huntsman corporation business confidential huntsman corporation gas treating gas treating units...

Huntsman Corporation Business Confidential

HUNTSMAN CORPORATIONGas Treating

Gas Treating Units

Amine Systems Training

Patrick E. Holub, P.E.


HUNTSMANTraining Modules

Introduction to Huntsman - Products & Services Amine Types Amine Chemistry Unit Operations

– Inlet Sep., Flash Tank, Absorber/Contactor, L/R Exchanger, Liq. Treater, Stripper/Reboiler, Reclaimer

Operational Issues Q & A


HUNTSMAN’s Gas Treating Products

DGA® Agent– CO2/H2S And Trace Sulfur (esp. COS) Removal

– Heat stable salts control– highest capacity

MEA – CO2/H2S Removal

– COS Removal with Degradation

DEA JEFFTREAT® Formulated MDEA Solvents

– From Selective H2S Removal To Bulk CO2 Removal

® trademarks of Huntsman Corporation


Amine Selection Considerations:

Capacity & Ability to Make Spec Heat Stable Salts (HSS)/Corrosion Cost of Amine, Logistics, Salesmanship Degradation/Corrosion Trace Sulfur Removal CO2 Slip/Removal What you already know


Base Chemistry


Chemistry of Gas Treating

Amine Structures & Types Reactions with

H2S

CO2

COS

Mercaptans Degradation

Incr

easi

ng E

ase

of R

emov

al


Amine Types: Examples

Primary (1’): MEA, DGA® Agent – React Rapidly With H2S, CO2 And COS

Secondary (2’): DEA, DIPA, MMEA– React With H2S, CO2 (some COS)

Tertiary (3’): MDEA, TEA – React Rapidly With H2S

– React Only Indirectly With CO2 (little COS) --> means they are Selective towards H2S


Chemistry: Equilibrium

Since amine-acid gas salts are reversible, the Equilibrium is important concept of minimum free energy

– Nature is inherently Lazy– Given infinite time, the bond falls apart – (drops into lowest energy state)

in gas treating terms: if you have a given amount of H2S and amine, how much H2S can be absorbed?



The answer is: the Equilibrium amount.

H2S

Tot

al E

nerg

y L

evel

Written as an equation: H2S + DGA ==>

DGA



H2S absorption generates energy

DGA-H2S SaltLoading = 1.0 m/m

Tot

al E

nerg

y L

evel

H2S

Written as an equation: H2S + DGA ==> H2S*DGA salt + Energy

DGA



The reaction can be reversed

H2S

Destroy DGA-H2S Salt

Tot

al E

nerg

y L

evel

Written as an equation: H2S*DGA salt + Energy ==> H2S + DGA

DGA



More DGA will “hold” H2S tighter...

H2S DGA

DGA-H2S Salt

Tot

al E

nerg

y L

evel

DGA DGA DGA




More DGA will “hold” H2S tighter...

DGA-H2S SaltLoading = 0.25 m/m

Tot

al E

nerg

y L

evel

H2S

DGA

DGADGA

DGA




Le Chatlier’s Principle.… APPLY REACTANTS --> Make Products

ProductsReactantsDGAH2S

DGA*H2SSalt + Heat



Le Chatlier’s Principle.… APPLY PRODUCTS --> Make Reactants

ProductsReactants

DGA*H2S SaltHeatDGA

H2S


Equilibrium - Summary

Equilibrium is a Balance More DGA, capture H2S more tightly Apply heat, liberate H2S (and DGA) --> the absorber must be “cold” --> the stripper must be “hot” --> to capture H2S tightly, use more DGA’s

than you have H2S’s


Equilibrium - Effect of Heat Stable Salts

Heat Stable Salts “pollute” amine…tie it up

H2S DGA

DGA-H2S Salt

Tot

al E

nerg

y L

evel

DGA DGA DGA


X = HSS

XX


Equilibrium - Effect of Heat Stable Salts

So the H2S isn’t held as tightly (fewer DGA’s)

DGA-H2S SaltLoading = 0.5 m/m (effectively)

