The Art of Natural Gas Processing

El Sayed Amer
 Bachelor's degree of Petroleum & Natural Gas Engineering 2012.
 Currently Senior Petroleum Engineer at Petrogistix KSA since 2022.
 Well completion and intervention Engineer at Disouq Oil Co “Disouco” 2018.
 Senior Gas Process and Production Engineer at Suez Oil Co “SUCO” since 2014.
 Worked for Weatherford drilling international for 2 years as well drilling and completion engineer.
 Instructor for Oil & Gas Upstream and downstream courses at MTC Egypt, Egyptian syndicates of
engineers, OGS, SPE, AAPG & OPA.
 Member of SPE, AAPG, AACE, NACE, Environmental Geoscience.
 IWCF , HYSYS process modeling, Eclipse certified.
https://bit.ly/2UFSgpn
00201065860658
Eng20072007@gmail.com
/elsayedameer

5
P A G E
Eng.Elsayed Amer
Petroleum System
Process plant Gas inlet
 Natural Gas Is saturated with water at
reservoir pressure and temperature.
 The higher gas temperature, the
higher water content of natural gas

6
P A G E
Eng.Elsayed Amer
Natural Gas Classification
Natural Gas Dehydration
Forms of water in natural gas
liquid form (free water) vapor form (saturated water)
Wet Gas
 Gas containing water vapor.
 less than 85% methane and has a higher percentage of liquid natural gasses
(LNG’s) such as ethane and butane.
Dry Gas
 Gas free of water vapor.
 Mostly methane
 Sales gas – processes gas – ready to covert to LNG.

7
P A G E
Eng.Elsayed Amer
What is Gas Dehydration?

8
P A G E
Eng.Elsayed Amer
What is Gas Dehydration?
Gas Dehydration The process of removing water vapor from Natural gas stream
Wet Gas
CH4 + H2O
Dry Gas
CH4
H2O
Process plant

9
P A G E
Eng.Elsayed Amer
Reasons for Gas Dehydration
Why Dehydration?
 Meet sales gas water content specifications ((4 to 7 Ib water /MMSCF)
 Prevent hydrate formation
 To avoid pipeline corrosion problems
 Water vapor reduces natural gas heating value.
 Water slug flow will reduce pipeline efficiency and capacity.
 cryogenic units Need to have less than 1 ppmv H2O in gas.

Eng. Elsayed Amer
Inlet Field separation
GasHydrate
2022
h t t p s : / / b i t . l y / 2 U F S g p n

11
P A G E
Eng.Elsayed Amer
Gas Hydrate
• Hydrates are solid components that form as crystals and resemble snow in appearance.
• They are created by a reaction of natural gas with water.

12
P A G E
Eng.Elsayed Amer
Gas Hydrate

13
P A G E
Eng.Elsayed Amer
90% Water 10% (C1 : C4)
Gas Hydrate
Formation Condition
 Primary Conditions Promoting Formation of Gas Hydrates:
• Gas at or below its water dew-point
• Low temperature
• High pressure
• High velocity
• Presence of H2S and CO2
< 20 C
> 20 bar

14
P A G E
Eng.Elsayed Amer
Gas Hydrate Properties
 Specific gravity : 0.98
 Float on water
 Sink in hydrocarbon
 Water presence is mandatory for hydrate formation
 May Exist up to 25 C at high pressure.

15
P A G E
Eng.Elsayed Amer
Hydrate Problems
 Hydrate formation leads to blocking of the pipes and equipment
 Hydrate formation leads to production shutdown
 Hydrate formation leads to risks of overpressure in the installations.

