Upgrading and uprating: Spain

Almaraz 1&2 power uprate

26 August 2011



Unit 2 of the Almaraz nuclear power plant in Extremadura, Spain, has now completed an intense four-year power uprate project encompassing a switch to a new digital Ovation system platform, large mechanical equipment replacement, electric equipment and first-of-a-kind software analysis at the plant. By F.J. Sanz


Studies and analysis into the feasibility of uprating the two reactors at Almaraz nuclear power station were carried out with the support of Westinghouse, Enusa and Empresarios Agrupados. This work showed the possibility of increasing the thermal power of the two units to 2947 MWt, an increase of nearly 10% from the initial plant capacity of 2686 MWt.

A small mini-uprate project based on increasing thermal power recovery by 1.6% was carried out in 2003 by recapturing measurement uncertainty through more precise instrumentation. This increased power from 2686 MWt to 2729 MWt. The power uprating described in this article added an additional 8% to bring the station up to the current 2947 MWt.

Work on the power uprating project at Almaraz began in January 2007 with the creation of a specific project group of technicians from CNAT (operator of Almaraz & Trillo nuclear power plants).

The objective of the project was to implement the power increase in unit 1 by November 2009 and unit 2 a year later. Meeting this ambitious target required a large number of design changes and analysis, as well as the design and manufacture of complex equipment including power generators and high-pressure (HP) turbines.

The project has required the replacement, expansion or adaptation of a range of equipment and systems. Design modifications developed in the power uprate project included:

Project REGEN (alternator replacement)

  • Changing the alternator and exciter
  • Installation of new cooling equipment associated with the alternator

Increased Power Project:

  • A new high-pressure turbine
  • Changing the condensate pump (CD) and the heater drain pumps (HD)
  • Installation of new ventilation equipment (BFA)
  • Changes in the Turbine Building cooling system (TC):

– Expansion of the TCA system cooling towers

– Implementation of a new system of cooling towers, TCB

– New water supply system to the cooling towers

– Power supply. Implementation of a new electrical enclosure

– New power supplies (power centre and motor control centre) in the turbine building.

  • New HD valves and improved digital control of heater drain system
  • Changing internal pressure safety valves (PSV) and new sewer line.

Project scope

Refurbishment of the main transformers for the new electrical power took place ahead of the uprating project. An additional reserve transformer was acquired to make necessary changes in a phased manner without interfering with the operation of the plant.

To address flow-assisted corrosion, the original moisture separator re-heaters (MSRs) had already been replaced during refuelling outages in 2007 (unit 2) and 2008 (unit 1). The MSRs were replaced with a more advanced design adapted to the new conditions associated with the power increase. The new design allows an MSR performance improvement of 10 MWe for each unit, and reduces the potential for flow-assisted corrosion through materials used and the decrease of velocity inside the unit.

During the project a new digital control system was installed to control drain tank levels. The alternators and associated equipment including hydrogen coolers; stator water cooling (chillers, pumps, filters and components); isolated phase bus bar coolers, seal oil coolers, chillers and exciter were also replaced. Further detail is outlined below.

The new intercooled alternators are designed and manufactured by Siemens. The specification is 1180 MVA at 1500 rpm, power factor of 0.9 and 75 psig hydrogen pressure. The generation voltage, 21 kV, is unchanged, but the new alternator allows higher voltage variations, -8.5% to +6.5% (19.22 kV to 22.37 kV), allowing greater flexibility to suit the requirements of the network. The ratio of current in to current out becomes 40000 A/5 A and incorporates three new transformers in the generation terminal.

Rather than adapting the existing turbine to accommodate the increased power of the reactor, the team chose to substitute it with an improved design.

The rotor of the new high-pressure (HP) turbine (pictured above) has 15 rows of blades, incorporating mobile 3D blades for greater efficiency and to reduce the secondary losses of the early stages.

The stationary part of the HP turbine is made up of a new intake ring, inner casing and two stationary blade carriers (one for each stream). The inner casing supports 14 sets of stationary blades (seven for each stream) and is designed for the new conditions of pressure and temperature of steam entering the intake section. The blade carriers each support seven stages of stationary blades.

