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2.5 Discussion
First the process simulation for the six cases is discussed. Specifically the dehydration, the turboexpander, and the fractionation train processes are discussed for all cases. Additionally acid gas removal is considered for the high acid gas case. Acid gas removal is not needed for Feeds #1–5 as acid gas levels (CO2 and H2S) already meet specifications. Free water removal is not needed, as it is assumed only bound water is present (see Section 2.4).
2.5.1 Process Simulations
2.5.1.1 Dehydration Process
For all five cases, the first unit operation of the gas treatment process is dehydration. The typical dehydration process used in natural gas processing is glycol dehydration, with the flowsheet shown in Figure 2.3. As mentioned previously, the goal of the glycol dehydration process is to remove thermodynamically bound water from the gas to permissible levels. Triethylene glycol (TEG) is the most commonly used solvent in industry for water removal. This process contains two loops, i.e. the contactor loop (where wet gas is contacted with TEG to remove water) and the regenerator loop (where water is removed from TEG in order to recycle the TEG back to the contactor).
Figure 2.3 Glycol dehydration process.
2.5.1.2 NGL Recovery Process
Figure 2.4 shows a typical NGL recovery process used in natural gas processing.
Figure 2.4 Turboexpander process (stream 19 shows the recovery of recompression work).
In all cases except for Feed #1 (for reasons discussed later), NGL recovery is done via the turboexpander process. This process is used to separate methane from the NGLs. A key feature of this process is the turboexpander, which is used to recover some recompression work done by the gas (see Figure 2.4). Another key feature of the process is the compact (brazed aluminum) heat exchanger. These exchangers can achieve much closer approach temperatures and can operate at much lower temperatures than can shell‐and‐tube exchangers [34].
2.5.1.3 Fractionation Train
As seen in Figure 2.5, NGLs may be further separated into their components using this distillation column sequence. This distillation column sequence is chosen such that components are removed in order from lightest to heaviest. This enables easy separation because it reduces the flow rate sent to subsequent columns more than would separate the components in the opposite order. The columns operate at very high pressure (from 120 to 285 psig) because at low pressures all of these components are gases. This is done for all cases except for Feed #1.
Figure 2.5 Fractionation train.
2.5.1.4 Acid Gas Removal
The acid gas removal unit simulated for this case is shown in Figure 2.6. This unit is similar to the dehydration unit (Section 2.5.1.1). The solvents (methyl diethanolamine [MDEA] and piperazine) are used to remove acid gases, CO2 and H2S, from the incoming sour gas in the absorber column, and the solvents are stripped of the impurities in the stripper.
Figure 2.6 Acid gas removal unit.
2.5.2 Profitability Assessment
Figure 2.7 shows the annual revenue associated with the five feeds and compares the revenue with the composition of methane in the feed.
Figure 2.7 Comparison of gas composition with revenue.
The total revenue increases with increasing quantity of NGLs in the feed, despite the fact that each feed is primarily methane (Figure 2.7).
Methane sales prices (heat value) are typically reported in $/MMBtu (see Table 2.5), which may be converted into an average price of US$0.02 gal/yr as shown in Table 2.6. This price is significantly less than the price of the NGLs as listed in Table 2.6. Thus, feeds with high NGL content generate higher revenue.
Table 2.6 Effective prices for products ($/gal).
| Commodity | Units | Base case |
| Heat value | $/gal | 0.02 |
| Ethane | $/gal | 0.262 |
| Propane | $/gal | 0.632 |
| n‐Butane | $/gal | 0.691 |
Table 2.7 shows the results from the economic calculations for the base case. The ROI exceeded 10%, meeting the minimum criteria for potential profitability (ROI > 10%).