CHAPTER 5

GAS TREATMENT

Prof. Dr. Ariffin Samsuri

1
 Gas Treatment
• Concept of Gas Treatment
• Gas Treatment Method
• Chemical Absorption
• Physical Absorption
• Hybrid
TOPIC • Direct Conversion
• Dry Bed Processes
• Selection Criteria
• Gas Treatment System
• System Selection Criteria
Expected Outcomes
Students should be able to
• Identify the impurities in gas stream and its consequences to
the equipment and gas utilities
• Explain the various type of gas treatment methods such as
chemical absorption, physical absorption, hybrid, direct
conversion and dry bed processes
• Select the suitable process based on certain selected
criteria

2
 CRUDE OIL & NATURAL GAS ORIGINS

• Decomposed ancient plants & animals remains  hc

• Geological events sequence @ millions of years , organic material deposited
@ earths surface  transported to depression or basins, accumulated &
gradually buried at great depths under layers & layers of sediments (source
rocks) which subjected to much higher P & T.
• Overtime & through series of intermediate chemical reactions  petroleum
• Petroleum type formed depend on source rocks depth (P & T), such as light
condensate, volatile oil, heavy oil etc:
• Relatively shallow : T = 60 – 80 oC (140 – 176 oF), organic material
converted to heavy oil
• Lower depth & higher T = 80 oC – 175 oC (176 = 347 oF), heavier, long
chain organic molecules began to break up into shorter molecules &
form medium & light oil
• T > 175 oC (347 oF) : molecules became even shorter & lighter, more
matter transformed into rich gas, and at 315 oC (600 oF), all transformed
to dry gas (C1)

3 A
S
 PRODUCED OIL & GAS SEPARATION & TREATMENT

• Produced fluids typically contain:

• Crude oil
• Natural gas
• Water
• Non hc gases
• Impurities
• Hc change state & volume @ flowing from reservoir to surface
• From wellhead, production stream flow to centralized surface handling facilities,
separators (pressurized designed vessels) used to separate oil, gas, water&
basic sediments (BSW).
• Water pumped back to reservoir or treated & disposed @ environmentally
friendly manner.
• Oil metered & stored in storage tanks, await pipelined or tanker transport to sale
point or terminal.
• Gas treated or conditioned to remove water vapor & other impurities, processed
to recover gas liquids before metered and sold.

4 A
S
HYDROCARBON CHANGE STATE & VOLUME (RESERVOIR – SURFACE)

5 A
S
VARIOUS PRODUCED FLUIDS COMPOSITION SEPARATED

6 A
S
 NATURAL GAS

• Mixture of hydrocarbon : C & H

• Vapor @ normal surface conditions
• Underground – vapor or in solution with crude oil until pressure reduced
• Two types: associated gas (found together with crude oil @ reservoir) & non-
associated gas (found without crude oil @ reservoir)
• Two categories: Drygas-4C,& Cu, very little condensable fluids.

• Dry or dry : high concentrations of C1 & C2 (typically 95% or more) &

very little condensable fluids.
liquidified of normal T

• Wet or rich : gas.

->

Wet ↑ 23& Ca, intermediate 25-C, water condensed of surface condition,

• higher concentrations of C3 & C4, and intermediate-weight

hydrocarbon C5 – C7
• Contains appreciable liquid volume which condenses @ surface
conditions  condensate (similar value as light crude oil
• Liquid petroleum gases (C3 & C4)  liquefied @ normal T
• As heavier molecule proportions increase @ mixture  exist as liquid @
atmospheric conditions.

7 A
S
 GAS HANDLING & PROCESSING

• Treated dry or lean gas

•  compressed & sent directly to sale point through high-pressure
pipelines or
•  cooling to -160 oC (-258 oF), turned into liquefied natural gas (LNG),
occupies only 1/625 of dry gas volume, allowing to be transported to
distant markets in specially designed ships or tankers.
• For wet or rich gas
• May be sent to gas processing plant for cooling to -101 oC (-150 oF), hc
condensed to natural gas liquids (NGL)
• NGL then sold to refinery or petrochemical plant.
• If NGL available sufficient, economical to separate into its constituent hc
through fractionation process in series column  sequentially warmed t
higher T, causing individual hc , first C2, then C3 and C4 etc to boil off
then condense  C2,C3 & C4 mixture is liquefied petroleum gases
(LPGs) and residual is natural gasoline, which can be stored at
atmospheric conditions.
• Natural gas, LNG. NGL, LPGs and hc have individual markets and their
final form can be used as fuels & petrochemical manufacturing.

8 A
S
RICH GAS HANDLING & PROCESSING

9 A
S
 Some Related Definitions

• Dry gas: produced in absence of a liquid stream (<5 bbls/MMSCF liquid)

• Wet gas: is a gas produced with some liquid (10 – 20 bbls/MMSCF liquid).
• Associated gas: gas produced simultaneously with a black oil
• Non-associated gas: gas produced from gas reservoir
• Sales gas: consists largely of C1 and some C2
• Liquified natural gas (LNG): natural gas liquefied by cooling to –258 oF (-161 oC) under atmospheric pressure
• Condensate: mainly C5 to C12
• Natural or ‘casing head’ gasoline: lighter fraction of condensate, roughly C5 to C8
• Heavy condensate: consists of kero and diesel roughly C9 to C12
• Natural gas often contains products termed natural gas liquids (NGL), which can be recovered economically in a processing plant and
sold separately. They are:
– Liquefied petroleum gas (LPG) consists of propane/propylene (C3) and butane/butylene (C4) in various mixtures, and can be
liquefied under light pressure at normal temperature. In Malaysia, the mixture is mainly propane and butane whereas for all fuel
in the United States, the mixture is mainly propane. LPG is used in all major end-user sectors as a heating fuel, engine fuel,
cooking fuel, and chemical feedstock
– Natural gasoline or ‘casing head’ gasoline - liquid at normal temperature and pressure, and consists of a mixture of butane and
heavier hydrocarbons such as pentanes and hexanes
• Sour gas contains H2S, sulfur or any sulfur compounds
• Sweet gas contains no or very little sulfur or sulfur compounds
• Acid gas contains mainly H2S and CO2 + H2O  acid
• Natural gas for vehicle (NGV) may be classified as follows, according to the fuel storage method:
– CNG vehicles – stored as a gas at high pressure (3,000 psig) in a gas cylinder
– LPG vehicles – stored as a liquid (at –162 oC) in a low temperature container
– Adsorbed natural gas (ANG) – stored at a pressure of 142 psig adsorbed into adsorbent material inside a gas cylinder
• Compressed natural gas (CNG) is natural gas compressed to about 1,500 psia. and same properties as natural gas except that the
volume is reduced

10
 Natural Gases Characteristics (Typical)

Leman Bank Groningen Libya* Brent* Lacq (France)

Compt (high C1) (high N2) (high C2, C3, C4) (North Sea) (high H2S, CO2)
C1 94.7 81.2 66.8 85.9 69.1

C2 3.0 2.9 19.4 8.1 2.8

C3 0.5 0.4 9.1 2.7 0.8
C4 0.2 0.1 3.5 0.9 1.5
C5+ 0.2 0.1 1.2 0.3 0.6
H2S - - - - 15.4
CO2 0.1 0.9 - 1.0 9.7
N2 1.3 14.4 - 0.5 -
He/Argon <0.1 <0.1 - - -
S.G. 0.59 0.64 0.81 0.62 0.75
Cal. value3
Btu/ft3 1037 843 1332 1053 910
MJ/m 38.6 31.4 49.6 39.2 33.9

* Associated gas

11
 Typical Sales/Disposal Specifications

Product Property Specification

Crude oil Vapor pressure <16 psi at 25 deg.C
Water content <0.5% wt
Salt content <70 g/m3
Temperature <40 deg.C
Pressure Atms for tanker export or pipeline operating pressure
Gas Caloric value Specified limits
Liquids None
Hc dew point < -3 deg.C
Water dew point <-8 deg.C
CO2 <3% wt
H2S < 4ppm
Temperature <40 deg.C
Pressure Pipeline operating value
Water Dispersed oil < 32 (Europe)-40 ppm (Mexico) 12
 Condensate vs Crude Oil

• Light crude oils are often hard to distinguish from condensate, therefore production by
OPEC beyond quota limits can be done by declaring light crude to be a gas condensate
• Therefore, in 1988 OPEC have agreed the following definition:
Condensates Crudes
API gravity above 50o below 45o
C7+ (mol % wt) below 3.5% above 8.0% min.
Gas/liquid ratio above 5,000 scf/bbl below 5,000 scf/bbl

Import of condensate into Japan*

Quota restriction on crude oil production in OPEC (natural gas production is
not restricted, therefore the productions of natural gas liquids is not
subject to quota)

* Japan imports all petroleum products and imposes an import duty on all of them. This duty is
however waived in the case of chemical feedstocks such as naptha or gas oil, imported by the
petrochemical industry. Condensate being alike to naptha, can therefore be imported duty free
provided its 90% boiling point does not exceed 200 oC. As a result heavy condensates are
frequently subject to import duty.