Modifications to the condensate (CD) pumps and heater drain (HD) pumps were also necessary. The increase in power requires an increase in heat transfer from the steam generators. This increase is created mainly by a 9.5% increase in the flow rate for the main feedwater pumps. In order to maintain operating margins in both feedwater pumps and valves, the pumps will operate at the same speed (4800 rpm), to stay on the same Q-TDH curve, and valves will have equivalent openings. The decrease in the total dynamic head (TDH) of the feedwater pumps associated with increased flow (as expressed by Q) is offset by the increase in their suction and a reduction in the pressure of the steam generators.

The increase in the suction pressure of the feedwater pumps and the 9.5% increase in flow is achieved by replacing the CD and HD pumps for new pumps with higher Q-TDH curves.

The cooling of isolated phase bus bars was modified by splitting the circuit to the three single-phase transformers in one side and to the main generator in the other side. The ventilated isophase ducts now include connecting legs between single phase transformers (triangle connection). The new ventilation system, TCB, ensures proper operation of the bars to a maximum intensity of 36 kA, exceeding the maximum intensity of expected generation and incorporating a higher level of redundancy in components and instrumentation, improving availability and operation.

The increase in the thermal power of the plant to 108% (2956 MWt) and replacement of the generators also meant that the turbine plant cooling water system, TC, has to remove a thermal load 30% higher than the previous load. Following successive performance improvements (to turbines, MSRs, etc) the original system was found to be insufficient to remove the thermal loads and maintain the temperature of the turbine building cooling system below 35°C throughout the year. A turbine building auxiliary cooling system, TCA, was therefore added to feed the hydrogen and exciter coolers during the hottest season. This TCA system comprises five cooling towers per unit.

Likewise, to be able to achieve the power uprate indicated and satisfy the requirement to keep the TC system water temperature below 35°C, it proved necessary to extend the TCA system with three new cooling towers and add another backup system, TCB, which also forms an assembly of three cooling towers (per unit, in both cases).

Both auxiliary cooling systems, illustrated in Figure 2, consist of forced-draft towers (cooled when the original TC system is inadequate), water coil, exciter and isolated phase bus bar rods (TCB) and the enhanced alternator hydrogen cooling system (TCA).

Replacement of the pressure safety valves (PSVs) as also necessary as the power uprate feasibility analysis identified that some accidents would require a rapid reduction of pressure in the pressuriser, greater than those margins available before the uprate. Resolving this issue required the removal of seal water from the PSVs. This could only be achieved by changing the valve type to match the internal pressure so that the valves seal under steam. Additionally it was necessary to establish a continuous drain in the water seal of the pressuriser.

Licensing process

Permission from the Ministry of Industry and Energy had to be gained prior to regulatory approval from CSN, the Nuclear Safety Council.

All documentation was completed and paperwork filed with the Ministry on 31 October 2008. The documentation included:

  • Technical description of the modification. The description and its justification were reflected in the licensing report. The licensing report followed the structure and content of US NRC guide RS-001, Rev. 0, December 2003, ‘Standard review for extended power uprate’
  • Safety analysis
  • Identification of documents that would be affected by the amendment, including the proposed text for the Final Safety Analysis and Performance Specifications
  • Identification of the tests necessary prior to the resumption of operation. The licensing report included a review of the capacity of all major systems of the plant, including electrical systems, cooling capacity and safety margins for postulated accidents in the final safety evaluation report.

The tests, carried out to verify the design margins and fuel integrity, covered the following areas:

-Determination of new operational parameters with increased power

-Accident analysis for new plant conditions necessary for licensing the increase in power:

  • Nuclear and thermo-hydraulic design work
  • Large primary break loss of coolant accident (LB-LOCA)
  • Small primary break loss of coolant accident (SB-LOCA)
  • Non-LOCA accidents
  • Anticipated transient without scram (ATWS)
  • Evaluation of LOCA consequences
  • Mass and energy discharge (from steam line breaks, LOCA)
  • Possible pressure and temperature transients
  • Analysis of radiological consequences
  • Evaluation of the fuel
  • Impact assessment in primary and secondary systems
  • Impact on components
  • Impact on generic programmes.

The latest tools and codes available in the industry were incorporated into the accident analysis.

