AICHE Symposium – September 2010 Questions & Answers on presented papers

AICHE Symposium – September 2010

Questions & Answers on presented papers

Paper 1a - Explosion of an Aqueous NH3 Scrubber Tank at Yara Italia, Ferrara

• Q.1 (Yusif  Alyaqoob, GPIC)

Did you check for mercury present in the system as one of the investigation element could cause explosion

• No, this was not done as we had no reason to expect any mercury contamination

• Q.2 (Nauman Waheed, Fauji Fertilizer)

Can investigation of internal corrosion be identified as a source for hydrogen in carbon steel tanks only as at Yara?

• No, we can exclude it. The tank was actually in stainless steel. In addition, the visual inspection after the incident did not reveal any signs of corrosion on the inside of the tank or in the scrubber column.

• Q.3 (Jason Norman, Quantum Sphere)

Aside from H2/Air and NH3/Air mixtures, did you consider the tertiary possibility of a H2/NH3 Air mixture as being the main source of explosive energy release?

• Yes, we have considered it and we can definitely not rule out an explosion of a tertiary mixture H2/NH3/air. However, we had only insufficient information available regarding the explosive range of H2/NH3/air mixtures at ambient conditions hence we could not draw a final conclusion on this. We recommend doing more research work on this issue!

• Q.4 (Mike Antony, Proplant Inc, Houston)

Did you consider providing large area rupture disc? In our opinion, nitrogen purge will solve the problem

• No we didn't. First it would be difficult to size the disc correctly (what explosion scenario do you assume as a base case?), second it would have been difficult to place it on the tank (issue of space constraints) and finally we believe a rupture disc to be too slow acting to prevent any damage to the tank in case of a hydrogen/air explosion. Regarding nitrogen purging - a properly designed nitrogen purging based on pressure control would have definitely prevented the incident.

Paper 1b - Safety Relevant Leakages in Ammonia Plants Due to Corrosion from Outside

• Q.1 (Carl Jaske, DNV Columbus)
  Have you considered using and/or reviewing the European guidelines for corrosion under insulation (CUI)? These provide excellent information dealing with CUI.

The guidelines were reviewed after the leakage in the Benfield system (Corrosion Under Insulation (CUI) Guidelines (EFC); Publisher: Woodhead | Pages: 176 | ISBN 1845694236 | 2008-03-2). Although the criteria for the testing program initiated at Borealis Agrolinz were slightly different (operating temperature range of lines ...), the program met the basic principles.

• Q.2 (V. Balasubramanian, Ruwais Fertilizers)
  Cracks on the Benfield pipe were they initiated from HAZ or the parent metal? Did you replace the whole length?
• Cracks were initiated from the parent metal. About 3 m of the line were exchanged. Small beginning cracks were removed by grinding.
• Q.3 (V. Balasubramanian, Ruwais Fertilizers)
  Synthesis section line - what type connection was used to replace the threaded connection?
• As Borealis Agrolinz has good experiences since more than 50 years, the type of connection was not changed.   
• Q.4 (Dorothy Shaffer,            Baker Risk)
  Was there a CUI programme inspection programme in place that missed this flow, or was a CUI initiated after the incident? Where on the radius did the crack occur, was it on the bottom?
• CUI was not a big issue for us, until this incident occurred. The crack occurred on the top the line (position 1 o clock).
• Q.5 (Laxmikant Jahagirdar, Burrup Fertilisers)
  Have you done a external corrosion testing on Ammonia pipes under insulation?
• The insulation of ammonia pipes was widely removed on site more than 10 years ago, because several leakages had been occurring.

Paper 1c - Ammonia Terminals Risk Management

• Q.1 (V. Balasubramanian, Ruwais Fertilizer)
  Does PHA Study came out with recommendation for internal inspection of any storage tanks. If so, what is the criteria recommended for inspection.

No.  The inspection of all equipment, including atmospheric ammonia storage tanks, is done as per our Mechanical Integrity standards for fixed equipment.

