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PROCESS ENGINEERING SECTION

Incident Description

On 21st Aug, 2012 at 11:27 hrs, Ammonia plant back‐end tripped due to C‐104 (Synthesis compressor)

tripping on low seal oil level security caused by turbine driven seal oil Pump (P‐122B) tripping. On

machine tripping, gas broke through compressor seals which caused splashing of oil through the oil

return header and console. Splash of oil on hot surfaces caused the fire which was effectively controlled.

Emergency Response Team mobilized and took control of the situation. Ammonia & Urea were shut‐

down; however CAN & NP remained in operation till 22nd Aug, 2012.

After evaluating the situation, it was decided to take about 10 days outage of the complex to attend

various other pressing jobs at all plants. However, while restarting the ammonia plant from 29th Aug,

various problems were encountered and the production could only be resumed on 15th Sep, 2012.

The plant startup activities commenced after box up of primary reformer furnace on 28th august 2012,

However, while restarting the ammonia plant from 29th Aug, various problems were encountered

including foaming in Catacarb causing carryover of solution to methanator, problem at cold box

expander, failure of HP steam let‐down valve, leakage in blow‐down headers, hot spots on transfer line

which were progressively resolved. Production resumed on 15th Sep, 2012.

SEQUENCE OF EVENTS: Shutdown: 21st August 2012:

1. 1127 hrs: C‐104 (Synthesis compressor) tripped on low seal oil level security caused by turbine driven seal oil Pump tripping. Gas broke through compressor seals resulted in splashing of oil on hot surfaces which caught fire.

2. 1212 hrs: Fire was completely extinguished after extensive efforts by Emergency Response Team (ERT).

3. 1800 hrs: Scope of Damage was assessed and it was estimated that production can be resumed after ~5 days, if there is not any additional hidden damage. Based on detailed assessment, it was decided to prolong outage to another 5 days (total 10 days outage) to complete other important jobs and TA‐2012 was postponed till March 2013 after consent of CEO.

22nd August 2012:

1. 1650hrs: GTG‐A was stopped to conserve fuel. 23rd August 2012:

1. 1600hrs: STG was stopped due to low steam requirement.

Start‐up: 28th August 2012:

1. 0440hrs: CGT‐102 was started in crank mode for wet washing of axial compressor. 2. 1730hrs: Catacarb solution circulation was established for passivation of towers.

29th August 2012: 1. 0800hrs: Primary Reformer furnace was fired after final inspection and subsequently process

steam, process gas and process air introduced in the system on achieving specific temperatures. 2. Performance of synthesis machine Seal oil pumps (P‐122A/C) was measured. P‐122A capacity

was found ~8.0 m3/hr (discharge pressure; 147 KG/cm2; dump valve, PV‐309 opening 22%) While P‐122C was found problematic (discharge pressure; 53 Kg/cm2 at 5% opening of PIC‐309).

30th August 2012:


1. 0148 hrs: Gas turbine CGT‐102 was fired. 2. 0313hrs: Process air was introduced into the secondary reformer.

3. 0520hrs: LTS was taken in service after catalyst bed heating.

4. 0807hrs: Methanator was lined up.

5. 1230hrs: Dryers and Cold box were taken in service. De‐riming and blowing of Cold Box was

carried out and dust was observed for first 3 blows.

6. 0936 hrs (Fire at GTG‐B): During wet washing of GTG‐B diesel engine tubing leaked and caught

fire due to oil splashing on high temperature of exhaust line. Fire was extinguished in ~10

minutes and oil leak was rectified.

31st August 2012: 1. 0315hrs: Ammonia refrigeration compressor was started but tripped 05 times on high radial

vibration (VI‐52/53). Machine was normalized on 6th attempt. After start up, 02 PROTECH speed

probes & 01 WOODWARD speed probe became faulty. PROTECH Over speed protection was

bypassed while WOODWARD probe was replaced with spare one.

2. 1130 hrs: NG booster compressor was C‐101 was started but tripped on dry gas seal vent high flow security. Compressor re‐started at 1432hrs after replacement of DGS filters.

3. 1730 hrs: Catacarb solution carried over with process gas to downstream exchangers and Methanator, R‐104 due to foaming in CO2 absorber. R‐104 was immediately isolated, depressurized and drained. Process gas was re‐introduced to Catacarb.

1st September 2012: 1. 0730 hrs: C‐104 Lube Oil pressure dropped due to low oil console level. Machine was

depressurized and seal oil bottles were drained. Seal oil was found in LPC/HPC & recycle line. Later it was revealed that Level indication of HPC seal oil bottle was faulty resulting in seal oil overflow into the compressor casing. Consequently 21.5 oil drums were recovered from casing. Level transmitter was provided on TK‐108 for early identification of level depletion in the tank. Furthermore additional PDT indication across Reference gas and seal oil supply was provided on all seal oil bottles.

2. 1400 hrs: Catacarb solution carry over was observed again due to foaming causing high level of absorber downstream knock out vessel, D‐133.

3. 2345 hrs: Process gas was re‐introduced to Catacarb section & Methanator was taken back in service. However, performance of E‐120A/B was not satisfactory indicating heavy fouling on tube side due to catacarb solution carry over.

4. Stucking behavior of HP steam let down, PV‐032 was observed. 2nd September:

1. 1510 hrs: Plant was stopped completely due to stucking behavior of PV‐32 (HP steam letdown) valve. Valve was shifted to work shop at 0145hrs (03rd Sep) and some scratches were observed on the cage. Valve was reinstalled after Polishing of Cage and plug.

2. 1030 hrs: Flushing of E‐120A/B was started with turbine condensate. Exchangers were filled and drained 7 times. K2CO3 concentration in outlet flushed condensate gradually decreased from 49 to <02% and cleaning was considered complete.

3. 1315 hrs: CT‐105 was stopped and inspection of speed probes was carried out. Total 3 out of 6 speed probes were found damaged (2 for over speed protect & 1 for wood ward). All 6 probes were replaced with new ones.

4. CT‐105 trip SOV’s‐ 125‐A/B fails safe mode was changed from fail close to fail open by replacing SOVs.

3rd September: 1. PV‐32 was reinstalled & stroke tested.


2. 1230 hrs: Primary reformer furnace (F‐101) was fired and process steam was introduced at 1730 hrs, Feed gas was introduced at 2120 hrs and process air to secondary reformer at 0015 hrs.

3. Catacarb circulation continued for solution regeneration by process gas. 4. CT105 SOV control action was changed, but SOV were not operating. Logic was checked and

problem was rectified. 4th September:

1. 1055 hrs: Methanator heating was started but delayed due to poor performance of gas exchanger (E‐120A/B). It was initially suspected that cleaning of E‐120A/B was inadequate and exchanger performance was poor due to fouling. However, detailed evaluation of exchangers by Process engineering revealed poor performance of shall side due to possible condensate accumulation. In field check it was confirmed as drain of Shell side was found blocked. Subsequently, condensate was removed by deblocking drain and exchanger performance normalized.

2. 1135 hrs: NG booster compressor C‐101 was started. 3. 2300 hrs: Dryers and expander were taken in service and cold box cooling was started after

resolving E‐120 low efficiency problem. 5th September:

1. 0019 hrs: C104 was rolled and loaded early morning. Synthesis gas was introduced to Ammonia Convertor, R‐105 by firing startup heater, F‐102.

2. Fire Incident at 0915 hrs: Fire was observed at C‐103 oil console due to splashing of oil on hot steam lines caused by over‐pressurization of oil console due to excessive seal gas leak through the HP oil drain line into the oil console. Consequently some instrument cables and instruments around C‐103 were damaged which were replaced.

3. 1245 hrs: C‐104 was re‐started keeping cold box bypass. 4. 1551 hrs: C‐104 was stopped again due to PM‐122A (Seal oil pump) capacity valve stem damage.

Stand by seal oil pump was already under machinery forcing stoppage of C‐104. 5. 2020hrs: C‐104 re‐started but stopped at 0147 hrs (6th Sep. 2012) to handover PV‐70 (Sealing

steam vent) and P‐122B replacement. 6th September:

1. 0030 hrs: After various tests, it was concluded that C‐103 seal gas line was blocked and deblockking without de‐riming / heating of Cold box was not possible. Consequently, it was decided to derime Cold box and its heating was started.

2. 0226 hrs: Sharp change in pressure of HP seal oil return line was observed confirming Seal gas line de‐blockage.

3. 0605 hrs: C‐103 was re‐started but stopped at 0610 hrs as oil splashed from oil breather of console along with gas. Several attempts to restart the Expander remained unsuccessful due to same problem. It was decided to dismantle C‐103 for detailed inspection.

4. De‐riming of cold box was carried out, Perlite was removed, expander box plates were cut, piping was dismantled and Expander was removed.

5. Flooding was again observed in CO2 absorber causing 100% level in D‐133. Immediately actions were taken to avoid solution carry over to methanator. All drains of downstream section were checked and found normal.

7th September: 1. 1330 hrs: Process gas was cut to Primary Reformer for leakage rectification of BDH headers at D‐

110 inlet line. Leak was rectified by installing sleeve and capping of bleeder neck. 2. 1028hrs: CT105 was stopped.

8th September 1. 0235 hrs: Front end start up activities commenced after welding job on BDH. 2. 0525 hrs: Gas was re‐introduced to reformer.


