DCS migration – planning is key
10 March 2015
A recent white paper from US-based systems integrator, Maverick Technologies, details the best approach for DCS migration, starting with justification and ending with commissioning and startup.
Power plants were among the first to implement distributed control system (DCS) technology, in the 1980s with systems based on mini-computers. Although many older plants are still mechanically sound, their control systems are now reaching the end of their useful lives, necessitating migration to a new automation system.
Reliability of any process or power plant is paramount, and it is critical to minimise the cost, risk and downtime of any upgrade project. While many industries are driven to upgrade by the promise of operational improvements, power plant upgrade projects, in particular, are typically guided by the goal of eliminating the risk of failure that accompanies older control systems.
Meeting these conditions requires deep domain knowledge and buy-in from all stakeholders, including power plant personnel and their upgrade partners. A key step toward this end is the development of an execution plan that minimises risk and reduces downtime.
To keep costs down and reduce downtime, power plants tend to shy away from changes to the automation system, preferring to keep things as is and opting for low-risk solutions. Unfortunately, stakeholders also often struggle to make a business case for replacing something that is working, albeit poorly — as is often the case with an older DCS.
Every older DCS will, at some point, need to be replaced with a newer automation system. The challenge is determining when the replacement should be made and this decision often comes down to a judgment call based on a number of factors including reliability issues, discontinued support and spare parts for existing system; plant expansion that cannot be accommodated by the existing system; connectivity issues; requirement for standardization of automation systems among plants; need for better plant performance or improved cyber security.
Once you have determined if and when it is time to replace the DCS, the next step is implementation, and this requires careful planning.
The new automation system could be a modern DCS, a PLC-based system or a PAC-based system. Whichever is chosen it is critical to follow a project plan — one that starts with a frontend loading (FEL) evaluation study.
The FEL is a multistep process that includes a comprehensive evaluation of the facility. It yields a list of project tasks with budget data durations and an overall project schedule and highlights any potential issues. The study can be undertaken internally. However, because major automation system upgrades are not performed regularly by many companies, it is often more cost-effective to engage an outside service provider.
There will always be risk involved, and in most cases there will be some downtime during a DC replacement project. However this can minimised through careful planning. The main items that should be addressed in a DCS replacement FEL include:
• Server-level applications such as HMIs and historians;
• Networks among servers, HMIs, controllers and I/O;
• Field wiring, networks and components;
• Interfaces to ancillary systems;
• Space requirements for new automation system components;
• Demolition, installation and commissioning plans;
• Compliance with safety standards and regulatory requirements;
• Alarm management
It is necessary to make decisions about each of these devices — including when, how and with what they should be replaced. For example, it may be best to replace the HMIs first, often by installing the new HMIs in parallel with the old ones to ease operator anxiety and reduce risk.
New automation system hardware will need to be tied together with a variety of digital interfaces, such as multiple variants of Ethernet, and one or more permutations of fieldbus networks. Interfaces to ancillary systems will be required, some via networks and others via simple hardwired I/O. All of these networks and interfaces must be evaluated for compatibility with existing systems.
Compliance with regulatory requirements will also probably require enhanced cyber security and, in many cases, a new alarm management system. When a proper FEL evaluation is conducted, the result is a successful DCS replacement, as illustrated in the following examples.
Finding reasons to upgrade
Ripon Cogeneration owns and operates gas-fired cogeneration plants in California. The heat recovery steam generator, deaerator and feedwater system, gas compressor system, compressed air system and water treatment plant were the main equipment in need of a new automation system.
In the initial phases of the project, the system integrator, Maverick, worked with Ripon to determine its goals from a technical and business perspective, allowing for an objective look at the technology available to best achieve the company’s objectives.
Rippon wanted to take advantage of its existing HART smart instrumentation and to standardise on a new automation platform to allow for increased maintenance team productivity. It also wanted to include a central and actionable alarm system that would give operators a means to quickly react and provide a solution to any process upset. Another area of concern was compliance reporting and ease of access to plant operating and performance data.
As with most power generators undertaking a major automation upgrade, the company was concerned with the impact of possible operational downtime on operations, and managers wanted to take advantage of existing field wiring and infrastructure. In addition, it wanted an open architecture automation system that would allow seamless interfacing with critical subsystems. Finally, it wanted a system that they could support primarily with internal resources.
These requirements framed the case for the DCS replacement and indicated what type of new system should be selected — in this case, a DCS from Rockwell Automation – PlantPAx.
As part of the FEL evaluation, a cutover plan was devised to minimise downtime and risk. Existing processor and I/O drops were replaced, but all existing field terminations were left intact, which reduced the need for new wiring.
The plant experienced no unscheduled outages during the migration process, and the facility started up on schedule with output ramped up to full power on the first day of operation.
Since the upgrade, the plant has experienced fewer outages than before, due in large part to the improved automation system. Performance has improved, and all of the company’s goals have been achieved.
Upgrading from the 1960s
In another application, a US municipal utility needed to replace pneumatic and relay-controlled combustion, steam and burner management systems on two units. Each of these units used a natural gas-fired boiler to supply steam to a turbine generator.
The reasons for replacing the existing automation systems were to stabilise critical control variables (such as steam pressure, temperature and drum level) in order to produce power based on varying dynamic load changes. The utility also needed to ensure it could maintain load during peak operating periods.
Although the existing automation system was not a DCS, the company faced similar challenges. First, the reasons for the upgrade had to be determined, then the goals identified, and finally a plan was made to perform the upgrade and meet those goals. The initial challenges of the project were to develop conceptual designs with very little data from the original configuration and with minimal information on any subsequent upgrades and/or changes to the facility. The first steps were to identify the goals and develop a baseline for the project.
Plant operators needed an efficient operational management system that would enable them to quickly address system upsets, and the facility needed to generate regulatory reports from historical trend data. To achieve these goals, it was important to create a system offering seamless control while providing centrally located operator consoles. It was also critical to minimise downtime during system cutover, and to provide the operations staff with an automation system that they could maintain with existing internal resources.
The evaluation study showed that the best way to satisfy operator demands was with a centralised HMI console that would include a number of PC-based operator interface terminals. Because the console would replace antiquated operator interface panel boards, training was also needed for staff prior to commissioning and startup.
The study also revealed that maintaining unit uptime was essential, as these units provide base load power to the city. To address this issue, a redundant automation system was specified. New coordinated combustion control and burner management systems were provided for each unit, and each of these systems was provided with triple-redundant controllers and dual-redundant power suppliers.
The automation system chosen for this application was a GE Mark VI integrated control system with Cimplicity HMI. To meet reporting and compliance goals, an OSIsoft PI data historian was also installed and integrated with the new automation system.
The data historian allows plant personnel to quickly generate reports to ensure regulatory compliance and identify operational performance trends. Identification and analysis of these trends enables performance improvements and can also pinpoint problem issues before they escalate.
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