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Solving gas plant

operational problems
Sound process monitoring, identication of probable causes, immediate action taken
by operations, analysis of the root cause and implementation of permanent remedial
measures are all effective methodologies for maintaining a high plant uptime
il and Natural Gas Corporation
Limited (ONGC) operates a gas-
processing complex at Hazira,
Surat, India. This complex contains
an integrated gas-conditioning plant
with a processing capacity of 41
MMSCMD (million standard cubic
metres per day) of sour natural gas
and associated sour hydrocarbon
condensate. The gas-conditioning
plant consists of multiple trains of
MDEA (methyl-diethanolamine) gas
sweetening, TEG gas dehydration,
condensate fractionation, dew point
depression, and the proprietary LOCAT
sulphur-recovery system. Safe, smooth
and optimised plant operation has
been the key to the plants 15 years of
operational success.
A sound process-monitoring and
logical problem-solving approach has
overcome any process upsets, effectively
reducing plant downtime and ensuring
a high-capacity utilisation. Identifying
problem areas, treating the symptoms
of process abnormalities, analysing and
then rectifying the root cause has
been a successful methodology for
maintaining a high plant uptime.
Each section of the plant has had its
troubles at some point during the many
years of operation. Guidelines have
been developed for the gas-sweetening
and dehydration units based on
previous operational problems, which
have proved helpful to operating
The ONGC sour gas-processing
complex at Hazira has grown to 41
MMSCMD through the addition of
multiple trains. The train concept,
apart from offering operational
exibility, provides the opportunity to
understand, formulate and test
operating strategies on one train and
then, once the processing objectives
have been achieved, to apply them to
the other trains. A guideline is
generated based on the problems
encountered, and any troubleshooting
can be used as a ready reckoner in the
day-to-day operation.
Gas-sweetening process
The gas-sweetening process involves
the selective removal of hydrogen
sulphide (H
S) from sour gas using
MDEA as a solvent. The outlet gas
specication is less than 4.0 ppm (parts
per million) of H
S and 4.55.0% of
(carbon dioxide). Each unit has a
processing capacity of 5.6 MMSCMD of
gas (two units with 6.3 MMSCMD). The
basic process involves:
High-pressure absorption for
selective removal of H
A medium-pressure system to remove
hydrocarbon from the rich amine
A low-pressure system for amine
Slip stream amine ltration.
Alok Chakraborty Oil and Natural Gas Corporation Limited
Saeid Mokhatab University of Wyoming William A Poe Consultant PTQ Q1 2007 111
Rich amine
Lean amine
Figure 1 Flow diagram of MDEA gas-sweetening unit
Gas ow 5.6 MMSCMD
Pressure 5560kg/cm
Temperature 2535C
Inlet H
S 50150 ppm
Outlet H
S <4 ppm
Amine feed temperature 4045C
MP system pressure 7.58.0kg/cm
LP system pressure 1.01.1kg/cm
Regenerator bottom
temperature 128130C
Regenerator top
temperature 105108C
Operating parameters in
gas-sweetening unit
Table 1
Figure 1 and Table 1 show the basic
process and the typical operating
conditions for the gas-sweetening
Gas dehydration process
Triethylene glycol (TEG) is used as a
solvent to dehydrate the sweet gas
produced from the sweetening units.
Figure 2 and Table 2 show the basic
process and the typical operating
parameters of the unit. The main
objectives of gas dehydration are to
prevent hydrate formation downstream
of the dew point depression unit,
prevent corrosion in the pipeline, as
the gas contains CO
and H
S, and to
meet customer specications.
The different sections of the glycol
units are the high-pressure (HP)
absorber, degassier to eliminate
hydrocarbons from rich TEG, and the
stripper reboiler to regenerate TEG.
It has been observed that every
section of the plant has some troubled
areas during operation. With experience
and effective troubleshooting using a
systematic approach, a guideline is
developed with the following format:
Monitoring parameters
Root cause analysis.
This will help the operating
personnel to troubleshoot during day-
to-day operation.