3. C103 was replaced with spare one and pressurized with N2 through seal gas line. Oil circulation was established & oil flow was verified from drains.

4. BT201 was handed over to machinery to attend its governor linkage. However, job could not be completed and Turbine was taken back in service without rectification of governor.

5. Smoke was observed from CT‐101 out board side which was immediately extinguished by applying fire extinguisher.

9th September 1. 0330 hrs: Power failure occurred during heavy rain which continued for ~13 hrs with recordable

values of 201 mm and high humidity of 96%. 2. Phase to Phase flash was observed on the breaker trolley arms, but timely tripping by protection

and AVR system prevented the major damage to machine. Immediate Route Cause of short circuit established was high humidity.

3. GTG‐B & A tripped one after the other on ‘Generator Lock Out Relay’ security.

4. EDG was started manually (K‐39 breaker did not open on auto mode) from the field. It operated

normal for four hours before tripping on ‘Crank Case High Pressure’ causing total black out and

steam failure due to the tripping of polish water supply pump to deaerator.

5. Starting motor of EDG was completely discharged during various checks and start‐up attempts.

Alternate batteries were arranged and EDG was started.

6. Diesel driven Fire water pump tripped on high engine exhaust temp. due to CW failure.

7. Instrument air supply was isolated when EDG went offline hence cutting IA supply.

8. Emergency power supply/ steam production resumed.

9. DCS power supply was cut when EDG went offline. However it was normalized after EDG

startup.

10. 1545hrs: GTG‐A was started and power supply restored. Subsequently steam headers heating

started on MP steam availability.

10th September 1. 0930hrs: Catacarb circulation started with lean and semi lean pumps. 2. 1200hrs: F‐101 was fired. 3. 1215hrs: Semi lean charge pump (P‐110C) started but had to stop due to abnormality in motor.

Motor was then decided to replace with a spare one. 4. 1530hrs: CGT‐102 rolled on crank speed and fired at 1958hrs. 5. 1745hrs: PHT‐110B rolled after rectification of ED logic. 6. 1800hrs: process steam introduced in primary reformer. 7. Catacarb sump drained with a portable pump considering contamination of catacarb solution. 8. 2313hrs: Process gas was introduced to Primary reformer.

11th September: 1. 0300hrs: Process air was lined up to secondary reformer. 2. Expander (C‐103) was taken back in service and cold box cooling was started. Activated carbon

bed was taken in service. 3. 1400hrs: LTS was taken into service. 4. 1532hrs: Secondary reformer tripped on faulty indication of bed temperature thermocouple. 5. 1700hrs: R‐104 was taken into service and subsequently C‐105 was started at 2000hrs. 6. 2354hrs: C‐103 seal oil circulation was started but leakage observed from LS outlet flange. C‐103

was re‐started at 0015hrs (12th Sep) after rectification of leakage. 7. 1445hrs: NG booster compressor C‐101 was started twice at minimum governor speed, but its

outboard side seal gas vent delta P increased. Machine was stopped and handed over for inspection of dry gas seals (DGS).


8. GTG‐B started after the completion of maintenance activities (replacement of isolators and

diesel engine turbocharger).

9. 12th September:

1. Excessive foaming was observed in absorber which could not be controlled even with excessive shock dosing of antifoam.

2. 1540hrs: Methanator bed temperature ran away to maximum value on first bed TI‐025B due to

high CO2 slip from absorber. Methanator trip security, I‐6 was manually actuated due to high

temperatures of Methanator. C‐104 was started at 1525 hrs and running at 1200 rpm when it

had to be stopped due to I‐16 actuation.

3. 1850hrs: Catacarb solution was drained from towers to Catacarb storage and fresh make‐up about 40% of total volume charged into the system.

13th September: 1. 0020Hrs: fresh Catacarb solution feeding started into the system and subsequently circulation

was commenced at 0405hrs. 2. Catacarb solution heating continued through Reboilers by process gas venting upstream of CO2

absorber. 14th September:

1. Additional chemicals were dosed to improve Catacarb concentration. F.E load was gradually increased to 70 %.

2. C‐101 bearings were removed for DGS inspection. One Dry gas seal was found damaged (NDE side) due to moisture ingress. Same was replaced.

3. 0055hrs: C‐103 was rolled after filling the startup checklist. 4. An indigenous modification by Process engineering (installation of degasifying tank to avoid Oil

console over‐pressurization and consequent fire due to slightly higher seal gas venting) enabled startup of Expander(C‐103) despite of excessive seal gas venting .

15th September: 1. 0137hrs: C‐104 was rolled. 2. 07:00hrs: Start‐up furnace, F‐102 was fired and R‐105 temperatures were increased. Ammonia

production started at 1540hrs at very low rate as reaction in 1st and 2nd bed of the convertor was very low while reaction rate of 3rd bed was normal. Water ingress was suspected in reactor due to moisture contamination with N2 gas while reactor in positive pressure.

3. 2230 hrs: Temperatures of 1st & 2nd beds normalized at about 2100hrs 4. 2330 hrs : C‐104 fully loaded and production rate normalized.

Summary of main problems faced during Start‐up:

DATE INCIDENT RCA DELAY (hr)

ACTIONS

21‐31 Aug Fire at syngas comp Tripping of seal oil pump and operating philosophy at that time

252.5 Number of Actions as per recommendation of Dresser Rand.

31st Aug 1st Sep

Catacarb Carryover/ High CO2 slippage

Foaming due to high SS caused by

High iron due to Tower bed churning

Amine Degradation

High SS in solution

20.5

Operating / lab / monitoring regime reviewed with tech supplier. All immediate actions


implemented. Medium term in‐hand.

1st Sep Overflow of seal oil to syngas compressor casing

Faulty Level Indicator

LG not visible / used.

Procedure compliance

32.25 Except two, all immediate actions implemented.

2nd Sep

HP steam letdown valve stuck at 30% opening

Mechanical problem/ foreign particle

No stand‐by letdown valve 38

FE shutdown to attend valve

3rd Sep Methanator heating issue

Condensate accumulation in Methanator effluent exchanger.

21 Troubleshooting/ condensate drainage

5th & 6th Sep

C‐103 (expander) Oil Console Fire

High process gas flow through HP / LP drains/ inadequate seal gas vent

Lack of care during shut‐down

38.25

Damaged cables replaced/ cold box de‐riming & spare expander installed

7th & 8th Sep

Leakage from common Blow down vent valve / header

Thinning / Corrosion

Thickness monitoring not done

Remaining action from project not taken up

21.5

Process gas was cut to reformer & leakage rectified. Medium / long term actions in hand.

9th Sep Power Failure during heavy rains in early morning

Flash in isolator of GTG‐B which caused GTG‐A also to trip.

Low clearances between phases of VCB trolley

Heavy rains caused saturated atmosphere

59.5

Worked with Siemens on RCA. Flash were due to design issues. Hardware improvements implemented by Siemens. Site audited by Siemens and cleared.

10th Sep

Front end Startup activities and Excessive venting of seal gas from C‐103 HP drain

Higher seal clearances 69

Operating procedures improved. Modification of Degasification tank/ vent height with GE.

12th Sep

Methanator high bed temperature and Catacarb Conc. achievement

High CO2 slip from absorber during shock‐dosing of antifoam to overcome foaming issue.

16 40% solution replaced with fresh chemicals

13th &14th Sep

Methanator high bed temperature and Catacarb Conc. achievement

High CO2 slip from absorber during shock‐dosing of antifoam to overcome foaming issue.

16 See earlier actions on Catacarb system.

15th Sep

Back end startup commenced Delayed activation of convertor catalyst

Possible ingress of moisture/ oil mist 46.5 Plant operation / monitoring regime reviewed.

15th‐18th Sep

Plant Low load operation

Catacarb system normalization, C‐101 DGS replacement/ recycle cooler leak rectification.

9.16


Details of Major Events:

C‐104 Fire:

This incident has been thoroughly investigated by multiple teams and following reports are attached to

PLR:

1. Report by Dresser Rand

2. Report by joint investigation committee (PFL & Fatima)

Summary of incident with key recommendations are given below:

Background:

C‐104 was running with both the seal oil pumps in operation for about last four months as none of the

pumps were delivering the desired capacity individually. Whenever either of the pump used to fail,

machine was taken on partial venting to control the situation. On incident day, P122B (turbine driven)

stopped delivering required pressure causing decrease in seal oil flow to compressor seal oil system.

Efforts were made from field to start P122B by adjusting manual dump valve. Although the pump was

started after several attempts but sharp decrease in levels in seal oil bottles of LPC & HPC was observed.

Machine was partially unloaded, which was the practice until then, to control the situation but the level

continued to drop. This led to the tripping of machine.

Analysis:

The seal oil system is designed to be almost fool proof. Oil pressure is kept above the process gas system

by the height of the seal oil overhead tank, which is above the compressor and is supplied with

reference pressure, which is suction pressure. If a seal fails then oil goes into the compressor but gas

does not come out. The only way for gas to come out is if the oil in the overhead tank and the line from

the tank to the compressor is completely drained of oil or the seal gas reference line does not respond

quickly to changes in process pressure. As per DR, following possible chronology of events leading to the

incident:

The LPC overhead seal oil tank level control valve was opened manually to over 80% to raise the level.