16
P A G E
Eng.Elsayed Amer
Hydrate Formation
Smørbukk
50
0
100
150
200
250
300
350
400
0 5 20 25 30
Temperatur (°C)
)
a
r
a
(b
k
k
y
r
T
Hydrates
10 15
Temperature (°C)
Pressure
(bar)
No
hydrates
Hydrate curve

17
P A G E
Eng.Elsayed Amer
Hydrate Formation
Hydrate formation Prediction
for Sweet Gases
The chemical formulas for natural
gas hydrates are:
CH4 – 7 H2O
Methane
C2H6 – 8 H2O
Ethane
C3H8 – 18 H2O
Propane
CO2 – 7 H2O
Carbon Dioxide

18
P A G E
Eng.Elsayed Amer
Hydrate Formation
1. Enter left side at 4200 kPa (abs) and proceed to the
H2S concentration line (4.18 mol%).
2. Proceed vertically to the relative density of the gas
(g ¼ 0.682).
3. Follow the diagonal guide line to the temperature at
the bottom of the graph (T ¼ 17.5 C).
4. Apply the C3 correction using the insert at the
upper left. Enter the left hand side at the H2S
concentration and proceed to the C3 concentration
line (0.67%). Proceed down vertically to the system
pressure and read
the correction on the left hand scale (1.5 C)
Hydrate formation Prediction for Sour Gas

19
P A G E
Eng.Elsayed Amer
Icing – downstream plug (J-T cooling)

20
P A G E
Eng.Elsayed Amer
Icing – downstream plug (J-T cooling)

21
P A G E
Eng.Elsayed Amer
Hydrate Inhibition
 Hydrate inhibitors are used to lower the hydrate formation temperature of the gas
 The most commonly used inhibitors
 Methanol  Ethylene glycol
Inhibitor
Inhibitor
Inhibitor
Inhibitor
Inhibitor
Inhibitor
Inhibitor
Inhibitor
Hydrate cage
Hydrate cage
Methane

22
P A G E
Eng.Elsayed Amer
Hydrate Inhibition
 Methanol As Hydrate Inhibitor
Methanol works well as a hydrate inhibitor
1. It can attack or dissolve hydrates already formed.
2. It does not react chemically with any natural gas constituents.
3. It is non corrosive.
4. It is reasonable in cost.
5. It is soluble in water at all concentrations.

23
P A G E
Eng.Elsayed Amer
Hydrate Inhibition
 Glycol As Hydrate Inhibitor
• Advantages
1. Used for plugs in well and risers.
2. Low volatility into the gas and condensate phases.
3. Less soluble in liquid hydrocarbons than methanol.
4. Recoverable.
5. Low operating costs as compared to the methanol injection.
• Disadvantages
1. High viscosity inhibits.
2. Possibility of salt precipitation and fouling.
3. Remains in the aqueous phase.
4. Must be recovered from production fluids

24
P A G E
Eng.Elsayed Amer
Hydrate Inhibition
ADVANTAGES DISADVANTAGES
Thermodynamic Inhibitors
MeOH : Methanol
Transport
Low CAPEX
Dissolves in HC
Volatile (high loss rate)
High OPEX
MEG : Monoethylene glycol Regeneration (low loss rate)
Low OPEX
High viscosity
Crystallizationrisk
High CAPEX
DEG : Diethylene glycol
TEG : Triethylene glycol
SALTS (Rule of thumb: 20 g NaCl/l = 1°C subcooling)
Low cost
Natural (formation salt)
Need high quantity
Corrosion
LDHI (Low Dosage Hydrate Inhibitor)
Low quantity
(Mixed
High cost
feedback…)
KHI : Kinetic Hydrate Inhibitor
• Nucleation Limiters
• Growth modifiers
Anti-agglomerants
• Thermodynamic Inhibitors are added in order to reduce the activity of water phase and prevent hydrate formation
• Low Dosage Hydrate Inhibitors (LDHI) will delay hydrate formation or growth but do not
stop them.

