Upgrading automation systems can often extend the life of power generation facilities by decades while reducing downtime, improving operations, and reducing required maintenance. The Maggotty plant in Jamaica offers one such example.
Many power generation facilities have equipment in good running order with many years or even decades of potential service life remaining, but operation is limited by the plant automation systems, which typically have much shorter service lives. Obsolete automation systems fail too frequently and are hard to support, causing excessive downtime. They are also very difficult to tie into other computing systems, which can hinder operational improvements and regulatory compliance.
That was the case at the Maggotty Hydro Power Plant in Jamaica. As the largest hydroelectric plant on the island, Maggotty is critical to the country’s grid. The running gear for the plant’s Unit A—the oldest of three units at the site—was in excellent condition, but the automation systems were becoming difficult to support and did not provide the functionality, capability, and ease of maintenance desired. Therefore, upgrading the automation systems while keeping the existing power generation equipment was viewed as the most cost-effective option to keep the unit operating for years to come.
Jamaica Public Service (JPS) Co. Ltd. is the sole electric utility in Jamaica, operating a fleet of nine hydroelectric stations in addition to wind turbines and oil- and diesel-fueled plants. Power from JPS supports the population of about 3 million and the country’s $25 billion economy.
Based on the success of prior projects completed by Piedmont Hydro Technologies (PHT), JPS again turned to the company in 2014 when it wanted to replace the aging control system on Maggotty turbine A. PHT’s project scope included replacing an ABB digital controller, which was becoming difficult to support and did not interface with newer systems that were running Units B and C. Achieving the level of unit-to-unit integration JPS wanted provided another good reason to upgrade Unit A to a newer control platform.
Maggotty Unit A (Figure 1) was built in 1959 around a Harland-Morgan Smith turbine (Francis type) and vertical-shaft synchronous AC generator supplied by Harland Engineering of Scotland (Figure 2). The generator turns at 400 rpm and produces up to 6.4 MW at 6.9 kV.
1. Island power. The 13.6-MW Maggotty hydropower plant—located in St. Elizabeth Parish, Jamaica—is the island country’s largest hydro plant. Courtesy: Piedmont Hydro Technologies
A dam and intake diverts flow from the Black River into a fiberglass penstock, carrying water downstream approximately 2 kilometers (km) and gaining a head of 88 meters (m). The penstock splits into three lines to supply water to all three turbines.
Modern Digital Controls
The original 1959 turbine controls were manual and included a flyball hydraulic governor—a very complex device with rotating weights and springs. The first digital controller was installed in 2001 as part of a larger plant modernization project, which included new switchgear, a discrete digital governor, and a solid-state exciter. A variety of sensors and actuators were installed throughout the plant at that time to operate auxiliaries and monitor machine conditions.
While the mechanical elements were in excellent condition, the automation system was becoming difficult to support, so JPS commissioned PHT to perform a “brain transplant.” Most of the plant equipment would be kept, but the controller and the human machine interface (HMI)—the main components of the automation systems—would be replaced.
PHT designed the new automation system around an AutomationDirect Productivity3000 programmable automation controller (PAC), an AutomationDirect 15-inch C-More EA9 touch panel HMI, Basler generator protection relays, and a Payne exciter (Figure 3). The digital governor and excitation controller systems installed in 2001 were replaced with a much simpler program running on the PAC.
3. Power PAC’d. The AutomationDirect P3000 programmable automation controller (PAC), shown here, was installed on a new back panel and tested offsite before commissioning. Courtesy: Piedmont Hydro Technologies
The new PAC replaced the old digital controller, and its built-in Ethernet connectivity made communication with the HMI and other elements of the larger system far easier. No additional space was required, and the cost of the new hardware was reasonable. Cost is one of the main reasons PHT has been using AutomationDirect hardware since 2011 and the P3000 PAC since 2012 in about a dozen plants, including one of its own. Component reliability and AutomationDirect’s technical support have been excellent, according to PHT.
The PAC controls the existing plant auxiliaries, generator breaker, exciter, and nearly all of the other equipment in the plant. Sensors and switches for vibration, temperature, and other parameters allow the PAC to monitor equipment condition.
The HMI provides local control and displays plant status, trends, and alarms. It also allows easy adjustment of the hundreds of settings. Technicians can monitor equipment remotely over the JPS intranet, just as they would in front of the local HMI panel. The staff at the main JPS control room on the other side of the island can monitor and control the generator at any time, even when the local site is unmanned.
The automation system is also designed to operate via remote access from the adjacent, new control room attached to Units B and C at the same site, monitoring Unit A over a fiber-optic Ethernet link. This allows all three generators to be operated from a single HMI. Operators, working either onsite or remotely, can turn the generator on and off, or adjust the power output according to the amount of water available and customer demand.
Controlling the Hydroelectric Process
Because the generator rpm and generator output frequency are directly proportional and linear, turbine speed has to remain at a specific rpm value. A speed sensor sends a signal to the PAC, and if the value begins to drift, the PAC compensates. The turbine speed is controlled using a specialized valve called a wicket gate, which is a series of vanes around the turbine, able to open and close to adjust water flow. An analog output module in the PAC controls a proportional valve, which activates a hydraulic cylinder to control the wicket gate valve. Position feedback sensors send an analog signal to the PAC, allowing closed-loop control of the wicket gate based on rpm measurement.
With the frequency controlled by adjusting water flow, the generator must then synchronize with the power grid at about the same frequency and in phase. It is also necessary to vary the excitation to match the voltage between the generator and the grid. When all three conditions are met, the breaker can be closed to start delivering power to the system, up to 650 amps at 6,900 VAC.
