Maximising gas plant capacity
Water entrapment and foaming must be avoided to maximise LPG recovery and minimise downstream unit contaminants
Tony Barletta and Scott Fulton, Process Consulting Services
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FCC and coker gas plant absorber/deethaniser (stripper) revamps need to fully utilise column capacity to maximise propylene recovery and capacity. Yet two phenomena – formation of a free-water phase and foaming – continue to limit capacity, reduce propylene recovery and increase LPG product C2 and hydrogen sulphide (H2S) content. Reliance on process models that do not predict where free-water forms or the increase in vapour/liquid loading that accompany it, and failure to account for foaming systems, are largely to blame.
FCC and coker gas plants recover C3 and C4 hydrocarbons from main column overhead wet gas, reject the bulk of the C2 and H2S to fuel gas and separate the C3 and C4 from the gasoline or coker naphtha. In the primary absorber, main column overhead liquid and debutaniser bottoms absorb C3 and C4 from the feed gas leaving the HP receiver. To meet downstream unit specifications, C2 and H2S must be stripped from the C3 and heavier hydrocarbons feeding the deethaniser (Figure 1).
In most gas plant designs the deethaniser bottom stream feeds the debutaniser where the C3 and C4 are fractionated from FCC gasoline or coker naphtha. In a small percentage of gas plants the deethaniser bottoms stream feeds a depropaniser operating at higher pressure (Figure 2). In this case, most of the water and C2 need to be removed upstream in the deethaniser. Otherwise, severe foaming occurs directly above, in the feed zone and directly below the feed in the depropaniser.
If the depropaniser diameter is too small or the trays are designed without using a system factor, flooding occurs well below design feed rates. System factors between 0.7 and 0.8 have been observed. Fortunately, only a few refiners have the depropaniser immediately downstream of the deethaniser, so this problem is not common.
Gas plant absorbers recover C3 and heavier hydrocarbons at operating pressures and temperatures between 100 and 260 psig and 50–140°F while C2 and H2S are stripped in the deethaniser. The goals are to maximise C3 recovery while removing only enough C2 and H2S to meet downstream unit specifications. Low temperature and high pressure in the absorber and HP receiver favour C3 recovery, but also increase the tendency to form free-water.
Water may be formed in the absorber as cold liquid streams contact hotter vapour at feed and inter-cooler return locations, but this causes few problems. Conversely, when a water phase is present in the top of the deethaniser, it can significantly reduce capacity. Moreover, low temperature and high pressure also increase this system’s tendency to foam.
Figures 3 and 4 show two common absorber/deethaniser system process flow schemes.
Figure 3 has two columns, external high-pressure (HP) condensers and receiver, and an inter-cooler. The HP receiver condenser cools compressor discharge, deethaniser overhead vapour and absorber bottoms liquid streams. Ideally, the HP receiver is designed to effectively separate condensed hydrocarbon liquid and water phases. Vapour containing C3 and C4 and lighter components feed the bottom of the absorber while the hydrocarbon stream saturated with water is pumped to the deethaniser.
Because the absorber bottoms stream is routed to the HP receiver condensers, water can be separated before feeding the deethaniser. Yet, in several instances poor HP receiver oil/water phase separation have caused free-water in the feed to the deethaniser.
An alternative flow scheme uses a single column for absorbing and deethanising (Figure 4). Discharge from the wet gas compressor is cooled and the three phases are separated in the HP receiver. The vapour stream feeds the absorber section while HP receiver liquid is pumped to the top tray of the deethanising section. Liquid leaving the absorber flows directly to the top of the deethanising section and deethanising section overhead vapour flows directly into the absorber.
Because stripper vapour and absorber bottoms liquid streams flow internally, they are not cooled. Thus, the single column design is more energy efficient and lower capital than a two-column flow scheme. But the single column design is more difficult to operate without high C3 losses to fuel gas. Furthermore, operating conditions are very favourable to formation of free-water phase in the top of the deethanising section, whereas the water phase is not always present with the two-column design.
Main column overhead liquid and debutaniser bottoms recycle streams recover C3 and C4 from the wet gas compressor discharge stream. Pre-saturators and inter-coolers are sometimes used to minimise temperature rise. Occasionally, chillers or refrigeration are used to lower operating temperature below cooling water temperatures (Figure 1). The deethaniser then strips C2 and H2S by adding heat with reboilers, side reboilers, and/or feed pre-heaters.
Absorber C3 and C4 recovery is largely a function of liquid/vapour molar (L/V) ratio inside the column, and operating temperature and pressure. Lean oil absorbs C3 and C4 and the temperature rises due to latent heats of the components being absorbed. Inter-coolers and pre-saturators reduce temperature rise and improve C3 recovery by 4–6% when designed properly. Some FCC gas plants use chillers to increase propylene recovery to over 99%. As absorber L/V increases and temperature decreases, propylene recovery improves. Yet as recovery goes up, the amount of heat that must be added in the deethaniser to strip C2 and H2S also increases.
Minimising heat input to meet downstream unit C2 or H2S specifications maximises absorber C3 recovery because L/V in the absorber goes up. But in practice, controlling deethaniser bottoms product C2 or H2S content is difficult because the quantities are very low, thereby making inferential control using temperature ineffective and unresponsive. Yet it remains the most common control methodology.
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