13
 LPG - Properties and Uses

• Composition: C3 and C4 (atmospheric

boiling point: -46 to +1 oC)
• Storage pressure: 5 - 30 bar approx.
(either butane only or all LPG)
• Storage in cylinders, tanks, refrigerated
vessel, underground
• Uses: domestic, industrial, commercial,
generally where piped is not available

14
 Need for Gas Treatment

• Natural gas consists various components which are present in different concentration (water, HC and
impurities)

• Removal of contaminant from natural gas

• Gas compositions to customers should be the same (eliminate all components other than methane) 
purified version
 it is essential to remove undesirable impurities such as H2O, HC, CO2 and H2S and to isolate for
separation

• Impurities and heavy HCs can be commercially attractive but they are just contaminants. Water vapor is
always unwanted

• Low concentration of C2 is acceptable but C2 is normally separated because of its potential use as a
chemical feedstock for ethylene manufacture

• C3 and C4 - for LPG

• C5+ - gas condensate, need to separate because of their interference with normal operation of gas
compression, transmission, metering, utilization, etc

• Liquids - NGLs - are more valuable than gases

15
 Reasons for Natural Gas Treatment

• To meet sales specifications and

customer’s requirement
• To recover other materials such as He,
CO2, condensate, natural gasoline, etc.
(higher price if marketed separately)
• To extract materials such as sulfur from
H2S - extra income
• To facilitate transmission - careful
moisture removal

16
 Gas Purification

• Removal of acidic gases (sour gas

processing)
• Removal of water vapour
(dehydration)
• Removal of heavier HCs

17
 Removal of Acidic Gases from NG

• Content :
– CO2 and H2S are main acidic gases; others only in
trace quantity
• Method:
– Combination of chemical reaction and physical
absorption; heat regeneration
– For high CO2, low H2S, carbonate processes and
molecular sieves are used occasionally

• Chemical:
– Monoethanolamine (MEA) [most effective)
– Diethanolamine (DEA) [most effective]
– Propanolamines, eg in Sulphinol process

18
 Why H2S must be removed?

• H2 S
– highly toxic and
– poisonous.
• Distinct odour at 0.15 ppm
• Exposure to 100 ppm after 15 minutes  drowsiness
• Exposure to 500 ppm after 5 minutes  severe breathing
• A brief exposure of 1,000 ppm (0.1 volume %) H2S is fatal
– H2S in the presence of water can cause corrosion to valves, pipelines, pressure vessels, etc.
• Sulphide stress cracking at 0.05 psi partial pressure
• Hydrogen embrittlement at 0.05 psi partial pressure : H2S + Fe  FeS + 2H+  H2
– Flaring  highly acidic sulphur dioxide (SO2) & sulphurous acid (H2SO3)
– Most pipeline specification limit H2S content to 0.25 g/100 cuft (4 ppm)
– Low concentration can be removed by solid absorbents/desicant (iron oxide or zinc oxide)
– Higher concentration can be removed by solvent extraction process
– Can be convert to solid sulphur by Claus process :
2H2S + 3O2  2SO2 + 2H2O
SO2 + 2H2S  3S + 2H2O

• Sulfur compounds, {reactive sulfur residue (RSR), carbonyl sulfide (COS) and carbon disulfide (CS2)}
– have objectionable odors and
– tend to concentrate in gas plant liquid product (most sulfur compounds must be removed before liquid
products are usable)
– Yellow solid sulphur product has many industrial uses:

19
 Why CO2 must be removed?

• Corrosive in the presence of water at 30 psi partial

pressure
CO2 + H2O  H2CO3
H2CO3 + Fe  FeCO3 + H2
• As an inert gas :
– has no heating value, in sufficient quantities, CO2 might
reduce the heating value (Btu/cf) below acceptable limits
• CO2 removal may be required in gas going to cryogenic
plants to prevent solidification of the CO2
• Most specification limit: 3% wt
• Can be removed by solvent extraction process

20
 Removal of Water Vapor from NG

Reasons:
1. Risk of solid hydrates formation
2. Natural gas containing liquid water is corrosive
3. Water vapor in natural gas may condense in pipelines  slugging flow
4. Water vapor increases volume & decreases heating value  reduced line
capacity
Sources: Water from formations, purification, etc.
Content estimation : experimental data such as McKetta & Wehe chart
Typical values: Reservoir gas (5000 psig/250deg.F = 500 lbm/mmscf
Trap gas (500 psig/125deg.F = 400 lbm/mmscf
Pipeline gas = 6- 8 lbm/mmscf
Treatment:
• Water stabilization vs removal
liquid absorption

• Glycol treatment (DEG, TEG) solid adsorption

• Other methods are molecular sieves, alumina, silica gel, etc.

21
 Heavier HCs Removal from NG

• Gas refrigeration/cooling
– Joule-Thomson refrigeration (Joule-
Thomson Effect)
– Expander for energy recovery
– Absorption in refrigerated solvent
• Expansion/compression energy exchange
(condensation in right order)
• Adsorption on molecular sieves

22
 Gas Sweetening Process

SWEET RESIDUE
GAS
Gas sweetening process
C1 – Cn To dehydration
splits a sour gas stream into N2 & HC recovery
two process stream: H2O
- Sweet residue gas
ACID GAS
- Acid gas
H2S
CO2
COS Flared or sent to
CS2 Claus sulfur
recovery unit
RSR
H2O
SOUR NATURAL GAS
C1 – CN
N2
H2S
CO2
COS (carbonyl sulfide)
CS2 (carbon Disulfide)
RSR (mercaptans)

23
 Gas Sweetening
• Removal of acid gases (H2S & CO2)
• Sour gas = gas contain H2S > limit
• Sweet gas = gas after sweetening or contain H2S< limit
• Why?
– With water  acids/acidic solution
– No heating value
– Cause problem to systems and environment
• H2S:
– Toxic
– Poisonous
– With water  extremely corrosive  premature failure to valves, pipelines & pressure vessel,
catalyst poisoning in refinery vessel
– Limit: 0.25g/100 cuft or 4 ppm
• CO2:
– CO2 solidification in cryogenic plant
– With water  corrosive

Popular process:
1. Iron-sponge sweetening
2. Alkanolamine sweetening
3. Glycol/amine process
4. Sulfinol process

24
 Gas Sweetening Process

• A number of gas sweetening processes are commercially

available, and more are being developed each year
• Gas sweetening processes can be group into 5 general
categories according to the type:
– Chemical absorption
– Physical absorption
– Hybrid
– Direct conversion
– Dry bed

Note: A process is classified as ‘selective’ if it removes H2S but

leaves CO2 in the sweet residue gas.

25
 Gas Sweetening Process

Chemical absorption
Includes use of amine and potassium carbonate
Utilize an aqueous solvent that reacts chemically with acid components
Acid gas components are held in solution until chemical reaction is reversed in
regenerator by ↑T and ↓P
Physical absorption
Use a solvent to physically absorb acid gas components
Use solution ambient T to separate acid gas components in the regenerator.
Hybrid
Mixture of chemical and physical solvents
Direct conversion
Elemental sulfur produced directly from H2S. No Claus unit is required.
Dry bed
Utilized no solvent.
Gas is passed over a dry bed, which removes H2S from sour gas.
26
 Gas sweetening process classification

Direct
Chemical Physical Hybrid Dry bed
conversion
MEA Selexol Shell Stretford Iron sponge
Sulfinol
DEA Purisol Claus Molecular
sieve
DGA Rectisol Sulfa-check Zinc oxide
Shell ADIP Flour solvent LOCAT Sulfa treat
(DIPA)* (propylene
carbonate)
Benfield
Catacarb
Hindered
Amine
*Diisopropanol amine

27
 PRIMARY NATURAL GAS TREATMENTs

• Acid gas in natural gas stream:

– Main component: H2S & CO2
– Additional : Mercaptans, carbon sulfide & carbonyl sulfide
• Process:
1. Gas sweetening
2. Dehydration
• Method:
1. Absorption
2. Adsorption
3. Chemical reaction
• Treatment process selection:
– Based on gas content & concentration
– Target: pipeline specification

28
 Chemical absorption

• Uses weak aqueous base solution to chemically react with and absorb the acid
gases in the contactor to form a new complex compound, which is held in the
solvent
• Contactor is operated at low T, high P
• Some of the absorbed HCs are released in a flash drum and normally used as fuel
• In regenerator, complex compound decomposes at higher T and lower P, which
force the reaction to reverse & to liberate the acid gas components
• Reactions involved are reversible by changing P and T, or both
• Aqueous base solution can be regenerated & thus circulated in a continuous cycle

29
 CHEMICAL SOLVENT PROCESSESs

• Remove : H2S or CO2 or both

• Method: by chemical reaction with material in solvent solution
• Reaction may be reversible or irreversible
• Reversible reaction:
– Reactive material remove gas in contactor @ high partial pressure, low temperature or both
– Reaction reverse by high T or low P in stripper
• Irreversible reaction:
– Remove H2S and/or CO2 need continuous reacting material makeup
• Some chemicals used:
– Monoethanolamine (MEA) - HOC2H4NH2
– Diethanolamine (DEA) - (HOC2H4)2NH
– Triethanolamine (TEA) – (HOC2H4)2N
– Diglycol amine (DGA) – H(OC2H4)2NH2
– Dilsopropanolamine (DIPA) – (HOC3H6)2NH
– Methyldiethanolamine (MDEA)
– Selexol - Polyethylene glycol derivative

30
 SOLVENT PROCESS SELECTIONs

• Gas treating process is very important due to impact on design of entire gas processing facilities such as acid gas
disposal method, sulfur recovery dehydration, absorbent recovery etc
• Based on:
– Process objectives & solvents characteristics such as selectivity for H2S, COS, HCN etc
– Ease of water content handling in feed gas
– Ease water content control of circulating solvent
– Concurrent hydrocarbon loss or removal with acid gas removal
– Costs including royalty
– Solvent supply
– Chemical inertness
– Thermal stability for various processing techniques
– Proper plant performance for various processing techniques

• Process solution selection determine by:

– Pressure
– Temperature
– Gas composition
– Purity requirement
– Removal selection – simultaneous or selective removal of H2S & CO2
• AAAA

31
 PROCESS SELECTION s

• Factor to be considered in evaluation & decision making:

1. Air pollution regulation regarding H2S removal
2. Type and concentration of impurities in sour gas
3. Treated gas (sweet gas) specifications
4. T & P @ sour gas availability and @ sweet gas deliverability point
5. Gas to be treated volume
6. Sour gas hydrocarbon composition
7. Selectivity required for acid gas removal
8. Capital cost
9. Operational cost
10. Liquid product specifications

