In 2007, EDF initiated the repowering project of its Martigues conventional oil fired power plant, which will see it converted into two state-of-the-art 460 MW combined-cycle gas turbine (CCGT) units. This project is a major part of the French utility’s renewal of its fossil fuel fired generation portfolio.

Dr Heather Johnstone, Senior Editor & EDF Thermal Plant Engineering Centre, France

The Martigues power plant is located on the shores of the Mediterranean Sea, approximately 30 km west of the French port of Marseille, at the edge of an industrial area. The existing power plant is a conventional steam plant, composed of four 250 MW oil fired units, which entered commercial operation back in the early 1970s.

Over the last 35 years or so, the power station has been dedicated to intermediate duty and peak load operation, as the majority of baseload power on France’s national electric grid is supplied by a fleet of nuclear and hydropower plants.

The contribution of Martigues’ oil fired units, however, has proved time and again to be important in securing the country’s power supply. This is especially true over the winter months, where peak consumption is high.

An aerial view of the site of the Martigues CCGT repowering project, taken in November 2009
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EDF’s Martigues repowering project involves the conversion of two out of the four existing oil fired steam plants into two efficient, ‘state-of-the-art’ gas fired combined-cycle units. The new CCGT units are designed to produce 460 MW each in duct-firing mode (rated at ISO conditions), with a targeted net electrical efficiency above 56 per cent.

The repowering project also involves the reuse of two Rateau-Schneider 250 MW steam turbines, recovered from Martigues’ existing units 3 and 4, which have accumulated 85 000 hours and 51 000 hours of service at baseload conditions, respectively. The steam turbines will be retrofitted to accommodate new steam parameters and the specific requirements imposed by CCGT operation.

The two combined-cycle blocks will be in a 1-1-1 multi-shaft arrangement, with a three pressure and reheat steam bottoming cycle. The horizontal heat recovery steam generator (HRSG) will be equipped with duct-firing burners that have the capability to increase the steam turbine output by an additional 40 MW.

The implementation of supplementary firing makes sense for the Martigues CCGT project because the steam turbines from the existing plant are oversized when compared to the exhaust energy released by the gas turbine. Furthermore, the power reserve available in duct-firing mode will allow the operator to take advantage of market opportunities and/or to compensate output degradation in hot summer conditions.

The first significant milestones completed were the permitting process, detailed process studies and preparation of call for tenders to purchase the primary equipment. The Martigues 5 and 6 CCGT units are scheduled to begin commercial operation in 2011 and 2012, respectively.

Keeping it in the family

EDF Thermal Engineering Center (EDF-CIT) has significant expertise in the design and construction of gas turbine based power plants, and has a reference list of more than 20 units built over the last ten years.

More recently EDF-CIT has managed the modernization and recommissioning of several thermal power plants that had previously been kept in reserve and maintained out of operation for years. These revitalization projects, which represent a total installed capacity of 2600 MW, are now available as peaking units to back-up and secure the French power supply.

Based on this industrial experience, EDF-CIT was appointed turnkey engineer of the Martigues CCGT repowering project. In this role, EDF-CIT is in charge of overall project management, site supervision, equipment procurement, interface matching and plant process studies. At the end of construction, EDF-CIT will coordinate plant start-up and related commissioning activities, including performance tests to ensure the new units have reliable operation.

Can we reuse?

With most repowering project the ability to extend the useful life of existing components is a much more attractive option than the purchase of new hardware, and this was no different for the Martigues project.

One of the biggest challenges faced is to find the right balance between the reuse of existing equipment and meeting the high performances requirements of the new CCGT units. From an early stage in the project, this engineering process was performed by EDF field experts, who scrutinized and subjected major existing equipment to residual life assessment, together with a cost estimate of the required modifications and upgrades.

Targeted boundaries between existing and new equipment at the Martigues CCGT repowering project
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Factors such as adequate equipment design, compatibility with new equipment, reliability and availability targets and impact on long-term O&M costs were also considered.

CCGT power block design

The layout of the new CCGT plant was drawn up by EDF, in cooperation with the main equipment suppliers, to best accommodate the site specifics of the Martigues project, which include:

  • Proximity of a high-pressure gas pipeline;
  • Connection to an existing 225 kV high voltage (HV) transmission line (unit 5 only);
  • Construction of a long distance rack to support piping and cabling connections between the new-built equipment and the existing power blocks;
  • Integrated design of buried networks and liquid effluents treatment facilities to minimize environmental impact.