• Q.2 (Cheyyur Dintkar,Qafco)
  Did you find oil in the tank and how did you manage that. What about sludge?
• The risk assessment program described in the paper did not deal with ammonia storage tank inspection.  These inspections are part of our Mechanical Integrity program and not the hazard assessment program.
• Q.3 (D Maxwell, Baker Risk)
  Were generic frequencies used, or frequencies from terminal experiences utilized? Were terminal incidents gathered and used in evaluating PHA scenario's?
• Both generic, or those published in best practice documents, and actual site experience frequencies were used for both initiating events and for the reliability of safeguards.  The site experience was used when known (from site history) and only if it was more conservative than the generic frequency. Yes, terminal incidents were gathered and evaluated as part of the PHA.
• Q.4 (Richard de la Bastide, Qafco)

During loading and discharging operations, the rail car or barge is considered to be an extension of the terminal. How does Agrium treat the risk created by deficiencies in railcars or barges during these operations?

• Since we have very little control over equipment owned by third parties, it is very difficult to manage these risks.  Our approach during the assessment process was to identify the risks they posed to us and we posed to them, and then ensure that we had adequate protection within our own facilities to mitigate the identified risks.  Also, we never considered layers of protection that were available from the transportation vessels (e.g. preventive actions of barge operator, pressure relief valves on rail car) as viable safeguards to mitigate the risks we identified..   
• Q.5 (Jatin Shah, BakerRisk)
  Did you include existing Agrium terminals as part of this risk assessment that were in the system prior to the acquisition of the 10 terminals?
• Yes.  All terminals, regardless of their time under Agrium ownership and regardless of previous ownership, were evaluated.  In other words, all terminals with ammonia storage under Agrium ownership at the time of the risk assessment program were included.
• Q.6 (Micheal Schlaug, Yara)
  What does Agrium believe to be safe / best practise on unmanned operation of ammonia terminals?
• This question could be the subject of a paper unto itself.  The guiding principal for this program was that alarms and operator response were not viable safeguards for any hazard unless a man was always on site during the activity (e.g. during load-in activities).  That restriction then dictates how automated the facility must be, and how reliable that automation must be.

 

Paper 1d - Repair and Inspection of QNP's only ammonia tanks while running on a 100 te bullet

• Q.1 (V. Balasubramanian, Ruwais Fertilizers)

Repair and replacement of insulation is a turnkey project through a consultant or contracting company? What type of insulation used, how the selection of new insulation material approved

• The design for repair was done by Billfinger Berger services Australia, but project management was done by QNP. The insulation used is Foam Glass. Apart from its insulating properties, Foam Glass has physical & chemical stability, fire resistance and more importantly, resistance to moisture absorption due to its closed cell structure.

• Q.2 (Greg Deis, Cytec Industries)

Was off gassing of the mineral wool pad on top of the liquid space a problem for inspection/entry?

• Yes, this was a problem. As the ammonia fumes were not very strong, we resealed the joint using denso tape, followed by continuous gas monitoring.

• Q.3 (Hal Cain, Cain & Associates)

Did your crew consider installing a high strength insulation concrete?

• After our experience with Perlite we were not in favour of using something similar. Lignostone was recommended as it is a highly densified wood and hence will not present the same problems that perlite did.

• Q.4 (Yasser Abdelmonem, EBIC)

How to drain the ammonia tank before repair, what about dead ammonia level?

• As explained in the paper, ammonia was drained through the lowest drain point using temporary piping. The remainder was warmed using a mixture of Ammonia vapour and steam. Finally Nitrogen was used.

• Q.5 (Nauman Waheed, Fauji Fertilizer)

Considering internal inspection of NH3 tanks may lead to SCC, what inspection intervals do you follow?

• We use RBI. Operational parameters are closely monitored. We ensure that there is adequate water content in Ammonia. The projected inspection period is 20 years. Since decommission and recommissioning activities have a risk of inducing SCC, a time-based inspection is not always the best solution.

• Q.6 (Nauman Waheed, Fauji Fertilizer)

Do you have any experience of welding repair on outer tank without decommissioning?

• We do not have any experience in this matter. It is not something we would recommend.

Paper 2a - Challenges Associated with a 36 year old Reformer Bottom Header Failure

• Q.1 (Cheyyur Dinakar, Qafco)

Please tell us if this header was cast or welded. (Reducer to header)? What was the cause of this refractory damage? Did modification involve offsetting this reducers? Did you not see hot spot on the header?