Gas-sweetening unit
A problem with the gas-sweetening
units (GSU) inlet separator knockout
vessel involved carry-over to the
absorber caused by an undersized inlet
separator or entrainment of liquid from
slug catchers, resulting in hydrocarbon
contamination of the MDEA (may cause
foaming) and fouling of the heat
exchange surfaces. Noting that this type
of carry-over problem occurs in the
GSU, a level transmitter and level
switches were included as monitoring
The action taken to solve the
problem was to drain and transfer the
liquid from the inlet separator based on
the status of the different level switches.
Low-level switches should remain
actuated during normal operation. The
root cause analysis involved:
Increase of level in slug catcher
Gas intake rate in the particular
Level build-up in outlet knockout
vessel of the condensate off-gas
compressor, whose discharge is routed
to the sweetening unit. The condensate
fractionation units off-gas is routed to
the GSU (of this plant) through a
HP absorber problems
and solutions
The HP absorber is the vessel where
sour gas comes into contact with
circulating MDEA and sweet gas exits
from the top. It has a number of amine
feed locations to handle the variation
in inlet H
S ppm. The operational
problems associated with the absorber
are mainly foaming and failure to meet
sweet gas specication.
Foaming is most frequently
encountered in the absorber, but may
also occur in the stripping column. It is
mainly caused by the contamination of
the solution by condensed light
hydrocarbons, nely divided, suspended
solids, such as iron sulphide (FeS), amine
degradation products or surface-active
agents carried by the gas streams.
Foaming results in amine losses, the off-
specication of treated gas and reduced
plant treating capacity.
Monitoring parameters included the
uctuating level of the absorber,
increase in the differential pressure
across the absorber and amine carry-
over to the outlet knockout vessel. The
course of action taken to solve the
problem was to:
Reduce or cut the gas ow to the
absorber, depending on the rate of
differential pressure increase and the
rate of level build-up in the outlet
knockout drum
If hydrocarbon contamination is
suspected, reduce the pressure of the
medium-pressure flash drum to
minimum operating pressure. Check
the flash drum for excessive
hydrocarbon and skim it
Shock dosing of anti-foam: it is
necessary to reduce the foaming
tendency of the amine solution until a
permanent remedy can be found
Check the lean amine feed
temperature to the absorber, which must
be 5.0C higher than the inlet gas to
minimise hydrocarbon condensation.
The root cause analysis noted:
Poor separation in the inlet
separator may lead to the carry-over of
liquid hydrocarbons, corrosion
112 PTQ Q1 2007
wet gas
dry gas
Stripping gas
Surge drum
Figure 2 Flow diagram of TEG gas dehydration unit
Gas ow 5.6 MMSCMD
Glycol circulation rate 5.0m
Reboiler bottom
temperature 180185C
Stripper top temperature 95C
% moisture in TEG Max 1%
Outlet dewpoint -55C
Operating parameters in gas
dehydration unit
Table 2
inhibitors or well-treating chemicals to
the absorber. All of these components
can cause foaming
Suspended solids such as FeS and
particulate matter in the feed gas,
including rust particles, dirt, pipe scale
and salts. All of these constituents
stabilise foam
Amine degradation and corrosion
Heat-stable salts.
Suspended solids can be removed by
10% slipstream ltration through a pre-
coat filter, and surface-active
contaminants such as hydrocarbons are
removed by carbon filtration.
Maintaining a clean system is the key
to foam prevention.
With regard to the potential problem
involving a failure to meet sweet gas
specications in the HP absorber, the
sweet gas specication for H
S is
targeted at 4.0 ppm. Failure to meet this
specification may be due to a
combination of factors.
The root cause is identied by
eliminating/checking a number of
factors (monitoring parameters). If the
online analyser shows greater than 4.0
ppm H
S, and laboratory results support
the fact, the following process
parameters should be monitored
carefully by trending:
Lean amine temperature too hot:
check the lean amine cooler outlet
temperature and bypass valve position
Lean amine concentration too high:
lack of equilibrium driving force; too
low, insufcient moles of amine or
removal of acid gas
Lean H
S and CO
loading high:
poorly stripped solvent
Stripper overhead temperature low:
indicates poor stripping
Absorber differential pressure
increasing: foaming tendency
Inlet acid gas concentration
increase: direct effect on outlet
Inlet gas ow maximum exceeded:
jet ooding.
All of these parameters have an
expected value based on design
consideration. Operating personnel
should compare the actual value to the
expected value for high deviation.
