Aug-2017

Optimise the route to emissions compliance

Increasingly stringent SO2 emission regulations may demand smart and 
cost-effective alternatives to generic amine based tail gas treating units.

ALEXANDRA CURTESCU, RIK SCHUFFELEN, PAVAN CHILUKURI and GARY BOWERBANK
Shell Global Solutions

Article Summary

Refiners and gas plant operators are under pressure to meet increasingly stringent global SO2 emission regulations varying from 150 mg/Nm3 to 50 mg/Nm3 SO2. Concurrently, oil and gas companies need to exploit more sour fields as sweeter fields deplete (or even sour over time), which results in higher levels of sulphur species and other contaminants in the refinery or gas plant feedstock.

As demands on sulphur handling capacity increase, greenfield sites will need to be designed with higher contaminant levels in mind. Existing off-gas treating units may need upgrading to avoid constraining the facility.

Considerable investment in capital and operating expenditure may be required to implement the technology, so choosing the right line-up is essential for a dependable return on investment. It is also essential for facilities to develop a long term plan that accounts for any future tightening in SO2 emission specifications.

Process designers tend to favour generic amine based tail gas treating units (TGTU) to increase the sulphur recovery efficiency of sulphur recovery units (SRU). Although these are reliable, and potentially achieve emission based objectives, considerable capital and operating expenditure savings may be possible by considering alternative technologies or process configurations such as SCOT Ultra, Shell Cansolv TGT+ and Thiopaq O&G line-ups. Each has its own merits, with considerations such as acid gas quantity, quality and contaminant type, local SO2 emission standards (short term and long term) and proximity to sulphur/sulphuric acid markets. The type of development, brown- or greenfield, will also have an influence.

This article analyses three separate scenarios, looking at a high level assessment of the potential line-ups and quantifying the benefits of the new high performance alternatives in the context of more stringent SO2 emission limits:
• Scenario A: utility constraints (chilling and/or steam)/Capex
• Scenario B: lean and very lean acid gases/high organic sulphur in feed
• Scenario C: low SRU flame temperature/limitations on LP steam/plot plan restrictions.

Scenario A: maximum performance with minimum investment to meet stringent SO2 regulations
Consider a scenario with the following acid gas feed to a two stage Claus unit which has to meet World Bank Standards (WBS) – 150 mg SO2/Nm3 – emission levels:
• Hydrogen sulphide (H2S): 60 vol%
• Carbon dioxide (CO2): 30 vol%
• Benzene, toluene, ethyl benzene and xylenes (BTEX): 0.1 vol%.

Applicable line-ups
Typical conventional line-ups (see Figure 1a) use generic amines in the TGTU to remove H2S from the Claus tail gas sent to the incinerator. Although this is a proven process line-up, the often overlooked downside is that the circulation rate required for generic amines to achieve WBS emission targets is quite high, which brings high utility consumption in the form of low pressure steam for reboilers and cooling duty for condensers and solvent coolers.

To overcome this high additional cost, Shell Global Solutions recently developed the SCOT Ultra process (see Figure 1b), which offers a step change in the performance of the established SCOT process. It features Shell and Huntsman Corporation’s jointly developed highly selective Jefftreat Ultra family of solvents, which can achieve deep decreases in H2S emissions and improved selectivity for H2S over CO2.

In addition, it features Criterion Catalysts & Technologies’ (Criterion) C-834 high activity, low temperature SCOT catalyst, which adds further value by increasing the destruction of carbonyl sulphide (COS) in tail gas by 50-60% compared against conventional catalyst.

Benefits
In addition to meeting more stringent emission regulations and delivering enhanced destruction of COS in tail gas, operators can benefit from lower operating costs when using the SCOT Ultra line-up. The TGTU converter can be run at a lower temperature, which gives operators the opportunity to prolong cycle length and reduce energy consumption by using indirect heating instead of line burners. A significant reduction in solvent circulation rate, combined with improved H2S removal performance at higher temperatures, is achieved in the TGTU absorber through the highly selective solvent, which translates into reduced steam, cooling and power costs, and facilitates much lower energy requirements.

To quantify the benefits, the impact on capital and operating expenditure for the TGTU section using the SCOT Ultra process is shown in Figure 2. A TGTU with a generic methyl diethanolamine (MDEA) solvent and a TGTU with a formulated MDEA solvent operating at 50°C are compared with SCOT Ultra technology at 60°C solvent temperature. In this scenario, the solvent circulation rate could be reduced by 50% with SCOT Ultra compared to a TGTU with a generic MDEA solvent.