PHT also installed a new, less-complicated exciter controlled by the PAC. The exciter generates the DC current to power the magnetic field necessary for the spinning rotor to create electricity. The PAC uses the generator’s measured voltage or power factor to control the exciter voltage from 0 to 180 VDC via a 4–20 mA analog output. Adjusting the excitation voltage controls the generator’s output voltage.
The PAC provides multiple excitation control modes to meet customer demand requirements including voltage regulation, power factor, and reactive power modes—plus a reactive power capability curve limiter.
Generator voltage is measured using a multifunction protection relay communicating with the PAC using Modbus protocol over an Ethernet connection. The old system used a cabinet full of transducers, analog cables, and connections. Done digitally now, all the metering is compressed into one box with a Basler 11g generator protection system reading voltage, current, frequency, and other parameters. If necessary, the generator protection system can shut down the generator by opening the breaker. The PAC also reads all of the metering data from the 11g system in real time and uses this data to synchronize and control the exciter—and to monitor kilowatts generated, voltage, current, and many other electrical values.
Generating PID Control
The basic strategy for most control loops utilizes a proportional-integral-derivative (PID) feedback mechanism. The governor compares generator speed to a setpoint and utilizes a PID controller to position the wicket gates. This is far simpler than the mechanical controller with its spinning weights, dashpots, valves, and linkages. The exciter controller uses a PID loop similarly. The setpoint is the grid voltage and the system compares the generator voltage against it, controlling it by varying exciter voltage. It tries to match voltages within about 2% to protect the generator breaker.
A PID loop also controls water level, measuring intake water level and varying turbine power to maintain the level at the setpoint. The Maggotty intake is about 2 km away from the powerhouse, so communication between the two is accomplished using Modbus protocol over an Ethernet connection. The level transducer and data acquisition module reads the analog level sensor input, and the PAC sends instructions back to the output module to control turbine power.
Because the river’s flow varies with weather conditions, controlling water flow is as critical as controlling power output. The PAC uses a PID loop to balance water inflow and outflow to avoid overflow while keeping the water level as high as possible to maximize head pressure and corresponding power output.
The end result is an overall control strategy using three interdependent PID loops in series. The first is a water-level loop that provides a power setpoint. The governor then uses the power setpoint, applied to another PID loop to set the wicket gate. The wicket gate then uses this setpoint along with the current position of the gate to provide PID control of the gate proportional valve.
To control power output, the plant can operate in two modes. One is based on water level, as just discussed, where water flow is the constraint. In the other, the operator can order a fixed, constant power level. This is useful when there is more than enough water flow to supply power demand.
The PAC and its ancillary equipment can be run by an onsite generator to allow black starting, which is restarting the plant without relying on the external transmission network. Although a hydroelectric generator requires only a small amount of external power to start up, it does require the PAC to control field flashing sequencing to inject current into the rotor.
Starting on Schedule
PHT designed, built, and tested the control system at its facility in North Carolina and then shipped everything to the Maggotty site. Technicians Carter Combs and Josh Knight and other PHT personnel traveled to the site to install and commission the new automation system. JPS personnel assisting PHT with the install included Peter Baker, Shane Montaque, Renwick Brown, and Horace Fuller. This collaborative effort made installation much faster while providing training for the JPS staff.
Because the retail cost of electricity on the island is high—roughly $0.33/kWh—minimizing downtime was important. The existing control cabinets were reused, but a new backplane was installed, with the new PAC and supporting hardware already in place. The existing door equipment was removed and a large rectangular hole was cut. A new laser-cut door blank was attached, with the HMI, switches, and protection relays already installed and tested (Figure 4).
4. Facelift complete. The AutomationDirect C-More human machine interface, visible in the center cabinet, was installed as an assembly with other control hardware to reduce installation time and save money. Courtesy: Piedmont Hydro Technologies
Most of the input/output (I/O) points from the connection blocks on the reverse side of the main control cabinet were reused, so it was a simple matter to connect to the terminal strip on the new backplane. Some sensors were added, including vibration monitors, an ultrasonic flowmeter, and pressure transducers. The existing exciter was replaced with a new Payne static exciter, which is essentially a DC voltage source controlled by the PAC.
After the wiring was completed, all I/O points were tested. Following that, functional checks of all the equipment were performed. This included hydraulic pumps, numerous valves (including a 1.25-m-diameter butterfly valve), the wicket gate operator, exciter, and more. Finally, the generator electrical protection relay settings were confirmed.
Once the systems were checked out, the unit was started. This included testing synchronization of the generator with the grid and producing power. Hundreds of settings, all easily available through the HMI, were adjusted to ensure safe, smooth, and reliable operation (Figure 5). PHT remained for the first few days of commercial operation, making minor adjustments and watching for problems. Startup went very well and finished on schedule.
5. Smooth startup. Extensive testing offsite and during commissioning ensured a quick and on-schedule startup. Courtesy: Piedmont Hydro Technologies
The new control system has worked as advertised during its first year of operation and overall plant uptime has been excellent. Maintenance technicians appreciate having spares available again, and operation has been greatly simplified for the plant’s staff. The new governor and excitation controls greatly improve plant usability by replacing the difficult-to-use “black boxes” with easily monitored and adjusted subsystems via the HMI. The new exciter and controller are much easier to tune, resulting in better voltage stability.
JPS has four other hydroelectric plants still controlled by old automation systems, similar to what Maggotty Unit A used before its upgrade. Management expects to replace one of these every few years until all are modernized. JPS has been technically competent and easy to work with during the upgrade as their personnel know the plant and have an intimate knowledge of its operation. Their technical, engineering, and management assistance was invaluable and greatly helped speed installation, startup, and commissioning. ■
— Kevin Edwards is owner and lead engineer at Piedmont Hydro Technologies.