• The bottom header, that experienced the creep failures, was fabricated from wrought material. There were no cast materials present.  The change in bottom header design used concentric reducers. The leaks in the bottom header resulted in small jet flames. Where these flames impacted on the furnace wall, a hot spot could be seen, particularly at night. The transfer header was fabricated from rolled and welded plate. The failure in the transfer header was caused by a weld defect in the site weld for the riser to header connection. There was also poor compaction of the refractory, in the area of the failure, which would have allowed hotter process gas to collect in the area. This higher temperature would have promoted the leak at the weld defect. It was not possible to see a hot spot from the transfer header leak, as the leak was under water, inside the water jacket. Instead, the flame was visible from the water jacket vents, after a storm ignited the leaking gas.

• Q.2 (V Balasubramanian, Ruwais fertilizer)

Being a 40 year old plant do you have done any plant equipment life assessment study?

• Yes, we have done a number life assessment studies. The bottom headers were subjected to several studies after 1998, when repairs to the riser to bottom headers became difficult. The final study in 2004, after detailed inspections, had recommended replacement of the headers during the next planned major shutdown, in 2006. Unfortunately, the header in the paper failed six months before the planned shutdown.

• Q.3 (Abdol Hassan Faraji, RPC)

Did you apply solution annealing heat treatment on the tubes before welding overlap patches?

• Because we were using wrought materials, instead of cast material, we did not believe that solution annealing was required. This decision was based on the premise that all welding would be done on the external surface of the aged header material.

• Q.4 (SG Gedigeri, Oman fertiliser)

Was there any thinning down of reformer tubes that you mentioned? What is the Material of construction of the outlet header?

• Any thinning down of the aged material was not significant dimensionally. The major problem found was growth in the header outside diameter, due to creep. The same situation can be seen in both catalyst tubes and risers.  The material in the bottom header was the 1969 version of Incoloy 800H. At the time it was know as "Nickel-Iron-Chrome Code Cas 1325-2 Grade 2".

Paper 2b - Steam Reformer Outlet Header Failure

• Q.1 (David Kelling, Praxair)

Were there any signs of hydrogen attack? What type of special QA/QC was done of the rebuild?

• There was no hydrogen attack found in the examination of the failed header section.  The rebuild had the same level of OA/QC that the original header had during its construction.  The typical pressure vessel type of QA/QC and the same level of OQ/QC on the refractory installation.  This was visual inspection at each stage of refractory installation.

• Q.2 (Yusuf Alyaqoob, GPIC)

What is the reason for increasing the header diameter from 22" to 24"? Did you use the original reformer inlet designed to the header or did you modify it to cater for the 24" design?

• The original reason for increasing the header size was never documented, although we can speculate that it was to reduce the overall header shell temperatures by increasing the insulation thickness.  Since the insulating refractory was changed to a low silica type during the project, then another reason was that an increase in insulating refractory thickness was required since the low silica refractory thermal conductivity was higher than the high silica refractory in the original construction.

Paper 2d - Safeguarding Stamicarbon's High Pressure Urea Vessels Equipped with Loose Liners

• Q.1 (Les Farbotko, Initec Pivot)

If use of steam / condensate is not recommended for cleaning blocked linen segments? What does Stamicarbon recommend

• This is not a simple question to be answered. We recommend approaching this step wise. First check whenever the drilled holes through the pressure wall are blocked. If this is the case, the hole can be opened up again by mechanical means (careful drilling, do not toughs the liner). In case the holes are not blocked, most probably the annular space between liner and pressure vessel is blocked. Stamicarbon strongly advice not to open up by using life steam; since corrosion my occur on the pressure shell (overall as well as stress corrosion cracking). It is advised to remove the liner segment in this area to clean up the compartment. This is more elaborate but gives less risk for corrosion of the pressure bearing part.

Paper 2f - High pressure piping safety incidents in urea plants

·         Q.1 (V Balasubramanian, Ruwais)

What type of connection do you recommend for instrument fittings like thermowell - flanged or threaded? Are threaded connections safe in HP carbamate service?

