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/Sm3 wet gas

30% C1 60% CO2 10% H2S 1500 mg/Sm3 wet gas

100 % CO2 1700 mg/Sm3 wet gas

- to determine H2O content requires experiment/gas analysis

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

• 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 pt2. 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

Phase Envelope (inlet gas mixture of 62% C1, 15% C2, 16% C3+, 4% H20, balance

H2S/CO2/N2)

0

2000

4000

6000

8000

10000

12000

-180 -150 -120 -90 -60 -30 0 30

Temperature (C)

Pre

ssu

re (

kPa)

hydrate line

bubble pt curve

dew

pt c

urve

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 Thyd form

• inject glycols or methanol

- combines w/ condensed aqueous phase decreases Thyd form

- chemical recovered with aqueous phase at separators

d)Gas Dehydrationi.        glycol units

• glycol is a l (DEG, TEG most common, tetraethylene glycol TREG)

• applications where TDP depression of 30-70 C required

• usually preceded by inlet gas scrubber to prevent slugging (H2O, HC, treatment chem)

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) = yaro/xaro

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

• 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 PPH2O in vapour space of reboiler so

get higher [glycol] at same T e.g. DRIZO, COLDFINGER, PROGLY

from GPSA Handbooks

• general considerations for glycol unitsif inhibitor present 40-60% absorbed in glycol which increases duty on reboiler and added volume loadglycol losses – mechanical carryover from contactor (13 L/106 Sm3), vapours from contactor/regenerator, foaming in absorber/regen, low P and high T (40 L/106

Sm3), losses glycol of gas w/ CO2 is higher than n.gas at P>6200 kPabecomes corrosive w/ prolonged exposure to O2

@ high T (>200C) decompositionlow pH decomposition

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)

3 types1. 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 Tregnerator lower

3. molecular sieve – aluminosilicates, high H2O capacity and produces lowest TDP ~-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

iii. Membranes• separate gas from H2O, CO2, HC

according to permeability where dissolve/diffuse through membrane

• driving force is differential PP across membrane

• CO2/H2O permeate thru membrane permeate at reduced P while nonpermeate @ P slightly<Pfeed

• C1+ in permeate f(∆P, SA membrane), 5-10% carryover

• only applicable to plants use low P natural gas fuels

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 condensateii.solid desiccant• activated alumina, Tdp~-70C, absorbs heavy HC• CaCl2 – brine has neg effect• MS too expensive for H2O removaliii.distillation• fractionation columns for use in dehy of NGLs• higher energy requirements