These values can be tracked and alarms
set for high deviation using a distributed
control system or plant historian. If any
parameter deviates from the normal
operating range, necessary action must
be taken to correct it. It is very
important to have a prior knowledge of
the operating ranges for the crucial
parameters generated from experience
with a particular plant.
In addition to the monitoring
parameters, there are certain other
parameters that need to be considered to
discover the cause of off-spec product:
Feed tray of amine is too low: not
enough contact time
Loss of contact areas/plugged
valves: lack of contact between gas and
Low gas pressure: reduced driving
Degraded solvent: less mole of
active amine for H
S removal
Mechanical damage: such as tray
Final identication of the cause is
through the process of elimination.
Case study 1
High CO
In the selective absorption of H
S, co-
absorption of CO
has a maximum
limit of 32%. Higher CO
may be due to certain factors, which
will be explained in more detail. The
reaction of CO
with MDEA is slower
than with H
S. The reaction of MDEA
with H
S can be considered
instantaneous, while the reaction of
with MDEA is kinetically controlled
(the reaction rate increases with
Problem: High CO
co-absorption in
the GSU. The operating objective is to
run no higher than 32% co-absorption
of CO
Troubleshooting: A variety of
parameters were checked such as the
gas ow rate, amine circulation rate
114 PTQ Q1 2007
and lean amine temperature. Each
absorber was operated with the lowest
amine feed tray. After optimising
temperature and ow, the only option
left is to reduce the contact time, which
will affect CO
absorption more than
Modication: The absorber outlet weir
plate of the downcomer has adjustable
slots. The weir height was reduced from
5040mm, thereby lowering the liquid
level on the trays and consequently the
contact time.
Outcome: Co-absorption reduced from
Medium-pressure system
A rich amine ash tank is employed to
remove absorbed hydrocarbons from
the amine solution. The ash tank
should be operated at a minimum
pressure to maximise hydrocarbon
recovery as fuel gas. In order to remove
S and CO
from the fuel gas generated,
lean amine is fed to the absorber column
at the top of the ash tank. A lean/rich
plate heat exchanger (PHE) preheats the
feed from the medium-pressure (MP)
system to the regenerator (104C) by
hot, lean MDEA from the regenerator
bottom (127C). Adequate pressure
should be maintained on the MP system
on the rich amine side to reduce acid gas
ashing inside the PHE, so the level
control valve should be downstream of
the PHE. Fouling on the rich side of the
PHE is the main problem faced in a
particular train due to the deposition of
FeS, as will be discussed in case study 2.
With regard to problems observed in
MP systems, sometimes pressure
maintenance becomes difcult, resulting
in the aring of gas through the back-
pressure control valve routed to the are
header. In these circumstances, the
monitoring parameters include pressure
values (the pressure of the rich amine
ash drum and the MP absorption
column) and the ash drum level.
If there is a sudden increase in
pressure, check:
HP absorber level transmitters/
gauges, switches and the bottom-level
control valves status. Gas may be
entering the MP system directly from
the bottom of the HP absorber
Treated gas knockout vessel drain
valve. The liquid from this vessel is
drained to the ash drum. Gas may be
exiting through the drain valve due to
malfunctioning level switches/trans-
mitter and the consequent failure of
the shutdown logic of the bottom drain
If a slow and steady increase in
pressure and aring is experienced,
check the feed gas and amine
temperature (can be optimised to
reduce hydrocarbon absorption). A
slight increase in temperature gives a
good result for reducing the absorption
and consequent generation of
hydrocarbon in the MP system. The
root cause analysis identied that any
difculty in maintaining pressure may
be because of a bottleneck in the fuel
gas header (case study 2) and high
hydrocarbon absorption in MDEA.
Case study 2
Flaring of fuel gas
In the reported problem involving the
aring of fuel gas in one section of the
GSU, it is noted that the three units of
phase 1 use the same fuel gas-piping
system provided in the original scheme.
The increase in pressure leads to
unavoidable, intermittent disposal of
gas to are to maintain the desired
value of pressure.