Tot

al E

nerg

y L

evel

H2S

DGA

DGA


DGA

XDGA

X

X = HSS


Amines Vary in Treating Effectiveness

DGA® Agent

MEA

DEA

DIPA

JEFFTREAT M (MDEA)

JEFFTREAT MS-300

JEFFTREAT MS-200’s

JEFFTREAT M-500’s / MP

TEA

CO2 H2S COS RSH

++++ ++++ +++ +

++++ ++++ +++ +

+++ +++ ++

++ +++ +

x +++

xx ++++

+++ +++ +

++++

xx +


Capacity: Amine Strength Molarity vs. Weight Percent

Amine weights…bigger is not better:

so 30%w Amine solution = ? Molar

TEA149

MEA61

DIPA133

DEA105

MDEA119

DGA®

105

2.0 2.3 2.5 2.94.9

12345

2.9Mol

arit

y

6


Capacity: Amine Strength Recommended Strength

Maximum Amine Strength (%w)

They provide different ACTUAL capacity:

TEAn/a*

2.33.8 4.8

3.012345

2.4Mol

arit

y

* applied only as formulation component with MDEA

6

DIPA 30%w MDEA 45%w DEA 25%wDGA 50%w

MEA 18%w


Operations


Simple Gas Treating Flow Diagram

ABSORBERREGENERATOR

RICH/LEAN EXCHANGER

CHARGE PUMP

LEAN COOLER

REFLUX CONDENSER

REFLUXACCUMULATOR

INLET GAS

RESIDUE GAS ACID GAS

RICH AMINE

REFLUX PUMP

TO FUEL

FLASH/SKIM VESSEL BOOSTER

PUMP

REBOILER

CARRYOVERSCRUBBER

INLETSEPARATOR

50 # SAT'D

STEAM

RECLAIMER

150 - 250 # SAT'D

STEAM

PARTICLEFILTERS

OIL

CARBONFILTER


Design Considerations

Inlet Gas Separator/Coalescer/Water Wash

Inlet Gas: 100 To 120 Deg F Amine-Gas Approach: 10 To

15 Deg F Overhead Carryover

Scrubber W/HLA Absorber&Stripper

Differential Pressure Measurement

Flash Tank: 20 to 30 Minute Residence Time W/ HC Skimming.

Final Amine Pressure Reduction Downstream of L/R Exchanger

210-220 Deg F Rich Feed to Stripper

10-20% Slipstream Particulate - Carbon Filtration


Inlet Separation/Pre-Treatment

Slug Catchers When Condensing Hydrocarbons Are

Prevalent Coalescers

When Aerosols Are Prevalent Water Wash

When HSS Precursors Are Prevalent Ammonia Concerns


Contactor/Absorber

Lean Amine Temperature 10 To 15 Deg F Higher Than Inlet Gas Should Generally Not Exceed 135 Deg F

Differential Pressure Measurement Water Wash(G/L outlet)

Minimize Amine Losses Ammonia Control

Off-Gas KO Pot With Alarm


Separations: Goals

Why we work in Staged equipment What goes on inside the absorber

when things are normal when things go wrong

The DGA® Agent absorber - operating range The DGA® Agent stripper - operating range


DGA

DGA

DGAH+HS-

H2S H2S

Separations: Simple Stage -

Spray / Crossflow


DGA

DGA

DGAH+HS-

DGA

DGADGAH+HS-

H2S H2S H2S

Separations: Simple Stages -

Spray / Crossflow, 2-Stage


DGADGAH+HS-

DGA

DGADGAH+HS-

H2S H2S H2S

DGADGAH+HS-


2 Stage, reuse Semi-Lean amine


DGA

DGAH+HS-DGA

H2S H2S H2S

DGADGAH+HS-


2 Stage, reuse Semi-Lean amine


DGADGAH+HS-

DGA

H2S

H2S

H2S

DGADGAH+HS-

Separations: Simple Stages - Same thing, stacked vertically

Huntsman Corporation Business ConfidentialDGADGAH+HS-

DGA

H2S

H2S

Separations: Absorber Column


DGADGAH+HS-

DGAH2S

H2S


Single Stage Detail


Tray Deck

Downcomer

Weir orOverflow Weir

Valve

Downcomer seal

Weir

Height

= 2”