The train was tripped due to low level, 18%, in the LPC overhead seal oil tanks. The seal capacity control valve actuator was in manual control. The seal oil pump pressure safety valves were passing. The HPC suction pressure suddenly rose from suction pressure of about 120 Kg/cm2 to the settle

out pressure of about 160 Kg/cm2. The seal oil pump pressure remained at about 120 Kg/cm2. The level in the HPC overhead seal oil tank fell to zero. The gas in the HP casing then escaped into the bearing housing which pressurized the lube oil drain

system. Oil then came out of the drain and bearing vents and dropped on the hot steam lines and the fire

started. The fire was made worse by the fact that the oil was probably contaminated by process gas. The seal oil pump was stopped but oil still came out of the vents as the HP compressor takes a long

time to depressurize. Conclusion:


As per DR, the cause of the fire was the fact that the seal oil pump pressure did not increase to the settle out pressure thus cutting off the flow from the pump to the HPC seals. The overhead seal oil tank then quickly ran down, as there was no oil from the pump. The reasons for the pump not making pressure are not clear‐cut. There are three possible causes or a combination of two or all of the three: ‐ 1. The seal capacity control valve actuator was in manual control. Had the control been in automatic

then it is possible that the pump capacity would have increased and the HP seals would have not been starved of oil.

2. The seal oil pump pressure safety valves were passing causing loss of capacity in the seal oil system. 3. The LPC overhead seal oil tank level control valve was opened manually to over 80%. Thus diverting

oil from the HP seals. DR reviewed the actions carried out by the instrument and mechanical maintenance teams and

confirmed that all their actions were correct and no further work was needed before C104 is restarted.

Recommendations:

Sr# DESCRIPTION/ OBERVATIONS ACTION Target DATE

1.

Third standby seal oil pump installed. Piping installed. Pump commissioning and testing being planned in available opportunity. New seal oil pumps to be ordered, adequately overdesigned to cater for increase in compressor seals clearance & piping. Recycle control valve to dump extra oil at lower clearance levels.

(Machinery) Feb.2013 DR reply awaited

2.

a) Improve reliability of other hardware including PSVs, Capacity Valves etc. Increase PM frequency till next ATA.

b) A flow glass should be fitted in the dump line to monitor the effectiveness of the pressure safety valve. MOC to be initiated.

c) Regular monitoring of dump valves should be carried out and logged. Any variation in the dump valve opening under same operating conditions will indicate PSV passing or pump performance deterioration which should be immediately rectified.

Machinery / Inst.

(Operations /Process)

(Operations)

Done TA‐2013 Immediate.

3.

System of Reliability enhancement being developed by nominating multidiscipline teams covering minimum of following aspects: Reliability incident Reporting, Operational Experience Enrichment Reporting, Abnormal operation management, Reliability Based Maintenance, Adopt Safety critical system at site.

DO

4. PHA of seal oil system should be conducted to evaluate all risks associated with present system and mitigation measures required to overcome these risks.

Process/Ops/Mach/E&I

15th Nov.

5. Develop, train and implement tag drills to block compressor through SOP’s. Procedure has been developed and discussed within team. Tag drills to be conducted.

(Operations). 15th Nov.2012


6.

a. A secondary level indication should be fitted to the overhead seal oil tanks.

b. LG is in service. PDTs installed, which should be corrected for secondary level indication.

c. LG and LTs readings should be logged / compared on two hourly basis and LT should be calibrated on immediate basis if any mismatch is observed between GLG and LT reading.

Process / Inst

Operation

10th Nov. 2012 Immediate

7.

a. The seal oil level controllers and dump valve, PCV309 should always remain in automatic control.

b. The use of the ‘auto‐tune’ facility in the DCS should be investigated to overcome the instability problems in the level control system.

c. In the event of machine trip the seal oil controllers should be switched automatically to “AUTO” or “CASCADE” mode.

Ops/proc./ inst.

Inst.

Ops/proc./ inst

30th Nov.

8. The seal oil level should be maintained at 82% with a control range from 70% to 94% as per the D‐R manual. Levels being maintained at ~70% to avoid any possibility of bottles overflow.

(Operations / E&I)

Done

9.

a. Study to improve trip oil security (2oo3 logic) by providing additional low level switches.

b. Bench‐mark seal oil system with FFC and Engro plants.

Ops /Process / Inst. Process

TA‐2013 15th Nov.

10.

The compressor train should be completely vented in the event of total seal oil pump failure, or if any of the seal oil overhead tank levels falls below 24%. (Quick depressurization shall be possible after installation of automatic SD valves, being studied with the Revamp option)

(Process /Operations)

30th Nov.

TBF

11. Alternately, Conversion of existing pneumatic MOVs to Motorized/Hydraulic SD valves to be studied. MOC to be raised.

(Operation / Process/E&I)

TA

12. Install fire detection and deluge system around the compressors. (Project) End 2013

13. A comprehensive procedure to be developed and implemented to cover abnormal situation management and handling guidelines.

Ops. Manager

30th Dec.

14. Review all critical procedures of plant in Sub SOC forum. Operation 30th Nov.


Catacarb foaming problem:

Catacarb foaming problem has been investigated in detail by Mr. Chao of Eickmeyer during one week

site visit to Fatima Site. Report of Mr. Chao is also attached with PLR for details Summary of problem

and key recommendations are given below:

On 31st Aug, Severe foaming was encountered in Catacarb system during the startup of the plant.

Foaming was noted on 1st Sep. 2012 by sudden overflow of CO2 absorber downstream KO drum and

decrease in Methanator Catalyst bed temperatures due to Catacarb carryover with gas. Severe foaming

restricted F.E load to ~40%. Matter was investigated in consultation with EICKMEYER & HTAS.

Mr. Chao of Eickmeyer advised that foaming was caused by Fe in the system and recommended

switching over to Silicon based antifoam (72‐S) from Glycol based antifoam (WBU). Furthermore, he

recommended maximizing filtration through mechanical filters and activated Carbon. Activated carbon

charge was replaced with new one and it was taken in service on 11th September. Furthermore, in‐house

modifications were carried out in mechanical filtration system to improve its effectiveness. Cleaning

frequency of mechanical filter considerably increased after these improvements i.e. filter started

choking in 15‐30 minutes intervals (initially 12‐14 hrs) with blackish fluffy deposits. Analysis of these

deposits indicated presence of Fe and degradation products (12% Fe, 56% LOI at 900C).

In view of high cleaning frequency of mechanical filter, an additional mechanical Filter was also installed

on 05th October to reduce downtime and maximize filtration of solution.

However, despite all these extensive efforts, there was minor improvement in solution foaming

tendency and Catacarb carry over was experienced twice on 31st august at ~ 60 % load.

Consequently, it was decided on 12th Sep. 2012 to replace about 40% Catacarb solution to improve

solution chemistry. Considerable improvement was observed in the system after this step and system

was stabilized at ~90% load with extensive anti‐foam addition regime.

In view of Catacarb solutions carry over to feed/ effluent exchanger, E‐121 and Methanator, HTAS

recommended cleaning of E‐121 with hot condensate and skimming of Methanator in available

opportunity. Based on HTAS advice, online cleaning of methanator feed/ effluent exchanger was carried

out. Performance of Methanator catalyst was found normal w.r.t DT and conversion. However there is

slight increase in its DP (increased from 0.1 to 0.23 kg/cm2). Its skimming being planned for TA‐2013.

Problem analysis:

Corrosion due to churning of Semi‐lean solution bed: Following extract from Eickmeyer report is

considered to be the root cause of the problem:

“During shutdown and initial startup, high iron and suspended solids have confirmed occurrence of local corrosion for a short period of time. Review of operating procedures and solution chemistry before shutdown does not show any abnormality. After discussion with operation, E&A deems local corrosion may be resulted from bed churning in semi‐lean regenerator during regeneration due to excessive liquid level. Solution levels usually rise after shutdown from drainage of holdups in the beds, especially for semi‐lean regenerator. According to operators, the solution was very dilute before startup, from above 27%wt. before shutdown to 21‐23%wt. during startup. Since no solution was returned to the storage, dilute solution means excessive liquid in the semi‐lean regenerator could very well submerged the reboiler vapor return nozzles. Because liquid is non‐compressible, pressure surges and oscillation from steam generation will cause water hammering on packed beds and packing. Through violent scratching and abrasion against carbon steel vessel walls and among carbon steel rings, passivation films can be breached and minor corrosion starts. Lab results clearly indicated high iron and


suspended solids. However, the analytical method for available inhibitor was interfered by dark solution color and did not detect any difference.”

In addition to above, following factors also contributed in deterioration of Catacarb chemistry:

1. Build‐up of Amine degradation products in the system as Activated Carbon was never taken in service since commissioning. Solution color index had gradually increased to ~22000 Hazen Units as against normal value of ~4000.

2. Design limitations of anti‐foam dosing and filtration system etc.

EICKMEYER Recommendations:

ITEM OBERVATIONS / RECOMMENDATIONS ACTION

BY

Target DATE

1. Put carbon filter into continuous service with an upstream mechanical filter of 5‐10 microns retention for suspended solids and a downstream filter of 1‐2 microns retention for carbon fines.

Maintenance Done

2. Replace activated carbons at least once every 6 months depending on performance of Activated Carbon.

Operations Being done

3.

