1. 2.3 dehydration dehydration or removal of water from gas stream is necessary to prevent hydrate formation and increase the heating value of the gas a) water content of gas f(T,P,composition) amount gas can “hold” increases with pressure sour and acid gases can hold more water (increased solubility of water) e.g. 100% C1 @37.8C 500 kPa1000 mg/Sm 3 wet gas 30% C1 60% CO2 10% H2S1500 mg/Sm 3 wet gas 100 % CO21700 mg/Sm 3 wet gas - to determine H2O content requires experiment/gas analysis

2. b)Hydrates crystalline “ice-like” structures, water lattice where CO2, HC, N2, H2S occupy cavities (diagram) crystalline molecular complexes formed from mixtures of water and suitably sized gas molecules water (host) molecules, upon hydrogen bonding, form unstable lattice structures with several interstitial cavities  gas (guest) molecules occupy lattice cavities and when minimum number cavities occupied crystalline structure becomes stable  solid gas hydrates forms even at temperatures well above the ice point. 3 recognized structures (so far) i. structure I – body centred cubic w/ smaller molecules (C1, C2, CO2, H2S) ii. II – diamond lattice, larger molecules (C3,C4) iii.III – most HC>C4 don’t form hydrates or stable lattice but some isoparrafins and cycloalkanes > C5 can form stable

3. in general hydrate formation is time dependent and the rate is f(gas comp, presence nucleation sites in l phase, degree of agitation) primary considerations effect hydrate formation (pt @ which first l forms) 1. gas or l @ or below dew pt 2. T, P, composition secondary considerations mixing, kinetics, physical site for nucleation (pipe elbow, orifice, dead space), salinity in general hydrates prone to form at high P or low T own figures

4. hydrate line bubble pt curve dew pt curve

5. c) Hydrate inhibition options to gas dehydration if not practical or feasible  try to inhibit the formation of hydrate by adding chemical which shifts the phase diagram away from hydrate (think adding salt to roads)  or decrease T hyd form inject glycols or methanol - combines w/ condensed aqueous phase  decreases T hyd form - chemical recovered with aqueous phase at separators d)Gas Dehydration i. glycol units glycol is a l (DEG, TEG  most common, tetraethylene glycol TREG) applications where T DP depression of 30-70 C required usually preceded by inlet gas scrubber to prevent slugging (H2O, HC, treatment chem)

6. regenerated glycol enters top tray of absorber (contactor), absorbs H2O in gas as flows down and gas goes up. Water rich glycol passes thru reflux condenser, soluble gas is flashed in flash tank, glycol/H2O heated in rich/lean HE, sent to regeneration unit where heated at atm P to drive off water PROBLEM – aromatics very soluble and can be significant absorption based on eqm constants (K) = y aro /x aro 10-30% of BTEX in gas can be absorbed higher the P and lower T  increased absorption aromatic absorption is f(circulation rate)  higher the rate the higher the absorption but independent of # of contactors therefore to minimize absorption must minimize circ rate and increase size of tower (decrease P) from GPSA Handbooks

7. Enhanced glycol concentration processes – standard designs limited to 98.6% TEG purity by reboiler op T (204 C at atm P) number processes increase purity by reducing the PP H2O in vapour space of reboiler so get higher [glycol] at same T e.g. DRIZO, COLDFINGER, PROGLY from GPSA Handbooks

8. general considerations for glycol units  if inhibitor present 40-60% absorbed in glycol which increases duty on reboiler and added volume load  glycol losses – mechanical carryover from contactor (13 L/10 6 Sm 3 ), vapours from contactor/regenerator, foaming in absorber/regen, low P and high T (40 L/10 6 Sm 3 ), losses glycol of gas w/ CO 2 is higher than n.gas at P>6200 kPa  becomes corrosive w/ prolonged exposure to O 2  @ high T (>200C)  decomposition  low pH  decomposition

9. ii.Solid Dehys comprise of 2 or more towers (one on, one off) - more expensive than glycol units therefore used when:  high H2S  lower dew pt regs  simultaneous control of H2O and HC dew pt  O2 containing gases  where CH3OH not favoured  both dry/sweeten NGL from Norwegian University of Science and Technology (NTNU)

10. 3 types 1.gels – alumina or silica gels (SiO2)  v and l dehydrated and HC recovered for natural gas (iC5+)  hydrocarbon recovery units (HRU), outlet dew pts ~-60C 2.Alumina – hydrated form Al2O3 (alumina oxide), TDP~-70C, less heat required than mol sieve and T regnerator lower 3.molecular sieve – aluminosilicates, high H2O capacity and produces lowest T DP ~-100C, can sweeten and dry gases and liquids (fig 20- 69) H2O capacity less dependent on ambient T and relative humidity expensive commonly used ahead NGL plants to recover C2 from GPSA Handbooks

11. iii.Membranes separate gas from H 2 O, CO 2, HC according to permeability where dissolve/diffuse through membrane driving force is differential PP across membrane CO 2 /H 2 O permeate thru membrane  permeate at reduced P while nonpermeate @ P slightly<P feed C1+ in permeate f(∆P, SA membrane), 5-10% carryover only applicable to plants use low P natural gas fuels

12. e)Dehydration of Liquid Phase HC typically amount of water in HC l is low, even at saturation (Fig 20-2) i.gas stripper counter current stripper w/ dry gas, used offshore, trayed contactor and stripper low cost, simple need dry n.gas stream, waste stream of VHC from condensate ii.solid desiccant activated alumina, T dp ~-70C, absorbs heavy HC CaCl2 – brine has neg effect MS too expensive for H2O removal iii.distillation fractionation columns for use in dehy of NGLs higher energy requirements