Resume - Have more than 20 years operation and maintenance experience in the thermal and ...

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Resume #85670

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NATIONALITY: Singaporean

LANGUAGE (SPOKEN): English, Malay and Tamil

LANGUAGE (WRITTEN): English

DOB: 16.5.60

MARITAL STATUS: Married

QUALIFICATIONS:
* Bachelor of Engineering (Mechanical, First Class Honours) (National University of Singapore, April 1985)
* Master of Science (Mech. Engrg.), (NUS, April 1990)
* Masters in Engrg Maintenance Management (Monash University, April 2004)
* Professional Engineer (Singapore, 1994)
* Chartered Professional Engineer (Australia, 1993)

WORK EXPERIENCE

January 2009 – Present:
Designated as Technical Specialist. My duties and responsibilities are:
* Assist the Sales team in evaluating spare part and service proposals for inspections, maintenance and repairs.
* Analyse Customer's needs and develop technical solution based on available portfolio of products and services. To provide ideas, based on field experience and customer feedback, to develop new products and services
* Provide technical and functional training on equipment including operational know how to technical and sales personnel
* Execute service projects to ensure timely completion and within budget
* Maintaining proper, complete and organised records of all service activities and technical history of equipment.
* Provide first line troubleshooting advice to Customers. Follow up on Operational issues raised by Customers.
* Carry out value added assignments in the Asia Pacific region when assigned by head office.

January 2008 – December 2008:
Technical Sales Manager in Alstom Power (S) Pte. Ltd. My duties and responsibilities are:
* Provide plant technical support, to the South East Asia region, pertaining to turbine (steam and gas) generator power plants.
* Assist the Sales team in evaluating spare part and service proposals for inspections, maintenance and repairs.
* Analyse Customer's needs and develop technical solution based on available portfolio of products and services. To provide ideas, based on field experience and customer feedback, to develop new products and services
* Provide technical and functional training on equipment including operational know how to technical and sales personnel

August – December 2007:
Business Development Manager (Turbine) in ABB Industry Pte. Ltd. My duties and responsibilities are:
* Provide technical support to the various departments on control system retrofits to turbine (steam and gas) generator power plants.
* Develop solutions for power plant clients in areas that improve efficiency and availability.

July 2004 – July 2007:
Asset Manager of the Oil & Diesel Department* of Pulau Seraya Power Station. My duties and responsibilities are:
* Managing a department of 75 staff comprising 4 Shift Operation Teams and a Maintenance Team who operate and maintain plant like boilers, steam turbogenerators (Parsons/Hitachi), gas turbines (Siemens/GE), diesel generators, pumps, electrical switchgear, DCIS systems etc.
* Managing work and supply contracts and the annual maintenance budget which amounts to approximately S$6 million.
* Managing plant modifications, extensions and improvements.
*Redesignated as Manager (Utilities Gen Department) wef 1.1.2007

May 1996 - June 2004:
Senior Engineer of the Turbine Maintenance Section of Pulau Seraya Power Station. My duties and responsibilities are:
* Managing a team of Engineers (4), Technical Officers and Technicians (27) who maintain plant like steam turbines (Parsons/Hitachi), gas turbines (GE) diesel engines, pumps etc.
* Managing work and supply contracts and also the annual budget which amounts to approximately S$4 million.
* Managing plant modifications, extensions and improvements.
* Had a major role in the development of mechanical specifications and the evaluation of tender bids for the 2 X 370 MW combined cycle plant in Pulau Seraya Power Station.
* Member of the restructuring team which transformed the function based organization structure to an asset based organization.

October 1990 - April 1996:
Engineer in the Turbine Maintenance Section of Pulau Seraya Power Station. My duties and responsibilities are:
* To supervise a team of personnel who carry out maintenance of equipment associated with 250MW Parsons/Hitachi steam turbines, 25MW GE gas turbines and diesel generators
* Carry out purchase of spares for plant
* Preparation of specifications of work contracts and managing them so that overhaul of equipment is conducted efficiently
* Trouble shooting of plant faults
* Carry out modifications to improve plant availability and reliability
* Led the maintenance team in ensuring that the erection and commissioning of the 3rd stage of Pulau Seraya Power Station was carried out smoothly

