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Modernizing Unit Controls at Hoover

The unit control upgrade under way at the 2,074-MW Hoover Dam hydroelectric plant has produced significant benefits. With 15 of the 17 units upgraded, power system oscillations are reduced and operating efficiency has increased significantly. Modernization of the final two units at Hoover will be completed by June 2010.

The U.S. Department of the Interior's Bureau of Reclamation, established in 1902, has constructed more than 600 dams and reservoirs. Reclamation is the second largest producer of hydroelectric power in the U.S. Its 58 power plants provide more than 40 billion kilowatt-hours annually, generating nearly $1 billion in power revenues and producing enough electricity to serve 6 million homes.

In October 2006, Reclamation awarded a $5.7 million contract to L&S Electric Inc. of Rothschild, Wis., to modernize unit controls for the 26 hydroelectric units at its 2,074-MW Hoover, 255-MW Davis, and 120-MW Parker facilities, all on the lower Colorado River. Davis is 67 miles downstream from Hoover, and Parker is 167 miles downstream from Hoover. The unit control modernization project at these three hydro plants involves upgrading the four primary subsystems – governor, excitation, protection, and unit controls (including human-machine interface) – to digital technology.

Power generation from Hoover meets load regulation requirements. Fast, predictable, repeatable unit control provides significant benefits, as units are used for ramping and reserves in addition to producing power. The modernization project upgrades all unit control and protection equipment, replacing some equipment dating back to the 1940s that was not providing precise control and was not easily maintainable.

Instead of issuing a specification for a custom design, Reclamation elected to obtain a commercial solution based on the vendor's demonstrated success in recent similar projects. Under this scenario, the vendor was to use commercially available components and previously proven designs. For this project, Reclamation identified work boundaries, conceptual requirements, and objectives, while also stating that cutting-edge technologies and custom solutions would not be acceptable.

Under this contract, L&S would:

– Upgrade the existing mechanical governors to digital. The old system had electromechanical governors. Keeping the control and sensing operation of these governors within tolerances required frequent maintenance. Digital governors with touch-screen interfaces provide very quick and predictable control of unit speed (generator off-line control) and loading (generator on-line control). Unit mode transitions including start, stop, condense, and generate are fast and repeatable.

– Install new digital generator and transformer protective relays. Previously, unit protection consisted of a mix of electromechanical and digital relays. With the old system, maintenance and wiring changes were tedious and error-prone. The new system replaces the many relays with a few digital relays while also providing redundant protection.

– Install new unit controls based on programmable logic controllers (PLCs). The previous user interface had a traditional control board that included numerous control switches, panel meters, and annunciators. The new PLC system features touch-screen user interfaces. The new system provides the operator with complete control and status of unit operation on the touch screen, integrating the function of control switches, panel meters, and annunciation into the new digital format.

– Replace static pilot exciters with new digital equipment. Each pilot exciter previously consisted of an analog automatic voltage regulator and static power rectifier. Voltage control was based on the rotation of motor-operated rheostats. It had become difficult to obtain replacement parts for the analog control components. The digital pilot exciter improves programmable setpoint voltage control and has extensive self-diagnostic and event capture capabilities.

Keeping the control and sensing operation of the old electromechanical governors (at top) at 2,074-MW Hoover within tolerance required frequent maintenance. The new digital governors (at bottom) provide repeatable and predictable control of unit speed and loading.

L&S was responsible for system integration, engineering, and supply of the standardized control cabinets used for the modernization. Prior to the modernization, control and protection hardware varied from unit to unit because the designs were developed under different contracts over the past 73 years. Remarkably, hardware design for the modernized equipment at all three dams resulted in identical equipment cabinets containing identical hardware for use in modernizing all 26 units. Twenty months after contract award, the first six upgraded units were operational. By comparison, similar automation projects based on traditional government specifications have taken five to ten years from award of the contract to the first operation of the new systems.