The analysis of a pipe break accident in the primary circuit (LOCA) for the new conditions of increased power required the use of a methodology not previously used for LOCA accidents at CN Almaraz.

We used the ‘best estimate’ methodology for LB-LOCA with automated statistical processing (Astrum), based on nuclear steam supply system modelling with WCOBRA/TRAC and a Hotspot rod code. This is the only methodology that Westinghouse has used in current LB-LOCA analysis reviews, and it covers safety issues not previously addressed by other models.

Astrum, licensed by the NRC in November 2004, is a methodology that is sufficiently mature to have a number of applications in the US and Europe. Astrum is an evolutionary advance of a Westinghouse LOCA statistical analysis methodology approved by the NRC for 3- and 4-loop plants in 1996.

Moreover, the analysis of containment pressure and temperature for mass and energy discharge in case of LOCA, or rupture of a main steam pipe, required the use of a new analysis code. The code used, Gothic, required the development of a containment model of the Almaraz reactor. The Gothic code was developed by Numerical Applications Incorporated (NAI) with funding by the Electric Power Research Institute (EPRI) and is approved by the NRC for applications in containment analysis.

The Ministry of Industry and Energy authorised the increase in power at unit 1, in December 2009, and at unit 2 in December 2010. Approval to operate at the increased power output, however, was made contingent on a testing programme.

The uprating testing programme aimed to demonstrate the safe performance of reactor structures, systems and components at increased power output. In particular, it aimed to demonstrate:

  • Adequate control of power rising up to the conditions of increased power.
  • Plant will operate under conditions of increased power in accordance with the design basis without compromising safety and public health.

Design modifications associated with power uprate project have been implemented correctly.

The CNA testing programme was based on the US regulation 10 CFR 50, Appendix B, criterion XI, and specific requirements for the definition of the testing programme of increased power are described in Regulatory Guide L.68 “Initial Test Programs for water-cooled Nuclear Power Plants” Rev. 3, and NUREG-0800, SRP 14.2.1, “Generic Guidelines for Extended Power Uprate Testing Programs” (Rev. 0, December 2002).

As part of the programme, CN Almaraz analyzed the dynamic response of the plant with the RELAP5 code for thermohydraulic simulation (with automatic best-estimate). The simulation model of Almaraz with Relap5/Mod3 (numerical) + NPA (graphical), called Almaraz Plant Analyzer (APA), has been validated against numerous real plant transients and the transient generator for validation in the full scope simulator for operator training.

Once the three conditions outlined above were met, the units were given permission to operate at the new maximum power of 2947 MWt. For unit 1 this occurred on 15 April 2010, and for unit 2 on 13 April 2011.

Activities

Although work on the unit 2 assembly benefitted from lessons learned during the implementation of unit 1 modifications, this work was more complex due to the different arrangement of the components to be replaced and the different configuration of the turbine building.

While moving the unit 1 stator did not require any lifting of components, this was not the case in unit 2, where the stator had to be lifted out of the building. Additionally, the placement of equipment associated with the generator auxiliary systems and condensate pumps in the central area of the building necessitated the removal of equipment to make way for replacements and for new equipment.

Although the turbine crane has a capacity of 180 tons, the stator has an approximate weight of 455 tons. A temporary crane gantry was required to lift and rotate the stator in order to relocate it. Given the characteristics of the turbine building, a beam system at the top of pillars of the building was used to manoeuvre loads up to 400 tons; with some weight distributed on the pillars. Calculations considered both the stator weight and beam system to determine a maximum load (conservative calculations) on the top of pillars of around 400 tonnes, which was lower than the allowable design value for the pillars. During the movement of stator the real load on the pillar was measured at 288 tons.

The features of the crane gantry installed were: height from ground 13.712 m; girder wheelbase 11.450 m; displacement 42.660 m. The manoeuvre required replacement of legs to allow increased stator turn at 3.450 m, with a displacement of 9.750 m to turbine building crane bay and total lift of 18.600 m.

The extraction of the old stator and the introduction of the new stator were complex and highly precise operations lasting 26 and 20 hours respectively. Figure 3 is a photograph from the operation showing new stator while it was being guided into the required position.