32
 ALKANOLAMINEs

• Most acceptable @ widely used due to reactivity & availability at low cost
• Can be considered:
– Acid gas partial pressure low
– Acid gas content required in sweet gas low (required specifications of treated gas)
– Gases rich in heavier hydrocarbon
• Some characteristics:
– Clear
– Colorless liquids
– Slightly pungent odor
– Stable (can be heated to boiling points w/o decomposition – MEA = 170.5 deg.C & DEA = 209 deg.C) except
triethanolamine (decomposes below normal boiling point, ie 360 deg.C)
– Can be selective
• Reaction for H2S removal:
– RNH2 + H2S < RNH3+ + HS- ; fast reaction
– RNH2 + HS- < RNH3+ + S-- ; fast reaction
• Reaction for CO2 removal
– 2RNH2 + CO2 > RNH3+ + RNHCOO- ; fast reaction
– RNH2 + CO2 + H2O > RNH3+ + HCO3- ; slow reaction
– RNH2 + HCO3 > RNH3+ + CO3-- ; slow reaction
• Chemical loading capacity limit: 0.5 mol CO2 per mole of amine

33
 Alkanolamine Sweetening

• Alkanolamine : monoethanolamine (MEA), diethanolamine (DEA),

triethanolamine (TEA) Specific getlow gas residual
use to acid

• Use to remove H2S & CO2 & not selective  total acid gases removal
• Typical reaction between MEA & acid gas : absorbing & regenerating
– Absorbing reaction:
MEA + H2S  MEA hydrosulfide + heat
MEA + H2O + CO2  MEA carbonate + heat
– Regenerating reaction:
MEA hydrosulfide + heat  MEA + H2S
MEA carbonate + heat  MEA + H2O + CO2

• MEA is preferred than DEA or TEA :

1. Stronger base
2. More reactive
3. Lower molecular weight  requires less circulation to maintain amine-acid gas mole
ratio
4. Has greater stability
5. Can be readily reclaimed from contaminated solution by semicontinuous distillation

34
 Alkanolamine Sweetening

• Chemical use: MEA, DEA & TEA (triethanolamine)

• Not selective – total acid gas removal (H2S & CO2)
• Specific use to get low acid gas residual
• Typical reaction between acid gas & MEA:
• Absorbing:
• MEA +H2S  MEA hydrosulfide + heat
• MEA + H2O + CO2  MEA carbonate + heat
• Regenerating :
• MEA hydrosulfide + heat  MEA + H2S
• MEA carbonate + heat  MEA + H2O + CO2
• MEA :
• stronger base
• more reactive
• Lower molecular weight  required less circulation to maintain amine/acid gas
ratio
• Greater stability
• Can be reclaimed from contaminated solution by semicontinuous distillation
than DEA or TEA  MEA is preferred

35
Typical Natural Gas Sweetening Unit with Reversible Chemical Reaction Process

38
 Typical Natural Gas Sweetening Process Flow (Reversible Chemical Reaction)
1. Sour natural gas enters through an inlet separator for separation of solids, liquid and gas
2. From separator, gas stream enters contactor bottom, where it contacts amine solution flowing down from top of
column.
3. In contactor, acid gas components in gas react with amine to form regenerate salt. AS gas continues pass up
contactor, more acid gases chemically react with amine.
4. Sweetened gas leaves top of contactors and passes through outlet separator to catch any carried over solution.
Sweet gas leaving contactor is saturated with water, so dehydration normally required before sale.
5. Rich amine solution from contactor flows through flash drum to remove absorbed hydrocarbon or skin off them
6. From flash drum, rich solution passes through rich/lean exchanger where heat is absorbed from lean solution
7. Heated rich amine flows through mid portion of stripper.
8. As solution flows down the stripper column to reboiler, H2S and CO2 were stripped. Amine solution leaves
bottom stripper as lean solution
9. Lean solution passed through rich/lean exchanged and lean cooler to reduce its temperature to 5 deg.C warmer
than inlet gas temperature (stay above hydrocarbon dew point)
10. Lean solution returned to contactor top to repeat cycle.
11. Acid gas stripped from amine at stripper passed out through stripper top to condenser and separator to cool and
recover water
12. Recovered water returned to stripper as reflux
13. Acid gas from reflux separator either vented, incinerated, sent to sulfur recovery facilities, compressed for sale,or
reinjected into suitable reservoir enhancement project.

39
 RECLAIMERs

• Usually required by MEA and DGA amine based system

• Help removing of degradation products, heat-stable salts, suspended solids, acids and iron compounds from solution
• For MEA based system:
– basic solution helps reverse reaction
– Soda ash or caustic soda added to MEA reclaimer to provide pH = 8-9
• Operate at 1-3% of total amine circulation rate, slightly above stripper column pressure
• Size depend on total inventory of plant and expected degradation rate
• Semi-continuous batch operation.
• Filled with hot amine solution and sometime added with soda ash
• As T increases, liquid begin to distill
• Overhead vapors can be condensed and pumped back into the amine system or returned to stripper
• Initial vapor composition is water.
• Continued distillation cause solution more and more concentrated with amine & raise solution boiling point and
amine begin to distill overhead.
• Fresh feed continually added until solution boiling point material in it reboiler reaches 140 -150 deg.C
• Distillation continued for a short time and only water added to help recover residual amine in reclaimer reboiler
• Reclaimer then cleaned and recharged, and cycle is repeated.
• Reclaimer sludge removed during cleaning must be handled with care

40
 MONOETHANOLAMINE (MEA)s

• Used when:
– Low contactor pressure
– Low or stringer acid gas specifications
• Remove both H2S and CO2 or selective and COS & CS2
• Capability @ low – moderate pressure:
– H2S <4.0 ppmv
– CO2 = 100 ppmv
• Total acid gas pick-up limit: 0.3 – 0.35 mol acid gas/mole of MEA
• Solution concentrations limit: 10 – 20 wt%
• Added inhibitor for much higher solution strength and acid gas loading
• Since MEA has highest vapor pressure  solution losses through vaporization from contactor & stripper can be high but can
be minimized using water wash
• Important technical points:
– Commonly used as 10-20% solution in water
– For carbon steel equipment acid gas loading limited to 0.3 – 0.4 mol acid gas per mole amine
– MEA is not corrosive but its degradation products are very corrosive
– COS, CS2, SO2 & SO3 can partially deactivate MEA, which to be recovered with reclaimer
– MEA (primary amine) has high pH so MEA solution can produce gas contain less 6 mg/Std.m3 acid gas at very low H2S
partial pressure
– MEA heat reaction for CO2 about 1930 kJ/kg CO2 and above 0.5 mol/mole total acid gas loading, the heat reaction
varies considerably and must be calculated as loading function.
– Easily reduce acid gas concentrations to pipeline specifications (<6 mg H2S/Std m3 gas or 0.25 grains per 100 Std ft3)
– Proper design & operation, acid gas content can be reduced as low as 1.2 mg H2S/Std m3 or 0.05 grains per 100 Std ft3

41
 DIETHANOLAMINE (DEA)s

• Cannot treat to pipeline gas quality specification at as low pressure as will MEA
• Used for high pressure, high acid gas content streams having relatively high H2S/CO2 ratio.
• High DEA solution concentrations (up to 40 wt%) with high acid gas loading & corrosion control
• Maximum attainable loading limited by equilibrium solubility of H2S & CO2 at absorber bottom conditions
• Highest mole/mole loading 0.8-0.9 but most conventional plants operate at low loading
• DEA vs MEA:
– Typical mole/mole loading @ DEA = 0.35-0.87 mole/mole, higher than MEA = 0.3 – 0.4 mole/mole
– No significant amount of nonregenerable degradation products by DEA, no need for reclaimer
– DEA cannot be reclaimed at reboiler T as MEA, no reclaimer needed
– DEA secondary amine & chemically weaker than MEA, less heat required to strip amine solution
– DEA forms regenerable composed with COS & CS2, and can be used for partial removal of COS and CS without
significant solution losses
• Important technical considerations:
– DEA commonly used in 25-35 mass percent range
– DEA loading limited to 0.3-0.4 mol/mole of acid gas for carbon steel equipment
– Using stainless steel equipment, DEA safely loaded to equilibrium. For carbon steel equipment, need inhibitor
– DEA degradation products much less corrosive than those MEA. COS and CS2 may irreversibly react with DEA.
– DEA is secondary alkanolamine, has reduced affinity for H2S & CO2  at low pressure gas stream, DEA cannot
produce pipeline specifications gas. But with split flow design, pipeline specification can be met
– At low pressure and liquid residence time on tray (2 second), DEA selective toward H2S & permit significant CO2
fraction remain in product gas
– DEA reaction heat for CO2 = 151 kJ/kg of CO2 (360 kcal/kg of CO2), 22% less than for MEA

42
 DIGLYCOLAMINE (DGA)s

• DGA (primary amine) is (2-(2-aminoethoxy)) ethanol in aqueous solution used in the process
• Capable to remove H2S, CO2, COS and mercaptan from gas and liquid stream
• Had been used in natural and refinery gas applications.
• Had been used to treat natural gas to 4.0 ppmv @ 860 kPa.
• Has greater affinity for aromatics, olefins and heavy hc absorption than MEA & DEA system so adequate carbon
filtration should be included in DGA treating unit
• Process flow same as MEA, except:
– Can get higher acid gas pick up per gallon amine using 50-70 % solution strength than 15-20% for MEA
– Lower required treating circulation rate with higher amine concentration
– Reboiler steam consumption reduced
• Typical DGA concentration= 50-60% wt  70% wt
• DGA freezing point = -34 oC (50% DGA solution)  advantage for cold climate area.
• Required reclaiming to remove degradation products due to its high amine degradation rate
• React with CO2 & COS to form N, N’, bis (hydroxyethoxyethy) urea [BHEEU]
• DGA can be recovered by reversing BHEEU reaction in reclaimer
• Some technical point considerations:
– Generally used as 40 – 60 mass percent solution in water
– Reduced corrosion (with mole per mole solution loadings equivalent to MEA)
– For gas stream with acid gas partial pressure, absorber bottom T can increase to 82 oC and above which will
reduce possible loading
– Has tendency to preferentially react with CO2 over H2S, higher pH than MEA  easily achieve 6 mg H2S/Std
m3 gas (0.25 grains per 100 Std ft3) except where CO2 amount relatively larger than H2S
– At higher concentrations DGA has some definite advantages over other amines  lower freezing point and
high heats reaction
43
 METHYLDIETHANOLAMINE (MDEA)s

