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Optimal processing scheme for producing pipeline quality gas

Exploring processing line-ups for optimal design of sour gas processing plants. The gas processing plant must be a ‘fit-for-purpose’ design, meeting project economics and environmental requirements.

SAEID MOKHATAB, Gas Processing Consultant
GERRIT BLOEMENDAL, Jacobs Comprimo Sulfur Solutions
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Article Summary
When determining the proper solution set for a gas processing project, it is not only important to select the proper technology within each processing unit but also to adjust sequencing of the processing steps in order to optimise the whole operation, thereby increasing operating flexibility within the overall gas processing plant. This article discusses the considerations required to determine the optimal processing line-up for sour gas processing plants producing pipeline quality gas.

The choice of gas processing plant configuration and its complexity depend upon the feed gas compositions and the levels of treating and processing required in meeting product specifications and emission limits. The values of the hydrocarbon liquid products can also be drivers for process complexity, which determines the levels of natural gas liquid (NGL) components to be recovered (see Figure 1). While contaminants and sulphur compounds must be removed to meet emissions requirements, the extent of processing to recover NGL components is project specific.1

A typical scheme for a gas processing plant producing pipeline quality gas is shown in Figure 2. As can be seen, different gas processing steps are required to meet the product specifications defined by the gas processing plant’s owner. The number of combinations of possible processing steps presents a challenge to determine the best processing scheme to meet technological and economic targets while providing flexible and reliable operability. In configuring the optimal processing line-up, the plant designer must understand the technology options available, their integration opportunities and their limitations. Technical risk, licensor experience, degree of commercialisation, safety, health and environmental aspects all need to be weighed along with the process and economic performance of the technologies concerned.

Proposed gas processing line-ups
Natural gas processing is often considered a mature industry with little opportunity for improvements or innovations. However, changes in the product market continue to drive improvements in gas processing technology. Experience has proven that operating costs and investment constraints are becoming more important when selecting the proper gas processing solution for developing more unconventional and stranded gas reserves. In general, the following steps shall be followed for determining the proper technology line-up for a gas processing project:2
• Select the appropriate technology for each gas processing step
• Consider interactions between different gas processing units
• Adjust the sequence of gas processing units.

This section proposes three integration schemes of the gas processing steps for a sour feed gas containing mercaptans. Typical schemes of each line-up have been illustrated in Figures 3 to 5. Note that for the selection of the acid gas removal technology to remove hydrogen sulphide (H2S) and carbon dioxide (CO2), differences are only marginal, where more often the technology selection is driven by the requirement to remove trace components such as mercaptans (R-SH) and carbonyl sulphide (COS). Whereas deep removal of H2S and CO2 is now mastered, mercaptan removal from a sour gas is still considered a 
challenge depending on the concentrations involved. Different options for the combined removal of acid gas components and mercaptans have been used in various gas processing plants. The optimum solution in many cases is the distribution of the mercaptans removal capabilities over the acid gas removal unit (AGRU), utilising a mixed chemical and physical solvent or a promoted methyl diethanolamine (MDEA) solvent, as well as the molecular sieve unit (MSU).3

In line-up A, shown in Figure 3, the sour feed gas is sent to the AGRU utilising promoted MDEA solvents in which all acid gas components (H2S and CO2) and some parts of the light mercaptans are removed from the feed gas. The sweet gas is then routed to the gas dehydration and mercaptans removal unit utilising molecular sieve technology, and finally to the hydrocarbon dew point controlling unit (DPCU) utilising a propane refrigeration system, which requires greater operator attention and maintenance than a silica gel system, but offers greater flexibility. In this case a side (slip) stream of cold propane can be used to keep the feed gas temperature of the MSU at 40°C or below (as required by most molecular sieve vendors).

Silica gel technology may be a feasible and competitive alternative for some feed compositions (not rich in C3-C4 components) and operating conditions (temperatures below 45°C and pressures above 28.5 bara). Since total pressure drop across the silica gel bed is very low (about 0.65 to 0.85 bar), this process does not require product gas compression. However, this process may require a pre-cooling system to achieve a maximum inlet gas temperature of 45°C.4

The Joule-Thomson (JT) expansion method would not be attractive unless the required outlet pressure is much lower than the inlet pressure or the inlet pressure is too high, having the operating range in the critical region. In the case of using a turboexpander for the hydrocarbon DPCU, the outlet gas usually needs supplemental compression to fulfill product gas pressure at the delivery point, requiring high power demand, though some of the power can be recovered from the expansion process. 

In line-up B, shown in Figure 4, the sweet gas from the AGRU is firstly routed to the gas dehydration and hydrocarbon DPCU using a propane refrigeration system in which monoethylene glycol (MEG) is injected to prevent hydrate formation. Although methanol is a more effective hydrate inhibitor than MEG at low temperatures, MEG is typically chosen since it is adequate for dewpointing temperatures, safer to handle, and easier to regenerate than methanol. In this line-up, mercaptans are removed utilising molecular sieve technology.

In line-up C, shown in Figure 5, silica gel technology allows the single step removal of both water and heavy hydrocarbons from natural gas to meet the required pipeline quality gas specifications. In this line-up, mercaptan removal would be done with a molecular sieve system.

In proposed processing line-ups A to C, tail (off) gas from a Claus sulphur recovery unit (SRU), which invariably contains small quantities of sulphur compounds, shall be sent to a tail gas treating unit (TGTU) to remove the residual sulphur species in order to meet emissions regulations. In the past, the most common approach for a 99.8% plus sulphur recovery was a SRU followed by an amine-based TGTU.5 In this method, all sulphur compounds in the tail gas are converted to H2S by hydrogenation followed by H2S scrubbing by one of the selective amine-type processes so that H2S-rich gas can be recycled to the inlet of the Claus unit. Therefore, the only emission is from the CO2-rich vent gas. In this case, the TGTU can also be integrated with an upstream AGRU or acid gas enrichment unit (AGEU) to reduce emissions, simplify operations, and reduce capital cost.1 Figure 6 shows an integrated tail gas treating and acid gas enrichment scheme in which the AGEU absorber can be used to selectively absorb H2S from the lean acid gas feed, producing an H2S-rich solvent and a CO2 overhead gas. Since the AGEU uses an aqueous solution of a selective amine, the CO2 reject gas still contains some traces of H2S and most of the mercaptans as aqueous solvents have little affinity for these species. Upon passing the reject gas over the hydrogenating section, most of the mercaptans (more than 80%) will be converted to H2S, which could be subsequently absorbed in an absorber using the same solvent as in the AGEU.5
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