PREPARING YOUR SYSTEMS FOR EFFICIENCY

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1 PREPARING YOUR SYSTEMS FOR EFFICIENCY BY Herb Acheson, PE A number of factors are prompting many power generation facilities to consider converting from coal firing to natural gas firing. This complicated conversion process requires the evaluation of a number of items, among them the integration of the control systems necessary for gas-fired plants.

2 INTRODUCTION Now more than ever, power generation facilities are considering or are in the process of converting their plants from coal firing to natural gas firing. This paradigm in power generation makes it imperative that plant operators take into consideration the inherit challenges of integrating one of their most valuable pieces of technology: control systems. Being aware of the common issues associated with this part of the conversion process will help prevent control system issues from resulting in an unsuccessful coal-to-gas conversion project. The process of analyzing a plant s existing system alone is long and complicated. A number of steps are required to determine the state of existing hardware and software, necessary upgrades or replacements, and compatibility of existing systems with new environmental regulations. It has been said that hindsight is 20/20, but determining these issues before beginning the design phase of the project will result in less unexpected costs during construction and start-up. Having an idea of what lies ahead is beneficial to embarking on the modification of the plant control system from a coal-fired system to gas fired with confidence in the end result. BURNER MANAGEMENT SYSTEM The burner management system (BMS) is dedicated to the safe and efficient operation of the combustion system. This piece of the control system requires extensive updating during a coal-to-gas conversion. There are two types of control platforms generally implemented as BMS: distributed control systems (DCS), commonly used plantwide, and programmable logic controllers (PLC). Often, there is a mix of DCS and PLC based systems. Conversion from coal to gas requires that the BMS logic is modified for implementation into the DCS or PLC. If the BMS logic is contained in a PLC, it must be determined if that PLC can support expansion and reuse, or if the BMS logic should be migrated into a DCS platform. If migration into a DCS platform is determined to be the most efficient design, then it must be determined if the existing PLC cabinet is of sufficient size to hold the new DCS power supplies, controllers and input/output (I/O) required for the expansion of the existing BMS. If the preferred design is to leave the BMS logic in the PLC, the cabinet size, the number of I/O modules and the capacity of the controllers will all need to be evaluated. The question of obsolescence is also of concern. If hardware required to expand the existing PLC is not available for purchase, then an upgrade of the entire PLC will be necessary. Either way, new cabinets, controllers and I/O modules are likely to be required for the conversion. The same issues are of concern if the existing BMS logic is contained in a DCS. Obsolescence of the existing DCS hardware could require an upgrade or replacement of the entire BMS. The necessary I/O expansion could require the purchase of new I/O modules and require more cabinet space than available. The existing master fuel trip (MFT) cabinet and relays will also need to be evaluated for possible expansion or migration requirements. As with the DCS and PLC cabinets, the existing equipment may need to be replaced and new cabinets supplied to handle MFT relay expansion. Regardless of decisions made concerning the challenges laid out above, the design of a safe and efficient BMS will be heavily determined by the latest edition of the National Fire Protection Association (NFPA) boiler and combustion systems hazards code. LOGIC/CONFIGURATION UPDATES The most common challenges associated with coal-to-gas conversion are generally not incorporated with the new BMS and combustion control logic. New logic definitions (logic diagrams or control narratives) are usually provided by the burner original equipment manufacturer (OEM) and need to be reviewed for functionality and NFPA compliance. The main challenges normally occur in finding the correct points in the existing logic for tie-ins, demolition of the coal burning logic and modification or tuning of miscellaneous systems. Finding tie-in points in the existing logic involves identifying the new BMS design logic requirements for communication with the existing plant control system. The design engineer must then become familiar with the existing plant logic and learn the most efficient way to search for the interface points PAGE 2 OF 5