Analyze catalyst total amines according to E&A’s titration method. Report total amines in normality (suggested range 0.4 N to 0.6 N.) Add 4550 liters or 22 drums of CATACARB 400 to raise total amines by 0.1 N, if needed.

Lab Done

4. Analyze available inhibitor according to E&A’s newly revised redox titration method.

Lab Done

5.

Watch total and available inhibitor vanadium levels

Keep total vanadium above 4000 ppmw

Maintain available vanadium around 70‐80% of total

Add air if available dips below 60%

Reduce air if available exceeds 90%

Operations Done

6.

Perform shake test on semi‐lean sample to get foam time a. Keep normal antifoam injection if foam time is below 5 seconds

(well de‐foamed) b. Increase antifoam injection if foam time falls within 5‐10 seconds

(moderately frothy) c. Inject extra antifoam if foam time is above 10 seconds and

consider replacement of activated carbons (very frothy)


7. Monitor iron and keep it below the suggested 100 ppm against possible corrosion.



a. Watch closely and take no action if total vanadium, available vanadium, and suspended solids are normal and steady (iron may rise slightly above 100 ppm from high capacity without corrosion)

b. Increase air injection if available vanadium drops c. Add inhibitor if total vanadium is below 4000 ppm

8.

Monitor suspended solids and keep it below the recommended 100 ppm against possible corrosion.

a. Take no action if total vanadium, available vanadium, and iron are normal and steady (no general corrosion.)

b. Increase mechanical filtration to remove solids. c. Adjust vanadium levels immediately if iron rises with corresponding

drops in total and/or available vanadium (active corrosion) d. Prepare 72‐S to combat possible iron oxides from active corrosion.


9.

Watch regenerator bottom level against damages from water hammering

a. Introduce heat to reboiler only after visual inspection of side glasses to ensure that liquid level is below vapor return lines and nozzles

b. Drain solution back to storage if liquid level gets too high c. Avoid circulation without reboiler in operation for an

extended period of time since pump seal water dilutes the solution and raises liquid levels.


10. Regenerate solution after shutdown by keeping reboiler in operation for 2‐4 hours so that bicarbonate conversion drops below 20%.


11. Passivate the system with solution before startup with air injection and hot circulation for 8‐16 hours before gas introduction.


12. Clean the open sump from time to time and provide a SS liner to avoid in‐leaks of contaminants as also recommended by Eickmeyer.

Maintenance/Operations

TA‐13

13. Adjust solution chemistry and operating parameters according to operating manual.


14.

Performance of Methanator catalyst was found normal w.r.t DT and

conversion. However there is slight increase in its DP (increased from

0.1 to 0.23 kg/cm2). Its skimming to be planned for TA‐2013.

Process TA‐13


Methanator Temperature Run‐away:

On 12th Sep during startup of Synthesis machine, suddenly high CO2 containing gas broke through to

methanator due to severe foaming issue. Methanator was immediately tripped (I‐6) by swift response of

Panel operator. However, temperature in the 1st level of catalyst bed reached out of scale (max value

recorded was 516 C). Reactor was immediately depressurized (within 1~ minutes) and cooled with

process gas after normalizing CO2 slip.

It was feared that temperature may have risen even higher than thermocouple maximum limit. However

detailed analysis and temperature profile of other temperatures ruled out this possibility. Same was

confirmed by HTAS in their analysis.

Since the vessel was brought to safe conditions (high temperature / low pressure) by quickly

depressurizing, it was thought that the stresses on the vessel may have remained within limits.

Complete data was sent to HTAS for their analysis and advice .HTAS recommended conducting Hardness

test mapping and micro structure inspection of the vessel by replica method in the next available

opportunity.

Hardness testing and replica test of vessel was carried out by third party and results were found

satisfactory. (Reference report attached)

Sr# DESCRIPTION/ OBERVATIONS ACTION

BY

Target DATE

1.

All safety incidents (including process safety incidents) should be classified according to HSE procedure (HSE‐QMS‐PRO‐SAF201) and detailed investigation report to be submitted according to the subject procedure. HSE to follow up for closure of recommendations and present as leading indicators in their Executive committee meetings.

DMs

HSE

Immediate

2.

SOP of methanator start up to be revised to ensure normalization of Catacarb before gas introduction into methanator i.e. CO/CO2 slip should be normal and stable / Catacarb system foaming is normal and stable etc.

Ops 15th

Nov.2012

3. Methanator trip on high level of upstream KO drum to be considered as per latest design practices

Ops/Process 30th Nov.

4.

Response of CO2 analyzer was very slow and unreliable since commissioning and therefore sharp rise in CO2 slip could not be picked up by panel operator. Subsequent to this incident, response of analyzer was improved and now working effectively.

Health of all critical analyzers and instruments should be ensured for reliable plant operation. A detailed survey to be carried out to identify all faulty instruments which are necessary for routine plant monitoring and same should be rectified on priority.

Info

Ops/Inst.

30th Nov.2012


Cold Box Expander (C‐103):

On 5th Sep when cool down of cold box was about to be started, expander was rolled but tripped due to

fire on its oil console. Fire was extinguished by applying Nitrogen blanketing and cutting the source of

ignition i.e. synthesis gas. Subsequent attempts to restart the expander revealed suspected problems in

its labyrinth seal.

During inspection of the expander its labyrinth seal and bearings were found damaged. Expander was

replaced with spare one available at site. However on restart, excessive seal gas flow through the seals

was encountered. To overcome this problem and avoid any further safety incident, an indigenous

modification was carried out and degasifying tank was installed to avoid Oil console over‐pressurization

and consequent fire due to higher seal gas venting.

During subsequent analysis of the problem, it was revealed that expander seals got damaged due to oil

freezing during Catacarb carryover incident. During this incident, methanator inlet valve, HV‐025 was

closed by panel operator which resulted in expander operating with its oil circuit while the gas side was

depressurized.

The matter was taken up with GE in detail and startup /shutdown procedure and expander logic has

been modified to improve the reliability and prevent recurrence of such incidents in future. The failed

expander seals and bearings were replaced under the supervision of GE VSM and is available as spare

presently.


1.

Start up, shut down and normal operating procedures of Expander,

C‐103 have been thoroughly revised in consultation with GE.

All operational staff to be trained for revised SOPs.

Info

Ops

30th

Nov.2012

2.

Trip logic of C‐103 has been modified and trip of C‐103 has been

incorporated on complete closure of HV‐025 to avoid expander

damage due to inadvertent closure of HV‐025.

info

Dry gas Seal Failure of C‐101:

On 31st august, NG booster compressor, C‐101 was rolled at 1130hrs which tripped on high seal gas flow

at 1240hrs. Seal gas filters replaced and compressor again put on roll at 1432hrs. C‐101 was remained

on and off due to various problems in plant startup.

On 11th September, when C‐101 rolled to MGS at 1445hrs, problem of high seal gas flow through the

seals recurred. After analyzing the data of high differential pressure across seal at PDIT‐400/401, it was

decided to check the health of seals and machine was handed over to machinery team.

On 14th September, inspection revealed the damage of seal on compressor NDE side which happened

due to moisture ingress with the seal gas caused due to leaking recycle cooler E‐101. The damaged seal

was replaced with new one under the supervision of Flowserve VSM. Special Operational procedure was

developed and implemented to start machine with leaking Recycle cooler.



1.

Detailed review of process parameters indicated that before seal

gas failure, flow to DGS had decreased to zero but same could not

be identified by the panel operator as it was already under low

alarm mode.

Set values of all process Alarms should be critically reviewed and

alarm values of all parameters which are running in alarm mode

during normal operation should be changed.

Operation /

Process 15th Nov.

2. DGS OEM, Flowserve has recommended installation of pre‐filter in

view of black sludge found in DGS filters. Same to be installed.

Machinery /

Process

15th

Nov.2012

3.

Detailed study to be carried out to identify potential impact of any

leak from exchanger during start up or normal plant operation.

Special procedures to be developed to cover impact of leak through

any exchanger.

Operation/

Process 30th Dec.

Miscellaneous General recommendations:

1. Mechanical governors of critical pumps at Ammonia plant should be replaced with hydraulic governor to improve reliability.

Machinery 2013

2. A comprehensive heat exchangers replacement plan to be developed and implemented based on history of KEMIRA plant.

Inspection / Equipment/process

30th Nov

3.

Performance of Pre‐reformer significantly decreased after plant outage. HTAS has analyzed the pre‐reformer data and advised that Pre‐reformer charge has completed its useful life and completely deactivated. Furthermore, HTAS recommended to take Pre‐reformer in service only after availability of recycle H2 gas. To be covered in revised Operating instructions.

Operations immediate

4.

During inspection of F‐101, convection section eastside wall refractory was found damaged. It is suspected that high flow / velocity of combustion gases flow through convection section caused by modified 3rd duct resulted in refractory damage. Damper of this modified duct should be kept closed to avoid recurrence.


5. On 2nd September, HP steam letdown valve PV‐032 stucking problem caused the complete shut‐down of ammonia plant

Process 2013


including steam network. Installation of additional let‐down valve parallel to PV‐032 to be studied to avoid complete outage of plant due to single valve.

6.

Numbers of failures have been observed on probes of C‐105 / CT‐105. Moisture in C‐105 lube oil was initially high (~2%) and it was considered to be root cause of probes failure. However, moisture has reduced to ~400 ppm but probe failure frequency is still high. Root cause of probes failure to be established in consultation with Bentley Navada / GE and reliable probes should be installed.