25
P A G E
Eng.Elsayed Amer
THERMODYNAMIC INHIBITORS
FREEZING TEMPERATURES OF AQUEOUS SOLUTIONS OF METHANE AND SOMEGLYCOLS
– Eutectic behavior –

26
P A G E
Eng.Elsayed Amer
EFFECT OF INHIBITOR INJECTION ON HYDRATE FORMATION TEMPERATURE

27
P A G E
Eng.Elsayed Amer
SELECTION CRITERIA
■ CHOICES TO MAKE
• Which inhibitor?
• Continuous or intermittent injection?
• Regeneration?
• Which concentration of regenerated (“lean”) inhibitor?
• Amount and concentration of “rich” inhibitor?
■ DATA TO COLLECT
• Flow rate?
• Minimum and maximum pressure in unit?
• Fluid composition (incl. heavy components)?
• Minimum temperature in unit?
• Water dew point specification?

28
P A G E
Eng.Elsayed Amer
SELECTION CRITERIA
■ METHANOL:
• PROVEN technique,
• BUT: highly TOXIC and FLAMMABLE, important LOSSES in gas and condensate, LARGE
QUANTITIES to be injected (OPEX, logistics, regeneration), often used for TEMPORARY
inhibition at any temperature.
• Glycols preferred when required permanent methanol injection > 120 l/h
■ GLYCOLS:
• PROVEN technique,
• BUT costly (CAPEX), regeneration feasible (piggy-back line), but RECLAIMING problems if
produced water is salted
• MEG: Continuous inhibition at T< -10°C (vaporization losses at higher temperatures)
• DEG: Continuous inhibition at T> -10°C (high viscosity, difficult to separate condensate
and DEG + Water)
■ Methanol/glycol content in condensate/LPG may be too high for refineries: sales
price to be discounted (for the field life?)

29
P A G E
Eng.Elsayed Amer
MEG Injection
NORTH FIELD – QATAR

30
P A G E
Eng.Elsayed Amer
MEG Injection
©
2
0
1
4
-
I F P
T
r a
i n
i n
g
EP 20269_a_A_ppt_13 - HYDRATES PREVENTION -INHIBITION
GAS to Gas
Treatment
CONDENSATES
To treatment
TANKS FILTRATION
MEG
REGENERATION
STORAGE
TANK
WELLHEAD PLATFORMS
(No Treatment)
Rich MEG
Lean MEG
PRIMARY
SEPARATION
SALT RECLAMING
ONSHORE PROCESSING FACILITIES
PIGGY-BACK LINE
Injection of:
MEG (Hydrate inhibition) &
AMINE (Corrosion Inhibition)

31
P A G E
Eng.Elsayed Amer
Inhibitor Calculation
• GLYCOLS:
• METHANOL:
4 kg/106 Sm3 of gas,
given by charts
■ Inhibitor losses to LIQUID phase
• GLYCOLS:
• METHANOL:
0.2 kg /m3 of hydrocarbon liquid,
2 kg/m3 of hydrocarbon liquid,
■ Inhibitor losses in REGENERATION system (for glycols):
• GLYCOLS: 25 kg/106 Sm3 of gas (mainly due to carry-over in inlet plant separator and regenerator)
Volume injected = Amount in free WATER + Losses to GAS + Losses to LIQUID HC
■ Inhibitor losses to VAPOR phase :
GAS
LIQUID HC
LIQUID WATER

33
P A G E
Eng.Elsayed Amer
HAMMERSCHMIDT correlation
CALCULATION OF REQUIRED INHIBITOR FLOW
■ HAMMERSCHMIDT: semi-empirical correlation (1934 - 100 measurements)
• W : weight % pure inhibitor in liquid water phase
• ΔT : depression of hydrate formation temperature (°C)
• Mw : molecular weight of inhibitor (kg/ kmol)
• Ki : Hammerschmidt constant (°C.kg /kmol)
Inhibitor MeOH MEG DEG
M (kg/kmol) 32 62 106
Ki (°C.kg/kmol) 1 297 2 220 2 220
27.0 29.5 41.7
MeOH MEG DEG
….. % Wt. ….. % Wt. ….. % Wt.
Example: to protect a 15°C hydrate sub-cooling what is the amount of MeOH or glycols
required to maintain in
liquid water phase?
Nielsen Bucklin correlation is better for Glycols
𝑊𝑊 = 100 ×
∆𝑇𝑇 . 𝑀𝑀𝑀𝑀
𝐾𝐾𝐾𝐾 + ∆𝑇𝑇