The benefits of the modernization have been immediate. The unit loading rate at Hoover Dam was increased from 30 MW to 100 MW per minute. The time to transition from condense mode to generate mode of operation decreased from 80 seconds to 20 seconds. These improvements at Hoover Dam reduced the number of units required to be generating from six to two during periods when the plant is operated to prioritize regulation requests while operating at low plant load. The net savings for every unit that can operate in condense mode during periods of low plant loading is 7 MW. The result of changing the operational modes is a significant improvement in overall plant efficiency (i.e., more power produced from water released down the river) while still prioritizing regulation of the power system.

Today, 15 of Hoover's 17 unit modernizations are complete. By June 2010, modernization of the remaining units will be complete.

Automating Reclamation facilities

Reclamation began computer (digital) automation of power generating facilities in the early 1970s. In the early days of plant automation, custom designs were necessary because automation was new to the electric power industry. A custom design required a complex specification of the system purchased that addressed a myriad of details. Preparing such specifications is labor-intensive, expensive, and tedious. In addition, vendor costs were high because of the unique work required for each project. Thus, U.S. electric power producers spent large amounts of money automating their plants using custom specifications.

By 2006, when Reclamation issued the request for proposals (RFP) for the work discussed in this article, both Reclamation and the hydroelectric industry had gained a lot of experience automating hydroelectric power plants. Operations, maintenance, and engineering personnel at Hoover agreed that the best approach was to install new automation systems similar to the systems already installed at hundreds of other hydro plants.

Reclamation works closely with the water and power customers who fund operations, maintenance, and improvements at Hoover Dam. As Reclamation began planning the automation upgrade in 2004, the power customers needed a cost-effective approach for the modernization project that would mesh with short outage schedules to minimize the loss of unit value during installations.

Historically, rapid evolution of computer equipment made it necessary to replace computer automation hardware and software frequently. In many cases, automation equipment was installed and integrated continuously as new subsystems (protective relays, exciters, governors, or controls) each were added at different times to existing investments. The priority on system security since the terrorist attacks on 9/11/2001 increased the number of computer changes required to secure the system. It was often necessary to defer the costs of upgrades to plant systems in order to fund changes to the computer systems. The result has been aging of power generating plant equipment, including governors, excitation systems, protection systems, and the control boards that were the traditional operator interface for unit control.

The old unit controls (at top) installed at 2,074-MW Hoover included numerous switches, panel meters, annunciators, and transducers. The new controls (at bottom) are based on programmable logic controllers, providing complete control and status of unit operation on the touch screen. The new equipment integrates the function of control switches, panel meters, and annunciation into the new touch-screen interface.

A primary objective of Reclamation and its power customers for this project was reliable, predictable load and voltage control. A new upgrade of computer hardware and software interfaced to outdated governor speed adjust motors in aging mechanical governors would not be an acceptable solution. Similarly, new computer controls interfaced to vintage voltage regulator motors in the analog exciters also would be unacceptable.

Integrating four systems

Reclamation assembled a team to guide the modernization project. During the planning process, this team learned about recently modernized hydro facilities. The goal was to learn what worked well at other facilities and to determine the best solution for Hoover, Davis, and Parker. During these visits, team members interviewed plant automation managers, operators, and maintenance specialists.

The best solutions used at other facilities replaced all four unit control subsystems – governors, protection, excitation, and unit controls – at once. Completing all the work in one planned outage (rather than in four separate outages) provides several advantages. For example, only one system integration and one revision of plant control is required. Requiring a system integrator to interface to existing subsystems introduces significant unknown risks and drives up vendor costs. Replacing all four subsystems at one time meant the vendor was integrating all the new equipment on a common platform.

Reclamation took several actions to reduce risk to schedules and costs. First, the team recommended an "off-the-shelf" approach to acquiring the modernization equipment. This eliminated the complex, time-consuming, and costly specification process that has been used on many similar projects. The reduced scope (time and cost) allowed the customers to fund the purchase of all of the equipment at one time. This made it possible to have identical equipment (hardware and firmware) for all 26 generating units in the three plants.

