CIS – 750 Advisor – Longin Jan Latecki Presented by – Venugopal Rajagopal
Major challenges experienced after commissioning of the ......C V Venugopal and S G Gedigeri Oman...
Transcript of Major challenges experienced after commissioning of the ......C V Venugopal and S G Gedigeri Oman...
Major challenges experienced after commissioning of the mega OMIFCO
complex
After successful commissioning of the OMIFCO complex in April-2005, teething troubles were
surfacing in different forms that had to be dealt with both in the short term and long term for
continuous operation of the plants. Meticulous Root Cause Analysis of the problems by the OMIFCO
engineers, vendor and the consultants and implementation of the corrective measures in the shortest
possible time was necessary to ensure safe and reliable operation of the complex.
This paper highlights the two major challenges faced by OMIFCO after commissioning of the plants:
the failure of the fresh cooling water system piping Y-joint on the pump discharge header and failure
of the Synthesis gas compressor turbine inlet pipe high pressure steam strainer. These major failures
caused significant loss of on stream days and productivity.
C V Venugopal and S G Gedigeri
Oman India Fertiliser Company
Introduction
MAN INDIA FERTILIZER
COMPANY S.A.O.C. (OMIFCO) was
set up as a joint venture project under
the initiative of the Government of Sultanate of
Oman and Government of India. OMIFCO is
owned 50% by Oman Oil Company, 25% by
Indian Farmers Fertilizer Co-Operative Ltd
(IFFCO) and 25% by Krishak Bharati Co-
Operative Ltd (KRIBHCO). OMIFCO was
registered in the Sultanate of Oman as a closed
joint stock company in the year 2000.
The Ammonia Urea complex comprises two
trains, each with a design capacity of 1750
MTPD Ammonia and 2530 MTPD granulated
Urea, along with all supporting Utilities. The
site is designed to produce a total of 1.65
million tonnes of granulated Urea and 0.25
million tonnes of surplus liquid ammonia
annually for export, using natural gas. Storage
facilities for Urea (2 x 75000 MT) and
Ammonia (2 x 30000 MT), as well as a jetty
with ship loaders are all part of the project. The
project was commissioned in April-2005.
Underground Reinforced Resin Piping
Failure
Description of the System:
OMIFCO uses a combination of Sea Water and
Fresh Cooling Water (FCW) as its cooling
medium. Seawater is used as the cooling
medium in the Ammonia Condensers and
Surface Condensers of the turbines driving the
air compressors, synthesis gas compressors and
carbon dioxide compressors. This is an open
loop cooling since seawater from the Sea Water
pump discharge after passing through the
condensers goes back to sea.
O
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The plant has a closed loop cooling water
system for all other exchangers using
desalinated water as the cooling medium viz the
Fresh Cooling Water System. Trouble free
performance of the Fresh Cooling Water system
is highly indispensable in sustaining the
operation of the entire OMIFCO complex. Here
again seawater is used, as the primary cooling
medium, which cools circulating Fresh Cooling
Water in Plate type exchangers (a total of 16) by
indirect cooling. Hot water from the process
plants is cooled here and returned to various
exchangers of the process plants. (See Figure-1)
Figure-1: Overall view of FCW Pumps &
Plate type Exchangers.
This FCW system consists of pipelines laid
partly underground and partly above ground. All
underground pipelines are made of Reinforced
Thermosetting Resin Pipes and above ground
pipelines are of carbon steel. All of the Sea
Water pipelines are made of reinforced resin
pipes. The base material of the Fresh Cooling
Water pipes and fittings has been filament-
wound, using polyester, vinyl-ester or epoxy
resin and glass-fibre reinforcement.
The applicable Codes and standards for Glass-
Fiber-Reinforced Thermosetting-Resin pipe are
ASTM D-2996, ASTM D-3517 and ASTM D-
3754.