Instrument

TA‐2013

7. DR has suggested some changes in Start up procedure of C‐105 and same should be followed in future. Operating procedure to be revised as per DR start up procedure.

Operations DONE

8.

In TA‐2012, skimming of HTS converter was planned to do which could not be carried out due to limitations in vessel entry and hence HSE concern. Gas inlet piping should be modified with removable inlet distributor,(like Desulphurisers inlet piping) for safe vessel entry and catalyst loading activity..

Process TA‐2013

9.

Seal gas backup system of C‐103 has not been commissioned since plant commissioning. A sudden change in plant front end pressure also affect the seal gas flow and possible entrance of seal oil into the expander casing. Back up seal gas system of C‐103 should be considered on priority.

Instrument / Operation

TA‐2013

Major Jobs carried out during Mini TA‐2012 and Plant startup:

Main HP steam Generator (E‐110) Leakage rectification & tube plugging. 03 leaking tubes were plugged. The performance of exchanger is satisfactory and no leak was observed after plant startup. Phosphate concentration in process gas at E‐110 outlet has reduced from ~60 ppb to <10 ppb after leak repair. However, slight increasing trend in Phosphate concentration is being observed (latest analysis 19 ppb on 31st Oct.) which is under close monitoring.

Inspection of Primary Reformer (F‐101) refractory and repair was carried out.

Two tubes of Synthesis Coolers (E‐136B) were found leaking and same were plugged.

Chemical cleaning of E‐136 was performed by CR‐Asia and a heavy layer of scale removed during this activity.

E‐101 tube side flow passes was reduced from 08 to 04 due to plugging of tubes and limitation for flow pattern.

Leakage rectification of Cold Box Expander (C‐103) & JT‐valve (HV‐054) Boxes was carried out.

Inspection of air compressor 1st stage KO Drum (D‐141) & Synthesis Driers (D‐112 A/B) was carried out.

Activated Carbon Drum (D‐132) Inspection, Cleaning and loading of fresh activated carbon charge cwas carried out.

Rectification of HP steam let Down Valve (PV‐032) stucking problem.

PV‐010 damper blades trimming for smooth manual operation & repair of damaged refractory .

Cleaning of 21 exchangers by Hydro‐jetting / brushing were done.

Complete Overhauling of C‐104 LP casing was carried out.

Bearing inspection and Seals replacement of MP and HP casings of C‐104 was done.


Bearing Inspection, Governor Actuator overhauling of CT‐104.

Combustion inspection of CGT‐102 was carried out.

Gas Turbine GTG‐A & B Combustion inspection, liner replacement, cross fire tube and retainer replacement.

C‐101 dry gas seal were replaced on 14th September.

C‐103 Cold Box Expander replaced with refurbished spare expander.

P‐122 A, B, seal oil pump overhauling and replacement, PT‐122 overhauling.


Power Failure:

On 9th Sep, 01 at ~0330 hrs, Power Failure was encountered during heavy rains.

Phase to Phase flash was observed on the breaker trolley arms, but timely tripping by protection and AVR system prevented the major damage to machine. Immediate Route Cause of short circuit established was high humidity.

Issue was taken up with SIEMENS and after investigation SIEMENS accepted that Pole to Pole distance of the circuit breakers (between live parts) is lower than standard value for site environmental conditions, which is the root cause of the short circuit.

Actual Pole to Pole distance measured by SIEMENS team was 91 mm which is on the minimum side of IEC recommendation which requires clearance of 90‐115mm.

Root Cause Analysis report is awaited from SIEMENS, however SIEMENS have recommended to add the separator sheets (Masonite Sheets) between the VCB poles to improve the insulation.

RCA: Flash in isolator of GTG‐B which caused GTG‐A also to trip.

Low clearances between phases of VCB trolley

Heavy rains caused saturated atmosphere

ITEM OBERVATIONS/RECOMMENDATIONS ACTION

BY Target DATE

1.

Reliability Task force should be developed to identify potential

reliability risks contributing to tripping of GTGS or downstream

power system leading to total power failure

Op. Mngr 10th Nov.

2.

A detailed replay coordination study has been conducted by

Siemens to improve design deficiencies of Fatima power

system. Recommendations implantation Status to be shared.

E&I 30TH Nov.

3.

Detail RCA report to be obtained from Siemens, Germany and

all recommendations should be implemented to avoid

recurrence of these problems.

Based on preliminary report of Siemens, additional insulation

has been provided in the panels

E&I

info

March

2013

4.

Number of attempts to start GTG‐A remained unsuccessful. it

was started on the sixth attempt (~ 12 hours after Power

Failure) due to following main problems:

a. Oil leakage occurred twice from the Turbocharger of starting

diesel engine. Finally Turbocharger of GTG‐B was installed

b. Loss of flame occurred twice

c. Fault encountered with the SRV (Speed Ratio Control Valve)

Operation/E&I

TA‐2013


Start‐up of GTGs on first attempt has always remained

problematic. Reliability of both gas turbines to be improved by

resolving all known issues which have caused start up delays so

that GTGs should always start on first attempt.

5.

During unavailability of GTG‐B due to flash in isolator panel,

GTG‐A could not be restarted due to problem in its diesel

engine’s turbo charger. Spare turbo charger was not available

and consequently, turbo charger of GTG‐B had to be installed

on GTG‐A for start‐up.

Critical spares should always be maintained in inventory as per

OEM recommendations.

Machinery/

Motor pool

6.

EDG was started manually as K‐39 breaker did not open on auto

mode from the field. Subsequently, K‐39 logic was tested in

detail and some bugs in logic were removed and logic was

tested on DCS and found ok.

EDG synchronized load test run with main bus bar to be

conducted on weekly basis to ensure reliability of whole

system and its proposer functioning in case of emergency

requirement.

EDG operated normal for four hours before tripping on ‘Crank

Case High Pressure’ causing total black out and steam failure

due to the tripping of polish water supply pump to deaerator.

Inspection of Crank case vent was carried out and it was found

blocked due to water ingress during rains. Subsequently, vent

was modified to avoid recurrence.

EDG compartment to be sealed for all sort of water leakages

Info

Operation / E&I

Maintenance

30th Nov.

7.

Due to unavailability of EDG, following major problems were

encountered:

a. DCS HIS power supply was cut to conserve UPS batteries.

b. Instrument air failure

c. Polish water pump failure and consequent steam system

failure.

d. CCR‐I & CCR‐II AC’s went offline and doors had to be

opened for cross ventilation. Consequently, humidity of

control room increased considerably which could have

potentially damaged sensitive DCS cards/ modules.

A complete Reliability study of EDG to be carried out to ensure

its availability in case of emergency.

Electrical/

Instrument

30th Dec.


Power failure scenario during EDG unavailability should be

thoroughly studied.

8.

Fire water diesel engine pump started on auto after power

failure however it tripped due to high coolant temperature and

remained unavailable for ~1 hr during power failure which is

great safety concern. As per design, there are two provisions for

its coolant supply i.e. Clarified Water supply and FW from its

own for stand‐alone operation.

The Clarified water supply went offline on power failure and

flow of FW from its own discharge was not aligned.

Fire water diesel engine pump should always remain in stand

alone mode to ensure its availability during power failure. SOPs

to be revised accordingly.

OU Operations

immediate

9.

All holes/ openings in breakers, marshaling and control cabinets

should be completely sealed and special arrangements (i.e.

fumigation/mice killing tablets etc) to be made for killing of

reptiles.

Electrical/

Instrument 30th Nov.

10.

GTG start‐up was delayed due to unavailability of power for its

auxiliaries after EDG unavailability for ~4 hours.

GTGs black start provision to be considered.

Electrical/

Instrument March‐13

11.

HRSG‐A burner C signal amplifier (installed in BMS cabinet in

CCR‐1) was blown due to short circuiting. Cable from burner to

field JB was found short circuited.

All electrical circuits to be sealed for water/ moisture ingress.

Necessary coatings to be used with the help of OEM

recommendation to protect them in case of heavy rains.

Instrument/

Electrical 30th Nov.


Extraordinary Rains: On 9th Sep. 2012, an intensive rainfall of ~300 mm in 24 hrs was recorded which was record figure for last 100 years of this area. The storm / rain water drainage system of Fatima Site is designed for max. rainfall of 40mm/day and recent rains proved that the basis for our site design needs thorough review in view of changing environmental conditions and there are some additional internal and external factors which need to be considered in this study e.g. canal breach, Topology of site and surroundings etc. Site infrastructure needs to be upgraded accordingly. Power failure during rains made the situation worst and connectivity between township and plant site was heavily affected due to accumulation of ~xx feet water on roads.

ITEM OBERVATIONS/RECOMMENDATIONS ACTION

BY

Target

DATE

1. Hardware of Rain water handling system to be completed as per K‐plant design.

PHT/Civil June‐2013

2. ROW and approval of rain water disposal to canal should be sorted out on priority.

RM Jan.13

3. A low budget pond to be constructed near EP‐4 for emergency disposal of rain water.

Civil June‐13

4.

Additional study to be carried out thru consultant to handle extra ordinary rains, possible effect of canal breech and mitigation measures and township rain water disposal system. APL drainage system should also be covered in the study to ensure continuous supply of Raw water in case of heavy rains.