Tray S

pacing =

18”

Dis-engaging Zone

FrothZone

Active Area

Separations: Simple Stages - The Parts of a Trayed Column


Tray Deck

Downcomer

Weir orOverflow Weir

Valve

Downcomer seal

Weir

Height

= 2”

Tray S

pacing = 18”

Dis-engaging Zone

FrothZone

Tray Features and Function

Active Area


Weir

Height

= 2”

Tray S

pacing = 18”

Dis-engaging Zone

FrothZone

Froth Height

Active Area

P =2”

Froth Height

= 10”


Tower Operating Range(Distillation)

Every tower has its operating limits Know those limits…for a CLEAN Column:

GA

S R

AT

E

LIQUID RATE

En

trai

nm

ent

Entrainment-Flooding Downflow-

Flooding(loading)

ChokingSTABLE

OPERATION

Weeping-Dumping


Tower Operating RangeGas Treating (Absorption)

Need enough amine to treat the gas Adds additional limit -- for a CLEAN

column:

GA

S R

AT

E

AMINE RATE

En

trai

nm

ent


Flooding(loading)

ChokingSTABLE

OPERATION

Weeping-Dumping

RICH loading exceeds maximum allowed


Separations in Stages:Conclusions

Staged operations are a more efficient way to contact amine and gases containing H2S

The major features of a tray were shown The “operating range” of a (distillation) tower

was defined The problems that lie outside of the

operating range were introduced The Absorber operating line was added


Separations: Things gone wrong

Fouled equipment Excessively high gas rate Excessively high liquid rate Foaming


Tower Operating Range Gas Treating (Absorption)

A dirty, fouled tower or one with damage Has different (and lower) limits

GA

S R

AT

E

AMINE RATE

En

trai

nm

ent


Flooding(loading)

Choking

Weeping-Dumping

STABLE OPERATION

RICH loading exceeds maximum allowed


Weir

Height=

2”

Tray S

pacing = 18”

Entrainment-Flooding due to High Gas Rate

P

= 10”

Froth Height =

18”

FrothZone

Dis-engaging Zone

Entrained Amine


Weir

Height=

2”

Tray S

pacing = 18”

Flooding: High Liquid Rate and/or High Viscosity Amine

P =

18”

Froth+Foam

Height

= 18”

Dis-engaging Zone

FrothZone

Entrained Amine

Entrained Gas


The DGA® Agent Absorber

Purpose: Scrub H2S from gas and liquid

streams Scrubs Ammonia Prepares clean feed for various

downstream units Meet environmental limits


The DGA® Agent Absorber Operating targets - vary by absorber, but

some overall guidelines are useful You should have targets of your own Rich loading: ca. 0.4 - 0.45 m/m, Max. Temperature: ca. 170 - 180F Min. LEAN Temp: 10 degr. Rule physical limits of the column

note: liquid treaters have different rules


The DGA® Agent Absorber Constant Gas Rate, Constant Steam Ratio

Amine Circulation Rate

H2S

in O

verh

ead

Begin to overwhelm coolers

Begin to “Choke” Absorber

Too

litt

le a

min

eto

trea

t H2S

Exc

eed

RIC

H

load

ing

guid

elin

e

Wit

hin

RIC

H

load

ing

guid

elin

e


The DGA® Agent Absorber You can treat H2S OK even when you exceed

the recommended limits on loading If you circulate TOO LITTLE amine, at some

point H2S treat will suffer If you circulate TOO MUCH amine, you can

actually perform worse How do you know how much to circulate?

You have guidelines for every absorber On some absorbers you can watch the T Bulge


The DGA® Agent AbsorberTemp. Bulge is useful

with a lot of acid gas present...