• Tertiary amine and can be used to selectively remove H2S to pipeline specifications at moderate – high pressure
– Reduced solution flow rate due to removed acid gas removal amount
– Smaller amine regeneration unit
– Higher H2S concentration in acid gas  reduced problems in sulfur recovery
• CO2 hydrolyzes much slower than H2S  Significant selectivity for H2S
• Can be partially regenerated in simple flash  bulk H2S and CO2 removal can be achieved with modest heat input
for regeneration
• Slow reaction with CO2, need activator (activated MDEA) to enhance CO2 absorption
• Some technical considerations:
– Most commonly used in 30-50 mass percent range
– Corrosion problems significantly reduced  acid gas loading can be 0.7-0.8 mol/mole practical in carbon steel
equipment
– Tertiary amine  less affinity for H2S & CO2 than DEA  can not produce pipeline specification at low
pressure stream
– Has lower vapor pressure, lower reaction heat, higher resistance to degradation, fewer corrosion problem and
selectivity towards H2S

44
 X TRIETHANOLAMINE (TEA) & DIISOPROPANOLAMINE (DIPA)

TRIETHANOLAMINE (TEA)

• Tertiary amine and selectivity for H2S over CO2 at lower P

• Inability to remove H2S & CO2 to low outlet specifications  replaced by MEA & DEA
• Has potential for bulk CO2 removal from gas stream & had been used to removed CO2 in ammonia plants

DIISOPROPANOLAMINE (DIPA)

• Secondary amine and selectivity for H2S but less than tertiary amine

45
 FORMULATED SOLVENTSs

• Amine based solvents

• Advantages:
– All MDEA advantages
– Equipment size reduction
– Energy saving system
– Some formulations capable of:
• Slipping larger portion inlet CO2 portion (than MDEA) to outlet gas & at same time removing H2S less than 4 ppmv
• Removing CO2 to level suitable for cryogenic plant feed
• Removing CO2 in ammonia plants
• To produce H2S to 4 ppmv pipeline specifications while reducing high inlet CO2 concentration to 2% at pipeline (bulk
CO2 removal)

– Benefits:
• Reduced corrosion
• Reduced circulation rate
• Lower energy requirements
• Smaller equipment due to reduced circulation rates for new plant
• Increase in capacity, ie gas through put or higher inlet acid gas composition for existing plants
• Reduced corrosion
• Lower energy requirements and reduced circulation rate

46
 Chemical absorption - Comparison of Chemical Solutions

Process MEA DEA DGA DIPA MDEA

Amine Type Primary Secondary Primary Secondary Tertiary
Reactivity High Moderate Moderate Moderate Moderate
Stability Fair Good Fair Good Good
HC Absorptivity Low Moderate High Moderate High
Vaporization Losses High Moderate High Moderate Low
H2S Selective No No No No Yes
Organic S Removal Low Low Moderate Low Low
Corrositivity High Moderate Moderate Low Low
Cost Low Low Moderate Low Moderate
Degradability
H2S None None None None None
CO2 Some Low Some Some Low
COS Yes Minor Some Severe Minor

47
 Physical Absorption - Introduction

• Physical solvent processes use

organic solvents and accomplish acid
gas removal mainly by physical
absorption.
• Most applicable to ↑P gas streams
containing appreciable quantities of
sour components.
• Physical solvent processes – e.g.
Selexol, Purisol and Fluor Solvent.

48
 PHYSICAL ABSORPTION METHODSs

• Various amines, Hot Potassium Carbonate Process, and Catacarb Process rely on chemical reaction to remove acid
gas constituent from sour gas streams.
• Removal of acid gases by physical absorption should be considered when:
1. Acid gas partial pressure in feed > 350 kPa or 3.5 bar (50 psi).

2. Heavy hydrocarbon concentration in feed gas is low

3. Bulk removal of acid gas is desired
4. Selective removal of H2S is desired
5. In general, physical solvents are capable of removing COS, CS2, and mercaptans.

• Solvents regenerated by:

1. multi-stage flushing to low pressure
2. regeneration at low temperature with an inert stripping gas
3. heating and stripping of solution with steam/solvent vapor.

• Various methods/processes name:

– Selexol
– Fluor solvent
– Purisol
– Sepasolv MPE
– estasolvent

49
 Selexol Process

• Use physical solvent

made of a dimethyl ether
of polyethylene glycol to
remove acid gas from
streams of synthetic or
natural gas.

• Chemically inert and is

not subject to
degradation.

• Most applications for

high CO2 contents but
very little H2S.

50
 Selexol Process

Advantages Disadvantages
• Selective for H2S, due to • High hydrocarbon coabsorption.
higher absorption capacities
for H2S than CO2. • Not applicable at low treating
pressures.(<400 psi)
• Since there are no chemical
reactions, no reclaimer is • Cost are relatively high and requires
required. payment of a license fee.
• Little corrosion

• Utilizes high acid gas

loadings & has a low utility
requirements (high partial
pressure condition)

51
Selexol Process Facilities

52
 Purisol Process

• Use N-methyl-2 pyrolidone solution.

• Processing scheme is similar with Selexol.

• More promise in refining and syngas applications where sour gas is especially
lean.

53
 Purisol Process

Advantages
Disadvantages
• Selective for H2S, due to
higher absorption capacities
• High hydrocarbon coabsorption.
for H2S than CO2.

• Since there are no chemical • Not applicable at low treating

reactions, no reclaimer is pressures.(<400 psi)
required.
• Cost are relatively high and requires
• Little corrosion payment of a license fee.
• There must be a use for sour stripping
• Utilizes high acid gas loadings
gas from regenerator such as boiler
& has a low utility
requirements (high partial fuel.
pressure condition)
• Exhibit better mercaptan (RSR)
removal than Selexol.

54
 Rectisol Process

• Uses methanol as a solvent in 2-stages

refrigerated absorber.
• Refrigerated to -5oF to -75oF prior to entering the
absorber.
• Used primarily in sweetening synthesis gas.

55
 FLOUR PROCESSs
Flour process main characteristics desired for right solvent selection:
1. Low vapor pressure at operating temperature is desirable
If solvent vapor pressure is appreciable, high losses  necessitate for complicated solvent recovery system or high operating costs due to
solvent loss. Therefore Fluor eliminated from their consideration several high vapor pressure solvents that had good solubilities for acid gas
constituents.
2. Primary constituents in gas stream should be only slightly, if at all, soluble in the solvent
Methane and heavier hydrocarbons should not be appreciably soluble in solvent. If they are soluble, then expensive and complicated procedures
required to prevent excessive losses.
3. Solvent should have low viscosity
High viscosities increase pumping costs, have an adverse effect on tray efficiencies and mass transfer. Operation at sub-ambient temperatures may
aggravate viscosity problem. Some solvent satisfactory for ambient temperature operation might prove undesirable at lower T
4. Low solubility for water
Increasing water content in circulating solvent lower its carrying capacity for acid gases. Dissolved water tend to increase corrosion and solvent
decomposition effects. If water is dissolved, then steps must be taken to maintain solvent water content at some specified level
 increases plant complexity, costs, and operational problems.
5. Solvent should not degrade under normal operating conditions
Solvent should not degrade chemically under normal operational T & P. This problem can be handled by filtration, reclaiming, and so forth, but
these items do increase investment and operating costs. Solvent should be stable with regard to oxygen and other materials. Storage tanks can be
inert gas blanketed, but this is a complicating factor to be avoided if at all possible.
6. Solvent should not react chemically with any component in gas stream
This can lead to solvent degradation loss and loss solvent effectiveness.
7. Solvent should be non-corrosive to common metals
Use of carbon steel construction, preferably without necessity for stress relieving, will minimize plant investment. In physical absorption process,
conditions are usually ideal for minimizing corrosion due to carbon dioxide and hydrogen sulfide. Temperatures are low.
8. Solvent should be readily available at reasonable cost
An excellent solvent would have appreciable effect on plant investment would not be desirable.

Recommended solvent for CO2 removal from high P gas stream

1. Polyethylene carbonate
2. Butoxydiethylene glycol acetate
3. Glycol triacetate
4. Methoxy triethylene glycol acetate

56
 Fluor Solvent Process

• Employs propylene glycol to remove CO2 and H2S

from sour gas streams.
main purpose

• Basically the same advantages and disadvantages

as selexol.

57
 Physical Absorption – Process Selection

• Depends on process objectives and

characteristics of the solvents, such as selectivity
for H2S, CO2, HCN, etc.
• Ease of controlling water content of circulating
solvent.
• Concurrent hydrocarbon loss
• Solvent cost & supply
• Chemical inertness, royalty cost, thermal stability
and proven plant performance for various
processing techniques.

58
 Comparison of Commercial Physical Solvents

• Aspects need to be consider:

• Heavy hydrocarbon effect
• Recycle compressor effect
• Selective H2S removal
• Process configuration

59
 Physical Absorption – Effect of Heavy Hydrocarbon

• In natural gas treating, loss of heavy

hydrocarbons is a concern. Selexol are miscible
with water, and water may be used to reject
these hydrocarbons.
• Water can actually be added to this stream to
reduce hydrocarbon solubility further.