MM March‐2013

5.

Motors were found dipped in rain water (OU backwash pit pump

motors).

Permanent draining arrangement by installing a submersible

pump to be studied.

Individual plant

operations/

Maintenance

30th Dec.

6.

Rain water accumulated in CCR‐1 cable cellar.

Permanent draining arrangement by installing a submersible

pump to be adopted.

Instrument/

Maintenance 30th Dec.


7.

Rain water seeped through CCR‐1 control room roof and it was

found dripping near Urea DCS board printers. Dripping was also

found on CCR‐1 first floor in front of room no.4.

Expansion joints to be completely filled with appropriate

sealants to completely seal the roof.

Civil 30th Dec.

8. Alternator of STG got damaged during the heavy rains. Shed on

STG to be constructed on priority. Maintenance 30th Dec.

9.

Diesel generator at APL was exposed to heavy rains and serviced

with great difficulties with the help of OEM. Proper shed to be

constructed on priority.

Maintenance March

2013

10.

Permanent de‐watering pumps to be considered at suitable

locations of each plant and periodic maintenance of these

pumps to be ensured by area owners.

Operation June‐13

11. Adequate no. of De‐watering pumps should be available in

Workshop tool room to handle the emergency situations. MM June‐13

12.

A special taskforce to be formulated to review the problems

faced during recent rains and avoid recurrence in next monsoon

season.

Op.Manager 30th Dec

13.

Based, on recommendations of task force, Special Emergency

handling procedure to be developed for rain handling and a

team to be nominated with clearly defined roles &

responsibilities in case of rain.

Op.Manager 30th Dec

Township

14.

Rain water was accumulated towards D‐type, E‐type, specially G‐

type housing & shopping area. Drain trenches are not available

due to which mosque shopping area was flooded.

A complete study to be carried out to provide adequate rain

water handling system in the colony.

Resident Manager March‐

2013

15.

Transformers placed in township were dipped in rain water and

power supply was then stopped in G‐type residence.

RM March‐

2013


Transformers base height to be increased keeping in view the

worst rain scenario in order to avoid water contact

Miscellaneous General recommendations:

10. Mechanical governors of critical pumps at Ammonia plant should be replaced with hydraulic governor to improve reliability.

Machinery 2013

11. A comprehensive heat exchangers replacement plan to be developed and implemented based on history of KEMIRA plant.

Inspection / Equipment

30th Nov.

12.

Performance of Pre‐reformer significantly decreased after plant outage. HTAS has analyzed the pre‐reformer data and advised that Pre‐reformer charge has completed its useful life and completely deactivated. Furthermore, HTAS recommended to take Pre‐reformer in service only after availability of recycle H2 gas. To be covered in revised Operating instructions.


13.

During inspection of F‐101, convection section eastside wall refractory was found damaged. It is suspected that high flow / velocity of combustion gases flow through convection section caused by modified 3rd duct resulted in refractory damage. Damper of this modified duct should be kept closed to avoid recurrence.


14.

On 2nd September, HP steam letdown valve PV‐032 stucking problem caused the complete down of ammonia plant including steam network. Installation of additional let‐down valve parallel to PV‐032 to be studied to avoid complete outage of plant due to single valve.

Operation /Process

30th Dec.

15.

Numbers of failures have been observed on probes of C‐105 / CT‐105. Moisture in C‐105 lube oil was initially high (~2%) and it was considered to be root cause of probes failure. However, moisture has reduced to ~400 ppm but probe failure frequency is still high. Root cause of probes failure to be established in consultation with Bentley Navada / GE and reliable probes should be installed.

Instrument

March‐2013

16. DR has suggested some changes in Start up procedure of C‐105 and same should be followed in future. Operating procedure to be revised as per DR start up procedure.

Operations 30th Nov.

17.

In TA‐2012, skimming of HTS converter was planned to do which could not be carried out due to limitations in vessel entry and hence HSE concern. Gas inlet piping should be modified with removable inlet distributor,(like Desulphurisers inlet piping) for safe vessel entry and catalyst loading activity..

Process TA‐2013


18.

Seal gas backup system of C‐103 has not been commissioned since plant commissioning. A sudden change in plant front end pressure also affect the seal gas flow and possible entrance of seal oil into the expander casing. Back up seal gas system of C‐103 should be considered on priority.

Instrument / Operation

TA‐2013.

Major Jobs carried out during Mini TA‐2012 and Plant startup:

Main HP steam Generator (E‐110) Leakage rectification & tube plugging. 03 leaking tubes were plugged. The performance of exchanger is satisfactory and no leak was observed after plant startup. Phosphate concentration in process gas at E‐110 outlet has reduced from ~60 ppb to <10 ppb after leak repair. However, slight increasing trend in Phosphate concentration is being observed (latest analysis 19 ppb on 31st Oct.) which is under close monitoring.

Inspection of Primary Reformer (F‐101) refractory and repair was carried out.

Two tubes of Synthesis Coolers (E‐136B) were found leaking and same were plugged.

Chemical cleaning of E‐136 was performed by CR‐Asia and a heavy layer of scale removed during this activity.

E‐101 tube side flow passes was reduced from 08 to 04 due to plugging of tubes and limitation for flow pattern.

Leakage rectification of Cold Box Expander (C‐103) & JT‐valve (HV‐054) Boxes was carried out.

Inspection of air compressor 1st stage KO Drum (D‐141) & Synthesis Driers (D‐112 A/B) was carried out.

Activated Carbon Drum (D‐132) Inspection, Cleaning and loading of fresh activated carbon charge was carried out.

Rectification of HP steam let Down Valve (PV‐032) stucking problem.

PV‐010 damper blades trimming for smooth manual operation & repair of damaged refractory .

Cleaning of 21 exchangers by Hydro‐jetting / brushing were done.

Complete Overhauling of C‐104 LP casing was carried out.

Bearing inspection and Seals replacement of MP and HP casings of C‐104 was done.

Bearing Inspection, Governor Actuator overhauling of CT‐104.

Combustion inspection of CGT‐102 was carried out.

Gas Turbine GTG‐A & B Combustion inspection, liner replacement, cross fire tube and retainer replacement.

C‐101 dry gas seal was replaced.

C‐103 Cold Box Expander replaced with refurbished spare expander.

P‐122 A, B, seal oil pump overhauling and replacement, PT‐122 overhauling.

HRSG Top

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5. Again test was repeated and EDG auto startup verified, but at this time EDG tripped and

“differential voltage alarm”, appeared which was then thoroughly checked by electrical team by

meggering of generator etc.

6. It was also found that the EDG NGR is opened and is not closing so was checked and get closed.

7. After above checks and PM activities dummy test again repeated and all the steps found normal and EDG auto mode startup on blackout conditions verified twice and found successful.

K39 close permissive:

Initially when EDG is in stopped mode and other generators are on load the K‐39 close

permissive is enabled on DCS.

When EDG is running and all other generators (GTG‐A/B and STG) are stopped / tripped,

then k‐39 close permissive on DCS will be disabled by DCS Operator.

It will be enabled after putting some load on main bus bars after starting any of the

other generators.

Root Caused Analysis:

Earlier K39 opening command was being written from two different sources;

o Manual command from DCS for K39 opening

o Auto command for from DCS for K39 opening

Manual command was always giving Zero value to DCS and EDG failed to start even after

generation of auto command from DCS.

Now K39 opening command will be generated on either of the following commands;

o On auto command from DCS on GTG A&B and STG tripping.

o Manual command from DCS display screen face plate by DCS Operator.


Urea Plant: Key highlights: On 21st August 2012, Urea plant was running at 60% load. At 2229hrs, Plant put on hold at 11:31:48.562hrs due to fire on C/CT‐104 at ammonia. P‐102A and P‐301A stopped from AC panel at 11:31:47.558hrs and 11:43:09.310hrs respectively. K‐102 taken on venting at 11:32:01:168hrs but stopped from AC panel at 1208hrs as suction pressure was continuously decreasing. NP CO2 compressor was also stopped due to same reason.PCT section also stopped at 1225 hrs. All shutdown actions were taken according to procedures. SEQUENCE OF EVENTS: Chronology of tripping sequence:

TAG SECURITY DESCRIPTION TIME

2HS1204‐2P102A‐ESD SW (AC)

HP ammonia pump P‐102 was stopped from AC by pushing ESD Hand switch.

11:31:47.558hrs

P‐102 stopped 11:31:48.258hrs

2XY1031 alarm Ammonia feed at ammonia pump P‐102 suction stopped through closing of 2‐XV‐1031

11:31:48.562hrs

2XY1061 alarm Ammonia feed to scrubber stopped through closing of 2‐XV‐1061

11:31:48.562hrs

2HS1025B‐2XV1043

CO2 compressor final discharge isolation valve to stripper was closed from AC by pushing Hand switch

11:32:00:935hrs

2XY‐1043B CO2 to E‐201 slowly closed. 11:32:01:168hrs

2HS3204‐2P301A‐ESD SW (AC)

HP carbamate pump P‐301 was stopped from AC by pushing ESD Hand switch.