34
P A G E
Eng.Elsayed Amer
Methanol Losses
27.0 29.5 41.7

35
P A G E
Eng.Elsayed Amer
27.0 29.5 41.7
Injection Rate ( GLYCOL & METHANOL)

36
P A G E
Eng.Elsayed Amer
Glycol (MEG or DEG) inhibition
27.0 29.5 41.7

37
P A G E
Eng.Elsayed Amer
HAMMERSCHMIDT correlation
■ Hammerschmidt's formula estimates the necessary inhibitor concentration required in
the aqueous phase to prevent hydrate formation. Its precision is sufficient for
methanol (which was used to develop it), and rather poor for glycols (MEG or DEG).
■ The Nielsen-Bucklen equation gives better results than Hammerschmidt's formula for
Water-Glycols mixtures.
■ The calculation of the flow rate of methanol to be injected to inhibit hydrate
formation must take into account the methanol losses in the gas, and in the
condensates (liquid hydrocarbons) if they exist. These losses are relatively
significant!!!.
■ The glycol (MEG or DEG) losses in the condensates (hydrocarbon liquids), and in the
gas are low but end up becoming a nonnegligible part of the OPEX (Operating
Expenditure), which must thus be controlled...

38
P A G E
Eng.Elsayed Amer
Low dosage hydrate inhibitors (LDHIs)
■ A recent and alternative technology to thermodynamic inhibitors.
■ The active material is expensive, but could be attractive due to low dosage Remark: before
deciding to use these additives, experimental testing is necessary to optimize the active material formulation
and quantify the injection rate
■ Types of Low Dosage Hydrate Inhibitors:
• Kinetic Hydrate Inhibitors (KHI)
• Anti Agglomerants (AAs) additives

39
P A G E
Eng.Elsayed Amer
METHOD OF INJECTING INHIBITOR
In order for the inhibitor to be effective, it must mix with water that condenses from the gas at the instant
condensation occurs.

40
P A G E
Eng.Elsayed Amer
METHOD OF INJECTING INHIBITOR

42
P A G E
Eng.Elsayed Amer
Dehydration Methods
Dehydration Methods
Adsorption Condensation
Absorption
Cooling to lowering HCDP
Inhibition
Refrigeration
Mechanical
refrigeration
Ammonia
Propane
Turbo
expansion
Glycol
Methanol
Alumina
Silica gel
Molecular sieves
CaCl2
MEG
DEG
TEG
JT valve

43
P A G E
Eng.Elsayed Amer
Dehydration Dew Point
Dehydration Method Dew Point
Solid Bed
Silica Gel -60 C
Alumina -70 C
M. sieve -90 C
Liquid Injection
Methanol -90 C
MEG -25 C
Liquid Contactor
TEG -9 C
TEG + Gas Stripping -50 C
Drizo -90 C
Membrane -40 C

Eng. Elsayed Amer
Natural gas Dehydration 2022
Absorption Method

45
P A G E
Eng.Elsayed Amer
Gas Absorption
Principles of Operation
 Using hygroscopic liquid desiccant to
remove water vapor from natural gas.
 Many liquids possess the ability to
absorb water from gas,
 EG :Ethylene Glycol
 DEG :Diethylene Glycol
 TEG :Tri-ethylene Glycol
 TREG :Tetra-ethylene glycol

46
P A G E
Eng.Elsayed Amer
Gas Absorption
■ Glycols are widely used for natural gas
dehydration (TEG)
■ TEG systems are used onshore and offshore
for both sweet gas and sour gas applications
■ Gas can be treated economically with TEG
between 10°C-100°C and between 10- 120+ bar.g
■ Water Dew Point depression typically 30°C - 100°C
■ Pure MEG Freezes at -6 C

