Revamping the sulphur plant
Expanding the capacity of sulphur recovery and tail gas units requires a thorough review of all plant systems.
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Sulphur is present in natural gas mainly as hydrogen sulphide (H2S). Many processes in the refinery produce acid gas which is rich in H2S. This acid gas is further captured in clean sour water and lean amine. Further, the sour water is processed in a sour water stripper (SWS) and the off-gas produced is sent to the sulphur recovery unit (SRU). The sour acid gas produced, also called ammonia acid gas (AAG), is usually rich in ammonia and H2S. The rich amine from different refinery units is collected and processed in an amine recovery unit (ARU). The produced gas, also called clean acid gas (CAG), is rich in H2S. The SRU processes CAG and AAG in order to recover sulphur from the H2S molecule. The tail gas treatment unit (TGTU) is usually installed downstream of the SRU to capture unreacted H2S and to meet environmental specifications. The SRU uses the Claus process. Table 1 shows typical compositions of AAG and CAG.
High sulphur crude is always needed for higher refining margins. This need in turn drives sulphur projects in the refinery. There is no home for H2S gas in the refinery other than the sulphur units. H2S or SOx cannot be emitted to the atmosphere for reasons of safety and environmental regulations. As a result of this, a refinery’s production and profits are at risk when the SRU/TGTU is not operating.
Figure 1 outlines the various stages of SRU and TGTU operations and the areas affected by a capacity increase. The SRU takes acid gas from the amine regeneration units and SWS, converting H2S to elemental sulphur using the Claus process. Unconverted tail gas from the Claus reactors is routed to a TGTU where sulphur oxides are converted to H2S and recycled to the Claus reactors, increasing overall sulphur conversion to >99% to reduce SOx emissions.
The two unit feeds, sour water acid gas and amine acid gas, are separated in the unit with segregated feed knock-out drums. This allows the AAG which is higher in ammonia to be injected at the inlet, increasing ammonia destruction in the thermal reactor. The combined acid gas steam is mixed with oxygen at the inlet burner and combusted. Combustion air is controlled to ensure partial combustion of H2S. This facilitates the reaction between H2S and sulphur dioxide (SO2) to form elemental sulphur. The combustion section generates medium pressure steam.
The thermal reactor is followed by a condenser generating additional steam and separating the condensed elemental sulphur from unconverted flue gas. The flue gas is then reheated using high pressure steam to the catalytic reactor. There are three reactor stages, each with dedicated reheat exchangers to control temperature. After each reaction stage, there is a condenser to remove elemental sulphur and generate low pressure steam.
Unreacted tail gas contains 2-8% of inlet sulphur in the form of SO2 and H2S. The TGTU uses an amine such as MDEA to collect H2S. After H2S is removed, the tail gas is routed to an incinerator. The incinerator combusts any unconverted sulphur components (carbonyl sulphur, carbon disulphide), along with residual H2S, to SO2.
Liquid sulphur is condensed and collected by sulphur traps, then collected in the sulphur pit. The liquid sulphur is further cooled and dissolved H2S in the liquid sulphur is removed by contact with the air. The air and H2S mixture is vacuumed out using an ejector. This mixture can either be sent to the reaction furnace or the incinerator. The mixture is usually sent to the reaction furnace to increase the efficiency of the sulphur plant, otherwise the unit capacity is limited by SOx limitations. Reactions for the various stages of the process are:
• Reaction furnace
• Claus reactors
• TGTU reactor
Sulphur plant capacity basics
Mass flow limited process
A SRU/TGTU operation is a mass flow limited process; the higher the flow, the higher the pressure drop according to pressure and flow correlation. Pressure drop in the system is proportional to the square of flow. The back pressure in the system will increase with the increase in flow needed for a revamp. Burner pressure increases with the increase in back pressure of the system. Nitrogen gas is inert and unwanted in the process; most revamps replace air blowers due to the requirement for higher head and flow. If we replace nitrogen molecules in the process with more oxygen molecules, this favours the hydraulics and the capacity can be enhanced.
All control valves and flow meters should be replaced or evaluated in order to obtain a very low pressure drop for the desired increased throughput. Main gas line pressure losses should be looked at for the increased flow case. The tail gas absorber and quench tower are usually replaced with very low pressure drop packing. Reactors, condensers, and reheaters are evaluated for increased flow rate in order to obtain low pressure drops.
Capacity impacted by hydrocarbons
Hydrocarbons, with their high hydrogen to carbon ratio, are unwanted in CAG and AAG. They take up capacity and consume oxygen which is much needed for the Claus reaction. Excess water is produced by reactions with hydrocarbons and this needs to be removed through the quench tower. Quench tower duty and equipment sizes increase with additional water removal requirements. Large quantities of hydrocarbon in the feed gas interfere with the oxygen demand controller due to the high hydrogen to carbon ratio. If there are aromatics in the feed, they can coke the catalyst and essentially reduce the plant’s capacity. Some other carbon and sulphur containing compounds such as COS and CS2 are difficult to destroy and can make environmental emissions go off-spec very quickly, so these are undesired molecules.
Commonly, all SRU units have CAG and AAG knock-out pots. One can design the appropriate demister pads and hydrocarbon removal capabilities for the knock-out pots so that any carried over hydrocarbons do not compete with oxygen demand in the Claus process. If the SRU unit does not have knock-out pots, it is necessary to add them to avoid issues with hydrocarbons. Rich amine flash drums, located in ARUs, are often not designed to remove hydrocarbons, so light hydrocarbons as part of the CAG will end up in the SRU. A good design for a rich amine flash drum has a residence time of 30 minutes for adequate separation of hydrocarbons from rich amine. Inefficient operation, for instance not enough reflux, insufficient reboiling of ARU and SWS, can cause hydrocarbon carry-over to the gas streams. The design of a clean sour water storage tank is also crucial in the removal of hydrocarbons.
Capacity impacted by ammonia
AAG tends to contain ammonia from upstream oprocessing units. Ammonia forms salt scaling which can build up over time and cause fouling and scaling. Increased scaling can reduce heat transfer in the reaction furnace and heat exchangers; ammonium salts deposit in the burner nozzles thus reducing capacity. The reaction furnace should be designed appropriately to destroy ammonia in the front chamber. A CAG preheater is often added to new projects and revamps. In addition, ammonium salt formation is favoured below 185°F (85°C). For this reason, AAG and combined acid gas pipes are often steam jacketed or contro-traced to prevent salt formation.
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