Apr-2016

Impact of light tight oils on distillate hydrotreater operation

Addressing the range of challenges brought to diesel and jet production by light tight oil processing

ROBERT OHMES and MATT LEHR
KBC Advanced Technologies

Article Summary

Light tight oil (LTO, also known as shale oil) formations are providing a new crude source to North America and soon to the world, with the construction of condensate splitters in the US Gulf Coast and the announcement that the US government was lifting the crude export ban. Agreements between the US and Mexico have been announced that will allow crude swaps, thereby sending LTO into refineries in Mexico. Other countries in the region are also examining the potentials of LTO imports. The economic advantages of processing LTO crudes are the low crude cost relative to world benchmark crudes and higher quality compared to other available crudes.

The production and processing of LTO crudes is relatively new, whereas Asia Pacific conventional crudes that have similar qualities (when compared to LTO crudes) have been in production and refined for many years. In addition, West African crudes and conventional US crudes (such as West Texas Intermediate, WTI) have been displaced from US refiners and replaced with LTO crudes. Therefore, a comparison of example LTO, conventional US, Asian Pacific, and West African crude distillate qualities presents a possible mechanism to provide operating and product impact insight for hydrotreaters in LTO processing facilities. The following will provide some high level impacts of LTO processing on a facility, and then use a kinetic model to highlight the unit specific impacts that can occur.

Impact of light tight oils on refinery operation
Figure 1 summarises some of the high-level impacts of processing LTOs in a conventional refinery. The key challenges include, but are not limited to:
•    Managing crude compatibility, asphaltene deposition, wax formation, and fouling in the crude and vacuum units
•    Handling the higher content of naphtha in crude, as well as the lower content of vacuum resid
•    Managing impact on reformer yields due to the poor N+2A content of naphtha
•    Finding ways to handle poor cold flow properties in distillate train
•    Identifying alternative operating and optimisation opportunities to fully leverage LTO processing.

Though outside the remit of this discussion, several resources are available to address the items listed above.^1-10 The focus of this article is to understand the impact of LTOs in the distillate train, and highlight areas that refiners should evaluate and consider as part of LTO processing in their facilities.
 
Distillate evaluation methodology
To begin the process of understanding the impact of LTO on conventional refining operations, benchmark crudes were selected that have similar properties of LTO crudes (high paraffin content, lower sulphur/nitrogen, poor cold flow properties, for instance). In reviewing crude qualities on a global basis, some of the sweet waxy crudes from Asia Pacific have similar qualities to LTO crudes. Hence, for this study, the comparison crudes chosen were Bach Ho, Gippsland, Cossack, and Kutubu. In addition, West African light sweet crude (Qua Iboe) was included in the analysis, as these crudes typically compete with LTO crudes in US refineries.

Crude assays from an assay database that KBC licenses were used as the basis to generate kerosene and diesel hydrotreater feeds. Each assay was individually processed in a Petro-SIM simulation model to generate a typical kerosene and diesel fraction. Each fraction was then processed in a generic kerosene or diesel hydrotreater (DHTR-SIM) model to predict the performance changes in unit operation. The model not only predicts the operational and product quality changes, but also the reactor heat balance and catalyst deactivation impacts.
Table 1 summarises the general operating conditions of each hydrotreater.

Though the design parameters, catalyst type, and operating targets for each refiner’s distillate hydrotreater units will vary, these generic units should provide valuable insight into the impacts of processing LTO crudes versus similar crudes.

Co-processing LTO with other feeds is an operational advantage for kerosene and diesel feeds. The unit capacity may not be entirely utilised by the LTO and a heavy/sour/aromatic feed might be included to utilise hydraulic and severity capacity. Kerosene and diesel boiling range fractions are generally compatible and operational issues due to blending of these dissimilar fractions are minimal. Compatibility for heavier boiling fractions (gas oils and resids) do exhibit different behaviour, but are excluded from this discussion. Therefore, cases were included to understand the impact of processing blended distillate feeds, especially cracked stock streams.

Prior to beginning the evaluation process, some background is included on distillate hydrotreater configurations and catalyst systems.

Fixed bed hydrotreating background
With refinery installed or revamped hydroprocessing units, the design basis was often dictated by processing of feedstock from heavy crudes, especially in the last decade. The aromatic nature of these heavy unconventional crudes, along with more heteroatoms in cracked lighter products, typically requires saturation and conversion via hydrotreating. The hydrotreater operation is severe and requires high temperature and pressure operations, with shorter run lengths than similar downstream refinery processes. ^7,8,12,18

When examining LTO processing, the initial belief was that the existing unit can likely handle this feedstock. However, the paraffinic nature of LTO presents a different challenge, as the severity requirement is low yet must be high enough to remove the required sulphur. This feedstock provides an opportunity for refiners to modify catalyst selection, feed rate, hydrogen partial pressure (ppH2), and operating temperature to maximise utilisation of a given hydroprocessing asset.

Fixed bed hydrotreating configuration
Two typical hydrotreating configurations are utilised for hydrotreating distillate range material. The typical single stage separator configuration is shown in Figure 2.

The single reactor and single separator hydrotreater design (see Figure 2) is typical for a kerosene and light diesel feedstock. The high pressure separator hydrogen-rich off-gas can be used in a once through mode (naphtha hydrotreating units) basis or recycled with a compressor (kerosene and light diesel units). The recycle gas is typically treated to remove H2S in this configuration in ultra-low sulphur service, but some configurations do not amine treat the recycle gas.

More severe feedstocks require a more complicated reactor and recycle gas system. A multi-bed reactor with three separator hydrotreater configuration and recycle gas treating is shown in Figure 3.

The reactor shown in Figure 3 includes a hydrogen quench to control the reactor temperature rise, which is caused by significant hydrogen consumption, and an amine treater on the recycle gas to remove H2S. This configuration also includes a water wash to remove the ammonia bisulphide from the reactor effluent air cooler (REAC).

When processing LTO feeds in these more complicated reactor systems, the operating conditions will change. The LTO feeds have low aromatics, sulphur and nitrogen, and hydrogen consumption is typically low. Therefore, the resulting heat release and temperature rise are lower, thereby reducing the need for hydrogen quench. The low heat release reduces the feed/effluent heat recovery and increases duty requirements on the feed heater, as well as impacting reactor quench control. Hence, these systems will require review as part of processing LTO feeds within these units to avoid operating outside of design conditions or reliable equipment capabilities.