Too LittleAmine

Col

umn

T P

rofi

le

50 ppmLEAN

RICH

WastedAmine

10 ppm

LEAN

RICH

EnoughAmine

10 ppmLEAN

RICH


Amine Liquid Treater Design Guidelines

Diameter: 10-15 Gpm/Ft2 (Total Flow) Solvent Flow: 10-20:1 LPG/Amine Amine Distributor: 170 Ft/Min HC Distributor: 70 Ft/Min Amine Superficial: 60 Ft/Hr HC Superficial: 130 Ft/Hr Solvent Temperature: 95 To 100 F (Min) Residence Time: 20-30 Minutes


Amine Liquid Treater Design Guidelines Cont.

Trayed Or Packed 10 Sieve Trays 2 To 3 Sections of 1 To 2” Packing

Water Wash


Liquid Treaters:Physical Effects

Physical Effects viscosity < 2 - 3 cP (at min. T)

– HSS effect, “inert crap”, loading effect LPG teater = quiet spot in system

– Fouling, particulate deposition likely– increases effective Jet Velocity

Pressure surges– poor P control, bubblepoint

Process chemical compatibility

SourLPG

LeanAMINE

Rich AMINE

Sweet LPG


Liquid Treaters:Physical Effects Cont.

Viscosity limits amine strength Max strengths for CLEAN amine:

DIPA = 2.5 M MEA not limited by viscosity (3 M)* MDEA = 3.1 M DEA = 3.5 M DGA® = 4.2 M

Liquid Treating mandates clean amine!SourLPG

LeanAMINE

Rich AMINE

Sweet LPG

* limited by corrosion concerns


Flash Tank/HC Separator

Application Pressure

5 To 75 PSIG Typical Hydrocarbon Removal(3-phase)

Adequate Instrumentation Residence Time

20 Minutes


Flash Tank

LC

LC

AMINE

OILGAS

3 PHASE INAmineGasOil

GAS OUT

AMINE OUTOIL OUT

Impingement PlateInlet Box or Pipe Elbow

Internal Baffle Box

P. E. Holub

January 1992

THREE PHASE FLASH SEPARATORWITH INTERNAL BAFFLE BOX

(Side Draw)


Lean/Rich Exchanger

Corrosion Concerns Metallurgy

– Based On CO2/H2S Ratio

– 304 Or 316 Stainless Steel Bundles

Pressure Rich Side As High As Possible Take Pressure Drop As Close To Stripper

As Possible


Stripper/Reboiler

Reflux Ratio Typical 1.0 To 3.0 Mole H2O/Mole Acid Gas

Reflux Purge Ammonia Control

Reboiler Temperature Control Top Temperature 210 - 230 Deg F Bulk Temperature <260 Deg F Heating Medium <350 Deg F

Differential Pressure Measurement


ACCUMULATOR

150 - 250 # SAT'D

REGENERATOR

REFLUX CONDENSER

REFLUX

ACID GAS

REFLUX PUMP

REBOILER

50 # SAT'D

STEAM

RECLAIMER

STEAM

LEAN SOLVENT

The DGA® Agent Stripper

PURPOSES Process RICH amine; contact with a

“fixed ratio” of stripping steam Regenerate the amine (make LEAN) Make CLEAN acid gas for Claus Feed the reclaimer a hot slipstream Take vapors (product) from the

reclaimer Remove Ammonia from the process


ACCUMULATOR

150 - 250 # SAT'D

REGENERATOR

REFLUX CONDENSER

REFLUX

ACID GAS

REFLUX PUMP

REBOILER

50 # SAT'D

STEAM

RECLAIMER

STEAM

LEAN SOLVENT


Typical targets: Stripping Steam: 1 - 1.3 lb / gallon Temperature <260 F (stripper) Overhead (varies) Lean solvent target: ca <0.01

m/m (varies by location) “overstripping” - H2S should be

measurable in the Lean



Constant RICH rate and loading

Stripping Steam Rate

H2S

in L

EA

N

Begin to “overstrip”

solvent

Begin to “Entrain”Stipper

Too

littl

e H

eat

to R

egen

H2S

Bel

ow R

atio

Gui

deli

ne

Wit

hin

Rat

io G

uide

line

Exc

eedi

ng R

atio

Gui

deli

ne


The DGA® Agent Stripper You can strip H2S OK even when you provide

too little stream, except you are close to the edge of an operating “cliff”

