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

295 AMMONIA TECHNICAL MANUAL2008

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

296AMMONIA TECHNICAL MANUAL 2008

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

297 AMMONIA TECHNICAL MANUAL2008

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.

298AMMONIA TECHNICAL MANUAL 2008

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-

299 AMMONIA TECHNICAL MANUAL2008

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)

300AMMONIA TECHNICAL MANUAL 2008

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

302AMMONIA TECHNICAL MANUAL 2008

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

303 AMMONIA TECHNICAL MANUAL2008

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.

304AMMONIA TECHNICAL MANUAL 2008

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.

305 AMMONIA TECHNICAL MANUAL2008

• 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