The material properties for Glass-Fiber-
Reinforced Thermosetting-Resin pipe are given
in Table: 01
Property Test Method Value in
Mega Pascal
Axial Tensile
Modulus
ASTM
D 2105
11000
Axial Tensile
Strength
ASTM
D 2015 75
Hoop Tensile
Modulus
ASTM
D 2290 20000 / 20500
Hoop Tensile
Strength
ASTM
D 2290 210 / 250
Table: 01
Reinforced Thermosetting Resin pipe was
selected for the following advantages:
It is non-corrosive in saline subsoil conditions
and does not require non-intrusive cathodic
protection, which adds to the cost of
maintaining the system while in operation.
FCW system being a closed loop has minimal
water losses and hence there is no make up of
desalinated water to the FCW System. But in
the first week of September, 2005, a FCW leak
at a rate of approximately 4-5 M3/hr, was
observed which gradually increased to around
20 M3 /hr in about two weeks time.
All exchangers and the complete FCW network
were checked to determine the source of water
loss but nothing could be found aboveground.
Two-inch diameter pit holes were dug to the
depth of the FCW header (3.5 m) at suspected
vulnerable areas to check for the location of
leakage. Also H2 gas was injected in the FCW
header and attempts were made to detect the
FCW leakage by checking for H2 explosivity.
H2 injection was done carefully considering the
hazardous nature of H2. For this job a special
instrument that can detect H2 up to a lower
concentration level of 200 ppb (0.2 ppm) was
purchased. As this concentration being
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substantially lower than the lower explosive
limits value (4.0 %) of H2, the leak test could be
performed safely.
These methods could not provide any evidence
of the leakage.
As water was not seeping to the surface, it was
understood that it was flowing underground
finding its way through the gravel and sand
placed around the FCW lines.
Excavations were made at process plant battery
limits in the region of the FCW header tap offs
to locate the area of leakage.
As no water could be found, this process largely
eliminated suspicion of underground leakage in
the FCW main headers for the Ammonia and
Urea plants. On 9th
November 2005 while
OMIFCO was still battling with the problem,
water surfaced behind the satellite control room
for the ammonia plants.
Upon excavation a FCW leak was observed in
the 6” FCW line. As this particular header could
not be isolated for repair, the whole FCW
system had to be shutdown to access and repair
the leak. Consequently both the trains of
Ammonia and Urea had to be shutdown with a
production loss of about five days.
The leakage in the pipeline was at the area
where the 6” pipeline passes through the wall of
the pit housing the isolation valves. It was
suspected that adequate allowance for expansion
between the wall and the 6 “pipe line might not
have been provided causing cracks in the pipe
line. The pipe was repaired by applying Vinyl
Ester tapes and resin. The plant was restarted on
12th
November 2005.
Once again on 22nd
November 2005 at around
18.30 Hrs, the FCW underground header at the
pump common discharge header between
pumps B & C, started leaking heavily when the
process units were stable at rated capacities (See
Figure-2). Leakage was so heavy that both the
Ammonia and Urea Plants had to be shut down
to undertake the repair job.
Figure-2: FCW Pumps - Area Flooded with
Water
Upon excavation it was observed that near the
discharge of Pump-B (near the Y-joint
connecting the main discharge header) there was
a hole of about 8” on the top surface of the main
header (See Figure-3). Thinning of the resin
material of FCW line was also observed at two
other places, which indicated leakage was there
for quite some time. It was understood that a jet
of water leakage might have caused churning of
gravel around the pipeline thereby grinding and
thinning the parent material, which ultimately
resulted in failure.
Figure-3: Hole on the top of FCW header
near Pump-B
A visual inspection of the header was carried
out from the inside that indicated cracks at the
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Y-joints of the B, C and D pumps. This was
repaired by the supplier/vendor of the RTRP
line by applying 16 layers of vinyl ester tapes
and resin wrapped around the OD of the main
header. Cracks observed inside the pipe at the
joints were also repaired. Upon start-up of the
pump, water was observed coming out at the Y-
joint of Pump-B again. Further investigation
revealed that water was coming out because of
de-lamination of the header near the joint.
As the Contractor was unable to provide the
cause of the failure in spite of a ten-day plant
shut down for repair, it was decided to minimise
the leak by installing an external clamp over the
pipeline and to operate the plant till a permanent
rectification plan could be put in place.
