Across the world there are high-hazard nuclear facilities which need to be decommissioned. Dismantling redundant equipment safely and cost-effectively is one of the biggest challenges facing the industry today, and an increasingly major issue for operators.

In 2014 the International Energy Agency said that almost 200 of the 434 reactors in operation around the globe would be retired by 2040, and estimated the cost of decommissioning at more than $100 billion. Some commentators felt even this was a great underestimate.

To meet a challenge of this scale, innovation will necessarily have a key role. With the engineering, safety and working time restrictions which apply to ‘active’ nuclear site environments, new technologies that can distance the human operator, be more efficient and save time can potentially play an important part in future decommissioning.

In summer 2016, OC Robotics led a demonstration project at the Sellafield site in northern England, to showcase one such new development which could transform the approach to dismantling redundant equipment.

For the project, called LaserSnake 2, a team led by OC Robotics integrated a high-powered laser cutter with a remotely-controlled snake-arm robot, and used it to cut up a 5.5 tonne steel dissolver vessel at the Sellafield site. While similar work has also been done in France, the LaserSnake 2 team was the first in the world to complete dismantling of a dissolver vessel using this technology.

The seeds of the LaserSnake 2 project were sown in 2001, when at OC Robotics we began to develop and build long, flexible, multi-jointed robotic arms. Software-driven and controlled by wire cables inside the arm, they are highly dextrous and can navigate through small spaces and cluttered environments, moving around and over obstacles. Depending on the equipment they carry, they can perform tasks such as inspecting structures, cleaning, sealing and welding.

Around 2011 we saw that there was potential to use such snake-arm robots in nuclear decommissioning work. Working with laser experts TWI (formerly known as The Welding Institute) we carried out a feasibility study, supported by the UK’s innovation agency Innovate UK, to integrate a snake-arm robot with a laser-cutter head.

In 2012, Innovate UK announced a competition for innovative ideas in decommissioning technology, with the winners receiving grants funded by Innovate UK, the UK’s Department for Energy and Climate Change , and the Nuclear Decommissioning Authority (NDA). Based on the success of the feasibility study, we applied and succeeded in winning a grant towards the costs of a full-scale demonstration. We called this project LaserSnake 2.

Marrying a snake arm and a laser cutter

The snake-arm robots developed by OC Robotics had already been used for inspection, welding and other remote tasks, for example in the aerospace and automotive industries. The concept was proven, but this would be an entirely new application.

Meanwhile our partners in the project, TWI (formerly The Welding Institute) had been developing laser-cutting processes since 1967, and successfully deploying the technology in many industries. TWI had previously tested laser cutters with conventional industrial robots to dismantle pond skips at Hinckley Point A in the UK – but only in a purpose-built decommissioning facility.

The question was, could a snake-arm robot effectively be fitted with a laser cutter for in-situ dismantling in a nuclear facility? The 2011 feasibility study showed that potentially it could.

To create a workable integrated system for this ‘live’ environment required both innovation and collaboration. OC Robotics and TWI teamed up with the UK’s National Nuclear Laboratory, and specialist companies ULO Optics and Laser Optical Engineering.

The LaserSnake’s cutting head is integrated with the flexible robotic arm. Photo courtesy: OC Robotics

For the project, we spent three years improving many of the mechanical, electronic and software aspects of our existing robots. The result was a new snake-arm robot with up to 4.5m (14.7 ft) of flexible length – double that of previous models – greater arm curvature and a payload increased from 5kg (11lb) to 20kg (44lb). This meant it could carry not only the laser cutting head but also a navigation camera, HD inspection camera, lighting and sighting lasers. Proprietary software which we developed allowed precise navigation and positional control of the laser cutter, working from a CAD vector file, or programmed by an operator.

The laser used for the dismantling task was a commercially-available unit producing 5kW of output power. The laser beam travelled via a 200 micron core diameter armoured optical fibre inside the snake-arm to the cutting head.

The laser-cutting head itself was developed by specialist company ULO Optics The cutting head, designed specifically for decommissioning, was configured to require little adjustment on site and weighed less than 2kg (4.4lb). The optical system focused the laser beam to a spot approximately 0.4mm (0.01 inches) in diameter, 15mm (0.6 inches) beyond the tip of the cutting nozzle. In trials, we found that this setting gave good cutting speeds, given the material to be cut, as well as tolerating variations in the distance from the cutting tip to the surface of the material being cut. This was important as it reduced the precision needed, and therefore the programming time, when setting the cutting paths.

ULO Optic’s laser cutting head also included a compressed air feed, with two roles – to cool the optics and to provide a stream of air alongside the laser to blow away the molten material and help the cutting process.

The challenge

At Sellafield, as part of their Future Decommissioning Strategy, the site operators continually seek new solutions for decommissioning challenges.

LaserSnake 2 fitted this brief very well, and the decision was taken to work with the project team to carry out a live demonstration.

The task chosen for the demonstration was the dismantling and removal of a steel dissolver vessel in Sellafield’s First Generation Reprocessing Plant. This was a real live problem facing the Sellafield decommissioning team. The vessel, situated on the eighth floor of the building, was 1.3m (4.25 feet) in diameter and weighed approximately 5.5 tonnes (6 tons). It had a dual-wall construction consisting of a 12mm (0.5 inch) thick outer shell and a 32mm (1.25 inch) inner shell, separated by a 40mm (1.5 inch) air gap.

The vessel was inside a concrete walled cell. In earlier work it had been taken off its mounting and cut into three sections using a diamond wire saw, but to remove it from the cell it needed to be reduced to much smaller pieces, each weighing no more than about 25kg (55lb).

