Dealing with depleting sour gas reserves: Part 1
Depletion of sour gas production in western Canada means that gas plants will have to evaluate their sulphur recovery units for future turndown operation.
MARCO VAN SON and SHASHANK GUJALE
Jacobs Comprimo Sulfur Solutions
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In recent years, most of the sour gas reservoirs in Alberta have been depleting and new wells coming on-line are sweeter and leaner, resulting in a reduction in the quantity and the richness of the acid gas available for existing sulphur recovery units to process. As a result, Jacobs Comprimo Sulfur Solutions has been involved in the investigation, evaluation and recommendation of processing options available to these sulphur recovery units that will need to be operated in severe turndown conditions.
As most of the sulphur recovery units in Alberta, Canada are older, they were not necessarily designed for turndowns as large as 10 to 1, or for lean acid gas operation. Different options were explored for several gas plants and also one refinery to allow the SRU to process the predicted acid gas and still maintain the regulatory requirements for the facility. These options vary from replacement of individual equipment items in the existing SRU, to operating with natural gas co-firing, to catalyst replacement and finally installation of a complete new SRU.
This article in two parts will describe plants where acid gas rates and composition have become a concern, what the proposed modifications were to ensure that the processing objectives of the facilities could still be met in the coming years. At the same time some performance data from operating with natural gas co-firing and its impact on sulphur recovery will be discussed. This first part of the article includes case studies for two gas plants; the second part will include case studies for a further gas plant and a refinery.
In Alberta, the maximum allowable regulatory requirements for sulphur emissions are dictated by the inlet sulphur rate to the plant. The overall sulphur recovery requirement can be calculated as seen in Table 1.
The information in Table 1 is specific to Alberta requirements and the local legislated sulphur recovery efficiencies need to be evaluated on a case by case basis depending on the location. As is clear from Table 1, in the case of reduced sulphur plant capacity, an option that can be considered is relicensing to allow lower sulphur recovery efficiencies in the plant.
Case study: using co-firing to produce mass flow
For the first case study, Jacobs Comprimo Sulfur Solutions evaluated the options for a sulphur recovery unit at a gas plant in Alberta which was originally designed for 550 t/d and expected to have a future processing capacity of less than 100 t/d. In addition, the original plant was designed for an acid gas quality of 75 vol% and it was expected that, due to the processing of leaner sour gas streams, the acid gas H2S concentration will drop to 50 vol%.
The plant in question had severe turndown limitations due to its configuration which consisted of two hot gas bypass reheaters and a gas/gas exchanger. The configuration of the unit is provided in Figure 1. In addition, the plant had a two-pass waste heat boiler producing 400 psig steam on the tube side, contrary to the more commonly employed firetube design. The condensers of the facility produced 50 psig steam and had a common steam drum. The original burner in the plant had been replaced with a high intensity burner.
The sulphur plant is an existing three-stage Claus unit followed by an 1100 t/d Sulfreen unit with an overall sulphur recovery efficiency of 99.0%. According to the Alberta Sulfur Recovery guidelines, the future regulatory sulphur recovery requirement for the plant is 98.5% when operating at 100 t/d or less inlet sulphur.
The obvious limitation of the plant to operate at high turndown is the reheater configuration. Based on the plant’s experience, the current minimum processing capacity of the unit corresponds with approximately 120 t/d. The key reason for the limitation is the inability of the gas/gas exchanger to heat the inlet gas to the third converter sufficiently to remain above the sulphur dewpoint in the catalyst bed. The plant indicated that after a recent replacement of the tubes in the waste heat boiler, the turndown capability of the plant had actually decreased, resulting in more concerns with the future operation of the plant. The impact of replacing the tubes in the waste heat boiler can be explained by the lower temperature from the first pass of the waste heat boiler. As the gas from the first pass of the waste heat boiler is used to heat the process gas to the first and second converters, a higher efficiency of the waste heat boiler has a negative effect as more gas is required to meet the same inlet temperature into the converter. This also results in less condensation of sulphur in the thermal condenser, thereby applying additional sulphur load on the second and third stage of the SRU. This has an impact both on recovery and on the sulphur dewpoints in the subsequent converters.
The following options were considered to allow the plant to process the expected future sulphur processing capacity:
1. Install a new 100 t/d SRU
2. Replace the second and third reheater with steam reheaters
3. Use co-firing with natural gas to increase the mass flow through the unit and use titania catalyst to counteract the higher formation of COS and CS2.
The first option, to install a new 100 t/d SRU meeting 98.5% sulphur recovery at an estimated cost of $25-30 million, was deemed too expensive by the client, so this option was eliminated without much review. In order to meet the required 98.5% overall sulphur recovery efficiency, some form of tail gas treatment would still be required and hence the installation of a grassroots unit was considered cost prohibitive. It would also limit the plant to being able to return to higher capacities in the future in case new sour wells were added to the plant.
As the key limitation of the plant’s turndown capabilities appeared to be its configuration, and more specifically the third stage gas/gas reheater, Jacobs evaluated the option to replace the third stage reheater with a steam reheater. A steam reheater was selected as the client was not in favour of adding additional burner management systems to the plant which would be required with the installation of a direct fired (either acid gas or natural gas) reheater.
In order to evaluate the performance of the first pass of the waste heat boiler, historical data were collected from the plant, where the outlet temperatures of the first and second pass of the waste heat boiler were plotted as a function of the throughput of the unit. Using this data, it was possible to estimate the minimum temperature required for the outlet of the first pass of the waste heat boiler to ensure sufficient hot gas would be available to reheat the inlet gas for the second converter, which would then ensure that there is sufficient heat available for the third converter.
In order to maximise turndown, the decision was made to consider both the second and third reheaters for replacement with steam reheaters. The steam available for the new reheaters was only 400 psig, corresponding to a temperature of 445°F (230°C). This steam temperature would limit the capability of the plant to perform a heat soak on the second and third converters. However, as the plant is currently already not able to do a heat soak in these beds, this was considered acceptable. The first stage hot gas bypass was maintained due to the inability to increase the inlet temperature into the first converter with 400 psig steam.
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