The extraction of condensate pumps and introduction of the new complex required the removal of old pump cans. During the preparatory analysis of the assembly work, study of the pumps showed that the free space (100 mm) between the can and the well bore was concreted the entire length of 10.209 m. The old can was removed and cut into pieces of about 3-4 meters by operators who had to descend through a hole in 1.300 m diameter to a depth of 10.209 m. These space restrictions necessitated using some frames, lifting and breathing aids, and a ventilation shaft.

After cutting and removing the cans, the remaining concrete had to be demolished. This subsequently allowed the introduction of new cans required for the new pumps, also 10.290 m long. Demolition and removal of existing mortar 100 mm in thickness across the shaft wall required installing a metal structure allowing simultaneous access to three wells of the condensate pumps and removal of debris by baskets. This frame had dimensions of 8.500 m x 3.200 m x 5.108 m.

The new larger pumps and motors required moving a series of piping and cable trays, and necessitated the movement of some 600 cables.

As indicated above, due to the location of the skid for the new alternator auxiliary systems, it was necessary to install a 7500 kg gantry crane in the heater drain pump access holes to insert and remove water cooling coil components.

Additionally, it was necessary to open a gap of 4.0 x 3.0 m in the east wall of the turbine building for access to extract and insert sealing oil system components as well condensate pump well debris.

As a result of the new location of the refrigeration unit for the isolated phase rods required removing.

The old isolated phase bus bar cooling unit located inside the building was removed and the new unit was installed outside the turbine building with the corresponding modification of ducts for cooling the generator zone and the new zone for triangle connection.

Finally it should be noted that in addition to the big manoeuvres described above, the scope of changes included modernising the control system of heater drains and an improvement in the control, supervision and monitoring of parameters associated with new turbine cooling systems and components incorporating vibration monitoring systems installed for major equipment. Assembling both instrumentation and signal wiring required more than 1000 alignments for wired and communicated signals, which gives some idea of the work required to fit new equipment and systems.

Lessons learned

As previously mentioned, the complexity of assembly and manoeuvres for unit 2 were much greater than for unit 1. Work in unit 2 required not only application of the lessons learned from the assembly but also specific analysis and resolution of physical blockages in unit 2. The greater height of the gantry structure required the longest rail beams with interference with existing MSRs. The need to save the carcasses of the low-pressure turbines required the removal of a large number of interferences and subsequent re-assembly.

In addition, following the introduction of changes in unit 1 as the results of tests performed during the start-up sequence and transient dynamics of the unit, specific lessons learned meetings were held to implement improvements in unit 2.

Monitoring the operating parameters of the new systems led to a number of changes to improve the heater drain system control, improve the performance of control valves’ water supply, temperature control of the pump heater drains, and so on.

Notable among the improvements made was the reduction in random vibrations of the condensate pump, which occurred at a frequency of around 8 Hz. The analysis of vibration spectra and of the specific models developed pinpointed the cause of the vibration not in the pump itself, but in the vortices that are produced in the first stage (double inlet impeller). The design and installation of an anti-vortex grid has reduced the excitation and the vibration level at this frequency from 12 mm/sec 0-peak to 2 mm/sec 0-peak.

Conclusion

The power increase at Almaraz unit 2 was made within the previously established programme. Costs were in line with the approved budget and the specifications for equipment, design and workmanship were all met. This has been shown in system tests during the start-up sequence, verifying the correct dynamic response of the plant transients.

It has been a complex project, which has undergone many changes. External organizations have participated as have a large number of professionals to whom I wish to express my gratitude and satisfaction. After four years of working together, we can all feel proud of the results.


Fig. 1: The new HP turbine rotor during assembly Fig. 1: The new HP turbine rotor during assembly
Fig. 2: An overview of the new auxiliary cooling systems A and B (TCA/TCB) Fig. 2: An overview of the new auxiliary cooling systems A and B (TCA/TCB)
Fig. 3: Alternator/stator lifting manoeuvre Fig. 3: Alternator/stator lifting manoeuvre
Fig. 4: Installation of the condensate pump assembly Fig. 4: Installation of the condensate pump assembly
Fig. 5: Assembly, testing and commmissioning team Fig. 5: Assembly, testing and commmissioning team


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