·         For thermowells I prefer the BHDT specification, which is a pressure bearing tube welded to the high pressure pipeline. I do not prefer a construction where a crevice exists in which carbamate solution could enter. For normal high pressure piping connections threaded flanges are common (for example the IG325 specification)

Paper 3a - Chlorine Dioxide: a choice for safety, environmental protection and operational continuity in ammonia plants

·         Q.1 (Marc Habermehl, Incitec Pivot)

How much ammonia was in your cooling water? Did you try to reduce your ammonia levels in the cooling water? Did you consider using a supplementary, non-oxidising biocide?

·         Ranges from 25 to 150 ppm. We try to reduce levels through constant monitoring and a change of dianodic corrosion inhibitor. If ammonia went over 150 ppm, the unit must be shot down for repair work.

The use of a non-oxidizing biocide is a complement to chlorine dioxide

·         Q.2 (Rajan Sinha, BFPL)

Chlorine Dixode is being used a corporate package of biocide. Who has supplied the complete package?

·         It is a total treatment program, the supplier is Clariant. We found better to contract the whole treatment and deal with one vendor, responsible for performance.

Paper 3c - Process safety improvements at CNC & N2000 ammonia plants

·         Q.1 (John Brightling, JM Catalysts)

In the process condensate SIL example a new trip valve was added to protect system downstream of LV1025. Why wasn't PRV-174C sufficient protection?

·         Using worldwide industry PFD's for the SIL study, the scenario of a blowthrough was ranked such that the physical protection (PRV-174C) and the other protections such as alarms, etc based on the frequency of the initiating event, the probability of enabling events occurring and the probability that identified IPLs will fail on demand (PFD) all worked out to a mitigated event frequency (MEF) which showed a gap between the target event frequency (TEF). If the TEF was ranked lower due to the circumstances of it, the PRV would have met the MEF and thus would have been sufficient.

·         Q.2 (Venkat Pattabathula, Initec Pivot)

Was there any high level trip on process condensate stripper in order to prevent any damage of primary reformer catalyst?

·         No there never was. The only trip was for a high Differential Pressure. This instrument had a history of being faulty and producing spurious trips so it was replaced with a low temperature trip for steam exiting the process condensate stripper to the primary reformer.

·         Q.3 (Harinarayan Reddy, Nagarjuna fertilizer)

Is there any attempt to filter alarms during plant shutdown where there will be avalanche of alarms to avoid monitor getting hanged leading to difficulty?

·         No but we were considering implementing conditional alarming in order to prevent the avalanche of alarms during trips. It was then decided to complete the rationalisation first and monitor the effects of the changes on the next shutdown.

·         Q.4 (Leonard Werner, Borealis Agrolinz)

Did you add a SIL3 switch to your plant?

·         Yes, we chose the equipment to be added to remove the gap between the target and the mitigated frequencies to be SIL 3 certified. Thus we met and even surpassed our criteria for the scenario.

·         Q.5 (S Gedigeri, OMIFCO)

How many alarms per operator or per day are targeted?

·         We are working towards the EEMUA benchmark of 144 alarms per day.

Paper 3d - Primary Reformer Loss Prevention from a Property Innsurance Perspective

·         Q.1 (Venkat Pattabathula, Initec Pivot)

What was the recommended 30 minutes period is it a best practice to box up reformer while it was hot or is it better to cool the furnace by opening dampers on ID Fan?

·         The 30 minute best practice hold period following a trip is not a time of simply waiting before attempting a restart of the unit/process.  Rather it is a time of intense focus on the equipment, process streams, fuel supply, and auxiliary support system to ensure they are in a safe position following the trip and have been properly prepared for a restart.  The correct action to take with respect to the primary reformer will depend on the conditions at the time of the trip  A decision to box up the reformer while it is hot or to allow ventilation by opening dampers on the ID fan needs to be based on an evaluation of the damage that may or may not be done in either scenario.  If boxing up the reformer causes the furnace tubes to overheat since there is no reforming reactions occurring, then opening the ID fan dampers is necessary.

·         Q.2 (Nauman Waheed, Fauji Fertislizer)

For loss prevention, application of heat sensitive painting was not mentioned for refactory lined equipment. Is a heat sensitive painting system not considered as an effective loss prevention measure?