The LaserSnake in action dismantling the dissolver vessel. Photo courtesy: OC Robotics

The conditions in the cell were categorised as C3/R4 with contact dose readings within the vessel up to 12 milliSv/hr.

This vessel was representative of the many challenging items likely to be encountered in decommissioning at Sellafield Site. In many of the cells on the site, due to radiation levels, access is either very limited or impossible without significant work to reduce hazards. Where manual dismantling of equipment is still possible, traditional cutting methods take a long time – exacerbated by the challenges of avoiding contamination spread and working in restrictive protective clothing.

In the past, bespoke remote working systems using traditional cutting tools have been created for such facilities, but they have often been expensive and unreliable. Plasma cutting was very challenging due to the precision needed, the length of time the process would take, and the number of cell entries.

In all, this made an excellent test case to demonstrate the potential of LaserSnake technology.

Deploying the LaserSnake

In the first half of 2016, Sellafield’s Active Demonstration team carried out a programme of work to prepare for deployment of the snake-arm robot. This included making the cell safe for laser light and installing a filtration unit, compressed air supply, electrical distribution, CCTV and lighting. The team also provided the necessary assessments, planning, documentation and logistics.

Working together, we then installed the system in its position. The body of the snake-arm system, with the laser generator and electro-mechanical systems, was outside the concrete cell containing the dissolver vessel, with the arm positioned to enter the cell through a hole drilled in the 5ft thick concrete wall. From arrival on site the system was installed in one week. We worked closely with Sellafield Ltd to create a modular containment system. When the snake-arm was pushed into or withdrawn from the cell, the negative air pressure in the cell prevented release of contamination. During cutting the arm was covered by a sleeve sealed to the wall, isolating the housing from the cutting process. The rail drive mechanism used to push the snake-arm into the cell was also sealed and its rack and pinion were left unlubricated to reduce the likelihood of trapping contaminants.

The controls and display screens were positioned at a workstation outside the cell, from where the operators would manage and monitor the cutting process.

Making the Cut

With everything in place, the cutting programme began in July 2016.

The LaserSnake arm was moved into the cell, directed remotely and monitored on screen. Tackling each of its two steel skins in turn, the cylindrical dissolver vessel was cut into man-handleable sections. The angle of the cutting beam was carefully managed so that the beam lost most of its energy as it passed through the steel, and the process was planned so that any residual energy struck other parts of the dissolver vessel rather than the structure of the cell. In this way no additional laser beam absorbing materials needed to be used until the very last cuts. Planning the cut angles was important to ensure the cut pieces of the vessel wall fell away rather than being trapped by their shape.

In 45 hours of cutting, over 66 metres (656 feet) of cuts were made at a typical speed of 80mm (3.1 inches) per minute. Due to the angles, the laser was frequently cutting through up to 60mm (2.3 inches) of steel, and at one point, on a flange, the thickness of material to be cut reached 75mm (2.9 inches)

By the end of the process in August 2016, the vessel had been successfully reduced to around 175 pieces, each weighing approximately 25kg (55lb) as planned, which could then be removed from the cell.

With installation, programming and cutting time and complete removal of the LaserSnake system, the team had spent a total of 48 days on site.

The LaserSnake is operated remotely from outside the cell. Photo courtesy: OC Robotics

Chris Hope, Sellafield’s decommissioning capability development lead, says that in this trial remote-controlled laser cutting has proved to be a far better solution than the alternatives. And for him, the most impressive aspect of the project was the speed of implementing this advanced technology on site. By adopting a ‘fit for purpose’ attitude, and through great teamwork, the partners planned and completed a potentially game-changing project in around a year from Sellafield’s first involvement. On the actual delivery and set-up phase, Chris Hope says “we had three objectives: to get the laser onto the site, to install it and to fire up the laser and do some cutting. We did all of that within a week.”

The challenges for the project partners were not just about engineering but about regulatory compliance and logistics – from nuclear safety courses for OC Robotics and TWI staff, to detailed planning to co-ordinate the work of the different teams.

To quote Chris Hope again, “This has been the best collaborative project the team have delivered. To bring new technology onto the site and enable a potential step change in decommissioning operations has been really rewarding.”

The project went on to win two awards in 2016; one an internal ‘Business excellence – people’s choice’ award from the site staff at Sellafield, and the second a Technology/Innovation Implementation award from the Nuclear Decommissioning Authority as part of the 2016 NDA Estate Supply Chain Awards.

Encouraged by the success of the project, the NDA is now funding a new competition, together with Innovate UK and Sellafield, to encourage further collaborative innovations in the decommissioning sector.

Meanwhile Sellafield Ltd are now looking at opportunities to make this kind of laser-cutting technology ‘business as usual’ around the site, to help dismantle other redundant items of plant.

They expect that in the foreseeable future the technology will be used routinely. Rebecca Weston, Technical Director for Sellafield Ltd, said “robotics is becoming an important part of our daily activities. The ability to support our clean-up mission by accessing areas that are too radioactive for human entry makes new robots, like the LaserSnake, an essential part of the team.”

With a typical remote cell estimated to cost around £15m ($18.7m) to decommission, the cost of decommissioning cells at Sellafield amounts to billions of pounds. The signs are that systems such as the LaserSnake, which can significantly reduce the time and personnel input required for dismantling tasks, have the potential to deliver major savings for nuclear decommissioning operators wherever they are in the world.

Nuclear Power Plants (NPPs) have been studied as a source of both electricity and heat for an array of cogeneration (cogen) configurations. These have included heat service for: (i) industrial processes (e.g., pulp and paper), (ii) food processing (e.g., corn milling and downstream operations), (iii) hydrogen production, (iv) heavy water production, (v) district heating, (vi) oil sands recovery, (vii) oil field production enhancement, and (viii) sea water desalination.