The GE 9FB gas turbine is a mono-shaft, cold end drive, can-annular combustor F-class machine. From a design perspective, the GE 9FB is as an evolution of the previous GE 9F/9FA engines. The transition from the GE 9FA to the GE 9FB involved machine components being upgraded or optimized to increase power output.

The GE 9FB destined for the Martigues project will be equipped with GE’s advanced combustion system, DLN2.6+. The DLN2.6+ is a mix of design features inherited from the existing DLN2.0+ and DLN2.6 versions that are said to provide enhanced stability and lower turndown on nitrogen oxides (NOx) and carbon monoxide (CO) emissions compliance. The combustion settings are optimized for a nominal fuel pre-heating temperature of 204 °C.

The gas turbine package and the related auxiliaries have an outdoor configuration.

The air intake system includes a three-stage, static-type filter arrangement, which has been designed to accommodate specific environmental conditions on the site, i.e. coastal and industrial. The gas turbine engines will be coupled to a GE hydrogen-cooled generator 330H rated 380 MVA.

Maximizing steam generation efficiency

The gas turbine exhaust gases will be used to generate steam in the horizontal HRSG, supplied by CMI, which has a three pressure levels and reheat design, with duct firing.

The feedwater entering the HRSG is gradually converted to superheated steam, which is eventually delivered to the steam turbine at two pressure levels, i.e. high-pressure (HP) and intermediate-pressure (IP).

The low-pressure saturated steam (LP) also available from the HRSG is only used to feed a separate deareator. The design constraints inherent to the repowering concept means this LP steam cannot be injected into the steam turbine.

The steam delivery pressures and the overall water/steam cycle parameters have been optimized via thermodynamic modelling tools to get the best cycle efficiencies at full load and partial loads.

The HP steam delivered to the HP steam turbine section is recovered from the steam turbine and is mixed with the main IP steam flow to pass through the reheater section of the HRSG.

This mixed and reheated IP steam – also designated as ‘hot reheat’ – is then injected into the IP steam turbine section and finally expanded through LP steam turbine section.

The LP steam leaving the LP steam turbine section will enter the surface condenser, transfering heat to the circulating cooling water and condensed into water. Under normal operating conditions, the vacuum expected in the condenser should be lower than 35 mbar.

The condensed water leaving the condenser is circulated towards the feedwater tank and the deareator via dedicated condensate pumps.

The gas fired duct burners installed in the HRSG are designed to release up to 95 MWth of additional thermal power to the HRSG, equivalent to a boost of approximately 40 MW to the power plant’s net electrical output.

Without post-firing, the condensing steam turbine would produce a maximum of 150 MW.

Two feedwater pumps are utilized to repressurize the condensate water and return it to appropriate injection points in the HRSG. The LP feedwater is extracted downstream of the condensate pumps.

The HP steam is led to the multi-stage HP superheater, the IP steam to the IP superheater and subsequently to the reheater. At the outlet of the HRSG, the HP and IP steam is attemperated with feedwater extracted from the HP economizer feedwater line and IP economizer, respectively. The LP steam is sent directly to the separate deaerator.

A continuous water flow rate is extracted from the IP economizer to feed a gas fuel pre-heater, also designated as a ‘performance heater’.

The 2 x 100 per cent main condensate pumps are reused from the former oil fired plant. During normal operation and start-up, one pump operates at full load; while other serves as a standby unit. The standby pump is automatically switched if the operating pump fails.

A single feedwater storage tank/deaerator provides feedwater storage for the HRSG, and preheats and deaerates the main condensate.

The 2 x 100 per cent HP feedwater pumps are also being recovered from the former oil plant. One pump is in operation while the second pump is maintained in standby condition can automatically switched on if the operating pump fails.

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The cycle heat rejection system will consist of the existing steam surface condenser and the open loop water cooling system. The heat rejection system receives exhaust steam from the LP steam turbine and condenses it to water for reuse.

When the full amount of HP steam cannot be sent to the steam turbine, the HP bypass system guides the HP steam via the attemperation station through the cold reheat line back to the HRSG. The water used for attemperation is feedwater that is extracted downstream of the HP feedwater pumps.