If you provide TOO MUCH stripping steam, you can overstrip the solvent (little or no H2S)

How do you know how much to circulate? You have guidelines for stripping steam rate (ratio) You can analyze the lean solvent for H2S


Typical Reclaimer

LC

Y Y4" Drain

Valves

Flushing Water

Water From RefluxPump Discharge

From LeanBooster Pump

1.0 to 3.0% of LeanCirculation Rate

16" Manway

Typical Process Flow for Reclaimer

250-275 PsigSaturatedSteam

ExternalSteamCondensatePot

Steam

Condensate

360 Deg F Max.

FC

TC


Reclaimer Operations

Keep the amine clean. Reclaimer

A distillation system that carries clean amine & water overhead back into the system and retains degradation and other harmful components.

Functional a zero micron filtering system


DGA Reclaimer Operations Cont.

Design Criteria 1.0 to3.0% side slip stream 65 -150 psig steam for MEA and 250 psig

for DGA® Agent to tube bundle. Condensate makeup for temperature. Sparger or continuos mixing setup Ability to add caustic.



Reclaimer Operations Max Bulk Temp. 360ºF. Operational Temp. 330ºF to 360ºF. 1.0 to 3.0% flow off hot lean circuit. Level maintained to cover tubes and

provide maximum head space. Operational time will depend on condition of

solvent being processed.



Reclaimer Benefits Cleaner amine Reduces corrosive materials in system

– Solids, Sludge, Salts, Decomposition & Degradation products

Aids in filtration of system– Better equipment wear and operations

Keeps the DGA healthy and reduces materials that complicate operations.


Filtration

Particulate Filter 10 Micron Absolute Typical 5 Micron Absolute For “Black Shoe Polish” 10 To 20% Slipstream Minimum

Carbon Filter 15 Minute Contact Time 2 To 4 Gpm/Ft2 Superficial Velocity 10 To 20% Slipstream Minimum


Filtration Cont.

Inlet gas “trash” or contamination Iron Sulfide, etc.

System modifications or upsets Concentration change Foaming Upset contactor

High Loadings Flashing and two-phase flow


Operational Issues


Operational Problems

Failure To Meet Product Specifications Corrosion Heat Stable Salts Solution Foaming Emulsions/Carryovers Excessive Amine Losses Degradation Products High Filter Changeout Frequency


Causes of Failure to Meet Product Specification

Under Circulation Under Stripping Low Solution Strength Foaming Change in Inlet Process Conditions


Factors in Corrosion

HEAT STABLE SALTS Keep Below 2-3 Wt.% 0.3% Of Total Solution Wt Has Been Corrosive

ELEVATED TEMPERATURES EXCESSIVE SOLUTION VELOCITIES

<3 Ft/Sec In Exchangers; <7 Ft/Sec In Piping

ACID GAS LOADINGS EXCESSIVE HEAT FLUX AMINE DEGRADATION POOR FILTRATION


Corrosion Control

Signs of Need: Dark/Black Amine Fouled Solution/ Equipment

Plugging Excessive Probe Corrosion

Rates Excessive Solution Foaming High Filter Changeout

Frequency Equipment Failure

Possible Control Actions: Evaluate Solution Loadings Improve Filtration Evaluate Solution Condition, Clean

or Replace

Oxygen Scavenging(?) Corrosion inhibitors(?)


Heat Stable Salt Management

Water Wash Reclamation - Thermal, Ion Exchange,

Vacuum Distillation Oxygen Control/Scavenging Neutralization Solvent Purging


Corrosion: The Iron Cycle (Higher Pressure Systems)