3 Demolition requires identifying all of the I/O and logic in the existing control system associated with coal firing, coal conveyors, mill feeders, ash systems, scrubbers, etc. After this is accomplished, the identified I/O will then be deactivated and disconnected from the obsolete logic. At this point, the logic can either be deleted or abandoned in place. The logic of fundamental control elements, such as the fuel master, boiler master and air master, will also need to be modified and tuned to work with the new gas burning system. CONTINUOUS EMISSIONS MONITORING Converting to a new fuel means new permits to meet new environmental requirements. Existing continuous emissions monitoring system (CEMS) instrumentation and analyzers are required to be evaluated in order to meet these new compliances. Existing NO X analyzers will also be evaluated to make sure the permitted limits of NO X are within the range of the CEMS analyzer. If not, the analyzer will need to be replaced. Analyzers used to monitor coal-fired flue gas constituents can either be abandoned in place or removed, but converted plants are require to meet stringent NO X limits. Several technologies can prevent the formation of NO X in natural gas-fired boilers. Among these are flue gas recirculation (FGR), low NO X burners, over-fire air systems, selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR). Several of these technologies can be used together to reduce NO X to permitted levels; however, SCR technology is the most effective method and can provide approximately 90 percent reduction of NO X compared to conventional gas burners. SCR technology uses ammonia catalysts as a reducing agent to convert NO X into nitrogen and water. Today s SCR systems can perform efficiently at a flue gas temperature ranging between 325 F and 750 F and can minimize fan requirements by eliminating or greatly reducing the need for FGR. Often times, a coal-fired plant already has an SCR or SNCR in use that can be retrofitted to the new gas fired system. COAL-TO-GAS CONVERSION: IS THIS A DCS UPGRADE? The challenges involved in purchasing and installing new control system equipment for coal-to-gas conversion projects are very similar in scope to the challenges associated with a DCS upgrade. If this part of the conversion is poorly planned, it can add unexpected issues and costs to the project. When it is decided that the existing DCS I/O is obsolete or that upgrades will be difficult to procure, the existing I/O hardware must be removed and replaced. New I/O hardware can differ from the obsolete hardware by signal and voltage levels, power requirements, flexibility, footprint, arrangement and termination type. Changing the I/O hardware is critical when existing cabinets are reused and existing wiring is re-terminated. Digital input modules and Sequence of Event (SOE) I/O modules are offered in several voltage levels. These modules can come as 24 volts DC (VDC), 48 VDC, 120 volts alternating current (VAC) and 125 VDC. When upgrading the digital input and SOE modules, the designer should be aware that some of the original I/O voltage levels will not be available in newer modules PAGE 3 OF 5

4 The facility will need to investigate what voltage level is best for its particular station. When the control system input module s voltage levels change because of new DCS hardware, field investigations may be warranted to verify that the field devices and switches can handle the voltage changes. When identified early in the project, these issues do not present major difficulties. When updating digital output modules, the voltage level, current ratings and voltage source need to be considered. Most DCS suppliers offer relay outputs that can withstand 120 VAC, 50 VDC or 125 VDC. Older control systems tended to provide only 125 VDC relay outputs. The lower voltage offerings available today provide the facility with a cost-effective option for relay outputs when 125 VDC is not available, as well as offer more outputs available on a relay output module. DCS suppliers also offer internal wiring of routed power through identified relay contacts for control of equipment such as solenoid-operated valves. During an I/O module upgrade, it is necessary to specify the type of service (voltages, currents, and field or routed power) that the relay output contacts will encounter in the early stages of the design to make sure that the DCS supplier has ample time to order the hardware and have it installed. Another consideration for DCS relay outputs is the quantity and type of contacts available for each relay output. Relay outputs are often specified with Form C (One Normally Open, One Normally Closed) contacts or with a Form X (One Normally Open). It should not be assumed that Form C contacts will be supplied on the relay outputs shipped from the DCS supplier. If the station prefers or needs Form C contacts for some or all I/O, this needs to be specified in the early stages of the design. One obstacle to that often arises, particularly for digital outputs, is maintaining the fail states. Consideration must be given to the point level to determine the ideal failure state in the event of a communication failure. Plant personnel need to be aware of this challenge so that the I/O partitioning can be accomplished in a manner that is acceptable to the facility and supports the appropriate output fail states. Control system cabinet footprints can vary significantly: some vendors provide din-rail mounted I/O modules and power supplies while other DCS suppliers hardware comes secured to prefabricated mounting plates. DCS hardware can be oriented horizontally, vertically or in a combination of the two. This is the concern when determining whether to reuse existing control cabinets. The decision to reuse existing cabinets or provide new cabinets should be made early in the project. Wiring considerations become important when updating I/O hardware because of the need to reuse existing cabling. Screw compression type terminals are the common type of termination supplied in a modern DCS. In many older DCS systems, I/O terminals used ring-lug type connections. Upgrading the DCS I/O to screw compression type connections may become an issue, specifically if ring-lug connections are a standard termination at the facility. When ring-lug connectors are used, larger gauge wire and multiple connections on a single terminal are allowed. When upgrading to DCS I/O modules that only support compression type fittings, this flexibility is lost. Ferrule type connectors are an option to support the larger gauge wire in a compression type termination, but still do not allow for multiple connections on a single terminal. It may be required that marshalling terminal blocks be used as an intermediate connection between the field wiring and the DCS. This can add to space requirements and increase procurement and constructions costs. CONTROLLER AND INTERFACE HARDWARE In addition to the issues encountered with the I/O hardware replacement, it is important to consider issues that can arise regarding the controller and communication interface hardware. A coal-to-gas conversion could be as simple as changing out the BMS controllers to a complete DCS controller upgrade. If the project goes in the direction of a complete controller upgrade, controller replacement is rarely one-for-one PAGE 4 OF 5