·         Yes, heat sensitive paint can be used as an effective loss prevention measure provided the area being monitored can be visually inspected periodically while the reformer is in operation.  However, the paint has limitations that need to be recognized.  These include the paint changing color over time if the surface is operating close to the change temperature.  Also, once the paint has changed color, it will not change back when the temperature is lowered.  The preferred approach is the strategic use of thermocouples to monitor the surface temperature.

·         Q.3 (Yusuf Alyaqoob, GPIC)

Did the insurance pay the claims in both cases of paper 3d and paper 3e?

·         Yes

Paper 3e - Ammonia Plant Primary Reformer Explosion

·         Q.1 (S G Gedigeri, Oman Fertiliser)

What is total start up time after implementing new burner management system?

·         First lighting of burners can take approximately 2 hrs. Total Start up of the primary Reformer is taken between 4 to 5 hrs. With experience, time of start up is expected to be reduced

·         Q.2 (John McGrath, Initec Pivoted LTD)

With 180 burners, if you fail the fuel leak test, do you have any way to narrow in on which valve may be passing? (Diagnostics to speed up fixing problem)

·         Yes. DCS alarm are available to detect the low pressure or failed flame detected on the incriminated row or header

·         Q.3 (Laximikant J, Burrup Fertilizers)

Does the revamped reformer have hot air draft and what are the conditions of reformer going in minimum firing?

·         Yes. Minimum firing of the burners is foresceen on the SMS in case of loss of feed gas (<6000 Nm3/hr, 2oo3, 40sec)

·         Q.4 (Venkat Pattabathula, Initec Pivot LTD)

Do you have PPT (positive pressure testing) on all 180 burners?

·         Yes

·         Q.5 (V. Balasubramanian, Ruwais Fertilizer)

How long it took to come back on line / production did you consider any explosion proof doors / windows during reconstruction?

·         10 months were necessary to reconstruct-commission and re-start the plant

Paper 3f - Investigations into Major Synthesis Gas Release from an ammonia plant

·         Q.1 (C Dinakan, Qafco)

Is the OEM British Engine Ltd? We have similar. Were the original bolts used? We never had any problem. We do lapping by ourselves. Do you have any problems of this valves passing after service?

·         The OEM is British Engine Ltd (BEL). The valves were stripped and inspected in conjunction with BEL.  We have no reports that the stud bolts were changed in the past and so we believe them to be original. The valves have passed in service and this is the reason why internal inspection of the valves had been undertaken.

·         Q.2 (Venkat Pattabathula, Incitec Pivot)

Did you consider installation of gas leak meters? Do the operators check for leaks using explosive meters on all the flanges in synthesis loop?

·         We did consider fitting ammonia detectors as well as the use of cameras to monitor the plant. The operators are checking all pipework valves and vessel joints.

·         Q.3 (V Balasubramanian, Ruwais Fertilizer)

How much man hour / man power being used to check all the valves? What about the valves in inaccessible areas? Changes of valves done in phases or in one go?

·         The routine checks are done quarterly and spread amongst the shift teams by plant area. To fit in with other work it usually takes a couple of shift cycles to complete. Weekly checks of known leaks are done every Sunday. Inaccessible valves are tested using a fishing rod and tube to gather the sample.  Valves are being changed in batches each turnaround.

·         Q.4 (Amod Datar, QNP)

What measures were taken to eliminate joints leaking? Did you consider change of joints?

·         Most of the joints on the synthesis loop are either Grayloc joints, which we have found to be generally reliable, or the metal-to-metal body joints on BEL valves which we are gradually replacing.

·         Q.5 (Terrence Poobalan Pillay, Qafco)

Valve design prone to induced bending moments. Lapped joints are not forgiving. Recommended to verify line supporting and stress analysis checks

·         As we have replaced the large bore metal-to-metal valves this was not necessary.

·         Q.6 (Dorothy Shaffer, Baker Risk)

Please briefly describe your critical joint procedure?

·         Critical joints are any bolted joint where loss of containment of the substance within will have the potential to give rise to a major accident hazard or major off-site implications due to its immediate affects or consequential escalation.  These joints are normally identified as a piping system due to the contents.  Those joints identified have additional procedural controls, which are predominately focused around inspection of the joint when broken for maintenance and prior to re-assembly by a nominated GrowHow maintenance person and written record of that inspection and any remedial work carried out - for example machining of the joint face. Joints are also tagged by the maker and the inspector to encourage ownership and traceability.  Certain joints might have further written procedures if they are known to be difficult to make or prone to leaks.