Accordingly a clamp was provided on the
header.
The clamp reduced the leakage rate to around 20
M3/hr. OMIFCO started the 30 day reliability
test on December 4th 2005. However, on
December 18th
2005 another leak was observed
on the FCW header, this time near the C pump
discharge. OMIFCO continued the operation of
the plants and successfully completed the
reliability test with the leak amounting to
around 100 M3/hr.
Water leaking from the header was collected
and re-cycled through one of the polishers to
maintain the inventory. On February 7th
2006
both gas turbines supplying captive power to the
complex tripped due to an instrument relay fault
causing a shut down of the complex.
On 8th
February when one FCW pump was
restarted, there was an uncontrollable leakage
after 6-hour duration, forcing the stoppage of
the pump.
On excavation it was observed that the pump-B
discharge line had sheared off near the Y-joint.
(See Figure-4). A hole was also observed on the
main header near Pump-C. Thinning of main
header was also observed at two places.
Figure-4: Shearing of RTRP Header ‘Y’
Branch at Pump-B
Causes of Failure:
The contractor’s report has expressed the
following views.
• Inadvertently subsoil conditions surrounding
the FCW pumps discharge header changed
and could not be restored by backfilling.
FCW header operation continued and
whenever a FCW pump was started or
changed over it introduced heavy stresses on
the Y-joints.
• The pump discharge header was subjected to
heavy axial thrust, as no restraint block was
installed at the dead end of the header.
• As the plant operation was continued
without correction of leaks, water from the
leaking points caused milling action of
gravel surrounding the RTRP pipe. The root
cause for the leak was the weak Y-joint at
the discharge of FCW pump-B. Over a
period of time, through-wall holes
developed in some of these areas, while
similar erosion took place at other places
that caused thinning of the RTRP pipe,
though penetrative holes did not develop.
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However, in-house study indicated the
following:
•••• Nature of cracks and failures suggested that
the common pump discharge header was
subjected to tensile stresses. It caused de-
lamination of the main pipe and cracks on
joints, which are presumably weaker than
the main pipe.
•••• Tensile stresses in pipeline are expected
during pump start-ups and sudden
stoppages.
•••• Contractor’s construction drawing shows
restraint thrust block at the dead end of the
header. No such restraint was found on
excavation. Contractor has not given any
satisfactory answer to this point.
•••• As part of future remedial action plan,
OMIFCO has given the flexibility analysis
and design job to provide an above ground
CS pipeline to a reputed consultant. The CS
pipeline design offered by the consultant has
shown restraint block at a few locations on
the pump common discharge header.
•••• It may be noted that CS line can withstand
higher tensile stresses than RTRP line.
Repair Job Done
The contractor has done the following while
repairing the pipeline:
Complete Y-Joint (Including 1.3M pump
discharge line and 2.2M common discharge
header) for Pumps B and C was completely
replaced with new RTRP line. Wall thickness of
the new pipe is 30 mm as compared to the
25mm for the old pipe.
During the repair when the Y-joints were laid in
position, gaps were observed at two places
between the new header and the old header.
Hence, 2.2M diameter pipe segments of 200mm
and 300 mm length, each again of 30mm
thickness were put in position and wrapping was
done with resin.
On the dead end of the common pump discharge
header a concrete block of about 150 tonnes has
been cast in-situ to restraint the lateral
movement of common discharge header.
At the bottom of the common discharge header
cement slurry has been poured over as
aggregate. Approximately half the diameter of
the pipeline was inside this aggregate-cement-
slurry mass. This was done to ensure that there
would be no settlement of the pipe during
normal operation or during water leakage.
A Neoprene rubber sheet of 3mm thickness was
installed at the interface of concrete and RTRP
line. Gravel and soil was also put in layers and
compacted for proper consolidation.
Figure-5: Repaired RTRP Header
Long Term Measures
Based on the haunting initial experience and
after weighing in the various risk factors
associated with maintaining the RTRP
underground piping, OMIFCO decided that it
would be prudent to install an above ground CS
piping, in parallel with the existing under-
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ground RTRP header from the pump discharge
to the inlet of Plate type heat Exchangers.