The team also recommended minimizing the vendor's role. The vendor's contract would require design and supply of equipment, yet no installation labor would be included. The only involvement of the vendor at the plants was to assist with training and commissioning during start up of the first two units. Reducing the vendor's risk reduced the project cost. This approach shortened the equipment design and supply contract to three years. It would take five years to install the equipment on 26 units in three plants, but the vendor would only be involved in the first two years of installation. Of the ten units modernized in the first two years, the vendor would commission the first two, train Hoover's personnel to commission the remaining 24 installations, and be on hand to support Hoover personnel through the commissioning of an additional six units.

To further reduce the vendor's risk and minimize the scope, the vendor would supply only a single design and a single set of drawings for the equipment supplied. This would be a fundamental part of the off-the-shelf approach. To make this recommendation feasible, Hoover personnel would accept responsibility for interfacing the existing plant equipment to the single design supplied by the vendor.

 

The old static pilot exciters (at top) at 2,074-MW Hoover were outdated, using control pulses to voltage regulator motors to control bus voltage and vars. It was difficult to obtain replacement parts. The new digital pilot exciters (at bottom) have extensive self-diagnostic and event capture capabilities.

To augment Hoover craft labor personnel, the team recommended a labor contract be awarded for removal and installation activities. The team selected an indefinite delivery indefinite quantity contract structure for the labor contract, which allows the contract work scope to be defined prior to each unit outage. The Hoover workforce would participate in some installations when plant labor was available. This facilitated in-depth training of plant personnel from hands-on installations of the new equipment.

The team explained the alternatives and associated risks/costs to the power customers, who approved the recommendations. Reclamation issued an RFP in June 2006. In October 2006, award was made to L&S Electric. L&S completed the engineering design, and Reclamation approved the design in March 2007. L&S delivered all of the equipment for the first two units (and a complete set of equipment for one unit to be used as spare parts) in August 2007.

Reclamation awarded the labor contract for installation to Koontz Electric Inc. in August 2007. In November and December of 2007, L&S, Koontz, and Reclamation jointly completed modernization of the first two units. L&S, Koontz, and Reclamation jointly completed modernization of four more units by the end of May 2008.

Reclamation's outage/maintenance season is from October 1 to May 31. Generation outages are avoided from June 1 through September 30 during the peak season of water and power delivery. After the first six units were completed, generation outages were avoided during the summer of 2008. Operation of the first six units during the summer of 2008 allowed the design to be tested and fine-tuned prior to modernizing the remaining units.

Koontz and Reclamation modernized five more units in 2009 and will complete the last four units at Hoover Dam by the end of May 2010. Modernization of the five units at Davis Dam will occur during October 2010 through March 2011. Modernization of the four units at Parker Dam will occur during October 2011 through May 2012.

There are many benefits for Reclamation and its customers that have been achieved as the unit control modernization project is completed at Hoover Dam. Chief among the financial benefits is the reduction in unit operating hours at low, inefficient loads. The availability of full capacity from the units due to positive wicket gate positioning is another key benefit.

Additional benefits include more streamlined documentation for the North American Electric Reliability Corporation (NERC) and Western Electricity Coordinating Council (WECC); integrated timing of all unit events; and the dramatic reduction in maintenance and testing of individual devices used between transducers and the supervisory control and data acquisition (SCADA) system. 


Chau Nguyen, P.E. and PMP, director of engineering planning at Hoover Dam, is the Bureau of Reclamation's project manager for the controls modernization described in this article. Terry Bauman, P.E., senior controls engineer for L&S Electric Inc., was a lead member of the design team, wrote the software, and was system integrator throughout installation and commissioning of the controls for the first eight units modernized at Hoover. 

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