Paper 4a - Troubles in radial ammonia synthesis reactors

·         Q.1 (V Balasubramanian, Ruwais)

When is next inspection planned. What are the preparation being done? What is the role of HTAS on repair, being a process licensor what is the technical support given. Any inspection done on the pressure shell during the outage?

·         The next inspection and catalyst changes are planned to be made in 2016.

·         Q.2 (Yusuf Alyaqoob, GPIC)

Would like the opinion of Haldor Topsoe about this failure?

·         Q.3 (H Duisters, Orascom)

Why did the screen in the ammonia synthesis reactor fail?

·         Q.4 (R Michel, Uhde Gmbh)

What was the material of the Johnson screen? What was the mechanism which led to the failure. Nitriding, hydrogen attack, thermal stress or other?

·         Regarding questions 2, 3 and 4 Pemex staff  issued a document requesting the information, which has not yet had a response from Haldor

·         Q.5 (Ahmed Nuruddin, GPIC)

What type of inspection was carried out in the reactor? What was the duration of the work carried out

·         The inspection carried out by Haldor was a complete overhaul of the state of the materials, covers and support the beds and their diagnosis of state by inspection.
The total time of unloading, repairing and loaded catalyst was 28 days.

Paper 4b - Lessons learnt with ammonia synthesis

·         Q.1 (Dorothy Shaffer, Baker Risk)

As touched on in this presentation, where leaking exchangers are a potential, an evaluation of the hazards of syngas entering into unexpected systems must be considered. Such leaks have resulted in at least one explosion of a stripping column and have a high potential for synthesis loop exchanger equipment, particularly during

outages.

Dorothy makes a valid point

·         Q.2 (Mohammad Azam, Koch Ferilizer)

Sulphur and chlorine are considered permanent poisons. There is a number for sulphur as 0.1% sulphur would cause poisoning. Is there a number for chlorine causing poisoning?

Johnson Matthey would recommend that wherever possible chloride levels should be below 5ppb in the inlet to the converter.

·         Q.3 (John McGrath)

Are there examples of people outside an open convertor being nitrogen purged being adversely affected? Can you quantify good practice

Whilst I am not personally aware such an incident, I have heard of people being affected when close to open ends on other sections of plant. Good practices that I am aware of include awareness training, marked exclusion zones, the wearing of personal monitors and the wearing of breathing apparatus as a precaution.

·         Q.4 (Cheyyur Dinakar, Qafco)

We have two experiences with sieving being recommended to reduce to reduce dust content which would prevent lower bulk density

We are aware that some ammonia converter technology suppliers have a blanket recommendation that all ammonia synthesis catalyst be screened, irrespective of supplier. Notwithstanding, Johnson Matthey's recommendation is that pre-reduced catalyst should not be screened and that it is not necessary to screen our oxidic catalyst

·         Q.5 (Ngatecho, Pt Pupuk Kaltim)

What are parameters to determine ammonia synthesis catalyst replaced if the catalyst performance is good with the age 24 years and how to do!

Johnson Matthey would be pleased to conduct a technical evaluation to assess the efficiency & throughput benefits that would result from replacing your catalyst. This could then be used to help determine whether catalyst replacement was economically justified

·         Q.6 (R Michel, Uhde)

The precondition of even gas distribution inside the cartridge cannot be ensured for in situ oxidization. So this paper should not be taken as a recommendation for an in-situ oxidation as this presents uncontrollable preconditions is a risk

Agreed, although in situ oxidation is described, it was not the intention to recommend or endorse the technique.

Paper 4d - Metal Degredation of methanator vessel

·         Q.1 (V Balasubramanian, Ruwais)

From your paper you had TA in 2001, 2002 and 2003 and so on, what is your TA frequency? Why do you S/D the plant every year?

·         We have to carry out T/A every year mostly due to gas shortage during winter; otherwise we had operated the plant for continuous 29 months when gas was available.

·         Q.2 (Cheyyur Dinakar, Qafco)

Qafco result did not show any indication of the attack on methanator. Did a reanalysis reveal the reasons? Any destructive tests were done?