ABSORBER

REGENERATOR

RICH/LEAN EXCHANGER

LEAN COOLER

INLET GAS

TREATED GAS

ACID GAS

RICH AMINE

TO FUEL

FLASH TANK

BOOSTER PUMP

REBOILER

FeS --> [Fe++] + H2S Dissolve: * particulates * passive film

[Fe++]+H2S--> FeS Form: * particulates

LEAN Amine is Clear,Lt. Amber/yellow

RICH Amine is Dark Green/Black


Foaming in Gas Treating Systems: Goals

Understand difference between foam and froth

Know some things that promote (cause) foaming

Know the difference in foam test results between the various amine types

Know some control measures to take when foaming occurs


Foaming Symptoms

Carryover - Overloading Downstream Knockout Equipment

High/Erratic Absorber/Stripper Differential Pressure

Erratic Absorber/Stripper Level Erratic Stripper Feed Flow Erratic Flash Tank Solution Level

And Flash Gas Flow Off-Specification Product


Foam Creation

Bubble surface circulates, relieving stress, allowing bubble to squeeze through the amine and rises quickly. Amine film flows freely, drains, thins, separatesBubble rapidly merges with vapor phase.

Soap (surfactant) coats the bubble surface, forms a rigid film. The tail ends of the surfactant line up, pointing outwards from the bubble, entangling amine, slowing bubble rise, preventing drainage from the film. The soap (surfactant) lowers the surface tension, allowing tiny bubbles to be created with less energy. The soap layer around the bubbles can repel other bubbles, preventing coalescence. A stable foam comprising many small, firm bubbles is created.

Amine

SoapGas

Gas

Amine

NORMAL BUBBLE

FOAM BUBBLE


Foam Stabilization

Gas

Surface circulation relieves stress, allows bubble to squeeze rapidly up through the amine film. The amine film drains freely, thins, and breaks. The bubble merges with vapor phase.

Bubble rises, solids coat surface, preventing circulation: bubble becomes rigid, rise is slowedSolids crowd interface, amine film can’t easily drain.Amine film thins slowly, preventing bubble from merging with vapor phase - Foam is stable.

Bubble rises, oils condense inside, preventing easy circulation: bubble becomes rigid, rise is slowed.Bubble must break through amine film AND oil film, Bubble can’t collapse fast.

Amine

OilGas

Gas

Amine

Amine

FeS


Weir

Height=

2”

Tray S

pacing = 18”

Foaming in the example absorber

dP = 8”

Froth+Foam

Height

= 18”

Dis-engaging Zone

FrothZone

Entrained Amine

Entrained Gas


Causes of Foaming Finely Divided Solids Heat Stable Salts Surface Active Agents Degradation Products

Heavy polymers “Black Shoe Polish”

Condensed or Entrained Hydrocarbons In TGTU’s ? Not likely 10 Degree Rule


Foaming Cures

Finely Divided Solids & “Black Shoe Polish” CLEAN AMINE !

Filtration, minimum 50% of stream flow Change filters at need; it is expensive but the cost of NOT

changing them is ultimately far greater Root-cause prevention - high rate of filter usage Corrosion prevention / elimination The DGA® Agent reclaimer is a “perfect” filter... Operation within process guidelines

– velocity (circulation rate), steam rate, lean loading, rich loading– SOLVENT HYGIENE


Foaming Cures

Heat Stable Salts - Main System why do they promote foaming? Corrosion = FeS solids lower pH (change chemical nature of amine solution)

DGA® Agent: RUN THE RECLAIMER Dump it at end of cycle! Water wash raw gas streams? (unproven) Reclaim only as much as you need to keep up... If you keep it clean, it is easier to keep it clean! Activated Carbon doesn’t solve heat stable salts problems oxygen scavengers don’t appear to stop the problem


DGA® AgentReclaimer Control Of HSS

Figure 1. History of Heat Stable Salts (HSS) Spanning DGA Reclaimer Startup

0

5000

10000

15000

20000

25000

Fe

b-9

4

Ma

y-9

4

Au

g-9

4

No

v-9

4

Fe

b-9

5

Ma

y-9

5

Au

g-9

5

No

v-9

5

Fe

b-9

6

Ma

y-9

6

Au

g-9

6

No

v-9

6

Ja

n-9

7

Date of Sample

HS

S A

nio

ns,

pp

mw

.

No Reclaimer

Reclaimer Operating

Formate25 ppmw/day

Total Anions36 ppmw/day

Reclaimer Startup


Foaming: Surface Active Agents

Surface Active Agents (soap-like materials) What are they?