To date however, nuclear cogeneration applications have been limited, primarily to district heating in the former Soviet Union and Eastern Europe, and heavy water production in Canada. Based on the current global price for oil and energy, this technology is not economically viable for most countries.

With oil and fossil fuel prices known to be highly volatile, and the Paris Agreement calling for a reduction in fossil fuel use, the economics of heat supplied by nuclear power may return to favor. As a minimum, cogen design may improve NPP economics by increasing operational flexibility and diversifying the revenue stream. To prepare for such a scenario, this study investigates design considerations for a prototypical modern Pressurized Water Reactor (PWR) plant, the Korean designed and built Advanced Power Reactor (APR1400) (e.g., Shin Kori Units 3, 4; Shin Hanul Units 1, 2; Barakah Units 1, 2, 3, 4).

Nuclear cogeneration can impact balance of plant system and component design for the main turbine, and condensate, feedwater, extraction steam, and heater drain systems. The APR1400 turbine cycle is reviewed for a parametric range of pressures and flow rates of the steam exported for cogeneration to identify changes to the established design and to determine operational constraints.

ADVANCED POWER REACTOR 1400 Overview

The APR1400 is an evolutionary Pressurized Water Reactor (PWR) developed in the Republic of Korea2. The design is based on the previous Korean reactor technology, the Optimum Power Reactor (OPR1000) which was successfully deployed in South Korea. The APR1400 is licensed for 3981 MWt (core). The first APR1400 unit, ShinKori Unit 3 is currently undergoing startup testing.

Secondary System Description

The steam cycle of APR1400 is comprised of the main Turbine-Generator (T/G) and associated support systems, and the Main Steam (MS), Extraction Steam (ES), Condensate (CD), Feedwater (FW), and Heater Drain (HD) Systems. The turbine-generator system consists of one (1) High Pressure Turbine (HPT) and three (3) LPTs coupled with the half-speed, 4-pole main generator. The cross-around steam passes through moisture separator reheaters with two stages of reheat.

The APR1400 CD and FW systems consist of seven (7) points of heating. Extraction lines transport heating steam from the LPTs to the LP FWHs and the deaerator, and from the cross around piping and HPT to the HP FWHs. The arrangement of the steam cycle is illustrated in Figure 1.

APR1400 Coupled with a Desalination Plant

In 2009, the Emirates Nuclear Energy Corporation (ENEC) awarded a contract for four (4) APR1400 units to the Korea Electric Power Corporation (KEPCO). Construction on all four units is proceeding. Due to climatic conditions in the UAE, water shortages across the Middle East, and a rapidly growing population, the potential for seawater desalination coupled with the APR1400 plant has been previously investigated.

This analysis presents a number of economic and technical advantages of combined power and water generation using APR1400 technology. However, the study did not address design considerations related to the APR1400 steam cycle. Those issues are addressed here.

METHODOLOGY

The study examines the possibility of coupling the current APR1400 design with a cogeneration application by exporting steam from the turbine cycle. Two locations for steam export were selected: (i) in the main steam line upstream of the Turbine Stope Valve (TSV) (High Pressure Export, or ‘HPE’), and (ii) from the cross around steam between the 1st and 2nd stage reheater bundle (Low Pressure Export, or ‘LPE’) [Figure 1]. The steam export interface was based on thermodynamic parameters in the cycle such as pressure and temperature. It was also assumed that there should be as little design modification as possible to simplify the licensing process and minimize the impact on operations.

Based on the pre-study, the decision was made that economic justification for the cogeneration projects requires a large and significant quantity of export steam. Two cases, one with ~500 and on with ~1,000 MWt of export steam heat were considered. The analysis for these values was performed using Microsoft Excel by respecting mass and energy balance in the cycle.

The base steam cycle is for the APR1400 design for the 60 Hz market as described in the Design Control Document4. However, for large quantities of LPE steam, the cross-around pressure is significantly depressed, and as described below, this results in a large power increase for the HPT and a severe challenge for the MFWP turbines. Therefore, a second case, the ‘modified’ T/G is also examined. For this case, the cross-around pressure for the VWO condition is raised ~15%. A higher cross-around pressure results in an overall production penalty (~7 MWe) but ameliorates several operational challenges for systems and components for both HPE and LPE steam conditions.

Design conditions were examined for the following systems: (i) MS System, (ii) Cross-Around Steam System, (iii) ES System, (iv) CD System, (v) FW System, and (vi) HD System. In addition, components subject to design challenges were reviewed, including: (i) Turbine-Generator, (ii) Feedwater Heaters, (iii) Moisture Separator Reheaters, (iv) Main Condenser, and (v) Main Feedwater Pump (MFWP) Turbines.

RESULTS

Steam cycle heat balances were computed for the configuration per Figure. 1 for both the baseline T/G and for the modified T/G with an increased cross-around pressure. Twelve cases were considered in all as follows:

1. B – APR1400 Baseline T/G
   1. B-VWO – Valves wide open case
   2. B-100 – 100% reactor power case
   3. B-H1.6 -1,600,000 lbm/hr HPE steam baseline case
   4. B-H3.2 – 3,200,000 lbm/hr HPE steam baseline case
   5. B-L1.6 – 1,600,000 lbm/hr LPE steam baseline case
   6. B-L3.2 – 3,200,000 lbm/hr LPE steam baseline case
2. M – APR1400 Modified T/G
   1. M-VWO – Valves wide open case
   2. M-100 – 100% reactor power
   3. M-H1.6 – 1,600,000 lbm/hr HPE steam modified case
   4. M-H3.2 – 3,200,000 lbm/hr HPE steam modified case
   5. M-L1.6 – 1,600,000 lbm/hr LPE modified case
   6. M-L3.2 – 3,200,000 lbm/hr LPE steam modified case

The thermodynamic parameters were calculated for each case and then used in further analysis of key steam cycle design conditions. As indicated below, large quantities of export steam present challenges for the design of systems and components. In particular, the following parameters experience significant adverse changes which may require re-design: (i) HPT shaft power, (ii) steam velocities in ES lines, and (iii) HD drain control valve capacity.