Troubleshooting: Initially, many
exercises were carried out by adjusting
the ow rate, temperature and level. A
detailed pressure survey was then
conducted to study the capacity of the
common fuel gas header. It was
concluded that the originally provided
2in fuel gas header from the fuel gas
control valve to the common fuel gas
knockout drum (KOD), and also from
the KOD to the outlet fuel gas header,
was inadequate to handle the fuel gas
generated from the three units.
Modication: A parallel 3in header
was laid from the fuel gas pressure
control valve downstream of each unit
to the fuel gas KOD, and an additional
3in outlet from the KOD to the header
was also provided. This improved the
handling capacity for fuel gas and
eliminated fuel gas aring.
Case study 3
Higher pressure in MP system
Higher pressure in the MP system was
required to push the liquid (rich amine)
from the MP system to the regenerator
through the level control valve after
the PHE. Maintaining level in the MP
system was difcult.
Troubleshooting: It had been observed
that the differential pressure across the
PHE cold (rich) side increased and
higher pressure was required to push
liquid through the lean/rich amine
exchanger. Fouling of the plates was
suspected. After checking the inlet
strainer of the cold side, back ushing
was performed, but this did not solve
the problem. The PHE was dismantled
and a black sticky deposit on the plates
was identied and tested as FeS. The
lean amine solution observed in the
surge tank and regenerator outlet was
clear. FeS in the presence of CO
iron bicarbonate in the regenerator.
Iron bicarbonate is soluble in amine
and cannot be ltered in lean amine
lters. This phenomenon had also been
observed in laboratory experiments.
The soluble iron bicarbonate reacts
with H
S in the absorber and forms FeS.
This FeS is partially retained in the PHE
and causes increased differential
The majority of the FeS is carried
over to the regenerator, where it
converts into soluble iron bicarbonate.
Increased soluble iron content in this
unit demonstrates that corrosion occurs
in the reboiler, the absorber bottom or
the rich amine piping.
The chemical cleaning of plates with
10% nitric acid solution removed any
deposit. An in-house procedure is being
used to clean the plates at regular
intervals when an increase in the
differential pressure on the cold side of
the PHE is observed. The problem of
increasing differential pressure is solved
after cleaning, but the problem of FeS
still exists, as the origin of the iron
sulphide is yet to be established.
The purpose of the stripper/reboiler is
to regenerate the amine solution by
stripping the H
S and CO
from the rich
MDEA with steam generated by the
reboiler. The heat is supplied through
steam in the reboiler to provide heat of
reaction to dissociate the amine acid
compounds and evaporate water, which
leaves the stripping section with the
acid gas stream. The quantity of vapour
required depends on the solution purity
needed to produce the specic product
gas. Stripping vapour, which passes out
of the column with the acid gas, is
normally condensed and returned to
the column as reux. The reux ratio,
calculated as moles of water in acid gas
to moles of acid gas stripped, ranges
from 1.03.0.
The stripper top temperature has a
direct relation to the reboiler energy
input. The reboiler temperature is
simply a reection of the boiling point,
which depends upon concentration
and pressure. Hence, reboiler
temperature is not a controlled variable.
Heat input should be such that the
desired overhead temperature (100
110C) should be achieved, depending
on the gas-treating application and
reux desired. The problems identied
in the stripper/reboiler involved:
High lean amine solution loading
(consequence of improperly stripped
Regenerator foaming
Carry-over of liquid with acid gas
observed in the downstream SRU
(sulphur recovery unit) inlet separator.
Monitoring parameters included:
For problem 1:
Steam ow to the reboiler
Regenerator pressure
Regenerator overhead temperature.
For problem 2:
Differential pressure across columns
and levels.
For problem 3: PTQ Q1 2007 115
Reux rate
Reux drum level transmitter and switches.
An increase in acid gas header pressure due to a problem
in the downstream SRU raises the regenerator overhead
pressure. It immediately decreases the overhead temperature
and acid gas reux rate.
If the regenerator overhead temperature is low (<99C) at
the normal operating pressure and concentration, it is best
to increase the steam ow in the reboiler (maximum bulk
solution temperature should not exceed 128C to prevent
MDEA degradation). Less reux is the consequence of a low
overhead temperature. If a tendency to foam is noticed, use
an antifoaming agent to prevent it. If liquid carry-over is
observed, check actual levels in the reux drum and reux
pump discharge.