47
P A G E
Eng.Elsayed Amer
Gas Absorption
Liquid
Solvent
High
absorption
efficiency
Easy and
economic
Noncorrosive
& nontoxic
No operational
problems &
contamination
Minimum
absorption
of HC

48
P A G E
Eng.Elsayed Amer
Gas Absorption
■ Glycol process
• Tens of thousands of glycol units dehydrate gas over theworld
• Simple operating principle
− Direct contact at pressure between gas andglycol
− Glycol circulating in a closed loop
■ Triethylene Glycol (TEG) is the preferred choice of desiccant because of:
• High thermal stability
• Efficient regeneration at high reboiler temperatures (up to204°C)
➔ Concentrations higher than 99.9+ wt% areobtainable
• Low vaporization losses
■ Key design factors: Low dew point application
• Contactor equilibrium stages : height of structured packing or number of trays)
• Glycol flow rate
• Glycol concentration
: typically 15 - 40 litre TEG/ kg H2O to remove
: typically 99.0 - 99.95 wt% and more…

49
P A G E
Eng.Elsayed Amer
Gas Absorption
 The most common liquid used in dehydration units is TEG.
 Absorption is favorable at a lower temperature and higher pressure.
• Belonging to the alcohol family.
• It is an odorless, colorless, sweet-tasting, viscous liquid.

50
P A G E
Eng.Elsayed Amer
Gas Absorption
Natural Gas Dehydration Inhibitor properties

51
P A G E
Eng.Elsayed Amer
Gas Absorption
Inhibitor properties
HYDRATE FORMATION INHIBITION DEHYDRATION
Methanol
MeOH
CH3OH
Mono-Ethylene Glycol
MEG
C2H6O2
Di-Ethylene Glycol
DEG
C4H10O3
O
Tri Ethylene Glycol
TEG
C6H1404
O
Molecular Weight kmol/kg 32.04 62.10 106.10 150.17
Normal Boiling Point (NBP) °C 64.5 197.3
Decomposition > 165°C
244.8
Decomposition > 165°C
288.0
Decomposition > 204°C (400°F)
Vapor Pressure at 25°C mmHg 120 0.12 < 0.01 < 0.01
Density at 25°C
Density at 60°C
kg/m3
kg/m3
790
-
1,110
1,085
1,113
1,088
1,123 (24°C)
1,091 (66°C)
Freezing Point °C - 97.8 - 13.3 - 8.3 - 4.3
Viscosity at 25°C
Viscosity at 60°C
cP
cP
0.52
-
16.50
4.68
28.20
6.99
56.0 (24°C)
8.1 (66°C)
Specific heat 25°C kcal/kg.°C 0.60 0.58 0.55 0.500 (24°C)
Latent heat of vaporization at 1 atm.a kcal/kg 202 129 97
Flash Point °C 12.0 115.6 123.9 176.7

52
P A G E
Eng.Elsayed Amer
Gas Absorption
1. Wet gas enters the bottom of a contactor,
or absorber tower.
2. Gas passes up the contactor, through a
series of trays through which the TEG is
flowing.
3. Trays are designed to force the gas to mix
with glycol.
4. The water from the gas is absorbed by the
glycol and dry gas leaves the tower at the
top.

53
P A G E
Eng.Elsayed Amer
Gas Absorption
Natural Gas Dehydration Process flow Diagram

54
P A G E
Eng.Elsayed Amer
Gas Absorption
Operation
parameters

55
P A G E
Eng.Elsayed Amer
Gas Absorption
FEED GAS SCRUBBER
 To be separate from the contactor
 To be as close as possible to contactor to prevent condensation (Heat loss + Friction)
FEED GAS FILTER & MIST EXTRACTOR
SOLID particles removal : > 99% of particles > 1 μm diameter
(tr LIQUID droplets removal : > 99% of droplets > 1 μm diameter

57
P A G E
Eng.Elsayed Amer
Gas Absorption
Contactor Tower
 Absorber is a vertical column used to remove
component from the gas.
 Vessel where glycol and natural gas make
contact Concurrent flow
 Gas flows up
 Glycol flows down
 Wet gas enters the Contactor (absorber)
where the Lean TEG contacts the wet gas and
absorbs water vapor.