Table 1 presents the shaft power and electricity generation with and without cogeneration. Generally, LPE operations lead to considerably increased high pressure turbine shaft power and this is applicable to both baseline and modified turbine cases.

Due to changes in volumetric steam flow while operating with steam export, some of the steam lines may not be suitable for cogeneration operations. It was assumed that the current APR1400 design can accommodate a 5% increase in flow velocity within existing design margins. Table 2 presents results for steam line sizing analysis. If the calculated line velocity exceeds 105% of the baseline case, the line velocity is indicated as a percentage of the baseline velocity. For the case of MS and 2nd stage reheating steam (Rht. 2), there is no adverse impact to design associated with cogen operations. However, a significant velocity

Analysis was also performed for HD System and MSR drain control valve sizing. Again, a calculated value of less than 105% of the base case requirement was considered to be within normal design margins, and would not require a change to hardware. The analysis indicates adequate margin across all valve positions in the current design for the following cases: (i) B-H1.6, (ii) M100, (iii) M-H1.6, and (iv) M-L1.6. For other cases and valve positions, the increase in required valve capacity is from 8 to 34%.

Design Considerations

Beyond the most significant impacts of cogen operations identified in Tables 2 and 3, a review of system and component design considerations is provided below. In general, design for cogen operations would start with design requirements for steam export and condensate return quantities and thermodynamic parameters and the interface locations with the APR1400 steam cycle. While the analysis supporting this paper did not identify significant design changes beyond those identified above, the review should encompass the scope described below.

MS System – As described previously, MS piping is not adversely impacted by cogen operations. However, additional analyses should be conducted for the safety and non-safety portions of the MS system. Due to bounding thermal, weight, seismic, and fluid transient loading conditions, no changes to the piping, piping supports, or components of the MS system is expected. A design review for cogen should include confirmation of:

• design pressure and temperature ratings,
• throttle margin revision,
• pipe stress and support load analysis,
• steam hammer loading, and
• containment isolation capability.

Cross-around Steam System – The T/G supplier is responsible for this piping as part of the scope of supply for the T/G. Impacts due to changes to steam pressure and mass flow rate can be significant, particularly for the LPE cases. A few design challenges were identified for this system including:

• Cold Reheat, and
  • Velocity analysis for Low Export Pressure cases
  • 1st Stage reheating steam velocity for all design conditions.
• Cross-Around Relief Valve (CARV) sizing and pressure setpoint.

ES System – Velocities increase in ES lines for every case with steam export. Velocity in these lines can impact Flow Accelerated corrosion (FAC) rates and vibration induced fatigue failures in expansion bellows. Any changes to ES line sizing will also impact sizing of inline valves. Therefore, the review of the ES System for cogen operations should include a review of:

• ES nozzles and line sizing,
• ES expansion bellows (e.g., design to EJMA criteria),
  • Limiting steam velocity revision
  • Stress loading
• ES Non-Return Valves (NRVs), and
• ES Block Valves

CD and FW Systems – It was determined that there is no adverse impact on the CD and FW systems. Flow rates remain with the existing design basis. CD pumps will see a slight decrease in flow. Analysis of the FWBPs and MFWPs indicates no material changes to the following parameters: (i) pump flow, (ii) NPSH ratio, (iii) pump speed, and (iv) flow vs. Best Efficiency Point (BEP) flow.

HD System – HD System drain control valves, both normal and emergency, are expected to see a significant increase in required capacity for steam export operations. This is associated with an increase in drain flows and a decrease in extraction pressures. For the HD System, the detailed design review should address:

• normal drain control valve sizing,
• emergency drain control valve sizing,
• line sizing, and
• pipe stress and support design.

T/G – The T/G vendor should be required to design for the full range of expected operations. A series of bounding heat balances should be prepared and provided to the vendor. The scope of review is the responsibility of the vendor. However, as a minimum the vendor would be expected to consider the following for impact:

• T/G shaftline analysis,
  • rotor dynamic analysis
• HPT throttle margin,
• overspeed protection analysis,
• Turbine Water Induction (TWI) analysis,
• steam flow path design considerations,
  • moisture management (including changes to crossing the Wilson line)
  • blade design optimization
• Last Stage Blade (LSB) design and optimal exhaust area determination,
  • low load performance analysis
  • low load stress analysis
  • self-excitation analysis (stall and unstalled flutter considerations).

FWHs – The FWH vendor should be directed to consider in the design the full range of conditions represented on design basis heat balance diagrams for limiting operations with and without export steam. Design considerations for the tube side include:

• tube side design pressure and temperature,
• tube side nozzle velocity limits,
• tube velocity limits, and
• pass partition plate differential pressure.
• Design considerations for the shell side include:
• shell side design pressure and temperature,
• shell side shell to bundle clearance and steam velocity,
• steam inlet and drain outlet nozzle velocity,
• drain inlet nozzle flux parameter,
• drain cooler inlet window velocity,
• operating vent capacity,
• condensing zone tube support plate spacing,
• drain cooler zone baffle plate spacing,
• impingement plate sizing,
• thermal centerline and nozzle locations,
• condensing zone tube vibration analysis for all design basis conditions, and
• drain cooler zone tube vibration analysis for all design basis conditions

MSR – In the design considered here, the MSR is configured for LPE steam extraction between the 1st and 2nd stage. For this and other impacts (e.g., high steam flows are reduced cross-around pressures), the MSR is one of the most impacted components under cogen operations. Design consideration of MSR should include:

• nozzle locations for the LPE case,
• steam shell side velocity,
• steam tube side velocity,
• 1st and 2nd reheat stages tube vibration analysis for all design basis conditions.