The above design temperature excursions were one of the main contributing factors for the severe material deterioration. For reanalysis purpose, metallographic examination (destructive testing) of the samples  from affected area were carried out. Please see the paper for details.

·         Q.3 (Don Timbers, D&E Consulting)

Did you use AUBT or straight UT Testing? Was in-silu metallography conducted? Metallography does not show de-carb around crack, why is this?

Straight ultrasonic testing method with angle probes (Pulse Echo method) was used. We agree that in-situ metallography was worth doing; however destructive metallography confirmed that the results of UT were correct. Not all but a few samples showed decarburization around crack.

·         Q.4 (Nauman Waheed, Fauji Fertiliser)

Can you elaborate on the type of ultrasonic testing for HTHA survey?

·         Straight ultrasonic testing method with angle probes was used that was a general purpose UT method.

·         Q.5 (R Michel, Uhde)

API 941 has taken out the C-0.5Mo curve from the main diagram but has a dedicated appendix A for C-0.5Mo and Mn-0.5Mo maybe this explains why QAFCO has not found hydrogen attack in their methanator of  0.5Mo material

Thank you for your valuable input.

Paper 4e - New technology for the inspection and fitness-for-service of critical in-plant piping systems

·         Q.1 (Amod Datar, QNP)

What level of cleanliness is expected in the pipe? What costs are expected?

·         The InVista intelligent pig applies high frequency ultrasonic sensor technology in order to determine the integrity of the pipeline being inspected.  Due to the physics associated with immersion ultrasonics, readings can be impacted by a poorly cleaned pipeline.  Piping systems and pipelines should be cleaned prior to inspection to ensure the highest quality data. The cost of the inspection and cleaning are dependant upon the piping system to be inspected. These costs  can be obtained by contacting Quest Integrity Group with a specific  pipeline to be inspected and assessed using the InVista and LifeQuest Pipeline methodology.

·         Q.2 (John Brightling, JM)

How long would it take to inspect an ammonia line that was 5km long?

·         The standard rate of travel for the inspection tools are 0.6 m/second (2 feet per second). This equates to about 2.5 hours for the inspection of a 5km long pipeline. Due to the accoustical properties of liquid ammonia, the ultrasonic based InVista intelligent pig could not be operated directly in this medium, however the pipeline can be inspected as long as another liquid medium (i.e. water, diesel, etc.) is used to propel the intelligent pig down the pipeline.

·         Q.3 (V Balasubramanian, Ruwais)

Is it possible to inspect buried piping range from 60" down to 6" with various branches? Is there any technology / method for inspecting non metallic piping (GRP/GRE etc)?

·         The current InVista intelligent pig designs are capable of inspecting pipeline diameters ranging  from 3-inch to 14-inch. The intelligent pigs tools have the ability to negotiate many unpiggable features such as unbarred tee fittings, diameter changes, and short radius bends down to 1D.

·         Q.4 (A Hassan Faraji, Razi Petrochemicals)

My question is about online inspection on water jacketed transfer line and secondary? How to know the condition of refractory lining?

·         Because the InVista intelligent pigs apply high frequency ultrasonics, they are not suited for inspection of refractory lined piping.

·         Q.5 (Nauman Waheed, Fauji Fertilizer Bin Qasim)

What recommendations do you give if a piping "marginally" passes an FFS assessment: replacement, monitoring or level 3 assessment?

·         All of these are options once the Level 2 API 579 assessment has been performed. The path will depend upon the piping system operator/owner's risk tolerance and other factors to be weighed into the replacement or repair versus further engineering assessment and monitoring decision.

·         Q.6 (Mike Antony, Proplant Inc)

By placing RFID tags along the piping the inspection methodology, records and technical details can be captured. The tags can send reminders through emails or text messages.

·         InVista utilizes Above Ground Markers (AGS) to stamp the inspection data with several pieces of information, including GPS coordinates.  This enables both the pipeline owner/operator and Quest Integrity to locate detected flaws after the inspection is complete.

Paper 5d - Safety audit in operating plants

·         Q.1 (John McGrath, Incitec Pivot Ltd)

Do you believe it is acceptable when an extra switch is installed to provide SIL1 trip function, to also use that switch to reduce the chance of control failure?