60
 Physical Absorption – Effects of Recycle Compressor

• Major energy user in physical solvent processes is

compression for recycle of flash gas to limit
methane losses.
• The higher the solubility of methane, the higher
the recycle compressor horsepower for the same
amount of methane product in treated gas.

61
 Physical Absorption – Selective H2S Removal

• Data indicate that Selexol and Purisol are superior

if selective H2S removal from gas containing
carbon dioxide is required.
• Actual experience confirms this prediction.

62
 Physical Absorption – Process Configuration

• Good thermal stability, chemical inertness, and thermal conductivity are also
necessary to permit flexibility in process schemes.
– For example, selective H2S removal can be benefited by use of heat.

• Reboiling solvent in regenerator may be necessary to meet treated gas purity

requirements for CO2, H2S.
• Demands on physical solvent processes are:
– increasing,
– losses of valuable components must be minimized,
– removal of acid gas and trace components to lower levels must be achieved.

• Process designer's ingenuity and innovations might easily outdistance small

inherent advantages of one solvent over another.

• Selexol has a clear experience advantage over all other solvents in all applications
involving H2S and C02 removal in hydrocarbon systems.

• Fluor Solvent and Selexol both enjoy a clear experience advantage over the other
processes in applications for CO2 removal only.

63
 Solubility of Gases in Physical Solvents

Gas Solubility (cc gas at 1 atm, 75F/cc solvent)

(Ferrin & Manning, 1984)

Gas Selexol Purisol Fluor Solvent

H2S 25.5 43.3 13.3
CO2 3.6 3.8 3.3
COS 9.8 10.6 6
C3 4.6 3.5 2.1

64
 Solubility of Gases in Physical Solvents

Gas Solubilities Relative to CO2 (Bucklin & Schendel, 1984)

Ga s Se le x ol Purisol Fluor Solve nt
H2 0.013 0.006 0.008
CO 0.028 0.021 0.021
C1 0.067 0.072 0.038
C2 0.42 0.38 0.17
CO2 1.0 1.0 1.0
C3 1.02 1.07 0.51
nC4 2.33 3.48 1.75
COS 2.33 2.72 1.88
H2S 8.93 10.2 3.28
nC6 11.0 42.7 13.5
CH3SH 22.7 34.0 27.2
C6H6 253.0 / 200.0
H2O 733.0 4000.0 300.0 65
 PHYSICAL & CHEMICAL PURIFICATION PROCESSESs

• Physical/chemical combined purification process, more successful than a single physical solvent
• Example: alkanol amines (mono- or diethanol amine) mixed with methanol
• Main advantage: good physical absorption of physical solvent component in combination with amine chemical
reaction.
• Combination of chemically active amine with low boiling point polar physical solvent such as methanol offers
major advantages in absorption of CO2 and sulfur components:
• Very low clean gas sulfur contents of less than 0.1 ppm, which required for synthesis gases

• Very low CO2 contents in purified gas

• Good absorption of trace components, such as HCN, COS, mercaptans, and higher hydrocarbons
• Low regeneration temperature due to solvent methanol has boiling point approximately 35 oC below water
• Solvent is non-corrosive  carbon steel equipment can be used.
• Disadvantages:
– As conventional alkanolamines such as monoethanolamine (MEA) and diethanolamine (DEA) are used as non-
selective solvents, sulfur components H2S and COS are absorbed together with CO2 and jointly occur in off-gas
 sulfur-rich off-gas should be treated.
• MEA/DEA are replaced by aliphatic alkylamines, ie: diisopropylamined (DIPAM) & diethylamined (DETA)

66
 DIPAM & DETA ADVANTAGES

• Advantages using DIPAM & DETA:

1. High thermal and chemical stability  no reclaimer needed
2. Higher effective CO2 and H2S loadings
3. High selectivity of solvent between sulfur components and CO2, and very low residual sulfur contents in clean
gas
4. Good industrial availability at moderate cost
5. Smaller difference between absorption and desorption temperature
6. No foaming tendency due to low surface tension
7. No corrosion problems
8. Considerable reduction in vapor pressure of amine neutralized by sour gases.
9. CO2 produced free from COS, pure and can be used for urea synthesis.
• Special applications:
1. Joint absorption of H2S, COS, and CO2 as well as trace contaminants, such as HCN, NH3, mercaptans, thiophenes,
etc., from raw gases to produce highly pure synthesis gases.
2. Selective absorption of all sulfur components from raw gases to obtain highly pure product gas and high sulfur
Clause gas.
• Note: Combination of physical/chemical purification processes and aliphatic alkylamine processes have
predominantly chemical characteristics  cost-effective for all gases with low to medium partial pressures sour
gas, and if sour gas partial pressures are high, physical gas purification processes should preferably be used.

67
 Hybrid Process

 Chemical absorption (to achieve H2S specifications) + Physical absorption (low

energy & easy of regeneration)
 Only truly commercial process = Sulfinol
 Can be dissolved in solvent large quantities of CO2 & H2S at low T , and releasing them again at high T.
Solvent rich CO2 & H2S recovered from absorption column bottom & transferred to regeneration column
where heat liberates absorbed CO2 & H2S. Regenerated solvent reused again.

 Consists of a mixture of sulfolane, isopropanol amine and water

RESIDUE GAS FLASH CONDENSER

GAS ACID
CW GAS

CW
LEAN LEAN /RICH
SOLVENT EXCHANGER
REFLUX
LEAN
SOLVENT
FLASH COOLER
TANK

STEAM

FREE
GAS

LEAN SOLVENT
SURGE
68
 Glycol/Amine Process

• Combination of dehydration & sweetening

• Use solution composed : 10 – 30% weight MEA + 45 – 85% weight
glycol + 5 – 25% water
• Simultaneous to remove water vapor. H2S & CO2
• Benefit : lower equipment cost than MEA unit followed by glycol
dehydrator
• Disadvantages:
• increased MEA vaporization losses due to high regeneration T
• Reclaiming must be by vacuum distillation
• Corrosion problems
• Application limitation - must be for gas stream that do not require
low dew points

69
 Glycol/Amine Process

• Use solution composed of 10%-30% weight MEA, 45%-85% glycol & 5%-
25% water for simultaneous water vapor, H2S & CO2 removal.
• Advantages:
– Combination dehydration & sweetening unit  lower equipment cost than standard
MEA unit followed by separation of glycol/amine glycol dehydrator.
• Disadvantages:
– Increased MEA vaporization losses due to high regeneration T
– Operating unit corrosion problems
– Limited applications for achieving low dew points.

70
 Hybrid Process - Sulfinol

 Uses of solvent mixture  behave as chemical & physical solvent process

 Solvent composed :
1. Sulfolane – physical solvent
2. diisopropanolamine (DIPA) – chemical solvent
3. water

 Formation of heavy, tar-like sludge  block exchangers & liners

 Absorb HCs due to sulfolane (physical solvent)
 Advantages:
 Low solvent circulation rate
 Small equipment & lower plant cost
 Low heat capacity of solvent
 Low utility costs
 Low degradation rate
 Low corrosion rate
 Low foaming tendency
 High effectiveness for carbonyl sulfide (ROS), carbon disulfide (CS2) & mercaptans (RSR) removal
 Low solvent vaporization losses
 Low heat-exchanger fouling tendensy
 None expansion of solvent when freezes
 Excellent H2S & CO2 removal
 Good for low P (100 –300psia)
 Can remove COS, CS2 & RSR with no degradation
 Selective H2S removal
• Disadvantages:
• Absorption of heavy hc, aromatic
• Formation of heavy, tar-like sludge  block exchangers & liners

71
 Sulfinol Process
• Use mixture of solvent to that it behave as chemical & physical solvent process
• Solvent composed of:
– Sulfolane – as physical solvent
– diisopropanolamine (DIPA) – chemical solvent
– water
• Advantages:
– Low solvent circulation rate
– Smaller equipment
– Lower plant cost
– Low solvent heat capacity
– Low utility cost
– Low degradation rate
– Low corrosion rate
– Low foaming tendency
– High effectiveness for carbonyl sulfide, carbon disulfide mercaptans removal
– Low solvent vaporization losses
– Low heat exchanger fouling tendency
– Non solvent expansion when freezing
• Disadvantages:
– Absorption of heavy hc & aromatics
– Expense

72
 Direct Conversion

 Uses chemical reactions to oxidize H2S &

produce elemental sulfur
 Based on reaction of H2S and O2 or H2S and
SO2, to yield H2O & S
 Licensed processes very expensive but
can sell
pure sulfur
gas

 Involved specialized catalysts and/or solvents

 Can be used directly on the produced gas
stream

73
 Dry Bed Adsorption

 Utilize solid materials rather than aqueous

solvents to remove acid gas constituents
 Retention may be:
 chemical reaction,
 capillary condensation,
 intermolecular forces,
 or combinations
 Gas stream must flow through solid particles
fixed bed that remove acid gases & hold them
in the bed

74
 SOLID BED SWEETENING METHODS

• Based on :
– adsorption of acid gases on solid sweetening agent surface , or
– reaction with some component on that surface.
• Best applied to gases containing low-to-medium concentrations H2S or mercaptans.
• Tend to be highly selective and do not normally remove significant quantities of CO2  H2S stream from process
usually high purity.
• Pressure has relatively little effect on adsorptive capacity of sweetening agent.
• Most batch type and tend to have low investment and operating costs.
• Some process:
– iron oxide (sponge) process
– molecular sieves