58
P A G E
Eng.Elsayed Amer
Gas Absorption

59
P A G E
Eng.Elsayed Amer
Gas Absorption
• Gas temp 60°-135° F
• Pressure 100 – 2600 psi
• Inlet glycol should be 10° F higher than inlet gas
– Lower temp than gas will cause foaming
– Higher temp might increase glycol loss
• 5 psig maximum pressure drop in contactor
• Liquid seal must be established
– Glycol circulation established on tray type tower
– Gas flow should be gradually increased
Contact Tower

62
P A G E
Eng.Elsayed Amer
Gas Absorption

63
P A G E
Eng.Elsayed Amer
Gas Absorption
Operational conditions of the contact tower
Variable Normal variable
Temperatura Inlet gas 60 - 120 ºF
Operating Pressure 500 - 1000 psi
Lean glycol Temperature 5-10 ° F higher than the gas entering the tower
Lean glycol concentration 98 - 99 %
number of dishes 6 - 12
Efficiency of dishes 20 - 33 %
Spacing between plates 24 in.
Packing height equivalent to a theoretical plate, HETP 1 Theoretical plate = 36 - 60 in.
additional height 6 - 10 ft.
Glycol circulation rate 2 - 7 gal/Lb H2O removed

64
P A G E
Eng.Elsayed Amer
Gas Absorption
• Filtration is a KEY POINT to ensure that this unit operates correctly. It prevents foaming
and corrosion problems and the loss of glycol, by eliminating.
Glycol Filters
• solid particles (corrosion products, sediments, etc.)
• liquid hydrocarbons
• products generated by degradation of the TEG
• The filtration is performed by:
a. Cartridge filter : eliminate the solid particles, greater than 10 μm, Two filters are
normally installed in parallel
b. Activated Charcoal Filter: eliminates all the contaminants in the glycol loop (liquid
hydrocarbons, polymers, TEG degradation products, etc.) by adsorption, which is
generally not removed by the mechanical filter (10 to 20%). .

65
P A G E
Eng.Elsayed Amer
Gas Absorption

66
P A G E
Eng.Elsayed Amer
Gas Absorption
■ Active charcoal filter
• This filter eliminates all the contaminants in the glycol loop (liquid hydrocarbons,
polymers, TEG degradation products, etc.) by adsorption, which is generally not removed
by the mechanical filter.
• The charcoal filter is installed downstream of the mechanical filter
• Given that these contaminants appear very progressively, it is sufficient to filter only part
of the total flow of the TEG loop (10 to 20%). The remainder of the flow bypasses the
charcoal filter (which is itself installed on a bypass).
Remark: if an active charcoal filter is Installed, a particle filter must be Installed
downstream of it to capture the charcoal particles which may be entrained with the TEG
solution.

67
P A G E
Eng.Elsayed Amer
Gas Absorption

68
P A G E
Eng.Elsayed Amer
GLYCOL/GLYCOL HEAT EXCHANGER

69
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration

70
P A G E
Eng.Elsayed Amer
Gas Absorption
• The regenerator is a combination of the glycol
reboiler and the still column.
• They operate together to regenerate the rich
glycol, making it lean again and ready for use in
the contactor column.
Glycol Regeneration

71
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration
• The reboiler supplies heat to separate glycol
and water by simple distillation.
• Glycol is heated to a temperature between
380°F and 400°F (193°C and 204°C) to remove
enough water vapor to regenerate the glycol to
98.5-99%
• The temperature of triethylene glycol should
not exceed 400°F (204°C) because TEG will
begin to break down at higher temperatures
(decomposition).

