Designing for sulphur removal and storage: part 1
Selection of technologies for the sulphur block must serve legislative demands and the efficient operation of upstream processes
Shamim Gandhi, Wayne Chung and Krish Nangia
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The sulphur block is an essential part of any new or revamp refinery project and its cost contributes significantly to the overall cost of a project. A typical sulphur block includes facilities for hydrogen sulphide removal, amine regeneration, sour water treating, sulphur recovery, tail gas treating, sulphur degassing, sulphur granulation and sulphur storage. The major criteria in selecting the sulphur block’s design include the project’s environmental regulatory constraints, process design requirements, operating philosophy, plant reliability, and the associated capital and operating costs.
This two-part article discusses some key issues in process design configuration, which should be addressed during the early phases of any sulphur block project. These include selection of unit capacity and number of processing trains, the sparing philosophy, amine system design considerations, such as solvent selection. It also addresses issues such as licensor selection for the sulphur recovery and tail gas treating units. Design considerations for revamping existing sulphur block units or installing new facilities, and integration of a new sulphur block with upstream process units are also discussed in this article.
Many projects aim to increase bottom-of-the-barrel processing and produce clean fuels mandated by regulatory agencies. Most of these projects are based on processing heavy crude with greater amounts of sulphur and nitrogen. Regardless of the configuration of the upstream process units, sulphur and nitrogen compounds are converted to hydrogen sulphide (H2S) and ammonia (NH3) and must be removed from the hydrocarbon product streams.
H2S and NH3 are processed in a series of downstream sulphur block units, including the hydrogen sulphide removal unit (HSRU), the amine regeneration unit (ARU), the sour water treating unit (SWTU), the sulphur recovery unit (SRU) and the tail gas treating unit (TGTU). To handle the additional H2S and NH3 load from new and modified upstream process units, either the existing sulphur block units are revamped or new units are added.
The SRU and TGTU sections contribute significantly to the capital cost of the sulphur block; however, the HSRU, ARU and SWTU also play an important role in integrating sulphur block units with upstream process units.
The following issues should be considered during the early phases of a sulphur block project; they are based on recent experience with new and revamp refinery projects:
• Project-specific environmental requirements
• Sulphur block unit capacity and train configuration selection
• Process licensor selection for SRU/TGTU
• Design basis for SRU/TGTU
• Amine system design issues, including solvent selection
• Sour water treating options
• Sulphur degassing and sulphur storage design considerations.
Sulphur block units are primarily environmental control process units. They allow upstream process units to generate revenue, while keeping the refinery in compliance with health, safety and environmental (HSE) requirements. The purpose of the sulphur block is to meet or exceed these requirements and to maintain a high degree of reliability so as not to interrupt the operations of the upstream process units.
One of the first activities is to identify clearly the environmental regulatory requirements that are specific to the project and could affect the design of the sulphur block.
Refinery fuel gas specification
Process units generate refinery fuel gas, which is treated for H2S removal prior to reuse as fuel in the refinery’s fired heaters and boilers. Typical specifications can vary between 50 and 160 ppmv H2S. In addition, for US refineries, the latest regulations under consideration â€¨by the Environmental Protection Agency (EPA) limit annual â€¨allowable H2S emissions. Other components such as carbonyl sulphide (COS) and mercaptans should also be addressed to meet total sulphur limits in the fuel gas.
It is important to finalise the H2S specification early in the design cycle; it affects solvent selection for the upstream process units and the fuel gas contactors.
Tail gas emissions specification
The specification for sulphur dioxide (SO2) emissions leaving the TGTU incinerator stack can vary between 10 and 250 ppmv, depending on local environmental regulations. The type of TGTU selected is based on the required level of sulphur recovery and the specification for SO2 emissions from the thermal oxidiser. The vent from the sulphur degassing section is normally routed to the thermal oxidiser for incineration. The degassing vent, however, can be recycled to the SRU reaction furnace if the requirement for thermal oxidiser stack gas emissions is very tight; say, less than 100 ppmv. The recycle affects the design of the SRU, especially its burner control systems.
Sulphur recovery requirement
Depending on local regulations, the sulphur recovery requirement can vary from 98.5–99.9%. A three-stage Claus process can achieve about 97%; however, recovery in excess of 99.5+% is typically required for new projects, which require a TGTU. Table 1 shows typical sulphur recovery levels for various SRU/TGTU technologies.
Regulatory requirements for sparing SRU capacity
Some agencies require the refinery to install spare SRU/TGTU capacity as a condition for permitting. This should be considered in establishing the capacity and train configuration. For example, some states have a requirement for 75% SRU/TGTU remaining capacity. This requires the refinery to maintain at least 75% capacity of the project requirement, even during a shutdown of one SRU or TGTU. This requires the refinery to install additional capacity over actual sulphur loads. It also essentially eliminates the possibility of the two SRUs with a common TGTU configuration, as a shutdown of one TGTU will cause the shutdown of both SRU trains.
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