The IP/LP bypass takes the IP and LP steam flows into the main condenser via the respective de-superheating stations. For the IP/LP bypass, the water used for attemperation is the main condensate extracted downstream of the main condensate pumps.

The steam bypass has been designed to accept 100 per cent HRSG live steam mass flow at 100 per cent live steam pressure.

Steam turbine: reconditioning and retrofitting

The Rateau-Schneider steam turbine is a four cylinder model, and the shaft-line, including the generator, is supported by a total of ten bearings. Nominal rotating speed is 3000 rpm. In the original configuration, the nominal steam conditions at HP admission were 166 bar and 565 °C.

As part of the Martigues repowering project, the two existing steam turbines will be retrofitted to properly match the HRSG and the CCGT steam parameters.

The operating life of the steam turbines will be extended to run for an additional long-term service campaign, with up to 100 000 hours and 5000 starts scheduled over the next 25 years.

The retrofit of the steam turbines comprises an in-depth reconditioning of the steam path, the renewal of the auxiliary systems and the upgrading of the turbogenerator control and protection system.

The upgrade of the steam turbine will incorporate spare components reclaimed from identical steam turbines units, i.e. rotors, diaphragms, rings and seal strips components.

New steam turbine start-up procedure and related steam turbine start-up curves will be established to illustrate the updated operating conditions. Thermo-mechanical finite element models have been developed to estimate rotor/stator clearance consumption induced by the main operating transients and pre-size tightening torques of steam turbine casing bolts, and get preliminary assessment of the resulting fatigue and creep damage factors in the highly stressed regions.

These simulations will also be helpful to optimize axial re-positioning of the steam turbine diaphragms. The retrofit also foresees the replacement of inter-stage seal rings and of all studs and bolts previously exposed to high temperatures.

On each steam turbine unit the retrofitting effort includes a detailed scope of engineering studies, manufacturing, and commissioning activities. The repowering project will deal with the following steam turbine components:

  • New turning gear with automatic engagement – governed by the steam turbine generator controller (STGC);
  • New jacking oil skid, fed by lube oil header, consisting of two 100 per cent centralized jacking oil pumps;
  • Upgrade of the gland steam system, which will be interfaced with the new CCGT auxiliary steam circuits;
  • New control and safety system, which will include four servomotors for the four HP control valves and four new servomotors, for the four IP control valves. The new solution will insure a reliable and effective control loop for the steam turbine regulation, along with an improved operating flexibility. New solenoid test valves will be provided, for testing of each HP and IP emergency shut-off valve during operation;
  • new fluid control skid, including two oil high pressure pumps, double pressure on-line switchable filters, and the related instrumentation (pressure gauge, level switches). The oil specified for the project is a fire-resistant grade, following recommendations of the safety standards. The control circuit will be designed to get the best achievable opening/closing times.

Daily start-stop operation of a CCGT plant – a typical load profile
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The steam turbine safety system and related protection logics will also be upgraded, including the replacement of bearing probes, axial displacement sensors and lube oil pressure instrumentation. The new protection architecture is designed to get a SIL-3 level certification

All operating parameters will be governed by the new STGC, using a unified control network based on Ethernet TCP/IP protocol.

Ensuring operational flexibility

Within EDF’s generation portfolio the Martigues CCGT units are likely to be dedicated to a cyclic operation mode, involving frequent starts and stops and high amplitude load variations.

In a conservative scenario and depending on future electricity market trends, the plant load profile is expected to be a so-called ‘daily start and stop regime’. This cyclic operating regime can be described as:

  • Start-up sequence initiated in the early morning;
  • Full power available to the grid during daytime, when domestic residential and industrial electricity consumption are at their highest;
  • Plant shutdown at night and during weekends.

In such a scenario, a plant’s operating flexibility is widely recognized among plant operators and project developers to be a key competitive factor.

However, operating flexibility is a complex concept, for which there is no straightforward definition. Load profiles assigned to CCGT plants can significantly vary from one power producer to the other, even at the very same location, because plant operating philosophy is strongly influenced by their respective business models, composition of their generation portfolio (balance between nuclear, coal, gas, hydraulic and wind capacities), gas pricing considerations and risk exposure sensitivity.