Accordingly an above ground Carbon Steel
piping header for FCW from the pump
discharge to the inlet of Plate type exchangers
has been installed at a cost of 2 million US
Dollars.
Figure-6: Completed Above ground Carbon
Steel piping.
While the CS header installation job was
nearing completion after connecting three of the
four FCW pumps, the RTRP underground pipe
header again started leaking on 28th
November-
2007, and necessitated immediate
commissioning of the new above ground CS
pipe header.
This timely action helped OMIFCO in averting
a production loss of more than 0.5 Million US
Dollars per Day and justified the decision to
install an above ground CS header for FCW.
Conclusions:
• As per the piping flexibility restraint thrust
block was to be installed at the dead end of
the pump discharge header. In the absence
of this restraint block the pump discharge
header was subjected to heavy axial
movement and stresses at the joints during
every pump change over and start-ups. This
resulted in frequent failure of Pumps
common discharge header.
• Also inadvertent changes in the subsoil
conditions leading to settling of the soil
surrounding the FCW pumps discharge
header increased the header lateral
movement during pump change over and
start-ups. This contributed to more stresses
on the pump discharge Y-joints. Timely
back filling could not be done as this could
be noticed only at the time of excavation
after the header failure.
• Piping flexibility compliances as per the
envisaged design are to be strictly adhered
to without failure in implementation of such
a massive under ground piping network.
• It is now felt that the entire stretch of the
FCW piping network should have been of
carbon steel material.
Failure of Synthesis Gas Compressor
Turbine (TK-431):
Salient Features of the Equipment:
The Synthesis gas compressor is propelled by a
28.6 MW extraction and condensing Steam
turbine TK-431. High pressure (HP) Steam at a
pressure of 110 Barg is introduced into the
Turbine and 77% of the inlet Steam is extracted
as Medium pressure (MP) steam at 45 Barg
pressure for use in Process and as motive steam
for other Steam turbines.
The Syngas turbine has two steam inlet nozzles
with Emergency Stop Valve arrangement for
each nozzle, each of which is equipped with a
strainer supplied by the turbine vendor. The
contractor provided one pipeline strainer on the
main high-pressure steam header down stream
of the turbine inlet main isolation valve.
(See Figure-7)
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Control Oil System
Turbine Governor
Synthesis Gas Compressor Turbine
HP Control Valve
LP Control Valve
Emergency Stop Valve (ESV) Strainer
ESV Strainer
To Surface Condenser
Extracted Steam @ 45.0 Barg and 389.5 Deg.C
A
B
Pipe line Strainer
14" Header High Pressure Steam
@ 110 Barg and 505 Deg.CMotor Operated
Valve
Isolation Valve
Motor Operated Valve
Note: A and B are Emergency Stop Valves
FIGURE-7: LOCATION OF STRAINERS AT TURBINE INLET
Parameter Details
Make-Model & Type
Nuvopignone Make
Model EHNK-
40/45 Extraction
cum Condensing
turbine
Max. Output 28578 KW
Max. Speed 10030 RPM
Inlet Steam
pressure/Temp
110 Bar. gauge /
505 ° C
Extraction
Pressure/Temp
45 Barg
389.5 °C
Parameter Details
Exhaust
pressure/Temp.
0.23 Bar.Abs. /
63 °C
Turbine Stages
Total 14 Stages
(HP 1Imp+4 Reaction)
(LP 1Imp+8 Reaction)
Bearing Type.
Tilting Pad Journal and
Tapered land Thrust
Bearing
Observations during Operation of the Turbine
The plant was commissioned in April 2005 and
the preliminary acceptance by the owner was
accomplished on 14th
July 2005. Prior to the
preliminary acceptance though entire pre-
commissioning and commissioning
responsibility was under scope of the contractor,
owners operation and maintenance persons were
directly involved in carrying out all the
activities.
The machine was operating without any
significant problems. On 24th
May 2006, the
steam flow through the turbine suddenly
reduced to 250 MT/hr from the normal 260
MT/hr.
