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Developing a sulphur master plan
South-East Asian refinery secures its licence to operate.
The environment is a key issue on the agenda of governments around the world – and refiners are right on the front line. They have a major role to play, not only in delivering the cleaner fuels that society is calling for but also in curbing plant emissions.
Despite having a strong track record of applying innovative solutions to meet environmental legislation, a South-East Asian refinery faced a particularly severe challenge in 2006.
The regulator that sets the environmental emissions limits for the country’s industrial facilities had indicated that the refinery’s emission limits were going to be acutely curtailed.
The regulator had been reducing SO2 emissions limits by 15% every three years, but now it was warning of a step change.
It was going to adopt the World Bank guidelines of 500 mg/Nm3 for fuel burning equipment and 150 mg/Nm3 for SRUs.
As the SO2 emissions from the SRUs were, at the time, substantially higher at about 30,000 mg/Nm3, this would require a change in operating philosophy.
The refinery was already operating close to its current limits, so much so that it had to process more expensive, low-sulphur crudes to avoid exceeding its limit.
The challenge was exacerbated because the refinery had plans to install a new hydrodesulphurisation unit to produce ULSD, as even better sulphur recovery capabilities would be required.
Moreover, sulphur was not the only challenge. Although the plant’s carbon monoxide (CO) emission limit was unlikely to change, the plant had difficulty meeting its existing CO emissions limit because of the gas treating configuration at that time. Any solution would have to factor this in as well.
The refinery’s response was to commission a sulphur master plan study. This involved site technologists, and gas processing specialists and process engineers from Shell Global Solutions. Working closely as an integrated on-site team, they conducted brainstorming sessions and technology selection studies before delivering detailed proposals for how the refinery could reduce its sulphur emissions. The team also spearheaded the implementation of these proposals, including the installation of new units.
Divergent thinking was a recurring theme of these early phases.
The team invested a lot of effort in challenging all aspects of the site’s situation and exploring technology options.
There are usually multiple solutions to a problem and the team was keen to identify all the paths that were available to them to ensure that they would ultimately select the solution most appropriate for their specific situation.
The refinery’s original gas processing configuration featured an amine treating system using diisopropanolamine as the solvent for removing H2S from the various refinery units.
The removed acid gas, along with sour water-stripper off-gas, which also contains significant quantities of H2S and ammonia, went to five SRUs that converted the H2S to liquid sulphur.
The tail gas from the SRUs passed to a common third-stage Claus unit and a third-party tail-gas-treating unit for enhanced sulphur recovery.
The remaining H2S was incinerated in catalytic incinerators and the tail gas produced was sent to the stacks.
A sulphur pelletiser unit solidifies the liquid sulphur from the SRUs.
The solid sulphur was collected in a storage pit and periodically removed and loaded on barges for transport to customers.
The team calculated that the 500 mg/Nm3 and 150 mg/Nm3 limits of SO2 translated to sulphur recovery efficiencies of 99.90 and 99.98% respectively. The existing tail-gas-treating unit could only take the refinery to about 99.3% sulphur recovery; to go beyond this would require a different tail-gas-treating technology.
The team considered numerous tail-gas-treating processes, including the standard Shell Claus off-gas treating (SCOT) process, which uses catalytic conversion and amine absorption processes to remove sulphur compounds from Claus tail gas; the LS SCOT process, in which a low concentration of an inexpensive additive is added to the amine to improve solvent regeneration and achieve very low sulphur emissions (as low as 10-ppmv H2S or 50-ppmv total sulphur); and the Super SCOT process, which uses an additional regeneration stage and can meet SCOT off-gas specifications of as low as 30-ppmv H2S.
The team also evaluated non-Shell technologies, but determined that the conventional SCOT process offered the most compelling solution for tail-gas treating. This was more appropriate because it offered the capability to reduce both SO2 and CO emissions from the SRUs. In addition, the reduction in SO2 emissions from the SRUs created short-term margin benefits. SCOT is a proven technology that is capable of meeting SO2 point source emission limits and hence is a no-regret investment for future compliance. Availability levels of greater than 98% can be achieved.
Crucially, the team was also able to meet the CO emissions regulation by making small modifications to the catalyst, the operating temperature and the reactor design typically used in a standard SCOT design.
In addition, to provide the extra sulphur recovery capacity that would be necessary when the new hydrodesulphurisation unit came on-stream, an additional SRU had to be installed.
The SCOT unit and the additional SRU have delivered value in several ways. First, and perhaps most importantly, they have improved the refinery’s environmental performance and secured its licence to operate. Second, there have been margin benefits through the refinery’s ability to process higher-sulphur, less-expensive crude and its ability to maximise its yield of ULSD without exceeding its sulphur emissions. Third, operating costs have also fallen because of the enhanced reliability of the new gas processing plant.
The SCOT unit and the new SRU have been performing well since they were commissioned in mid-2012 and early 2013 respectively. All performance guarantees have been met.
The success of the project is due, in large part, to the refinery taking early, positive action when faced with the prospect of having to substantially cut both sulphur and CO emissions. This meant that it was able to take a reasoned, phased approach, which helped to manage the capital expenditure requirements. It also meant that the team could evaluate the widest possible technical solution set, something that can be key to avoiding regret investments.
The SCOT unit and the additional SRU have improved the refinery’s environmental performance and secured its licence to operate .
The refiner’s willingness to bring in external expertise was also a significant factor. The refinery technologists played a vital role, as they brought knowledge of the refinery’s specific processes, drivers and constraints to complement the global operating experience of Shell Global Solutions. Its staff, for instance, were able to relay their experiences of what has worked well at other similar projects around the world and to show them Reference sites to demonstrate similar technology schemes in operation.
This customer’s drivers are not uncommon – other refiners are likely to face similar challenges in the next few years as regulators worldwide tighten their emissions controls. Many will have to adapt to World Bank standards, which prescribe that refineries should emit no more than 150 mg/Nm3 SO2, and restrictions on CO emissions are also imminent, but this particular case demonstrates that technology solutions exist to meet them.
Senior Engineer, Shell India Markets Pvt. Ltd
South East Asia
|Solution type||New units
|Principal conversion units (pre-project)||Hydrocracker, FCC unit, hydrodesulphurisation units
|Conversion facilities to be installed as part of the project||ULSD hydrodesulphurisation units
|Sulphur recovery facilities (pre-project)||Five SRUs followed by a third-party tail-gas-treating unit
|Sulphur recovery facilities (post-project)||Six SRUs followed by a SCOT unit
|Post-project feed||Heavier, sourer crudes|
|Post-project product slate||Gasoline, ULSD, jet fuel, fuel oil|