75
 IRON OXIDE (SPONGE) PROCESSs
• Selectively removes H2S from gas or liquid streams and limited to streams containing low concentrations H2S at pressures
ranging from 170 to 8300 kPa (ga).
• Employs hydrated iron oxide, impregnated on wood chips.
• Care must be taken to maintain pH, gas T, and moisture content to prevent loss of bed activity
 injections of water and sodium carbonate sometimes needed.
• H2S reacts with iron oxide to form iron sulfide and water. When iron oxide is consumed, bed must be changed out or
regenerated.
• Bed can be regenerated with air; only about 60% of previous bed life can be expected.
• Bed life of batch process dependent on H2S quantity, iron oxide in bed, residence time, pH, moisture content, and T
• Iron oxide or dry box process is one of oldest known methods for sulfur compounds removal from gas streams with
advantage when sulfur in gas < 7–9 ton /day and concentration < 2400 g/100 sq.m3 [1000 grains H2S per 100 sq.ft3] of gas.
• Hydrate iron oxide (Fe2O3) reacts with H2S to form Fe2S3, which may be regenerated with air.
• Continuous regeneration possible by injecting small stream of air into feed-gas stream, which converts sulfide to oxide and
liberates elemental sulfur. Regeneration is normally finished when outlet oxygen concentration reaches 4–6% and bed outlet
temperature starts dropping.
• Each charge of sponge may be regenerated several times, but it gradually becomes less efficient and requires replacement.
• Advantages:
a. Complete removal of small to medium hydrogen sulfide concentrations without removing carbon dioxide
b. Relatively small investment, for small to moderate gas volumes, compared with other processes
c. Equally effective at any operating pressure
d. Used to remove mercaptans or convert them to disulfides.
• Disadvantages:
• Batch process requiring duplicate installation or flow interruption of processed gas
• Prone to hydrate formation when operated at higher pressures and at temperatures in hydrate-forming range
• Effectually removes ethyl mercaptan that has been added for odorization
• Coating of iron sponge with entrained oil or distillate requires more frequent change out of sponge bed.
76
 Iron-Sponge Sweetening

• Batch process with hydrated iron oxide (Fe2O3)sponge

supported on wood shaving
• Reaction between sponge & H2S
2Fe2O3 + 6H2S  2Fe2S3 + 6H2O
2Fe,0, +6HS -> 2FezSs + 6H2O

• Reaction occur if T < 120 degF or supplemental water spray

• Bed regenerated with air continuously/batch addition
• Regenerated reaction:
2Fe2O3 + 3O2 2Fe2S3 + 6S
2FeS, +302 -> 2Fec0s+6S

77
 Iron Sponge Sweetening

 Dry oxidation batch process -for sulphur compounds removal from coal gas.
 Sponge : sensitive, hydrated iron oxide (Fe2O3), supported on wood shavings
 H2S is converted to sulphur, using oxygen in carriers which react with it at ordinary
temperatures.
 Reaction between iron sponge & H2S:
6H2S + 2Fe2O3 = 2Fe2S3 + 6H2O
• Reaction proceeds best at temperature 37.8°C (kept below 120deg.F) and alkaline
environment.
 Can be with supplemental water spray
 Pellets, or hydrated iron oxide (sensitive) on shavings are distributed in large containers
called dry boxes or on trays in towers.
 Bed can be regenerated by air addition (continuously or batch)
 Regeneration reaction: 2Fe2S3 + 3O2 = 6S + 2Fe2O3
 Process is a two-stage one.
 First stage removing H2S,
 Second stage reoxidizes (regeneration) Fe2S3 to the oxide.
 Since sulfur remains in the bed, regeneration steps is limited and bed need replacement

78
Iron Sponge Process Flow

79
 Iron Sponge

Advantages
 Low initial cost Disadvantages
 Low power consumption  Proprietary media
 No furnace erosion and  Level of effort for
boiling, more patching life removal of media
varies
 Low consumption of cast
iron  High unit operating
costs
 Better yield
 Increase in production
 Low burning gas, harmless
to worker's health
 More profit
 Positive effect on bottom line

80
 MOLECULAR SIEVESs

• Used for removal of sulfur compounds & CO2 from gas streams.
• Hydrogen sulfide can be selectively removed to meet 4 ppmv specification.
• Sieve bed can be designed to dehydrate and sweeten simultaneously.
• Crystalline sodium-calcium alumino silicates can be used for selective removal of H2S and other sulfur compounds
from natural gas streams. Common crystalline forms used in commercial adsorption are synthetically manufactured
and activated crystalline material is porous.
• Molecular sieves have large surface area and highly localized polar charges which provides very strong adsorption of
polar or polarizable compounds on molecular sieves  much higher adsorptive capacities by molecular sieves than
by other adsorbents, particularly in lower concentration ranges.
• Concentrations of acid gas are such that cycle times are 6–8 hrs.
• To operate properly, sieves must be regenerated at T close to 315 oC for enough time to remove all adsorbed
materials, usually 1 hr or more.
• Regeneration molecular sieve bed concentrates H2S into small regeneration stream that must be treated or
disposed of. During regeneration cycle, H2S will exhibit peak concentration in regeneration gas. Peak approximately
30 times H2S concentration in inlet stream.
• Problem of COS formation during processing according to reaction:
H2S + CO2  COS + H2O
 Molecular sieve products have been developed that do not catalyze COS formation. Regeneration cycle central
zone most favorable to COS formation.

81
 Molecular Sieve

 Inlet gas simply passed through tower containing absorbent.

 When molecular sieve approaches saturation, inlet stream
switched to second tower.
 While absorbent in first generated by following heated, dry
gas counter-flow to the direction of stream that was being
dried.
 Moist generation gas is cooled and much of water is
condensed, separated and removed from the system.
 Generation gas is then either
 Mixed with wet inlet gas to the adsorbing tower, or
 Returned to lower pressure distribution line.
 Tower must be cooled by a cool flow of dry gas before being
placed back in service.

82
Molecular Sieve

83
 Molecular Sieve

Pros Cons
• Economically favored for • Regeneration of gas
small quantities of H2S requires treatment if it
• Very selective (reject can not be blended
100% of CO2) into fuel.
• Sweeten & dehydrate • Carbonyl sulfide
gas simultaneously if H20 (COS) can be formed
present in the molecular sieve
bed from the reaction
of CO2 and H2S

84
 Characteristics of Gas Treating Processes

Process Capable of Treating Capable of Treating Chemical Reclaiming Average Losses

Rich Gas Streams At Low Pressure Degradation Possible LB/MMscf Acid Gas
MEA Yes Yes Yes Yes 5
DEA Yes Yes Yes No 5.5
DGA Sometimes Yes Yes Yes 3.5
Shell ADIP Yes Yes Yes Yes 5
Benfield Yes No No Not required 3
Catacarb Yes No No Not required 3
Physical Solvents Yes No No Not required 4
Shell Sulfinol Sometimes Yes Yes Yes 1.5/5
Stretford Sometimes Yes Yes No /
Mol Sieve Sometimes Yes Requires Regeneration / /
Iron Sponge Yes Yes Cannot be regenerated / /

85
 DESIGN – QUICK ESTIMATION s

1. Amine circulation rate

2. Heat exchange requirements (H - duty & A-area)
3. Pump power requirements
4. Amine plant contactor diameter

86
 AMINE CIRCULATION RATE ESTIMATIONs
• Amine circulation rate estimation for H2S + CO2 concentrations < 5 mol% and maximum amine concentration 30% wt.

• For MEA (assumed 0.33 mol acid gas pickup per mole MEA):
Qa = 328Qy/x

• For DEA (assumed 0.5 mol acid gas pickup per mole DEA – conventional):
Qa = 360Qy/x

• For DEA (assumed 0.7 mol acid gas pickup per mole DEA- high loading):
Qa = 256Qy/x

• For DGA (assumed 0.39 mol acid gas pickup per mole DGA & DGA concentration of 50-60 wt%):
Qa = 446Qy/x

Where:
Qa = amine circulation rate, m3/h
Q = sour gas to be processed, Msq.m3/day
y = acid gas concentration in sour gas, mol%
x = amine concentration in liquid solution, mass%

FACULTY OF PETROLEUM & RENEWABLE ENERGY ENGINEERING (FPREE)

87
Innovative. Entrepreneurial . Global
 HEAT & HEAT EXCHANGE REQUIREMENTSs

• Reboiler (direct fired):

– H = 93Qa
– A = 4.63Qa

• Rich-lean amine heat exchanger (HEX):

– H = 58Qa
– A = 4.6Qa

• Amine cooler (air cooled):

– H = 19.3Qa
– A = 4.18Qa

• Reflux condenser:
– H = 38.6Qa
– A = 2.13Qa

Where;
– H = duty, kW
– A = area, m2

88
 POWER REQUIREMENTS ESTIMATIONs

• Main amine solution pumps:

Hp = 0.00031QaP

• Amine booster pumps:

Hp = 0.2Qa

• Reflux pumps:
Hp = 0.2Qa

• Aerial cooler:
Hp = 1.2Qa

Where:
Hp = power, kW
P = pressure, kPa(ga) - gauge

89
 DIAMETER ESTIMATIONs

• Amine plant contactor diameter:

Dc = 10750[Q/(P)0.5]0.5
where:
Dc = contactor diameter, mm before rounding up to nearest 100 mm
P = contactor pressure, kPa(abs)
Q = gas to contactor, Msq.m3/day

• Regenerator diameter below feed point:

• Dr = 10750[Q/(P)0.5]0.5
Where:
Q = amine circulation rate, gpm
Dr = regenerator bottom diameter, mm

Diameter of section of still above feed point = 0.67 Dr

90
 2.8
101.3kPa HrS (O2 0.6 +
=

Q
+

+latm
=

P
=3. Y

main amine solutions pump: Reflux

Qa:y Up 0.00031 Qa P
=
Up 12.24=
kW P 5860 101.3
=
+

=0.00031(61.2) (5860) =5961.3

Aerial cooler:
=III. 18kW
360(1)(3.4)
Hp 1.2 Qa
=

Amine booster
20
Up 0.2Qa
=

=1.2(61.2)
=61.2m3/hr =0.2
=
(61.2)
12.24 kW
:73. Y4kW
b=
10750
10750(T3
Reboiler:
HEX:
Amine cooler: reflux condensor. =