When a high MDEA concentration or high regenerator
pressure is encountered, a high heat input is required to
obtain the desired overhead temperature. A control scheme
can be implemented that adjusts the heat input to control
the overhead temperature. It is good practice for the
regenerator overhead temperature to be measured prior to
the condenser and to be pressure compensated.
If both the reux ow and overhead temperature are
normal but the solvent is poorly stripped, check for
mechanical damage inside the column. In the case of
foaming, check all the points discussed in absorber foaming.
Surging reux in the overhead reux drum needs internal
inspection if other parameters are normal.
Case study 4
Hydraulic instability
When the regenerator becomes hydraulically unstable, it can
lead to surging reux into the overhead reux drum. The
surges and instability indicate ooding. The bottom product
continues to meet specication, suggesting the ooding
commences near the top of the column. The relatively small
pressure-drop increase during surging reinforced this
conclusion. Foaming was suspected, but the addition of an
antifoam agent brought little improvement. Raising the
regenerator pressure also produced marginal benet. Finally,
it was decided to open and inspect the column. It was
observed that the reux seal pan portion was sheared off
(opposite the reux feed nozzle). Below the seal pan feed
entry to the column (two-phase feed), a tapered slot in the
feed inlet line was facing upwards (towards the seal pan).
The width of the slot was greater at the side where the failure
occurred. It appears that the two-phase ow was impinging
the reux seal pan from the bottom. A crack had developed
at the clamp and propagated, which lead to the shear-off.
A new seal pan was fabricated and installed. Stiffener
plates were added at both sides of the clamping lengths. The
surging problem was solved. Further inspection is required
in future turnarounds.
Amine plant solvent losses do not normally cause
immediate concern and require quick action. The loss rate
should be measured over a period of time to obtain the
quantity (in kg) of MDEA/MMSCM gas processed. Once this
measurement is higher than anticipated, the source of loss
should be identied. The root cause analysis generated the
Mechanical loss: leaks from anges, gaskets, sample lines,
heat exchangers, frequent lter changing, and excessive
Entrainment loss: ooding of columns (ie, physical carry-
over of amine solvent to treated or acid gas due to poor tray
hydraulics), damaged knockout vessel (ie, demister pad and
mist eliminator)
Vapourisation loss: amine vapourisation depends on
parameters like temperature, pressure and concentration. An
equilibrium is established between the amine vapour in
solution and the partial pressure of the amine in the gas
116 PTQ Q1 2007
stream. If the temperature increases and
pressure decreases, the amount of gas
phase amine rises due to the higher
vapour pressure of the amine on the gas.
As treated gas removal is continuous,
additional amine will go to the gas
phase to maintain equilibrium. In the
stripper, reux water contains 1% to 5%
amine. Acid gas while exiting is almost
water washed, and the ow is small
compared to absorber gas. Hence,
vapourisation loss is less. In normal
conditions, vapourisation is a small
fraction of the loss rate
Degradation loss: chemical degradation,
thermal decomposition, heat-stable salt
Gas dehydration unit:
high-pressure absorber
Wet gas from the GSU enters the TEG
absorber, where it counter-currently
contacts the lean TEG to remove
moisture from the gas. The main
problems associated with the absorber
are insufficient dehydration and
foaming. The outlet gas moisture dew
point indicates the performance of the
contactor. A minimum lean glycol
concentration is needed to achieve a
specific dew point. Monitoring
parameters include:
Gas ow rate
Inlet gas and glycol temperature
Glycol ow rate
Temperature of the reboiler in
Stripping gas ow rate.
Action to take includes:
Reduce GSU outlet gas temperature,
if possible
Adjust glycol circulation rate
Reduce gas ow rate temporarily
Increase reboiler temperature if
margin is there
Adjust stripping gas.
Root cause analysis:
Lean glycol purity: glycol
concentration plays a vital role in the
rate of absorption of moisture
High reboiler temperature: can be
increased up to 204C, above which
glycol degradation starts
Reboiler temperature must be
maintained between 180185C at
1 atm pressure and stripping gas ow
1015 nm
/hr to achieve 99.5% glycol
Temperature of the inlet gas dictates
the amount of water fed into the unit. A
lower inlet gas temperature will require
less water to be removed by the glycol.