Main Condenser – The main condenser has design margin to accommodate all cases considered here. However, there is the opportunity to improve the efficiency of the steam cycle once the external cogen cycle is determined. In particular, the temperature of the returned condensate will determine the injection point and additional design features which may be warranted. If condensate is returned at a temperature lower than the saturation temperature in the condenser shell, it should be distributed in a tray system or sprayed into the condenser to preheat the returned condensate and to assist in reducing backpressure. If condensate is returned to the system at a temperature higher than the saturation temperature in the condenser, the return system should be provided with a high head pump in order to inject either downstream of FWH No. 1 or FWH No. 2. In either case, the additional components can serve to improve the cycle efficiency.

MFWP Turbine – The component most impacted by cogen operations is the MFWP turbine. Under either HPE or LPE operations, the cross-around pressure will experience a significant reduction of the ability of the turbine to operate with only low pressure steam admission. The design of this component should be studied separately.

As found in the standard industry design, the MFWP turbines can be supplied with either high pressure or cross-around steam, or a combination of the two. Under HPE or LPE operations, and without modification, the MFWP turbines would be expected to meet design duty, but would use a significant quantity of high pressure steam. This has two adverse impacts. The first is relatively minor, but is associated with reduced efficiency of the component. The second is significant and is associated with the flow of wet steam through the steam flow path. This can have very adverse consequences related to FAC and it is strongly advised that such operations should be avoided.

To address adequate capacity with reduced cross-around pressure (for either the baseline cases or the modified T/G cases) it is expected that the MFWP turbine would require a significant re-design to increase the low pressure inlet bowl coefficient. This will reduce efficiency when operating without steam export. As an alternative, a change in the drive system for the MFWP to a variable speed electric motor could be considered.

About half way through the spring 2016 outage at the Alvin W. Vogtle electric generating station in eastern Georgia, workers were ahead of schedule and gaining momentum. Vogtle ended the outage 32.5 hours ahead of their scheduled outage duration. According to Southern Nuclear Operating Co., this represents the best outage time in the company’s history.

“It’s all about teamwork, looking ahead, communicating, and following the schedule,” said Keith Taber, Site Vice President for Units 1 and 2.

Southern Nuclear Co., Westinghouse Electric Co., Day & Zimmermann and General Electric said the outage team developed an achievable schedule. They identified contingency planning for high-risk activities that, if not implemented correctly, could delay the outage. Once the team had a detailed plan, all that remained was for the working teams to follow the schedule, provide timely and accurate updates, and make sure their contingency plans were established and tested.

The team also maintained clear and consistent communications, and with early and frequent participation of new senior management who were involved in planning and accountability, removing any roadblocks that arose during the outage. Lessons learned from previous outages were examined and applied as part of continuous learning and improvement. The payoff was significant.

Any day added or removed from a planned outage equates to millions of dollars in expense or revenue. Outages are expected to be accurately planned and precisely executed in terms of safety, time and quality of work. For power plant outages, where completing more than 9,000 tasks is common, this is no small effort.

Planning

Structured, thorough planning in which all outage work is identified far in advance of the actual outage using tools such as condition-based maintenance data, operator data and subject matter experts, is the first step to a successful outage. This is necessary to schedule work being performed by plant and contract personnel in an integrated schedule that optimizes these resources. Planning starts several years in advance. Vogtle’s outage strategic plan maps out major projects through 2023. The more detailed milestone schedule includes the next three outages. Deadlines for “pre-outage” milestones occur year-round, with the bulk due in the six to nine months prior to refueling. In this case, there was only a six-month window between the spring and fall outages.

The detailed and collaborative planning done by the plant and by contractor personnel on the scope and schedule was the foundation for a successful outage, said Vogtle Outage Manager Mike Griffin.

“For this outage, we laid out the most accurate and realistic schedule we’ve ever developed,” Griffin said. “Schedule fidelity and table top readiness reviews were fundamental in delivering the best outage we have ever executed.”

Refueling machine mast lowering a fuel assembly into the core. Core reload was done in 11.5 hours less than the planned schedule. Note – The blue glow occurs when a charged particle, such as an electron, travels faster than the speed of light in water – it’s called the Cherenkov Effect. Photo courtesy: Elizabeth Adams, Southern Nuclear.

Vogtle follows a set procedure and publishes its milestone schedule almost immediately following the last outage 18 or six months in advance, depending on the cycle year. Southern Nuclear and Westinghouse are Alliance Partners. For the latter, this means that as soon as Vogtle’s milestone schedule is published, Westinghouse aligns and schedules the people and equipment needed to make sure that all of the plant’s outage needs, for which the company is responsible, are met. Two months before an outage begins, Southern Nuclear and all of the contractors involved in the outage follow a strict procedure-based process. This process includes meetings on site that Southern Nuclear and contractor executives attend to challenge the outage teams and verify the details concerning all aspects of implementing the outage, including budgeting and the progress of pre-outage activities.

Under the plant’s new senior leadership, Vogtle had already begun to improve cross-functional teamwork to facilitate earlier identification of methods to increase efficiency, which advanced their work management practices. It paid off just as well during the outage, Taber said. “The behaviors we’ve established for work management and the way we get things done while the units are online are really paying off now as we execute 2R18,” he said on Day 11 of the outage.