72
P A G E
Eng.Elsayed Amer
Gas Absorption
CONVENTIONAL TEG PROCESS – REGENERATOR STILL COLUMN

73
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration

74
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration

75
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration

76
P A G E
Eng.Elsayed Amer
Gas Absorption
Glycol Regeneration
Freezing Points of Aqueous
Triethylene Glycol Solutions

77
P A G E
Eng.Elsayed Amer
WATER DEW POINT OF A NATURAL GAS
AT EQUILIBRIUM WITH A TEG SOLUTION
Given an overhead contactor temperature
of 35°C, what is the lowest achievable
Water Dew Point for the dry gas?
≈ - 10 °C
………

78
P A G E
Eng.Elsayed Amer
TEG CIRCULATION LOOP
BUBBLE TEMPERATURE
OF COMMERCIAL TEG SOLUTIONS
4 - Given the maximum allowable
temperature of regenerator of 400°F
(≈ 204°C), what is the HIGHEST achievable
purity for the Lean TEG ?
≈ 98.7 % Wt
………

79
P A G E
Eng.Elsayed Amer
MOISTURE CONTENT OF DRY GAS
WATER DEW POINT OF A NATURAL GAS AT
EQUILIBRIUM WITH A TEG SOLUTION
5 - Given an overhead contactor
temperature of 35°C, what is the lowest
achievable Water Dew Point for the dry
gas?
≈ - 10 °C
………

80
P A G E
Eng.Elsayed Amer
CONTACTOR DESIGN
6 – Assuming a glycol circulation flow of 25 liter
of TEG / kg of water to remove (= 3.00 US gal of
TEG / lb of water), estimate the number of
required trays.
≈ 6 Trays
………
ESTIMATION OF THE NUMBER OF
SEPARATION TRAYS OF THE TEG
CONTACTOR
!

81
P A G E
Eng.Elsayed Amer
CONTACTOR DESIGN
In the contactor, the liquidflow is negligible compared
to the gasflow.
Hence, only the gas flow is considered for the design of
the contactor diameter.
Estimate the contactor diameter for a gas feed of 100
MMSCFD.
≈ 72 inches
………
ESTIMATION OF THE
DIAMETER OF THE TEG CONTACTOR

82
P A G E
Eng.Elsayed Amer
REGENERATOR DESIGN
8 – Estimate the Still Column (TEG
Regenerator) diameter.
≈ 17 inches
………
ESTIMATION OF THE
DIAMETER OF THE TEG REGENERATOR
1
liter
=
0.264
US
galon

83
P A G E
Eng.Elsayed Amer
Saih Rahwl – Oman, 1998 “One of the largest Glycol Unit in theworld"
View of a TEG regenerator
2 TEG regenerators (1500 MMSCFD ; TEG rate 80 m3/h each)

84
P A G E
Eng.Elsayed Amer
Gas Absorption

85
P A G E
Eng.Elsayed Amer
Gas Absorption

86
P A G E
Eng.Elsayed Amer
IMPROVEMENT OF CONVENTIONAL PROCESS
■ How to approach 100% lean TEG concentration?
■ Three (3) main techniques are used :
• Secondary water extraction (COLDFINGER®)
• Gas stripping
• Solvent stripping (DRIZO®)

87
P A G E
Eng.Elsayed Amer
Regeneration Improvement

88
P A G E
Eng.Elsayed Amer
Regeneration Improvement

Eng. Elsayed Amer
Natural gas Dehydration 2022
Adsorption Method

90
P A G E
Eng.Elsayed Amer
Gas Adsorption
 Adsorption is a process in which a solid desiccant
removes a particular component from gas
mixture and holds this component on its surface.
 This solid is known as an adsorbent material.

