capability to upgrade isomerate to New Fuel rather than selling it as naphtha. All of the isomerate is blended into New Fuel whereas 7000 b/d was sold in Scenario 1. The key limiting specification for the New Fuel blend is the specific gravity. However, since the endpoint can be higher than gasoline, some kerosene is blended to increase the gravity and energy content. New Fuel provides the refiner with significant product blending flexibility and a value added disposition for low octane naphtha streams.