An optimum line-up for sour gas processing
Analysis of technical, economic and licensing considerations in the selection of an optimum gas treating line-up recommends a choice of technologies
Tehran Raymand Consulting Engineers
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Sour gas fields brought into production in the near future will contain considerable amounts of sulphur components. Such gas poses challenges in adapting processing technologies to meet environmental standards, improve reliability, and achieve higher margins.
This article discusses five approaches to the integration of gas treating processes in order to establish the optimum treating line-up for the design of sour gas processing plants, taking all the process limitations into account within a flexible, operable and economically justifiable window. The conclusion is that the best line-up, with respect to maximisation of treating train operability and flexibility, is the route employing molecular sieve technology for gas dehydration and mercaptan removal, with hydrocarbon dew point control using a propane refrigeration system.
A range of gas processing systems are available to provide products to the specifications defined by plant owners. This variety places a huge burden on the owner to select the right technologies to fulfill an optimised scheme that meets technological and economic targets. Given the magnitude of the investment in a gas processing plant, it is appropriate to carry out a rigorous selection study to identify the most cost-effective and appropriate treatment package. A general scheme of a typical gas processing plant is shown in Figure 1. Field production, on arrival at the processing plant, is processed in a slug catcher, which captures liquid and allows it to flow into downstream equipment and facilities at a rate at which it can be handled properly.
Gas from the outlet of the slug catcher is directed to a high- pressure (HP) separator, where final separation of the liquid from the gas takes place. The HP raw gas flows through to the gas sweetening unit (GSU), in which acidic components including H2S and CO2 are removed by means of chemical solvents. The enriched acid gas from the GSU is processed to produce elemental sulphur in a sulphur recovery unit (SRU), consisting of a Claus unit, and an associated tail gas treating unit (TGTU) if higher recovery rates are specified for the SRU itself. The final residual gas from the TGTU is incinerated.
Water, mercaptan (RSH) and the heavy hydrocarbon components of the sweetened gas from the GSU should be reduced to meet sales gas specifications. The gas pressure also needs to be boosted by HP compressors before passing through the sales gas meter and into the export line.
Liquids from the reception facilities are separated again into produced water and condensate. Produced water is treated and used, while the condensate is combined with hydrocarbon liquids knocked out in the dew point control unit (DPCU). It is then processed in the condensate stabilisation unit (CSU) to reduce the Reid vapour pressure (RVP) and enable storage in atmospheric storage tanks. For sour condensate coming in, if any treatment is required for the heavier sulphur components, complex treatment involving hydrogen is necessary.
The arrangement of gas processing units shown in Figure 1 is typical and illustrates the functional blocks required to achieve the objectives of a plant designed to produce pipeline gas from a sour gas feed. The function of each of these blocks (or combinations of blocks) can be achieved in a variety of ways; some technology options may result in one or more of these functions being achieved simultaneously (thus reducing the complexity of the design). As an example, molecular sieves can be used for both dehydration and mercaptan removal, reducing the two steps presented in the scheme to one.
The water and mercaptans desorbed from the bed during regeneration can be captured by a physical absorption process to concentrate the mercaptans in a stream being sent to the SRU. The bulk of the mercaptans might be reduced in this way and will limit the sulphur species being condensed in the different natural gas liquid (NGL) cuts. Instead of having to use expensive caustic-based processes, molecular sieves or other adsorbents could be used for the fine sweetening of the liquids.1 However, operational problems and upsets in the molecular sieve unit can make that unit the bottleneck of the plant. Where a molecular sieve unit is a bottleneck, extensive know-how may be needed to improve its performance.2
Process treating line-ups
Natural gas processing is often thought of as a mature technology with little opportunity for improvement or innovation. However, changes in the requirements of customers continue to drive improvements in technology. Five aspects of integration of the treating processes involved in a sour gas processing plant are proposed here in order to establish the best treating line-up. A typical scheme for each line-up is shown in Figures 2 to 6.
Line-ups 1 to 3 (see Figures 2 to 4) have the same gas treating sequence but different technologies for controlling the hydrocarbon dew point. In fact, in line-ups 1 to 3, the sweetened gas from the GSU is first routed to the gas dehydration and mercaptan removal unit utilising molecular sieve technology, then to the hydrocarbon DPCU utilising propane refrigeration, silica gel technology and Joule-Thomson expansion technology, respectively.
Line-ups 4 and 5 (see Figures 5 and 6) have the same gas treating sequence with different technologies for gas dehydration and hydrocarbon dew point control. In line-up 4, the sweetened gas from the GSU is first routed to the gas dehydration and hydrocarbon DPCU using propane refrigeration accompanying methyethylene glycol (MEG) injection, and then to the mercaptan removal unit utilising molecular sieve technology. Line-up 5 (see Figure 6) is the same as line-up 4, wherein silica gel technology has been applied for both gas dehydration and hydrocarbon dew point control.
Input parameters used for the study
In order to make a practical comparison of an integrated and optimised treating configuration for the design of a sour gas processing plant, typical gas composition and operating parameters for a sour gas field have been used in this study (see Table 1). The data given here is for illustrative purposes and should not be construed to be applicable for definitive design purposes.
More details of undefined sulphur species were not available, hence, a few properties, such as MW = 120, boiling point (BP) = 182°C and ideal liquid density = 837.7 kg/m3, have been assumed for the simulation.
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