Cross-organizational teamwork was also positively affected with plant and contractor teams identified earlier. Westinghouse Outage Manager Larry Burrows said, “Normally in an outage, the team doesn’t feel like a team until five or six days into the outage. In this case, everyone knew who the teams were and who they would be working with two to three weeks prior to the start of the outage. New senior management really got the teams to take ownership of their work – there was a very positive can-do teamwork approach.”

Contractors were also brought on-site much earlier for the larger-scope work. This was coupled with extensive preplanning and improving the approach to such work, especially the installation of a new refueling machine.

An Example of Continuous Learning Success

Westinghouse was contracted to supply and install a new refueling machine for Unit 2. They had done the same for Unit 1, but not in the timeframe planned or desired. To correct that performance for the Unit 2 outage, Westinghouse and Vogtle personnel worked together to capture and take into account more than 100 lessons learned. They made changes to all four involved procedures: Installation, Demolition (of the old refueling machine), Site Initialization Procedure and Site Acceptance Testing. The improvement process began almost immediately after the Unit 1 outage ended.

This work included two refueling machine project management leads from Vogtle spending eight weeks with Westinghouse personnel at Westinghouse’s Shoreview, Minnesota, site, which is dedicated to designing and manufacturing equipment required to move fuel assemblies. One of them also spent a week at the Waltz Mill Field Services Center of Excellence located in Madison, Pennsylvania, where the installation team is based. The refueling machine team reviewed video footage Westinghouse had taken with a Go-Pro camera during the Unit 1 installation. They applied this information during a rigorous retesting of the Unit 2 refueling machine and proceeded to make modifications which eliminated obstacles to the machine’s movement that had been encountered during the Unit 1 installation.

To accomplish it, Vogtle and Westinghouse project leads and engineers worked together and created a device they used to avoid a problem faced during the Unit 1 installation. The device is a mock-up identical to the lower portion of the refueling machine bridge. Using it, they were able to sweep the entire area of the machine’s movements along the embedded rail track on which it rides before the refueling machine was brought into containment for installation. The embedded rail track is used to guide the refueling machine during operation. Also based on lessons learned, Westinghouse pre-installed dozens of clamps and wiring connectors on the refueling machine, which reduced the scope of electrical work that would need to be done in containment on the critical path schedule. It also eliminated drilling inside containment for the clamp installation, which had proved time-consuming and presented foreign materials challenges during the Unit 1 installation. Additionally, the teams conducted electrical walk-downs in three phases: performing two independent reviews in Shoreview – one each by Westinghouse and Vogtle personnel – and a third on-site at Vogtle Unit 2.

This heated, lighted and ventilated temporary shelter allowed the teams to conduct pre-installation work without weather interference, saving time on critical path schedule. Photo courtesy: Elizabeth Adams, Southern Nuclear.

Some pre-installation work needed to be conducted outside. To avoid delays that had been caused by inclement weather during the Unit 1 installation, the team erected a 50-foot-high, 136-foot-wide, 60-foot-deep tent with lighting, heating and ventilation that allowed workers to unwrap, inspect, prepare and pre-assemble portions of the refueling machine. They also were able to conduct walk-downs of the machine, including foreign material inspections and wiring placement verification. Additional pre-work included pre-identifying and stenciling into the refueling machine the locations of each weld that would be made in containment.

Time continued to be saved on the refueling machine with streamlined activities during the Site Initialization Procedure and Site Acceptance Testing phases – the final processes that had to be completed before the new machine could be used to reload the fuel. Time was saved by conducting encoder testing at the factory and by identifying and removing duplicative steps between the two final processes. The on-site testing sequence was also optimized to minimize movement of the refueling machine, and to reduce hoists over the reactor core.

All of this resulted in the Unit 2 refueling machine installation being completed in half the time of the Unit 1 installation and a day ahead of the planned schedule. Since this installation was driving the critical path schedule, this savings was helpful to the overall outage schedule.

Consistent and Improved Communications

On a more typical 18-month schedule, meetings between Vogtle and the outage support team would be held daily. On the six-month compressed schedule, the Alliance Partners and key contractors met twice each day. Mr. Taber attended many of those meetings, helping to drive accountability for work and follow-through, as well as remove obstacles if they arose. But more of a presence of senior management did not mean that people were less empowered. The decision-making was driven to the worker level whenever possible. Workers would report up twice per day and this proved a very effective approach for efficiency, accountability and removing potential barriers from completing tasks before they impacted schedule.

Another important improvement and among the top lessons learned per Mr. Griffin is the value of all-inclusive schedule reviews. “All-inclusive schedule reviews means that when we met to review an outage task, we included everyone required to make that outage activity a success. Every person on the team with a role was there to go through a dry rehearsal of what their job was and what was required to complete it,” he said. In the past, it was incumbent upon people to read the schedule and make it happen. The all-inclusive schedule reviews ensured that all of the tasks were completely understood by all team members, whether plant or contractor personnel.

Another significant communication improvement was equipment-based. Vogtle had made a major upgrade in communication technology to expand communication with, and within, containment groups. In past years, radiation protection, refueling and polar crane personnel wore headsets and belt packs to communicate but all were on different systems. With the new system, which was fully implemented during 2R18, more groups – including containment coordinators, radiation protection, polar crane, refuel team, Radium Inc. nozzle dam team and Westinghouse eddy current technicians had dedicated channels on the same system. An additional open miscellaneous channel was assigned to the refueling machine team. The contracted nozzle dam and eddy current teams brought in their own equipment and that equipment was connected to Vogtle’s new system, which had not been possible in the past.

