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Oct-2015

Dealing with depleting sour gas reserves Part 2

Gas plants in western Canada will have to evaluate their sulphur recovery units for future turndown operation as sour gas production falls.

MARCO VAN SON and SHASHANK GUJALE
Jacobs Comprimo Sulphur Solutions
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Article Summary
In recent years, most of the sour gas reservoirs in Alberta have been depleting and most of the new wells coming on-line are sweeter and leaner, which has resulted in a reduction in acid gas feedstock available to the existing sulphur recovery units (SRU) installed in the gas plants. As a result, Jacobs Comprimo Sulphur Solutions has been involved in the investigation, evaluation and recommendation of processing options available to these SRUs to enable them to operate in severe turndown conditions. The first part of this article (PTQ, Q3, 2015) introduced recovery guidelines in Alberta and presented two case studies on techniques for adapting sour gas plants for reduced throughput capacity. This second part of the article discusses two further options.

Case study: refinery turndown from 80t/d to 5 t/d
At a refinery in Canada, the overall processing capacity of the existing SRU was expected to fall from 80 t/d design to 5 t/d. The plant consisted of a conventional three-stage Claus unit, which only processed amine acid gas. At this particular facility, the sour water acid gas from the sour water stripper unit was routed to the incinerator, where the ammonia was destroyed to an unknown level and the H2S was converted to SO2 before emission to the atmosphere via the stack. This is common practice when a two-stage sour water stripper is installed and the ammonia and H2S are segregated. The ammonia, which contains some H2S, can be routed to the incinerator and the H2S is routed to the SRU. For this refinery, a single-stage sour water stripper was installed and all H2S released from the sour water stripper was routed to the incinerator. This was fairly common practice in the past, however with more stringent regulatory requirements for refineries, this is no longer the practice in industry. For the purposes of the study, it was assumed that the plant would continue to operate this way in the near future. In addition, and again contrary to current industry practices, there was no government regulated overall sulphur recovery efficiency that needed to be met.

Jacobs evaluated the addition of co-firing with natural gas to ensure that no back-firing could occur in the existing burner and recommended changes to the control system to the plant to ensure safe and reliable operation with co-
firing. In this facility, the burner management system for the natural gas supply to the burner was not tied into the control system and it was common practice at the facility to relight the burner from the hot refractory. Additionally the SRU operators were used to operating the unit with excess air during natural gas firing. In order to prevent fires in the first converter, a portable oxygen analyser was used downstream of the waste heat boiler to ensure that the excess oxygen did not exceed 0.5%. This practice was not favoured by the operators and Jacobs was requested to provide assistance in revising the control system to allow for controlled hot standby operation. For this particular project, the control system of the SRU was redesigned to include flow measurement of the natural gas and options to the operator to operate the unit in super- and sub-stoichiometric ratios for cold start-up and hot standby operation respectively. In addition, the option to use moderating steam in a controlled fashion during natural gas firing was added to control the furnace temperature.

The proposed modifications to the control system for the existing unit are shown in Figure 1. As can be seen, pressure and temperature compensation for all of the gas streams was added to improve on the accuracy of the control. In order to properly control overall air demand, the control included air to acid gas and air to natural gas ratios, with the ability to choose the combustion stoichiometry of 
natural gas. Typically, Jacobs recommends a stoichiometry of 95% for dry natural gas. Pipeline quality natural gas is preferred, however fuel gas may have to be considered in certain scenarios when no natural gas is available. It is our recommendation to install a fuel gas analyser in case of unsteady fuel gas composition. 
This will allow on-line adjustment of the air to fuel gas ratio as a 
function of the fuel gas composition.

Several additional items, such as ESD valves on both the combustion air and the moderating steam supply, were also recommended. These items were not always part of the design of a SRU in the past but especially the ESD valve on the combustion air supply to the burner is currently highly recommended to prevent back flow of acid gas or natural gas to the suction of the combustion air blowers.

Further to the control modification, a fully automated light off for the main burner was also implemented. This particular plant still lit the main burner from the refractory and had no purge procedure before introduction of combustible gases, thereby increasing the risk of deflagration in the furnace during light off. It is a well-known fact in the industry that most of the failures in a SRU occur during start up and shutdown of the facility. Therefore Jacobs believes that by fully automating the light off of the burner, the risks for potential problems are substantially reduced. The light off procedure consists of the following steps:
• Automated purge of the main burner and reaction furnace
• Typical value five volumes in five minutes
• Automatic introduction of air and natural gas at a predefined ratio set for light off
• Automatic insertion of a retractable igniter into the burner and ignition of the flame
• Once a flame has been established, the control of the burner management is given over to the operator.

With the recommended modifications, this facility can operate comfortably between 5 and 80 t/d capacity. Of course, overall sulphur recovery will be impacted by the addition of natural gas co-firing, however as this plant was not bound by regulatory limitations further modifications were not required at this stage. For the future, further design improvements during turndown can be considered by this facility, such as the addition of sour water acid gas and the installation of titania catalyst for increased COS and CS2 hydrolysis.

One item that was considered and recommended to this refiner was to process the sour water acid gas in the main burner instead of the incinerator. As the turndown of a high efficiency burner, which had been installed in this facility, is typically limited because of pressure drop across the burner, adding the sour water stripper acid gas would require a higher air demand and thereby increase the overall flow through the burner. This could result in reducing the amount of natural gas that needs to be added during normal turndown operation to prevent back firing of the burner. Of course, additional evaluation of the capability of the plant to properly destroy the ammonia present in the sour water stripper acid gas will be required. This will ensure that ammonium salts do not deposit in the colder areas of the unit due to poor ammonia destruction in the reaction furnace.

In conclusion, the availability of a well designed and tuned control system is essential to allow the plant to operate under all conditions. The installation of air to acid gas and air to natural gas ratios, and ensuring that the flow measurements are compensated for pressure and temperature, will provide the operator with more flexibility and control of the plant. This will apply during normal operation as well as hot standby operation and minimise the risk of sulphur fires and sooting of the catalyst that can result from poor control of natural gas firing.
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