Complex hydrocarbons (naturally occurring) things like napthenic acids, etc

Additives in process chemicals some antifoams are formulated with spreading agents, that

in the absence of the foam-cutting agent can CAUSE foaming

example: oleic and palmitic acids in some silicone antifoams

Some types of corrosion inhibitors (“filmers”)


Foaming Cures: Surface Active Agents

Surface Active Agents (soap-like materials) ANTIFOAM & PROCESS CHEMICAL CONTROL

operators are responsible for all amine-process chemicals what is added at one absorber can effect the entire system; Too much antifoam can actually cause foaming! Test the antifoam to know it is compatible with LIQUID C3’s Use Activated Carbon; use pre- & post- filters on the carbon Antifoam and process chemicals (inhibitors, etc) use up

activated carbon capacity that is needed to cure foaming


Hydrocarbons and Foaming

Single most blamed source of Foaming Condensed vs. Entrained (aerosol) Dewpoint and Shrinkage

the 10-degree Rule

Kerosene cuts foaming (?) Napthenic Acids promote foaming General rule: more complex, more viscous,

presence of hydrophilic groups…likely to promote foaming

OH


Foaming Cures: Hydrocarbons

Condensed or Entrained Hydrocarbons Oil management

Compressor Lube Oil water wash if you have it Keep upstream K-O’s on line, and monitor make Skim at the flash/skim “3-phase” vessel

– Have it large enough to do the job (30 minutes)

Skim the Reflux if you can the “10 degree Rule”


OIL CONTROLInadequate Flash/Skim Vessel

ABSORBERREGENERATOR

RICH/LEAN EXCHANGER

CHARGE PUMP

LEAN COOLER

REFLUX CONDENSER

REFLUXACCUMULATOR

INLET GAS


RICH AMINE

REFLUX PUMP

TO FUEL


PUMP

REBOILER

CARRYOVERSCRUBBER

INLETSEPARATOR

50 # SAT'D

STEAM

RECLAIMER

150 - 250 # SAT'D

STEAM

PARTICLEFILTERS

OIL

CARBONFILTER

OIL

“Oil” slug to Claus

Possible High Amine Losses

Possible High Carbon Consumption

Possible Foaming

Possible Foaming

Possible High Filter Usage


CLAUS PLANT Ratio Control

ACID GAS

“CLEAN”

H2SSO2

Ca. 30 Seconds from Furnace to Tail Gas

AIR (O2)

SOURWATERGAS

H2S + 3/2 O2 ---> SO2 + H2O

SO2 + 2H2S <---> 3S + 2H2O

= 2

TAIL GAS to TGTU

= 2= 50= 50= 0= 0= 8= 8= 1


OIL CONTROLAdequate Flash/Skim Vessel

ABSORBERREGENERATOR

RICH/LEAN EXCHANGER

CHARGE PUMP

LEAN COOLER

REFLUX CONDENSER

REFLUXACCUMULATOR

INLET GAS


RICH AMINE

REFLUX PUMP

TO FUEL


PUMP

REBOILER

CARRYOVERSCRUBBER

INLETSEPARATOR

50 # SAT'D

STEAM

RECLAIMER

150 - 250 # SAT'D

STEAM

PARTICLEFILTERS

OIL

CARBONFILTER

OIL

NormalH2S

to Claus


Foaming Cures: Degradation Products

Degradation Products all amines degrade if you abuse them

with DGA® Agent, you can remove the degradation products with the reclaimer reclaim normally 1% slipstream run the reclaimer no hotter than 360 degrees F use condensate in preference to reflux the level control is vital: prevent carryover into the process dump the reclaimer at end of cycle: normally 3 to 6 months