Installing the new refueling machine – a critical path task. Photo courtesy: Elizabeth Adams, Southern Nuclear.

Vogtle’s new communication system incorporates key panels in the Control Room and in the plant’s Outage Control Center. The new key panels equipped Vogtle’s Unit 2 Control Room personnel with the ability to communicate with the refuel team and containment coordinators, and Vogtle Outage Control Center personnel to connect to more than a dozen different groups at the press of a button. With safety always a top consideration, certain teams, such as the polar crane and refuel teams, could be heard and could communicate among themselves, but could not be interrupted by personnel outside the teams. This safeguard is meant to avoid distractions during heavy load and fuel assembly moves.

Westinghouse also applied a relatively new communication system this outage, known as the LiveCANâ„¢ Field Communications System. This portable and rapidly deployable system supplied the Westinghouse full-scope refueling effort with audio, video and data communications capabilities. Developed by Westinghouse in 2015, LiveCAN connected Westinghouse field workers in containment to Westinghouse on-site project management personnel and to the Westinghouse Outage Control Center located at the Waltz Mill Field Services Center of Excellence. Real-time data sharing via the LiveCAN system assisted the Westinghouse refueling team in making a big contribution to the overall outage success. With fuel reload faster than predicted using the new refueling machine, the reload was completed 11.5 hours earlier than the planned schedule. The new refueling machine’s enhanced reliability and production capabilities will continue to contribute to improved refueling performance.

Adherence to Schedule

To help drive workflow in containment, Vogtle implemented another new strategy for 2R18 with the addition of containment managers, one each on the day and night shifts. During the outage, their main job was to drive critical path activities and ensure personnel were ready to perform a task the minute it could be undertaken. Vogtle wisely selected two seasoned veterans, Tom Petrak and Steve Waldrup. Both are former shift managers, are Vogtle Outage Control Center leads and NRC-licensed Senior Reactor Operators.

“We’re always looking a day or two ahead to try to identify what might challenge us from meeting the schedule. I see the role of containment manager as doing everything I can to help the people working in containment understand what the OCC [Outage Control Center] is trying to accomplish with regards to working the schedule,” Mr. Petrak said.

The guidance of containment managers with authority and a great degree of experience helped outage personnel develop more proactive behaviors, Mr. Waldrup said, “I see the whole mindset of people inside containment changing. I think we’re changing the culture on how we execute critical path – which is going to shrink the time it takes to do all these activities.”

During the spring 2016 outage, Vogtle performed most critical-path tasks in less than the allotted time, and the presence of containment managers is credited for this achievement.

With a large part of the outage work, 66 percent, Westinghouse also had an experienced outage manager in the field, Larry Burrows, and also made some strategic changes. For refueling activities, Westinghouse flipped its model from the Unit 1 outage staffing of 10 technicians and 18 containment support workers to the Unit 2 outage model of 18 technicians and 10 containment support workers. Technicians can move fuel, but the support workers cannot. While maintaining the same headcount, more technicians meant a qualified person was always available to move fuel and insert shuffles as soon as these tasks could be done rather than waiting until one was available. “The skill level of the technicians and the containment support workers was very important,” Burrows said. “People were able to safely conduct their tasks with little supervision. I was there for many reasons, but a main one was to get ahead of any foreseen or emergent issues, remove the roadblocks and then let competent people get the job done.”

Burrows felt that the collaboration between the site personnel and contracted personnel was excellent. He said, “Whenever we needed site personnel to get involved so we could continue a task, they were ready, whether it was maintenance, mechanical, electrical or chemical groups. We had great collaboration and the outage preplanning and execution were done very well.”

There was no single improvement that made the Vogtle Unit 2 spring 2016 outage the best in the company’s history. There were changes in strategy, increased and all-inclusive participation in schedule review meetings, lessons learned examined and applied, an exemplary collaboration between teams and plant and contractor personnel, senior management support, employee empowerment and teams brought on-site earlier than in the past, among others.

Most importantly, the Vogtle spring 2016 outage was completed with no significant human performance or safety events. Every task was completed safely.

Performance like this will help the U.S. nuclear industry reach the goals of its Nuclear Promise initiative of continuing to improve safety, reliability and economic performance, including reducing operating costs 30 percent by 2018.

Author: Donna Ruff is a communications consultant is a communications consultant in PR and Trade Media Relations for Westinghouse Electric Co.

Each year about this time, we spend a large part of an issue discussing renewable energy. Something about renewable energy harmonizes nicely with the prospect of happy days ahead.

As I sit here at my desk not long after Christmas, considering both renewable energy and nuclear power, it’s probably inevitable that the two ideas would bump into one another inside my brain. It’s got me thinking; just what is the relationship between renewable energy and nuclear power? Are the two fast friends or strange bedfellows? Can nuclear power rightly be considered a form of renewable energy?

Type any of these questions into Google and you’ll get lots of disparate opinions. Seems like everyone from political pundits to hard-charging investigative journalists have some take on the issue. (And every one of them is right, of course. Just ask them.) It occurs to me, though, that we editors of nuts-and-bolts magazines like this one have a peculiar advantage over many other sources of information on the topic-access to a highly technical readership that is disproportionately informed on matters such as these.

Problem is-and maybe this will surprise you-we don’t hear from you folks enough. Maybe it’s because we’re somehow insulated from the public by the vagaries of an opaque publication process, or maybe you guys out there in magazine-land are just like the rest of us, too busy getting through your day to sit down and fire off an unsolicited tweet. No matter. You may now consider yourselves officially solicited; I’m asking for your comments.

So what do you say? Is nuclear power renewable or merely sustainable? Is it even worth making such a distinction, or is that splitting hairs?