Under close monitoring, the operation of the
turbine was continued as there were no other
adverse symptoms such as high vibrations, high
temperature etc. Subsequently plant load was
reduced keeping flexibility for extraction flow
variation. After load adjustment the turbine inlet
steam was varying between 205 MT/hr – 226
MT/hr.
301 AMMONIA TECHNICAL MANUAL2008
On 30th Oct2006, the turbine tripped on low
temperature of the high-pressure steam inlet.
While the machine was slowing down, upon
reaching about 4500 rpm, the speed suddenly
increased to 8000 rpm due to depressurisation of
the LP & HP compressors caused by high
primary seal leak off from the LP case drive end
seal.
The machine was stopped to repair the
compressor seal leakage and it was decided to
open the turbine to investigate the problem of
low steam flow during operation.
Major Damages found in the Syngas
compressor Drive Turbine:
The high-pressure steam pipeline strainer was
not found in place. Strainer debris was found
stuck in the Emergency Stop Valve (ESV)
strainer and in the HP nozzle box. The ESV
strainer of south side steam inlet nozzle was
found completely damaged and the north side
ESV strainer was found having debris of
pipeline strainer lying around it.
Upon inspection of the ports of the five
governing valves, a large amount of debris of
ESV strainer strips was found lying inside the
nozzle box.
Valve numbers 1 and 2 were found to have the
most amount of debris. On dismantling of the
Emergency Stop Valves, the south side valve
seat was found having a dent on the sealing
surface. The north side valve seat was found in
good condition. On inspecting governing valve
seats, two of the valve seats were found having
dents due to entrapment of strainer debris.
On removal of the outer casing, the rotor was
found having heavy rub on fins of the balancing
drum area. Most of the rotor fins were found
damaged.
Rotating blades row no. 5 was found having
heavy rub and impact marks. Some of the front
as well as rear end Journal bearing pads were
found damaged. Two of the thrust bearing pads
were found damaged.
Two shrouds were found missing from the
bottom half of the LP Guide blade carrier, row
No. 5. The shrouds of LP Guide blade carrier
row nos. 6 and 7 were also found in loose
condition. The inter-stage fins of almost all the
guide blade carriers were found in damaged
condition.
The LP guide blades as well as HP nozzles were
found having dent marks. Some of the HP
nozzles were found plugged with ESV strainer
strips. The last stage of rotating blades was
found having indications of less flow in LP
section.
Figure-8: Normal Pipe line Strainer
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Figure-9: Normal healthy ESV Strainer
Figure-10: ESV Strainer pierced with pieces
of Pipe Line Strainer
Figure-11: Damaged ESV Strainer in
Position.
Figure-12: Removed damaged ESV Strainer.
Figure-13: Dents on ESV Seat
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Figure-14: Damaged Impulse stage Blades
Figure-15: Damaged inter stage blades
Figure-16: Missing Shroud on LP Guide
blade Carrier
Figure-17: Magnified view of ESV Strainer
pieces stuck up in ESV plug and seat.
Possible Causes of Failure
The synthesis gas turbine has two steam inlet
nozzles with ESV arrangement for each nozzle
and each nozzle is provided with ESV strainer
by the turbine vendor. One permanent pipeline
strainer on the main high-pressure steam inlet
line to the turbine was provided by the
contractor down stream of the turbine inlet main
isolation valve.
The pattern of damages observed indicate that a
premature failure of the turbine steam inlet
“line” strainer had taken place, which
subsequently plugged the ESV strainers, and
caused extensive damage to both the ESV
strainers and the turbine internals.
There are a total of three strainers upstream of
the syngas steam turbine. The contractor
provided one “line” strainer on the main high-
pressure steam inlet line installed down-stream
of Turbine inlet main isolation valve. The steam
supply then split into two inlet nozzles.
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For each of these inlets, the turbine vendor
supplied ESV strainers and ESVS.
(See Figure-7)
On further scrutiny it was noticed that the
material of line strainer was ASTM A249 TP-
316L grade with an average thickness of about
0.5 mm only.