Foam vs. FrothFoam Stable suspension of bubbles in Amine

Tight, soapy, stable bubbles stacked on top and in amine

Causes erratic P

Poor removal of H2S

Causes high amine losses, carryover into knockouts

Happens when amine is dirty, polluted with salts or surfactants

BAD; Abnormal

FrothQuickly-resolved mixture of gas and amine

Fragile, clean bubbles in amine and droplets sprayed into gas

Creates stable P

Good & Quick removal of H2S

No level gain or valve action in knockout

Good froth promoted by clean amine

GOOD; Normal


Foam: Conclusions

Keep the system clean run the reclaimer Use particle filtration, change the filters when they

need it Use activated carbon, change it when needed Be vigilant with antifoam; use it sparingly and know

who and how much… Prevent oil ingress (an equipment issue) Don’t blame the CLAUS/TGTU if upstream upsets

cause pollution


Amine Loss Control Strategy

Define Current Loss Rate And Establish A Target Baseline (LB/MMSCFD)

Mechanical Carryover Amine Conservation: Filter Changeout, Sump Pumpouts, Etc.

Process Based HSS Formation High Temperatures Foaming


Sources of Excessive Amine Solvent Losses

Mechanical Undersized Tower Diameter Trays Operating Above Flood Limit Plugged Or Damaged Trays Poor Amine Distribution Damaged Mist Eliminator

Entrainment Foaming Solubility

Vaporization Degradation


Causes of High Filter Changeout Frequency

Excessive Corrosion Carbon Fines Upstream Contaminants Upset Operational Conditions Micron Rating Too Low or Filter Too

Small


Start Up

Pre- Startup Inspection Prepare A Checklist

Plant Clean Out Chemical Wash Remove Residual Amines If Changing To A

Performance Product Load New Amine According to Pre-

Determined Procedures


Keys For Successful Troubleshooting

Solution Analysis Historical Trending

Operating Data Summaries Historical Trending

Computer Simulation Bench Marking


Solution Analysis

Use As Tool To Resolve Plant Operational Issues

Program Should Be Designed to Provide Necessary Information All Sample Analysis Are Not Created Equal

Three Categories Routine, Periodic, Special


Solution Analysis Cont.

Historical Trends Of Solvent Analysis Spot Analysis Shows The Current Quality

Of The Solvent Historical Data Will Show

– Where The Solvent Quality Is Heading– Where The Solvent Quality Has Been

Consistency With Analysis Is Important


Sample Analysis Frequency Routine (Time Critical)

Often Completed On Site Field Analysis Loading, Solution Strength, HSAS (Refineries)

Periodic (More Extensive) Requires More Sophisticated Equipment Normally Completed At Central Lab Describes The Overall Condition Of The Solvent Huntsman Routine Tests Are Periodic

Special Non Routine Analysis Very Sophisticated Equipment (NMR, GC/MS, CE Etc.)


Foaming TestIC/HPLC/NMR Analysis

(Cation Analysis) Trace Metal AnalysisAmmonia (Reflux)ViscositySpecific GravityTrend Analysis

Total Alkalinity - Solution StrengthTotal Nitrogen by Kjeldahl (Total Amine)Karl Fischer WaterHSS Determination by

Titration and IC Anion AnalysisH2S/CO2 Acid Gas Loadings

Analytical Services Provided By The Huntsman Gas Treating Labs Include:

Gas Treating Solvent Analytical Services


Sampling Procedure

Use Huntsman Sample Kits for Premium Products

Samples Should Be Taken During “Steady State” Operating Conditions

Take Care to Properly Flush Lines, Fill Bottles, & Label the Sample


Operating Data Summaries

Use As A Tool To Track Unit Performance Should Be Designed To Provide

Necessary Information Too Much Information Is As Bad As None At

All Historical Trends Of Operating Data

Cannot Tell Where You Are If You Do Not Know Where You Have Been


Computer Simulation

Copy Of A Computer Simulation Based On Design Or Smooth Operation Simulation Is Still An Art Difficult To Evaluate Results Without A

Base Case


Bench Marking

Compare To Industry Standards Compare Current Operation To Past Difficult To Define And Address Problem

Areas Without It Concentrates Efforts


In Review

Analyze Your System Compare vs Operational Guidelines Make Adjustments - record Repeat 1st three until you system is

within guidelines Monitor Your System Communicate with other Users and SRU

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