·         No problem. The SIL trip function is leading and stays intact when the switch is also used for something else.

·         Q.2 (Mohammed Azam, Koch Fertilizer Canada

Can you share with us what additional measures were taken to reduce the risk of lifting the relief vales on the ammonia sphere?

·         On our Ammonia Sphere we have installed

- high level alarm

- high level switch 1(stopping feed)

- high level switch 2 (stopping feed) with separate measuring system from nr. 1

- high pressure alarm

- high pressure switch (stopping feed)

Paper 5e - Urea dust explosibility testing

·         Q.1 (Bill Taylor, Yara Belle Plaine)

We tested urea once by applying a cutting torch to a sample of urea - nothing happened - no fire, no explosion - it decomposes.

·         Exposing a material to a blow-torch is not a conservative test. Many materials will exhibit this property.  Polyethylene, in fact, will melt and show very little flame until dispersed in air (i.e., at which time it poses a dust explosion hazard).  In addition, it is expected that urea would need containment to be a hazard. 

·         Q.2 (Mike Antony, Proplant Inc)

Can you explain the effect of free ammonia in urea dust on explosivity

·         No.  We do not have sufficient data to make a definitive response to this question.

·         Q.3 (Les Farbotko, Incitec Pivot Ltd)

Please clarify comment on slide 'urea will ignite against a hot surface' this is not our experience. Urea will melt and decompose. I have never seen it burn.

·         It is our belief that if urea were spilled on a bare high-pressure steam pipe, it would first melt and then flame.  However, we do not have definitive data to support this position.  Limited tests were done outside of the scope of the work described in this paper that indicated urea dust could ignite (i.e., yield a flame) if brought into contact with a very hot surface.

Standby Questions 1 - Technical Survey of steam reformer to control tube metal temperature

·         Q.1 (Glenn Combs, Chem-Engineering services)

Suggested use of alkali promoted reforming catalyst in top portion (40%) of reformer tube loading will minimise carbon formation

·         Usage of alkali promoted catalyst was also considered but not adopted. With improved tube metallurgy and increase in catalyst volume, our plant is running normal. In our opinion, alkali promoted catalyst is mainly required for natural gas with high carbon content.

·         Q.2 (Hari Narayan Reddy, Nagarjuna Fertilizers and Chemicals)

Can you please share the operational charges taken up to handle composition change of Natural Gas to Lean Gas in Ammonia plant of Sabic, how it was handled ok?

·         With lean natural gas, impact is mainly on steam reformer, as both feed and fuel flow rates increase.  Load on natural gas compressor and reformer ID fans also increases. Reforming load may be partially shifted to secondary reformer. If enough margin is not available in such critical units, plant load will be restricted.

·         Q.3 (Amod Datar, QNP)

Were the tubes uniformly hot all around or only on one side? Why did this not happen to all tubes? Were the tubes that had failure the ones that were hot?

·         Tubes were hot all around. Tube metal temperatures are measured through peephole and the space is available is too small to accurately measure all around the tube. Reason for not happening in all tubes could be due to variation in gas flow rates through each tube, caused by variation in pressure drops in feed gas distribution system, catalyst loading, catalyst crushing, etc. Failures were mostly in hot tubes.

·         Q.4 (V Balasubramanian, Ruwais)

Why did lean gas from Aramco affect only one plant and some tubes only?

·         Lean gas affected other plants also, especially those not having enough margin in reforming capacity.

·         Q.5 (Mohammad Azam, Koch Fertilizer Canada)

What was the operating heat flux with respect to design heat flux?

·         Actual heat flux with lean gas was 74,434 kcal/hr/m2 and the heat flux with normal gas was 72,700 kcal/hr/m2.

Standby Question 2 - When is the ideal time to change my catalyst?

·         Q.1 (Shashi Singh, KBR)

This paper applies to conventional technology based ammonia plants. In KBR's purifier technology aging of catalyst have lesser impact on the plant performance as purifier removes CH4/inerts and make up syngas is always pure.

·         We agree that the paper referred to modelling of a conventional technology based ammonia plant and that the results for a KBR Purifier technology plant would be different.