11:43:09.310hrs

2HS‐1103 K‐102ESD SW 2K‐102 CO2 compressor was shut down from AC 12:08:47hrs

2XS‐11011‐2K‐101 STOP 2‐K101 process air blower stopped. 12:08:47hrs

Chronology of startup sequence :16th September

2‐FI‐1099 Carbamate feed introduced 15:10:21hrs

2‐SI‐1006 Compressor turbine was rolled. 16:03:48hrs

2‐FI‐1038 Ammonia feed introduced 19:05:02hrs

2‐FI‐1024 CO2 feed introduced to stripper 19:10:06hrs

Prilling resumed at 23:20hrs.

Prilling diverted 2350hrs

Prilling started again continuously 01:10hrs

DETAILS OF ACTIVITES CONDUCTED AT UREA PLANT DURING MINI TA: Mini TA was announced on 21st August 2012 so following activities carried out at urea plant.


1. Operational activities

a) Reactor, stripper and scrubber completely were drained, depressurized and flushed.

b) Steam circuit was depressurized and drained.

c) LP/PCT and vacuum sections were drained, flushed and purged.

d) Ammonia circuit was depressurized and purged.

2. Maintenance Activities

a) Calibration of PSVs R202 A/B, PSV‐AM 4002/4009, PSV‐SC‐4097, PSV‐C‐801 and PSV‐C‐803

done.

b) Back washing of exchangers done i.e. E‐702, E‐703, E‐704, E‐801, E‐901, E‐151, E‐152, E‐

153, E‐154, E‐206 and E‐314A/B.

c) Suction strainers of all pumps cleaned especially P‐102A/B.

d) Ammonia suction filters SP‐253A/B cleaned.

e) Internal Inspection of steam drums V‐905 and V‐909 done. Only internal repair in V‐909

done.

f) Internal inspection of 2nd stage separator S‐402 done, its repair work of previous TA found

Ok, also vessel was cleaned from inside.

g) Internal visual inspection of S‐101 and S‐151 was done and declared Ok.

h) Steam leakages at various points rectifies as per list.

i) PV‐1203 d/s I/V replaced as its d/s flange had cut.

j) R‐202 sample point safurex valve replaced as it had passing.

k) Almost all jobs related to maintenance in job list completed.

3. Instrument Activities

a) LV‐1201 dismantled and sent to workshop due to passing problems but passing increased.

b) LT‐1024A/BC at compressor third stage separator S‐153 and LT‐1013A at compressor first

stage separator were calibrated by applying MOS during plant running.

c) FT‐1099 installed at Carbamate pump P‐301A/B discharge

d) PM of all instruments done.

4. Machinery :

a. K‐101 blower replaced with new one due to oil leakage.

b. P‐301A/B, P‐364A/B, P‐361 and P‐362 couplings inspection job done.

c. Lube oil of various pumps replaced.

5. Electrical :

a) Meggering of all urea plant motors carried out before start up.


6. Other Activities

a. V‐102 (ammonia receiving vessel) top fire water nozzles de‐blocked.

b. Prilling tower walls and floor washing done in first shutdown.

c. Back washing of lube oil coolers of compressor, ammonia pumps and Carbamate pumps done.

d. Scraper B‐604 gear box replaced by machinery.

e. K‐101 blower replaced by machinery.

f. P‐303A/B discharge valves replaced due to passing problems.

PLANT STARTUP SEQUENCE CO2 machine rolled at 1600hrs, carbamate feed given to scrubber at 1500hrs, NH3 feed given to scrubber at 1900hrs, while CO2 feed to stripper at 1910 hrs. Prilling resumed at 2320 hrs. Prilling Feed remained divert most of the time between 2350 to 0110hrs times due to PH&S belts tripping. OBSERVATIONS RECORDED DURING STARTUP

Scrubber was continued to fill with water through HP flush water pump P‐902 into scrubber for almost 4hrs resulting in extra accumulation of water in reactor through overflow of scrubber and water was filled in reactor for long time above calculated quantity. It resulted in high level of reactors approximately 89% during start up. In cold start up, calculated quantity of water should be added for reactor and scrubber filling. (Urea Operation)

In previous shutdown Urea Solution in reactor remained for almost 120hrs. Whereas maximum allowable residence time for solution in reactor is close to 72hrs .This need to be confirmed from the vendor or maximum allowable limit of 72 hours should be followed. (Urea Operation)

Turbine condensate pump P‐151A tripped twice due to some unknown cause and could not be started for few minutes even on putting it on manual mode.

Heavy leakages observed from ammonia filters top flanges one by one. Both were rectified before startup.


NITRIC ACID PLANT

DATE 21‐08‐2012

TIME 1418 Hours

INCIDENT Low Ammonia Inventory

DOWNTIME DETAILS

COMPLETE 624.2hrs

PRODUCTION LOSS 31,210 MeT

REASON FOR SHUTDOWN

Low Ammonia Inventory

BASIC CAUSE Tripping of C‐104 at Ammonia Plant.

INCIDENT DETAILS:

On 21st August at 1127 hrs Ammonia Plant tripped on low seal oil level security and resulted in tripping

of C‐104. NA Plant was planned to stop on 21st August at 1418 hrs due to low ammonia inventory.

Complex outage for 10 days was announced after evaluating the situation. TA continued till 16th

September.

Following major jobs were performed during TA.

Cleaning of exchangers.

Replacement of Pt/Rh/Pd Catalyst.

Inspection and Lamont Boiler shell and Baskets

Plant startup activities resumed as per following sequence

Compressor train rolled at 0630 hrs on 16th September,2012

Plant ready for ignition at 0930hrs but delayed for 5 hrs due to problem in Ammonia transfer

pumps

Ignition carried out at 1425 hrs on 16th September,2012


NP PLANT

DATE 23‐08‐2012

TIME 0125 Hours


DOWNTIME DETAILS

COMPLETE 582 hrs

PRODUCTION LOSS 23,280 MeT

REASON FOR SHUTDOWN



DOWNTIME BREAKUP:

DEPARTMENT Upstream Plant Startup NP Operation

DOWN TIME (hrs) 553 hrs 5 hrs 24 hrs

PRODUCTION LOSS (MT)

22,120 MeT 200 960

REASON Low ammonia Inventory

Startup Activities Off spec Slurry (RDVFs didn’t take load)

INCIDENT DETAILS : Plant back‐end tripped at 11:27hrs on 21st Aug, 2012 due to C‐104 (Synthesis compressor) tripping on low seal oil level security on seal oil Pump tripping. On machine tripping, gas broke through compressor seals which caused splashing of oil through the oil return header and console. Splash of oil on hot surfaces caused the fire which was effectively controlled. Ammonia & Urea were shut‐down; however CAN & NP remained in operation till 23rd Aug, 2012. After evaluating the situation it was decided to take about 10 days outage of the complex to attend various other pressing jobs at all plants. TA of the plant which was to begin from 24th Sep, 2012 has been rescheduled to March, 2013. Following is the sequence of Shut Down activities of NP Plant:

1. Dissolving stopped on 21st Aug, 2012 at 0930 hrs.


2. Drum Filters both trains taken out of service on 21st Aug, 2012 at 1343 hrs. 3. Feed stopped to Neutralizer train A on 22nd Aug, 2012 at 2145 hrs. 4. Feed stopped to Neutralizer train B on 23rd Aug, 2012 at 0137 hrs. 5. Feed cut to Evaporator 6‐40‐2106 on 23rd Aug, 2012 and to Evaporator 6‐40‐2126 on 23rd Aug,

2012 at 0302 hrs. 6. Finally Prilling was stopped on 23rd Aug, 2012 at 0303 hrs

Shut Down Jobs at NP Plant Followings are the major shut down jobs which were performed at NP Plant during Mini Turn Around, 1. Routine Operational Activities

Cleaning/flushing of Digestors seal pots and vent headers

RT filter grids dismantling for cleaning of trays and grids

Dismantling of cloth wash box , cloth wash tank 6‐40‐2039 and piping for cleaning

Following tanks manhole were dismantled for internal cleaning. 1. 6‐40‐2091

2. 6‐40‐2092

3. 6‐40‐2094

4. 6‐17‐2004

5. 617‐2006

6. 6‐17‐2025

Dismantling of overflow and Vent Headers of Both Neutralizer trains for cleaning and inspection

Acid Washing of NP Evaporators 6‐40‐2106/26, Falling Film Evaporators, 6‐17‐2105/06 and AC Tower, 6‐17‐2201

Replacement of AC tower damaged packing with new PP Rosset rings and SS Paul rings 2. Instrument Jobs (Control Valves Inspection & Cleaning)

Following Control Valves were dismantled, cleaned and inspected during Shut Down:

1. 6‐FV‐0059

2. 6‐LV‐0053

3. 6‐LV‐0055

4. 6‐FV‐0100

5. 6‐FV‐0030

6. 6‐LV‐0033

7. 6‐FV‐0015

8. 6‐FV‐0016

9. 6‐FV‐0019

10. 6‐FV‐0020

11. 6‐FV‐0055

Calibration of both Rock weigh belt feeders was done.

3. Modifications Followings are the modification jobs performed during Shut Down

Tie‐in of filtrate line from tank 6‐40‐2089 to 6‐40‐2020

Tie‐in of Demin Water line for cloth washing spray nozzles of RT Filter


Tie‐in of new Crystal suspension pump 6‐40‐1105 A

WA Transfer line from the discharge pumps of 6‐40‐2018 tank to 6‐40‐2020 tank.