October 1985 - September 1990:
Engineer in the Generation Development Section of the Public Utilities Board. My duties and responsibilities are:
* Preparation of long-term electricity generation system expansion plans
* Preparation of specifications for power station projects (Jurong and Senoko Gas Turbine Plant)
* Evaluation of tender bids for major power station projects

COMPUTER SOFTWARE:
MS-Word, MS-Excel, MS-PowerPoint

MAJOR ACHIEVEMENTS:
The following are examples, which had a significant financial impact. They highlight my strengths in resolving complex technical problems, trouble shooting with an eye on efficiency and availability which impacts generating costs. In addition, my ability to work (and negotiate) with OEMs to achieve positive outcomes is reflected in these examples.

Efficiency Issues
* In the 90s, the high pressure feedwater heaters, which had generic design defects, were having poor availability for long durations. I investigated the problem and led the exercise to repair these heaters. The repairs improved the efficiency of each unit by about 1% point. These repairs were carried out in 1999/2000
* In October 2004, it was reported to me that Unit 4 had problems raising vacuum during startup. I led the investigation and found that a flange on the quick start air ejector had loose fasteners and the air inlet valves on the steam jet air ejectors were passing. In addition, the pressure gauge for the steam supply pressure had drifted by 10bar thus actual steam pressure was low. Every 1 mm HG change in vacuum results in a 0.1 % change of heat rate. This translated to a fuel saving of around S$80,000 a year. Assumptions: fuel cost at S$323/ton and CF of 50%.
* In July 2004, Unit 7 had tube leaks on heaters 5 and heater 3 of Unit 9 was out of service because of actuator problem with the feedwater outlet valve. I advised the operation and maintenance teams to expedite the return to service of the heaters as they cause a 0.5% and 1.5% deterioration in heat rates. Whilst the heaters were out of service, I advised that they be committed last for generation in view of the increased generation cost.

Negotiating Skills
* In July 2008, successfully secured a contract (approx $1million) for a major inspection of a 300 MVA generator. Led a team to offer a $10 million tender for a CW pump, mechanical cleaning device and associated ancillaries in September 2008.
* In December 2007, I was part of the technical risk assessment team to evaluate a tender proposal for a plant condition monitoring tender for a power plant in Malaysia. I provided valuable technical and project management inputs to minimise the commercial risks.
* In 2000, I successfully reduced the contract sum, for the overhaul of the 250MW steam turbogenerators (3 units), by S$0.5 million without any reduction in the scope of work.
* In 2004, I decided to use an open tender for the major overhaul of the stage 1 turbogenerators. The tender covered the overhaul of the 3 units as well as the replacement of the last row blades of the LP turbine. The savings achieved was close to 15% against the original budget i.e. S$3.93m vs. S$4.62m (overhaul) and 19% i.e. S$3.79m vs. S$4.5m (LP blades)
* During the minor overhaul of Unit 4 (11/2003), 6 diffuser (LP turbine) mounting bolts were found sheared. I made the decision to replace these bolts without removing the exhaust hood even though the contractor wanted it otherwise. I decided not to order the bolts from the OEM as they proposed to upgrade the material and increase the cost. This approach helped to keep the cost of repair as low as possible and without extending the outage period.
* In 2000, I reviewed the technical specifications for the combined cycle plant. I updated specifications to include weld-in condenser titanium tubes for higher reliability; variable speed feedwater pumps instead of constant speed feedwater pumps which were originally offered by OEMs; pre-qualified major equipment (pumps, valves etc) suppliers.
* Unit 4 had generator hydrogen seal problems in March 2002. However the symptoms had appeared earlier. Two seal oil pumps had to operate, seal oil vacuum tank level was lower and hydrogen make-up was excessive. The generator was overhauled in October 2000. I led the investigation to identify the exact seal and root cause of the failure. The OEM was engaged and further inspection revealed that the steam end of the rotor had been scored at the seal ring area. The rotor had to be removed for machining at a local workshop. I also pursued the design of the seal clearances and the filter mesh size and managed to convince the OEM that the selected filter mesh size was unsuitable.
* In 1996, Unit 7 had turbine expansion problems during commissioning. I investigated the problem with OEM and advised them that the problem was due to poor piping layout as there was a possibility of trapping steam/condensate. The gland steam piping was modified and the startup procedure was revised i.e. to allow for warming and draining.
* In the 90s, the feedwater regulating valve (large) in stage 1 used to fail frequently. I traced it to improper machining on the valve bonnets. The OEM was also approached to provide an improved design for the valve bonnet. Subsequently, the reliability of these valves improved significantly.