H 58
=

Qa
H 19.3 Qa H 38.6 Qa
H 93(Qa)
= =
=

58(61.2)
=

:93(61.2)
=19.3 (61.2) 38.6(61.2)
=

=1223.
=3549.6k(N
41mm
1181.16kW
=

=1362.32kW
=5691.6kW
A 4.6 Qa
:

A 4.18 Qa A:2.13 Qa
A 4.63(ka)
:

4.6(61.2)
=

=Y. 18(61.2) 2.13(61.2)

=281.52 m2
4.63(61.2)
=

255.82m"
=
=130.36 m2

283.356m2
:
 GENERAL CONSIDERATIONSs

1. Corrosion
2. Inlet scrubbing
3. Amine losses
4. Filtration
5. Amine reclamation
6. Foaming
7. Amine-amine heat exchanger
8. Regenerator reboiler
9. Amine solution selection

91
 GAS SWEETENING PLANTS CORROSIONs

• H2S and CO2 with water practically ensures corrosive conditions @ plant.
• Generally , gas streams with high H2S-CO2 ratios gas stream less corrosive than those having low H2S-CO2 ratio
• H2S concentrations (ppmv) range with CO2 concentrations of 2% or more tend to be corrosive.
• Corrosion in sweetening plants tends to be chemical in nature,  function of T & and liquid velocity.
• Sweetening solution type & concentration used strong impact on corrosion rate  increases with stronger solutions
and higher gas loadings.
• Hydrogen sulfide dissociates in water to form weak acid  attacks iron  insoluble iron sulfide adhere to base
metal & provide some protection from further corrosion, but it can be eroded away easily, exposing fresh metal for
further attack.
• CO2 in free water presence  carbonic acid  attack iron  soluble iron bicarbonate that, upon heating release
CO2 and an insoluble iron carbonate or hydrolyze to iron oxide. If H2S present, it will react with iron oxide  iron
sulfide.
• High liquid velocities can erode protective iron sulfide film  high corrosion rates.
• In general, design velocities in rich solution piping should be 50% of those that would be used in sweet service.
• Reboiler & amine–amine exchanger rich side, tend to experience high corrosion rates @ T
• Stripper overhead condensing loop also tends to experience high corrosion rates @ low pH
• Acid degradation products also contribute to corrosion : degradation products act as chelating agents for iron when
hot. When cooled, iron chelates become unstable, releasing iron  iron sulfide @ H2S.
• Primary amines more corrosive than secondary amines due to primary amines degradation products act as stronger
chelating agents.
• Treating plants normally use carbon steel as construction principal material.
• Vessels and piping should be stress relieved to minimize stress corrosion along weld seams.
• Corrosion allowance for equipment ranges from 1 to 6 mm, typically 3 mm.

92
 GAS SWEETENING PLANTS CORROSIONs

• When corrosion to be a problem, or high solution loadings required, stainless steel or clad stainless
steel may be used in following critical areas:
1. Reflux condenser
2. Reboiler tube bundle
3. Rich/lean exchanger tubes
4. Bubbling area of contactor and/or stripper trays
5. Rich solution piping from rich/lean exchanger to stripper
6. Bottom five trays of contactor and top five trays of stripper, if not all.
• Common ss used : 304, 316 or 410 (410 ss in DEA service for CO2 removal with no H2S may
experience corrosion)
• If alloy welded  used L grade
• High chloride content @ plants  use duplex ss
• T of solution in reboiler and steam should be kept as low as possible
• Use of high T heat carrying media such as oil in reboiler should be avoided to maintain lowest
possible metal skin T
• Lowest possible P on stripping column and reboilers should be considered to avoid severe reboiler
tubes corrosion
• Inert gas blanketing facilities should be considered for solution exposed to atmosphere
• Positive pressure on suction side of pumps should be ensured for excluding oxygen from system
93
 AMINE LOSSES & INLET SCRUBBINGs

AMINE LOSSES
• Can be very expensive
• Separator on sweet gas stream leaving contactor is advisable
 will also help elimination of amine losses from unexpected foaming or surges

INLET SCRUBBING
• Foreign material in sour gas: liquid hc, entrained solids, corrosion inhibitor, drilling mud
and well acidizers
 plant operational problems, ie foaming, corrosion, reboiler tube-burn-out etc.
• Inlet separator equipment should be sized and designed with considerations of foreign
material in sour gas stream including nature of foreign material (solids, slug, surge etc),
and extremely high instantaneous flow rates.

94
 FILTRATIONs

• Proper solution important for maintenance of clean, efficient amine solution  filtration required
• Filtration of treating solution to remove entrained solids in essential  successful plant operation
• Two stage filtration generally recommended
– 1st stage typically cartridge type or precoat filter, designed to remove particles down to 10 mm or
less
– 2nd stage typically activated charcoal and designed to remove degradation products, smaller
particles entrained solids, hydrocarbon and other contaminants (by adsorption).
• Carbon granule size can remove particles down to 5 mm
• Activated carbon filter should always be located downstream of 1st stage filter due to
deposition of solids would plug carbon filter
• Carryover carbon fines can be controlled by locating 2nd cartridge type filter immediately
downstream of carbon filter or using graded carbon bed (larger granules placed at filter
outlet to trap fines
• Filtration system should be capable handling at least 10-20% of amine circulation rate
 permit quick cleanup of amine solution after upset
• Full-flow filtration, parallel filters with no bypass is recommended
• Best location : on rich amine solution at contactor outlet or on lean amine solution just before solution
enters contactor
• Filtration rate should be as high as practical : range = 5% of circulation to full stream
• Removing particles down to 5 mm is recommended

95
 FOAMINGs

• Due to foreign material contamination in stream, such as;

– Suspended solids
– Organic acids
– Corrosion inhibitors
– Condensed hc
– Soap based valve greases
– Makeup water impurities
– Degradation products
– Lube oil
• Indication :
– Differential pressure across contactor sudden increase, or
– Sudden liquid level variation at contactor bottom
• When foaming occur
 poor contact between gas and chemical solution
 reduced treating capacity & sweetening efficiency, and
possibility of outlet specification cannot be met
• Contamination from upstream operation can be minimized through adequate inlet separation
• Hc condensation in contactor can be avoided by maintaining lean solution T at least 5oC above hc dew point T of
outlet gas
• Temporary upset can be controlled by antifoam chemicals addition (usually silicone or long-chain alcohol type)

96
 AMINE RECLAMATIONs- - Reclaimer

• Reclaimer used to remove entrained solids, dissolved salts and degradation products which can cause
foaming & corrosion problems
• An easy-to-open entry should be located on reclaimer shell so that solids can be simply washed out at
cycle end and drain line should be large enough to pass solids
• Tube bundles should be raised 15 cm or more from reclaimer shell bottom to provide space for sludge
accumulation below tubes and give better solution flow around tubes
• Packed column should be placed on top of reclaimer to eliminate foam and entrainment from overhead
vapor stream. Glass site port installation in vapor line will help keep check on carryover
• Tubes should be widely spaced for easy cleaning
• Make certain stream supply not superheated
• Recorder should be used to monitor reclaimer T throughout cycle
• Amine feed to reclaimer should be controlled by level controller on kettle to maintain liquid level at
least 15 cm above tube.
• T indicator should be provided on reclaimer outlet line
• Sufficient vapor space should be allowed above liquid layer in reclaimer to prevent liquid carryover in
overhead vapor line
• Provision for chemical analysis of reclaimer bottom and amine solution should be considered to
identify solution contaminants and determine degree and rate of solution contamination

97
 AMINE-AMINE HEAT EXCHANGERs

• If intermediate flash separator is not used, contactor pressure should be maintained through
amine-amine heat exchanger to minimizes acid gases breakout from rich amine solution,
excessive corrosion of control valves, heat exchanger, and downstream piping

• Linear velocities in amine-to-amine heat exchanger should be low – (0.6 – 1.0 m/s)
 reduces heat transfer coefficient and increases surface area requirement

• Flowing amine solution should not impinge directly on vessel surfaces; impingement
baffles should be utilized in exchangers.

98
 REGENERATOR REBOILERs

Reboiler system design should consider:

• Common low pressure saturated steam used - 500-380 kPa (135-142oC), to strip amine solution.
• Steam T above 140 oC should be avoided to prevent excessive skin T on tubes
• Amine Unit should be designed for pressure operation. Higher operating P increase regenerator bottom T and to provide more complete
acid gases stripping, especially CO2
• Maximum allowable kettle T for solution regeneration depends on amine type used to prevent amine degradation
• T controller valve should be on stream inlet, not on condensate outlet, to keep excessive condensate out of tubes. When condensate
partially floods reboiler tube, heat load concentrates in bundle top section  can cause tube failure
• Stripping stream requirements vary depending on sweetening degree required for treated process stream. Normally stream consumption
should be at least 120 g of excess stream per liter of solution circulated
• To provide good circulation of amine solution around tubes and to reduce fouling causes by sludge accumulation, tube bundle should be
placed on slide about 15 cm above reboiler shell bottom.
• Amine solution should enter reboiler at several locations to help improve liquid natural circulation in reboiler shell. Several vapor exit
locations will reduce stagnant acid gases pockets in reboiler.
• Tube bundle should be supported to prevent tube vibration. Teflon or other protective inserts prevents tube cutting.
• Tubes length should be limited to prevent condensate “logging” and water hammer. Water hammer effect can produce severe tube
vibration and grooving tubes at support baffles.
• Square pitch tube pattern recommended for reboiler and heat exchange bundles to provide easy cleaning. Tubes should be widely spaced
to permit rapid escape of liberated gases and to reduce the high velocity scrubbing action associated with two-phase flow. This scrubbing
action will remove protective film and increase corrosion.
• Reboiler should be designed to provide liberal amount of vapor disengaging space between tubes, and with sufficient surface to produce
simmering action rather than violent boiling. In existing installations where vapor binding is a problem, some tubes can be removed to
form an “X” or “V” in bundle center to provide low resistance path to escaping vapors.
• Reboiler bundle should always be kept covered with 15–20 cm liquid to prevent localized drying and overheating. Severe corrosion will
occur if liquid level lowered until some tubes exposed.
• Analysis of amine solution entering and leaving reboiler will determine stripping operation efficiency. High acid gas loading in reboiler
causes tube corrosion.