A cursory check on the thickness of other
pipeline steam strainers indicated a thickness of
about 1.5 mm. The material in use for the ESV
strainers was examined by external agencies and
was found to be of ASTM A249 TP-304L
grade.
The material (TP-316L) used for the line
strainer has a higher tensile strength than the
material (TP-304L) used for the ESV strainer.
As 1.5 mm thickness line strainer provided for
refrigeration compressor turbine has been
working normally, it is suspected that the line
strainer of 0.5 mm thickness might have yielded
under the normal operating conditions. Both the
strainers are made of the same material ASTM
A249 TP-316L grade only.
Further the construction of ESV strainer has a
corrugated coil strip type fabricated design
which gives higher impact resistance strength
compared to the pipe line strainer which is made
by making perforations on a thin sheet.
It was suspected that 0.5 mm thickness of line
strainer would not have been adequate and
might have failed under the normal operating
conditions.
Rehabilitation of the Equipment
After assessing the extent of damage to the rotor
and stator parts of the turbine two possible options
for quick rehabilitation were considered.
OPTION-I
• Replacing of damaged LP Guide blades (5, 6
& 7) with new set of blades.
• Replacing of damaged /missing shrouds of
LP carrier with new shrouds.
• Replacing of HP fins with new fins and
caulking wire.
• Replacement of damaged fins of guide blade
carrier with new fins and guide blade
carriers. Replacement of damaged ESV seat
and blue matching with valve plug.
• Lapping of two governing valves. Removal
of pipeline strainer.
• Replacement of both the ESV strainers with
new ones.
• Replacement of rotor with new spare rotor
after ascertaining the dimensional check.
Replacement of damaged journal-bearing
pads with new ones.
• Steam blowing of steam inlet pipelines.
Complete inspection and repair of damaged
rotor as a stand by rotor.
OPTION-II:
• Shaving off the damaged LP guide blade row no.5.
• Repair (welding) of damaged of LP carrier
with new shrouds/Repair of looses shrouds
of LP carrier blades rows 6 & 7.
• Repairing of HP fins with new fins and
caulking wire. Machining of damaged ESV
valve seat and blue matching with valve
cone.
• Lapping of two nos. of governing valves.
And removal of pipeline strainer.
• Replacement of one ESV strainer (out of
two) with new one.
• Replacement of damaged journal-bearing
pads with new ones.
• Repair of damaged rotor in built fins at
balance drum portion, shaving off rotating
blades row no.5 from rotor and balancing of
rotor at operating speed.
• Steam blowing of inlet pipelines.
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• Procure complete new set of guide blade
carrier assembly from OEM as spare for
future.
Option-I was selected for rehabilitation and
option-II was sidelined because of lower
reliability and additional shutdown requirement
again for putting back new guide blade carriers.
As one Ammonia train remained on forced shut
down, the speedy restoration of turbine has
become essential. Considering the critical nature
of the job and due to lack of requisite stationary
Guide Blade Carriers (GBCs) at site, it was
decided to get damaged GBCs repaired through
OEM vendor from their global facilities.
The damaged GBCs were sent to Florence Italy
for refurbishing and one OMIFCO engineer was
continuously kept at works site for speedy
execution of the repair job.
Conclusions:
• The main cause of damage was the result of
failure of the on line steam strainer wherein
the specification has been doubted to
withstand the operating conditions of high-
pressure steam.
• The improperly scrutinized line strainer
failed to withstand the adverse non-routine
process conditions and got damaged
prematurely, which subsequently damaged
the reliable ESV strainers provided by the
Turbine vendor.
• Usage of line strainers should be practiced
with utmost care unless warranted by the
specific process requirements.
• The material selection and specification
should be verified by a third party
certification before putting into use.
• The selected specification of line strainer
must have been in use at least in three
similar equipment installations where no
problems had been reported over sufficient
period.
• There should be a procedure in place for
periodic inspection of on line strainers and
equipment strainers of critical equipment, so
that major colossal damages of main
equipment could be averted.
*****
306AMMONIA TECHNICAL MANUAL 2008