DM water connection is provided for Vacuum pumps 6‐40‐1112/88/92

Clarified water connection is provided for 6‐40‐2069/70 Tanks.

Bleed of acidic scrubber 6‐40‐2213 is connected to basic scrubber 6‐40‐2212

Vessel entry of CN reactor and spargers cutting job

4. Equipment Maintenance Jobs

Replacement of AC tower damaged packing with new PP Rosset rings and SS Paul rings

Shaft bush replacement and casing patch welding to mend leakages of following screw

conveyors

a) 6‐40‐1259

b) 6‐40‐1260

c) 6‐40‐1261

Vessel entry of CN Melt tank 6‐40‐2022

Ammonia spargers for Neutralizer train B were made free to rotate.

Diaphragms replacement of PF plate packs # 4,5,18 & 20

Collection tray welding job and connect its drain line to 6‐17‐2025

Repair work of its outlet chute for trouble free cake discharge

Pf hydro cyclone 6‐17‐2311 body leakage repair

Enlisted Heat Exchangers were cleaned and inspected,

6‐40‐2101A/B

6‐40‐2119

6‐40‐2122

6‐40‐2124A/B

6‐17‐2102A/B

6‐17‐2103A/B

6‐17‐2124A/B

5. Machinery Maintenance Jobs

Shaft bush replacement and casing patch welding to mend leakages of 6‐40‐1259/60/61

Complete filter cloth and underlying nylon cloth of RDVFs were replaced.

Inspection of control head of 6‐40‐2305 to check drum, drum main drive shaft and valve

bridge plate.

Agitator drive gearbox and shaft 6‐40‐2305 were removed from the drum filter and shifted

to workshop for repair work

Control head of 6‐40‐2311 was removed for inspection. O ring in the control head was also

found damaged. Damaged control head bush, and O‐ring were replaced.

All preventive maintenance checks were done on 6‐40‐2311, Bearings were packed with

fresh grease. M02 gearbox oil was replaced.

All preventive maintenance checks were done on 6‐40‐2326. Teflon pieces fitted in it to

control air blow port size and washing port size had been removed. Brass bush in the control

head was damaged. Shaft sleeve under the control head was also damaged. Complete shaft


sleeve was removed from the shaft by cutting it. A new sleeve was machined locally and was

installed on the shaft. Damaged control head PTFE valve bridge plate, O‐ring and PTFE plate

were replaced.

Driving and Non‐Driving end bearings of 6‐40‐1256 were slightly damaged. DE shaft was

shifted to workshop and repaired by buildup and machining

DE side bearing 6‐40‐1257 was found damaged. Cage of bearings was broken. Bearing areas

of both the shafts were damaged. These shafts were repaired by welding and machining in

the workshop.

Preventive maintenance of both Prilling bucket assemblies

Replacement of 6‐40‐1210 Belt Conveyor

Inspection of supporting/tensioning rods

Gland packing of all neutralizer agitators was leaking. All the gland packings were replaced.

Gland pusher of 6‐40‐1376 was damaged. A new gland pusher was machined locally in the

workshop and was installed on the agitator.

Pressure Filter guide roller inspection and greasing

Maintenance of tensioning roller motor of PF

Screen patch work to mend holes of PF

Cleaning 6‐17‐1201 and replacement of its faulty rollers

6. NP Plant Start‐Up Sequence

Following is the sequence of Shut Down activities of NP Plant: 1. Dissolving started on 17th Sep, 2012 at 2321 hrs. 2. Drum Filter train A taken in service on 18th Sep, 2012 at 1204 hrs. 3. Drum Filter train A taken in service on 17th Sep, 2012 at 1700 hrs. 4. Feed was given to Neutralizer train A on 18th Sep, 2012 at 0236 hrs. 5. Feed was given to Neutralizer train B on 18th Sep, 2012 at 0812 hrs. 6. Feed cut to Evaporator 6‐40‐2106 on 18th Sep, 2012 at 0942 hrs and to Evaporator 6‐40‐2126 on

17th Sep, 2012 at 0345 hrs. 7. Finally Prilling was started on 18th Sep, 2012 at 0303 hrs

7. INCIDENTS DURING SHUT DOWN

1. AC Tower Packing Damage during Acid Washing Activity

On 22nd August at 1230hrs acid washing activity was started. At 1300hrs AC tower bed

temperatures started to increase and reached to103 OC at 1320 hrs. Yellow fumes were

witnessed from the AC Tower top which was due to burning of Polypropylene Packing Rings.

Temperature of AC tower normalized at 1630hrs.

2. Roof Bulging of 6‐40‐2056

In night shift of 25 Aug, 2012 at 2352 hrs. On/off valve XV‐0083 at the drain line of Crystallizer 6‐

40‐2228 malfunctioned and solution drained to Crystal suspension tank 6‐40‐2056. Crystal

suspension tank 6‐40‐2056 was already filled up to 65% and the drained solution from the

Crystallizer 6‐4‐2228 didn’t over flow due to partial chocking of line. Overfilling pressurized the

tank 6‐40‐2056 and resulted in its roof bulging and agitator seal damage.

IFR Reports for above two incidents have been issued separately.


CAN PLANT

DATE 23‐08‐2012

TIME 0125 Hours


DOWNTIME DETAILS

COMPLETE 617:50 hrs

PRODUCTION LOSS 34261.8 MeT

REASON FOR SHUTDOWN



DOWNTIME BREAKUP:

INCIDENT DETAILS:

On 21st August at 1127 hrs Ammonia Plant tripped on low seal oil level security and resulted in tripping

of C‐104. CAN Plant was planned to stop on 23rd August at 0125 hrs due to low ammonia inventory.

Complex outage for 10 days was announced after evaluating the situation. TA continued till 17th

September.

Following major jobs were performed during TA.

Cleaning of exchangers.

Dryer gear box replacement and alignment.

Hot Product Elevator chain reinforcement.

Scrubber demister pad washing.

DEPARTMENT Upstream Plant CAN Instrument CAN Maintenance

DOWN TIME (hrs.) 614:35 00:20 03:00

PRODUCTION LOSS (MT) 34059 36.57 166.23

REASON Low Ammonia Inventory

P‐3403 safety pull cord switch issue

P‐3403 & P‐3404 misalignment


Roller replacement of MTM.

Installation of Lime weigh feeder.

Recycle product belt replacement.

Plant startup activities resumed as per following sequence

1. At 06:30hrs by loop filling of CAN plant granulation circuit.

2. AN plant was started at 0830hrs and it got trip twice; 1st at low nitric acid flow, 2nd on flash

vessel (D‐107) high pressure.

3. AN Plant was started at 0855hrs by keeping open PC‐503A/B 100% on process steam header.

4. Process Steam header pressure was normalized at 1000hrs.

5. Filled material rotation and heating started at 1300hrs after making required level in AN buffer

tank (D‐2401).

6. Loop heating was stopped at 1345hrs due to hot product belt (P‐3403) misalignment. Belt was

normalized at 1520hrs and CAN plant evaporation unit was taken in service.

7. Plant was started at 1635hrs after achieving the desired concentration of Ammonium nitrate.

8. Plant was stopped at 1715hrs due to trippage of final product elevator (P‐3409) against low

speed switch actuation.

9. Plant restarted at 1913hrs after alignment of final product elevator (P‐3409).

10. Plant load remained limited to 70% till 2210hrs due to low Ammonium Nitrate inventory.

INCIDENTS DURING TA:

INCIDENT#1: On 25th August while pressurizing the Nitric acid line on B pipe rack with plant air for drainage, hose pipe got disconnected from utility point resulting in nitric acid spillage in the CAN‐3 building. ROOT CAUSE ANALYSIS:

Root cause for the spillage was improper hose pipe connection. OBSERVATIONS & RECOMMENDATIONS:

1. All drain valves and Nitric acid B.L valve at CAN‐3 was close and plant operator opened the plant air supply at CAN‐3 which resulted in the back pressure of circuit and ultimately the detachment of the hose pipe. Proper SOP to be developed for draining of nitric acid line. (Operations)

2. Plant air hose pipe for the purging was connected using metallic wire. Proper coupling needs to be purchase to connect hose pipes to bear pressure. (Operations)

3. Some portion of nitric acid line at B pipe rack make dead region, which cannot be drained . Drains to be provided for proper draining of the dead areas to safe location. (Process/Maintenance)

INCIDENT#2 On 1st September Control Valve (LV‐0053) from AN Transfer line was removed to transfer AN from CAN to NP. Heavy steam emission was observed from the open end of Ammonium nitrate transfer line at pipe rack near ANC area. Steam was containing ammonium nitrate and acid solution.


On investigation it was found that area operator had opened 10 bar flushing steam in AN line without any information. Flushing steam was cut after 20 mins. Line was blinded later. ROOT CAUSE ANALYSIS:

Root cause for the emission was miss communication and miss‐operation. OBSERVATIONS & RECOMMENDATIONS:

1. Valve was removed to transfer AN from CAN to NP plant, which resulted in the open end on one side. Permanent arrangement needs to be developed to transfer AN from CAN to NP. (Process)

2. Nitric acid was found in the AN line as acid cleaning activity was performed at NP side and the acid had penetrated in the circuit.

Arrangement to be developed to avoid acid entrance in the AN line while performing acid washing the at NP plant.

syn.gas compressor fir&foaming in catacarb system

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