Availability Issues
* The condensate extraction pumps (on the stage 2 units) had frequent cracks on the column pipes. This problem started with a pump of Unit 6 in April 2000, which was under warranty. Initially, weld repairs were used to overcome the problem. I pursued the issue with the OEM and was able to get a modification done to the pumps, which improved the reliability of the pumps.
* In 2002, I led the project to modify the turbine hydraulic systems (6 units), which resulted in an estimated savings of S$8 million dollars. This project was a result of the poor reliability and high cost of maintaining these systems.
* In 2005, Unit 9 was returning from boiler major overhaul. The unit could not be resynchronised because of AVR/Excitation trouble. Eventually, after solving the problem, it was found that the IP turbine differential expansion had reached the High-High limit and ARU prevented from raising turbine speed. I instructed the logic to be defeated and the unit was started successfully and resynchronised under my direct supervision. Savings is due to earlier resynchronisation instead of waiting for the turbine to cool and the differential expansion value falling below the alarm limit.
* In Feb 2005, I resolved the issue about corrosion in the furnace hoppers of stage 3 boilers. The root cause was the excessive use of auxiliary steam for cooling the burner guns. The savings in repair costs, demineralised water cost, fuel cost and unavailability is immense.
* In 2001, Unit 3 had exhibited high LP turbine differential expansion problems. I instructed the Operation department to shutdown the unit. I led the investigation and found that No. 2/3 axial keys were seized in the keyways and there was an improvement after easing the keys. I continued with the investigation of the expansion problem and found that a jackscrew was left in the extended position and was causing obstruction to free expansion. The jackscrew was cut off whilst the Unit was on-load and the expansion problem was solved. A similar inspection of the other jackscrews showed that Unit 1 had one too and was similarly cut-off. A budget of S$1 million was reserved to realign Unit 3 because of the expansion problems and this amount was saved.
* The condensers (stage 1) had experienced a series of tube failures due to excitation by steam flow. I led the project to improve the reliability of these tubes and developed the technical solution to solve the problem.
* The conversion of FRF pumps (stage 1) from using hydrostatic thrust bearing to anti-friction bearing was done under my direction and supervision in 2001. In addition, I advised the potential OEM for the stage 3 units, to use anti-friction bearings for the pumps yet to be installed.
* The HP feedheaters in stage 2 had started to exhibit erosion of the waterbox partition plates. This causes shortfall in heater performance. I led the rehabilitation programme and it was completed on all 3 units in 2001.
* Unit 1 had vacuum raising problem in December 2000. The Operation department had planned for a unit shut down for adjustment of the LP turbine diaphragm. I instructed the Maintenance staff to temporarily adjust the seal and it was successful. The permanent rectification was scheduled during the subsequent two-shifting of the unit. A similar incident happened in 1993 (Unit 1) when I gave the same advice, which allowed the unit to be able to be dispatched to meet system demand during the peak period.
* Black Start Gas Turbine 2 was not available in December 2000 because of "exhaust temp high" condition. Gas Turbine 1 was not available because of repainting work on the chimney. I led the investigation and working with other maintenance departments, got both units back within two days. The faults on both units were due to faulty servovalve and loose cable (GT2) and faulty control card (GT1). The black start payment per day was S$8,000 as long as one unit is available.
* In stage 2, I led the modification to install isolating valves at the inlet to the turbine control oil filters so that the servovalve could be maintained without stopping the lube oil pump. Previously, maintenance staff had to endure oil spills and fire hazards in order to maintain the servovalve.
* In 1996, the condensate extraction pump (stage 3) motor thrust bearing had frequent failures and was due to high temperatures from excessive loadings whenever the CEP was operated alone and feeding the deaerator. I worked with the OEM on this and highlighted to them that it was due to high thrust loading on the bearing. The problem was resolved by changing the operation procedure.
* In the 90s, the lube oil pressure control system (stage 1) used to be problematic. The DC pump used to cut-in whenever the AC pump was stopped. My investigation showed that this was an inherent problem, which had manifested itself during the commissioning phase. I led the programme to modify the pump control. In 1995, I pursued this matter to have similar modifications for the units in stage 3.