99
 AMINE SOLUTION SELECTIONs

Factors should be considered:

• Initial selection should be based on :
– pressure
– sour gas / acid gas content and
– product gas purity specification
• Based on currently “accepted” operating conditions, MEA usually not preferred for its high reaction
heat and lower acid gas carrying capacity per unit volume of solution. However, MEA still used for
plants where inlet gas pressure is low and pipeline specification gas or total removal of acid gases is
required.
• DEA, is used for its lower reaction heat, higher acid gas carrying capacity, and lower energy
requirements. However, its potential for selective H2S removal from streams containing CO2 has not
fully been realized.
• DGA, despite high reaction heat, has very high gas carrying capacity that usually produces very
reasonable net energy requirements. DGA also has good potential for absorbing COS and some
mercaptans from gas and liquid streams, and, therefore DGA has been used in natural and refinery gas
applications
• MDEA, with its some outstanding capabilities, resulting from its low reaction heat, can be used in
pressure swing plants for bulk acid gas removal. MDEA currently best known for its ability to
preferentially absorb H2S

100
 FLASH TANKs

• Rich solution leaving contactor may pass through a flash tank.

• Flash tank is more important when treating high-pressure gas. Gases entrained in rich solution will be
separated.
• Amount gas absorbed decreased because flash tank lower operating pressure
• Using a flash tank will:
• Reduce erosion in rich/lean exchangers
• Minimize hydrocarbon content in acid gas
• Reduce vapor load on stripper
• Possibly allow off-gas from flash tank to be used as fuel (may require sweetening).
• When heavy hydrocarbons are present in natural gas, flash tank can be used to skim off heavy
hydrocarbons that were absorbed by solution.
• Residence times for flash tanks in amine service vary from 3 to 10 min, depending on separation
requirements.
– Inlet gas streams containing only methane and ethane require shorter residence times.
– Rich gas streams require longer times for gas dissociation from solution or separation of liquid
phases.

101
 CARBONATE PROCESSs
• Hot potassium carbonate process for bulk CO2 removal
• Not suitable for sweetening gas mixtures containing little or no CO2 since potassium bisulfide would be very difficult
to regenerate if CO2 is not present.
• Advantages:
a. Continuous circulating system employing an inexpensive chemical
b. Isotherm system in absorption and desorption of acid gas conducted at nearly uniform high T as can be obtained,
thus no heat exchange equipment in fluid circulating system required
c. Desorption by stripping accomplished with smaller steam rate than required for an amine plant
• Disadvantages:
a. Not commercially reduce H2S content to pipeline specification. For this, conventional amine plant should be used
b. Similar to other acid gas removal processes  prone to corrosion (can be reduce by inhibitor,
ie arsenic & vanadium salts and dichromates)
c. Like other liquid absorbents in sweetening plants  prone to suspended solids and foaming problems

• Catacarb process:
– Employ modified potassium salt solution containing very active, stable & nontoxic catalyst & corrosion
inhibitor
– Amine borate utilized to increase hot potassium carbonate activity

• Special notes:
– Used ss for reboiler tubes, control valves and solution pumps, impellers & inner valve
– Can used carbon steel : absorber, stripper, piping (stress relieved)
– Sometimes plastic coated or gunnite lined can be used for stripper column
102
– Carbonate solution can be filtered through side stream filter
 PROCESS DESIGN CONSIDERATIONSs
• Selected process should have given satisfactory service at process conditions and with required gas compositions

• Particular attention to feed gas heavy hydrocarbon analysis . If hydrocarbons condensed absorbed in treating solvent,
severe process problems occur. Design shall incorporate features to remove or accommodate heavy hydrocarbons.

• Selected solvent must considered oxygen in feed gas which will caused oxygenation of certain treating solvents
• Solvent storage tanks shall be blanketed with sweet natural gas or inert gas. Vacuum systems shall be avoided. If solvent
selected subject to oxygen degradation, design provision to prevent oxygen from entering system must be considered
• Solvent-acid gas loading shall be proportionated within accepted industry guidelines and/or recommendations of process
licensor(s).
• Solvent storage shall be provided with heating coils if freezing or high viscosity should prevent its normal transfer.
• Solvent filters shall be provided in accordance with accepted industrial practices.
• If solvent selected, capable of regeneration, complete regeneration facilities should be considered and designed.
Regeneration equipment shall be designed in strict accordance with Licensor’s specification.

• Acid gases may be combusted in flare or thermal oxidizer if compatible with environmental regulations

• Due to considerable water vapor in treating plant, all essential determinations shall be considered in process design,
including but not limited to:
1. Solvent stripping still shall be designed to prevent vacuum collapse in the event of tower blocked in, when at hot condition
2. All equipment should be designed for potential vacuum collapse
3. Acid gas disposal lines and facilities shall be designed so that water will not accumulate at bottoms/lower ends
4. Particular emphasis shall be given to lines in intermittent service such as drains, instruments, gage glasses, etc., to be
freeze-protected.

103
 PROCESS DESIGN CONSIDERATIONS – cont.s

• Safety measures must consideration:

1. For toxic solvents (if selected), safety showers, eye-wash fountains, shall be provided at strategic
locations
2. All solvent and hydrocarbon tanks shall be diked to contain their contents in the event of tank rupture
3. An Emergency Shut-Down (ESD) system shall be provided if applicable. ESD shall be automatically
and manually actuated and designed to block feed and products gas lines of (affected) train in
treating plant. Affected train shall be vented to flare, at rate not to damage equipment. Gas flow to
all fired heaters shall be stopped and all rotating equipment shall be stopped
4. Plant pressure relief valves shall be separate from the ESD vents. ESD pushbuttons shall be provided
at main gate, main control panel, and main entrance
5. Hydrocarbon detectors shall automatically trip ESD system. They shall alarm at 20% of lower explosive
limit for methane and trip at 40%. They shall be provided at:
• air intake to each control building
• analyzer house
• each compressor building
• in the gas contacting area
• above each cooling tower cell
• any other locations may deem necessary for safety requirements.
6. H2S detectors and alarms shall be provided if gas to be treated contains more than 10 ppmv H2S.
Detector shall have solid state sensors. Detector heads shall be located in proper places and alarm
system should have two-level warning tone. One level shall be announced at an H2S concentration
in ambient air of 10 ppmv. Other level shall be announced at 30 ppmv H2S in ambient air.

104
 PROCESS DESIGN CONSIDERATIONS – cont.s

• Material selection for vessels, drums, and separator must considered:

1. General
Whenever the fluid to be handled in the process system contains:
a. >50 ppmw dissolved H2S in free water
b. free water pH < 4 and some dissolved H2S
c. free water pH > 7.6 and 20 ppmw dissolved hydrogen cyanide (HCN) in water and some dissolved
H2S present;
d. >0.0003 MPa absolute (0.05 psia) partial pressure H2S in gas in processes with gas phase.
Partial pressure of H2S determined by multiplying mole fraction (mol.%+100) of H2S in gas times
system P
2. Materials
a. All carbon steel and low alloy steel material used shall comply with, but not be limited by
requirements of NACE Standard MR 0103-2003. (Material Requirements- Sulfide
Stress Cracking Resistant Material for Oil field Equipment, latest Revision).
b. Use of special corrosion-resistant materials, alloys, or clad steels other than standard materials
shall be subject to approval. Copper or copper alloys shall not be used.
c. Approved materials for use in sour services, based on American Society for Testing and Materials
(ASTM) specifications. These materials should also satisfy the physical and chemical
properties requirements.

105
 PROCESS DESIGN CONSIDERATIONS – cont.s

Piping must considered:

1. Whenever fluid handled in process system contains:
a. Sour gas of 0.34 kPa (abs) or greater partial pressure hydrogen sulfide (H2S), and if system pressure is 450 kPa (abs) or
greater
b. Sour oil and multiphase of 70 kPa (abs) or greater partial pressure H2S, whenever system pressure is 1825 kPa (abs) or
greater or, whenever gas phase contains over 15 percent H2S at any system pressure
c. Rich sweetening agents, such as amines, sufinol, etc.
2. In general, the materials used shall be based on the following:
a. All carbon and low alloy steel material used shall comply with, but not be limited, by the requirements of NACE Standard
MR 0103-2003, latest revision
b. Use of special corrosion-resistant materials, alloys, or cold steels other than standard oil field materials shall be subject to
approval. Copper and copper alloys shall not be used
c. Stainless steels of the 400 series or other martensitic steels shall not be used unless specifically approved
d. All carbon and low-alloy steel materials shall have the following properties:
– Ratio of percent manganese to percent carbon (%Mn/%C) shall be greater than or equal to 3.0
– Percent carbon plus one-quarter of the percent manganese (%C + %Mn/4) shall be less than or equal to 0.55
3. For materials used in piping components such as plates, pipes, fittings, flanges, valves, gaskets, etc.,
applicable provisions of the following standards shall be considered along with manufacturer’s
standard specification:
a. ASTM-A 516, ASTM-A 106, Grade B, or ASTM-A 333 for plates and pipes respectively
b. ASTM-A 234 Grade WPB for fittings unless otherwise specified
c. ASTM-A 105 or ASTM-A 350, Grade LF2 for flanges unless otherwise specified
d. All valves shall meet the requirement of NACE Standard MR 0103-2003
e. All gaskets in sour service shall be TP 304 SS, TP 304 SS oval rings to ASME B 16.20 shall be used as minimum.

106
THANK YOU

107