5 Normally, when existing control systems were installed, the controllers had limited capacity and computing speed compared to what is currently available. These differences must be considered when migrating from the current installation. Because of the speed and capacity of modern controllers, quantity and arrangement of controllers can be reconsidered when upgrading. Most generating plants have controllers segregated by function and it is probably desired to match this segregation. In some cases, this segregation is required by code (e.g., NFPA and ASME TDP-1). Within a fossil power generation facility, the following represents typical controller areas by function: Burner Management System (BMS) Combustion Control System (CCS) Data Acquisition System (DAS) Turbine Control System (TCS) Turbine Water Induction Protection (TWIP) Motor Control System (MCS) Electrical Auxiliaries System (EAS) Balance of Plant (BOP) Foreign Device Interface (FDI) Each area typically includes several sets of controllers, depending on the size of the facility and the amount of equipment. Because controllers purchased today have much more processing power and memory than the controllers they are replacing, it is likely that the quantity of controllers can be reduced during the conversion. Hardware required for foreign device interface and communications with the DCS can cause unexpected challenges if it is not considered early in the project. If the existing DCS interfaces with certain equipment with little to no hardware, it does not always mean that new DCS hardware will be able to do the same. When procuring new DCS controllers and hardware, all foreign device interfaces should be identified and submitted to the DCS supplier. The DCS supplier will then quote and provide hardware and software necessary to communicate with the identified equipment. When providing the necessary hardware for foreign device interfaces, NERC/CIP requirements will need to be considered (i.e., router placement, use of an ELC or comparable gateway, etc.). Identifying the foreign device interfaces early in the project may prevent challenges that can arise by making assumptions regarding foreign device interface. SUMMARY Because a number of power generation facilities considering a gas conversion project have older, outdated control systems, the BMS is often ultimately replaced with new controllers, cabinets, I/O modules and MFT relays to overcome the NFPA compliance and resulting system integration challenges. The BMS has many tie-in points to the plant combustion controls and miscellaneous points in the DCS, leading to an evaluation of the rest of the DCS hardware. A plant may determine that the existing DCS hardware is sufficient to interface with the design of the new BMS, only to update the parts of the DCS that interface with BMS or do a complete DCS upgrade. Control system integration/upgrades are complicated processes that require a vast amount of consideration and encounter many challenges, some of which have been identified here. It is the goal of the Burns & McDonnell team to provide awareness to plant operators that coal-to-gas firing conversions involve a great deal of control system integration and that some of the most common challenges can be mitigated by dealing with these questions early in the project. BIOGRAPHY HERB ACHESON, PE, is an instruments and controls engineer serving for the last nine years in the Energy group of Burns & McDonnell. His more than 22 years of experience include acting as project manager on control system upgrades across the country, as well as lead instrument and controls engineer on major power generation plant conversions in Indiana, Kansas and Florida. His breadth of knowledge extends from control system design for nuclear power plants to production of schematic and wiring diagrams to supervising and overseeing of project staff CON PAGE 5 OF 5