Analytical (Troubleshooting) Skills
* In 1998, I led the effort to restore reliable supply of cooling water to the three steam turbogenerators (stage 1) when an influx of seaweeds caused the failure of the bandscreens at the pumphouse. The effort involved major repairs to the screening equipment and pumps besides managing the manual removal of seaweeds to ensure continued operation of the turbines at slightly reduced output.
* In 2005, I led the programme to identify the root cause(s) of high fuel oil header pressures on the stage 2 boilers. This had caused load limitations and in the event of system disturbance, units have tripped due to main steam pressure falling has a result of increased load demand and boiler being unable to maintain set steam pressure. A major cause was traced to the wrong burner tips being used.
* In Sept 2005, I led the investigation to identify the root cause for operational problems on the condensate extraction pumps in stage 2. The investigation led to finding that the suction strainers were choked and the strainer DP alarms were not functioning (isolation etc).
* In Feb 2004, Unit 7 had a very bad incident of high chloride in the condensate. This was due to a tube plug coming off. Subsequently, the unit was put in operation with frequent drum blowdowns. I found that the sampling pumps were not working and arranged for an inspection. There was plenty of seawater in the sampling pump piping. The unit was subsequently returned to service and the chlorides levels returned to manageable levels. However, when the unit returned from the annual inspection on 10.4.04, the unit suffered extremely high chloride levels. Three tubes were found to leaking very badly. These leaks were new and I instructed that an inspection be made on the steam side. 8 tubes (including the three plugged) had weld slugs lodged on them.
* In May 2003, CCPP block 20 could not be placed on barring gear. I investigated the problem and found that the emergency stop valve was passing. This allowed steam to enter the turbine. Unfortunately the drain valve between the stop valve and turbine control valve was shut (logic calls for the valve to be shut after 5 hours). Further, the control valve has pilot holes too, which allowed steam to enter the turbine. Thermocouples on the HP turbine show a difference of about 100C (max should only be 30C). I recommended to the OEM to modify the logic such to remove the "5 hour reqt." and also to service the emergency stop valve.
* In December 2002, both generator seal oil pumps had to be in operation for Unit 3. I led the investigation and found out that the pump suction strainers were choked with sludge. This sludge was due to the oil being contaminated with water.
* Two units tripped in October 2002 in stage 1. One unit tripped due to boiler problem but in addition the CW pump also tripped. Since two condensers were in service this resulted in the other unit tripping also. The Operation department decided to operate more CW pumps to overcome this problem. This solution if implemented would have resulted in high auxiliary power cost as well as damage to the CW pipes due to throttling of the CW valves. The root cause of the problem was the improper functioning of the open transfer of the 6.6 KV supply and not the number of pumps in operation.
* In August 2001, Unit 9 tripped on high vibration. I led the investigation on the cause of the trip and also the inspection of components. I concluded that the root cause was due to the low LP gland steam temperature, which caused the trip. The subsequent run up was successful. Through my leadership, we saved the cost of inspecting the LP turbine and all other associated financial losses.
* In Dec 2000, Unit 1 was facing the potential of forced outage due to the FRF (hydraulic) pumps. The pump discharge filters on both pumps showed high differential pressure and the filters were being changed on a regular basis. I led the investigation to determine the root cause which was traced to contaminated hydraulic fluid. During the overhaul in January 2001, the FRF was renewed.
* In March 2000, a tertiary turbine governor valve was found chattering on Unit 3. Though there were plans to carry out an inspection of the valve, I correctly identified that it was an instrumentation problem. A governor valve inspection would be costly. Subsequently, the Instrumentation and Control department found out that the resolver (instrument) was loose and interfering with the valve control system.
* In 1994, the IP turbine of Unit 3 had undergone extensive damage due to insulation failure. I led the investigation to identify the root cause and concluded that it was due to poor thermal insulation.

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