Hence, performance of the sweet gas
cooler and the lean amine cooler of the
GSU should be monitored
Lean glycol temperature at the top
of the contactor will affect the water
partial pressure at the top stage. A high
TEG temperature will cause high
moisture content in the outlet gas.
Foaming causes glycol to be carried out
of the absorber top with the gas stream
and consequent glycol loss, along with
a decrease in efciency. Foaming is
caused by liquid hydrocarbon, well-
treating chemicals, salts and solids in
the glycol. Monitoring parameters
Outlet knockout drum level
Differential pressure across the
Action to take includes:
Immediate reduction of gas ow
Inlet TEG temperature should be
5C higher than the gas temperature
Check the cartridge lter and carbon
bed. Particles of 5 microns and larger are
removed by the cartridge lter. Activated
carbon removes organic products, acids
and liquid hydrocarbons
Check the pH of the glycol
Reboiler bulk temperature should
not exceed 204C to avoid excessive
heating and degradation.
In the stripper/reboiler, the problem
areas are lean glycol purity and glycol
losses due to vapourisation. Monitoring
parameters should include:
Reboiler temperature
Stripper top temperature
Stripping gas ow.
The plume leaving the glycol stripper
is an indication of glycol vapourisation.
As it is heavier, a plume towards ground
indicates glycol is being vapourised.
Depending on the percentage of
moisture in the lean glycol from lab
analysis reports and considering
vapourisation loss, steam to the reboiler
must be adjusted along with the
stripping gas ow. Glycol purity of 98%,
98.5% and 98.8% can be obtained at
182/193/204C and at 1.0 atmospheric
pressure without stripping gas.
A root cause analysis shows that the
water vapour leaving the top of the
regenerator is monitored regularly,
since some TEG may be lost. A reux
coil in the top section cools the vapour
and partially condenses it to provide
reux and reduce the glycol loss. The
optimum temperature prole for
various combinations of stripping gas
and reboiler temperature are carried
out. The glycol purity and outlet gas
moisture content is checked. Thermal
degradation of the glycol cannot be
ignored. This is a result of a high
reboiler temperature, high heat ux
rate and localised overheating.
Glycol loss
Glycol loss requires much attention
and analysis for GDU operation. Since
most of the loss is due to the carry-over
of glycol with the gas stream, a demister
pad is tted at the top of the absorber.
The knocked-out liquid in the sweet gas
KOD is normally taken back into the
system. An efcient demister in the
outlet KOD will also prevent the loss of
glycol. The absorber gas velocity should
be within permissible limits.
Evaporation loss from the glycol
reboiler/regenerator has already been
previously discussed. Glycol injection
pumps are generally reciprocating
plunger pumps, and packing leaks are
very common. Proper packing
adjustments reduce loss.
A systematic approach for solving
the operational problems typically
encountered in amine sweetening and
glycol dehydration is the key to stable
operation with fewer upsets. Proper
diagnosis and correct remedial measures
are very important. This fundamental
approach leads to protable operation.
The authors wish to thank Mr M V SubbaRao,
DGM (P) of ONGC, for his expertise in
helping to solve many of the problems
Alok Chakraborty is superintending
engineer (production) of Oil and Natural
Gas Corporation Limited, India. He has
been involved in the eld of sour gas
processing over the past 15 years. He is
a member of Indian Institute of Chemical
Engineers (IICHE) and Indian Institute of
Gas Engineers.
Saeid Mokhatab is an advisor of natural
gas engineering research projects in the
chemical and petroleum engineering
department of the University of Wyoming,
USA, as well as an international associate
of David Wood & Associates, Lincoln, UK.
His expertise lies in the area of design and
operations of natural gas transmission
pipelines and processing plants.
William A Poe is a Houston-based
consultant with 24 years of experience
in chemical and gas-processing plant
design and operations. His main area of
focus over the past 15 years has been
automation, multivariable predictive
control, advanced process control, and
optimisation design and implementation
for the natural gas processing and
treating, sulphur recovery, ammonia
synthesis, methanol synthesis, liqueed
natural gas and power generation
Proper diagnosis and
correct remedial measures
are very important. This
fundamental approach
leads to protable
operation PTQ Q1 2007 117