91
P A G E
Eng.Elsayed Amer
Gas Adsorption

92
P A G E
Eng.Elsayed Amer
Gas Adsorption
Adsorption Mechanism

93
P A G E
Eng.Elsayed Amer
Gas Adsorption
• NG to be dried through a solid bed of adsorption which selectively adsorbs water.
• The process is cyclic, as the adsorption bed needs to be periodically regenerated by heating
(to 200 – 315 °C) and vaporizing the absorbed water
■ Most common solid desiccants are:
• Molecular sieves (Zeolites)
• Alumina (Al2O3)
• Silica gel (SiO2)
• Activated carbon
SOLID DESICCANTS – PRINCIPLE

94
P A G E
Eng.Elsayed Amer
Gas Adsorption
• Solid desiccant consists of solid materials having an large surface area per unit weight.
• This is because it has microscopic pores and capillary openings.
■ Specificities of Gas Drying by Solid Desiccants
• Extremely low dew point
• Capacity less sensitive to temperature
• Excellent selectivity
• Limited resistance to liquid water
• Limited acid resistance
• High catalytic activity

95
P A G E
Eng.Elsayed Amer
Gas Adsorption

96
P A G E
Eng.Elsayed Amer
Gas Adsorption

97
P A G E
Eng.Elsayed Amer
Gas Adsorption
Silica gel

98
P A G E
Eng.Elsayed Amer
Gas Adsorption
Silica gel
 Allows simultaneous removal of water and heavy HC (C5+)
 Can be competitive with refrigeration/turbo-expander processes for NGL recovery For
C5+ recovery much shorter absorption cycles are needed to avoid displacement of C5+
by adsorbed water: typically 30 –45 mn
 High overall adsorption capacity

99
P A G E
Eng.Elsayed Amer
Gas Adsorption
Molecular sieve
 A molecular sieve is a material with
pores of uniform size. These pore
diameters are similar in size to small
molecules, and thus large molecules
cannot enter or be adsorbed

100
P A G E
Eng.Elsayed Amer
Gas Adsorption
Molecular sieve
Can achieve very low water dew point
Can dry oxygen containing gases
Both dehydration and gas sweetening
High capital cost
High operating cost
Large footprint / weight

101
P A G E
Eng.Elsayed Amer
Gas Adsorption
Molecular sieve

102
P A G E
Eng.Elsayed Amer
Physical properties of main desiccants
Gas Adsorption

103
P A G E
Eng.Elsayed Amer
Gas Adsorption

104
P A G E
Eng.Elsayed Amer
Gas Adsorption
PHYSICAL ADSORPTION –
EXAMPLE OF BED
ARRANGEMENT

105
P A G E
Eng.Elsayed Amer
Gas Adsorption

106
P A G E
Eng.Elsayed Amer
Gas Adsorption

107
P A G E
Eng.Elsayed Amer
Gas Adsorption
QatarGas 1 Driers Photo – Courtesy of QATARGAS

109
P A G E
Eng.Elsayed Amer
TROUBLESHOOTING – DEGRADATION & CONTAMINATION OF TEG

110
P A G E
Eng.Elsayed Amer
QUALITY REQUIREMENTS FOR THE LEAN TEG SOLUTION

111
P A G E
Eng.Elsayed Amer
GLYCOL DEGRADATION

112
P A G E
Eng.Elsayed Amer
KEY POINTS TO REMEMBER
■ The most common technique for dehydration is physical absorption usingTEG
■ Purity of TEG is determining the water dew point of dried gas. The higher the TEG purity, the lower the
water content and the water dew point of the dried gas
■ Improvements are being made to conventional TEG units to increase the purity of TEG in regeneration.
Good scrubbing and filtration is the key for the effective performance of TEG unit and minimizing
foaming problems and glycol losses
■ Physical Adsorption using solid desiccants is another technique for gas dehydration which makes it
possible to obtain dry bone gas (very low water dew point)
■ Use of Alumina as solid desiccant is more effective when the water content is high and use of
molecular sieves is more efficient when water content islow
■ Dehydration and low temperature separation for NGL extraction can be coupled in a process called IFPEX
using methanol as inhibitor and then regenration of methanol through an izeotropic distillation

The Art of Natural Gas Processing

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to The Art of Natural Gas Processing

Similar to The Art of Natural Gas Processing (20)

More from Elsayed Amer

More from Elsayed Amer (20)

Recently uploaded

Recently uploaded (20)

The Art of Natural Gas Processing