Will the combination of technologies like fast breeder reactors and seawater uranium extraction render nuclear fuel effectively limitless, or at least, as some say, in sufficient supply to outlast the solar system? If the answer is no, and nuclear power cannot technically be labeled renewable, can more efficient mining render uranium ore plentiful enough to liberate us from pedantic debates about the shaded meanings of words?

And what about greenhouse gases? Certainly it can be argued that the low-carbon nature of nuclear power is at least in keeping with the “first do no harm” environmental ethos of the renewables movement.

But then what are we to make of that elephant in the room-the great quantities of spent nuclear fuel that must be stored as waste at great cost and for untold years?

I won’t claim to know the answers to all of these questions. Nuclear power has suffered some setbacks in recent years, both from the economic pressures of low-cost natural gas and the political and environmental fallout of nuclear disasters.

If nuclear power is not exactly the poster child for economical and safe energy, does it continue to have a role to play in an increasingly renewable landscape? Can it play well with wind and solar?

When calling on other forms of power to prop up intermittent renewables, the industry tends to turn to fast-start combined-cycle plants, or energy storage facilities like pumped hydro and chemical batteries.

A lumbering nuclear plant is not exactly top of mind when the wind stops blowing or the sun stops shining, and demand exceeds supply. What then? Does this curtail the utility of nuclear power in a future filled with solar-powered flying cars and wind-charged robot servants?

I’d like to ask our readers to weigh in on these issues. I invite your comments on the matter. Let us know your opinions on the issue. We care about what you think. Share your thoughts using the Twitter handle @PwrEngineering. And as always, you can email us at pe@pennwell.com.

The “It’s a Small World” attraction at Disney World is iconic. Its feel-good objective is to build awareness of the diversity of the human race and the value that can come from engagement with people that look, talk, and act differently.

This sense of global awareness is increasingly important to U.S. nuclear plant owners. What happens elsewhere can have impacts here, particularly as units age and materials issues emerge. Fukushima is the definitive example, but several other recent issues highlight the importance of staying plugged into what’s happening around the world. Let’s look at two.

Baffle-former bolts are bolts that attach vertical core baffle plates to horizontal former plates in the core barrel of pressurized water reactors. The purpose of the core baffle is to direct coolant flow through the core and provide some lateral support to the fuel assemblies. To cool the baffle structure, a portion of the water flowing through the reactor vessel is directed between the core barrel and baffle plates in either a downflow or upflow configuration.

In early 2016, hundreds of degraded or missing baffle-former bolts were discovered during outage inspections at the Indian Point and Salem nuclear power plants. The issue appears to be limited to four-loop reactors with a downflow configuration and bolts made of type 347 stainless steel. The degradation is attributed to irradiation assisted stress corrosion cracking over years of operation.

Notably, such degradation was first detected in PWRs outside the United States in the late 1980s. The NRC communicated this overseas operating experience in 1998, and the industry adopted inspection and evaluation guidelines that included inspection of baffle-former bolts during the time when bolt degradation is most likely to appear. It’s not yet clear why the extensive degradation was not detected in a more timely fashion, but the NRC conducted a risk-informed evaluation and determined that the issue did not pose an immediate shutdown risk to the affected plants.

Indian Point 2 and Salem 1 replaced potentially degraded bolts with type 316 stainless steel bolts and were able to restart. The other U.S. reactors susceptible to this issue are accelerating scheduled inspections to examine their baffle-former bolts, and at least one – D.C. Cook – has replaced some baffle-former bolts. The NRC also is evaluating a generic industry communication.

The second issue with potential global repercussions involves investigations by French authorities into excess carbon levels in certain steel forgings and the potential falsification of quality assurance records. These investigations have rocked the French nuclear industry, forcing French utility EDF to take some plants off-line for additional inspection and analysis.

The carbon issue came to light in 2014 when excess carbon levels were found in the reactor vessel manufactured for the Flamanville EPR plant under construction in France. Excess carbon levels can affect the mechanical properties of steel, potentially rendering it more brittle. EDF has said that its latest tests of the Flamanville reactor vessel demonstrate its structural integrity, but the French nuclear authority ASN has not yet released its analysis of the test results.

Citing concerns about the extent of condition related to the excess carbon issue, ASN ordered the shutdown of 18 plants in France to allow more detailed analysis. ASN and EDF subsequently reaffirmed the ability of the plants to safely operate, and all have since returned to service.

ASN also is investigating suspected instances of falsified quality documents at Areva’s Le Creusot forge, dating back more than four decades. Thousands of documents are being reviewed to assess whether, and the extent to which, employees may have modified quality control data. As reported by the Financial Times, David Emond, head of Areva’s component manufacturing business, said that employees would sometimes round numbers up or down so they fell within technical safety limits. Emond noted that while 70 components with falsified documents had found their way into French nuclear reactors – and 120 into overseas power plants – no safety problems have so far been discovered.

The mention of those 120 overseas power plants highlights the global impact of this issue. The ASN actions in France prompted the NRC in early January to release a list of 17 U.S. nuclear reactors with parts from Le Creusot, although the agency does not see a need for plant shutdowns. In a blog post, NRC spokesman David McIntyre said, “We are confident at this time that there are no safety concerns for US nuclear power plants raised by the investigations in France. Our confidence is based on the US material qualification process, preliminary structural evaluations of reactor components under scrutiny in France, US material aging-management programs, our participation in a multinational inspection of Creusot Forge, and information supplied by Areva about the documentation anomalies.”

It’s often said that a nuclear plant issue anywhere is a nuclear plant issue everywhere. The issues described above bear truth to that adage. My apologies if the Small World song plays over and over in your head for the next week.