On the Martigues repowering project, the engineering focused on improving the plant cycling capability. CCGT architecture, equipment specifications and control system have all been optimized to meet several predefined flexibility criteria thought to directly impact long-term project profitability.

From a design standpoint, the following flexibility issues were addressed as a matter of priority by the EDF engineering team:

  • Starting reliability;
  • Smooth and efficient operation throughout the full operating range;
  • Low plant turndown;
  • Optimized and automated startup sequences in hot, warm and cold conditions, within the maximum load ramps and thermal transients allowed by the major equipments;
  • Frequency response capability, capability to deliver customized grid services on demand;
  • Additional power reserve, achieved via supplementary firing.

A CCGT dedicated to cyclic operation will most likely be exposed to several thousands start/stops transients over its entire service life. These frequent start/stop cycles and subsequent load changes can induce thermo-mechanical stresses and create fatigue damage to the main components.

When compared to baseload operation, cyclic duty inevitably results in accelerated components degradation, notably affecting the boiler HP section, the HP steam turbine and the gas turbine hot gas parts. Repeated start/stops are also well-known to negatively impact water/steam cycle chemistry (dissolved oxygen).

On the Martigues CCGT project, specific design and construction provisions were made to address these cycling issues, and incorporated in equipment upfront specifications.

In addition to fatigue and O&M concerns, a good cycling-oriented CCGT design should also target maximum starting reliability and achieve reasonably short start-up and shutdown durations.

Minimizing plant start-up time is an important objective, although generally not a decisive competitive factor for a CCGT owner-operator. Safe, repeatable, fault tolerant and reliable startup procedure is preferable to aggressively fast start-up times, which are inherently more exposed to trips/failures and put mechanical integrity of the major equipments at risk.

Control logics developed by EDF engineers are targeting the shortest achievable start-up time, while conservatively keeping within the thermal gradients permitted by critical components, such as the HRSG drums and the steam turbine.

Significant gains on CCGT start-up time can be obtained by an optimal coordination of the main equipments essential to start-up. Therefore, Martigues CCGT plant start-up procedure has been carefully analyzed, split into detailed steps and illustrated by component-by-component chart diagrams.

These pre-simulated start-up scenarios helped to exhibit the critical path of plant load ramp-up to full power (from hot, warm and cold conditions) and identify the related limiting factors on gas turbines, steam turbines, HRSGs and other auxiliary systems.

Within this framework, specific design provisions were made by the plant engineering and by the OEMs in order to optimize cycling capability of the Martigues CCGT units. The following tracks were taken into consideration:

  • Advanced automation of startup and shutdown procedures;
  • Installation of a robust, adequately sized, auxiliary steam boiler;
  • Optimized control strategy of steam bypass system during start-up;
  • Reinforced de-superheating capability on HP steam circuits;
  • Mitigate undesirable cooling down of critical equipments during overnight and week-end shutdowns, thus extending duration of so-called ‘hot standby conditions’, e.g. stack damper, thermal insulation, auxiliary steam devices);
  • Stability of plant chemistry parameters;
  • Case-by-case optimization of equipments instrumentation and related control logics.

The repowering of Martigues is an important part of EDF’s renewal of its fossil fuel generation portfolio, and once completed Martigues 5 and 6 units will represent the first large-scale CCGT units ever built by EDF in France.

Construction activities on the Martigues site began in 2008. The first significant project milestones, i.e. the civil works and the installation of the turbomachinery foundations, were completed successfully and on schedule. The major equipment have been delivered on-site, and mechanical and electrical assembly works are now in progress.The first repowered Martigues combined-cycle unit is scheduled to enter commercial operation in 2011.

In parallel to the Martigues project, EDF is simultaneously managing the design and construction of four greenfield combined-cycle blocks – Blenod in France and West Burton in the UK.

Thanks go to Karim Alexandre Aabadi, Karine Lhomme, Gilles Panozzo, Carlo Stoisser, Rodolphe Verlin and Vincent Vittu of EDF-CIT for their valuable contribution to the article.

The article is based on a paper presented at POWER-GEN Europe 2009 in Cologne, Germany, which won the Best Paper Award in the ‘Track 3: Gas Fired Generation’ category.

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