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Scheduling Maintenance Outages

Scheduling maintenance outages is more complicated than in the past. Factors to consider include: the effects of electricity market competition, environmental requirements, and minimizing revenue lost due to unit downtime. Six project owners share their strategies for scheduling maintenance outages.

The scheduling of maintenance outages at hydro projects can be a complex process that must take into account a variety of factors. Six hydro project owners with recent experience scheduling maintenance outages share their insights and lessons learned in the areas of: factors to consider when planning a maintenance outage, allocating responsibility for decisions regarding outage scheduling, what affects acceptance or rejection of an outage request, analysis tools for determining the best outage timing, and taking best advantage of the time available for an outage.

Representatives of the owners are:

Hydro Review: What factors affect your organization’s timing of a maintenance outage?

Lonnie Gourley: Repetitive maintenance outages – outages that are scheduled on a recurring basis (every year, every other year, etc.) – of each unit at projects associated with the Upper Colorado Region – Colorado River Storage Project (CRSP) are scheduled annually in “shoulder” months. These are months when power is less expensive to purchase, or when CRSP customer demands are lightest. These schedules are continuously reviewed by the Western Area Power Administration (WAPA), which markets power produced at our projects.

Greg Lewis: There are a variety of factors we consider. Electricity prices and demand throughout the year are important considerations. Ideally, we schedule outages when prices and demand are low. We also take into account the effect of the large hydro units on the overall system peak demands, primarily considering the amount of system reserve or shortfall projected at that time of year.

In our system, nuclear and fossil plants have priority in scheduling maintenance outages. Outages at nuclear and fossil plants can require hundreds of workers, compared with the 20 or 30 that may be needed for a normal large hydro outage. As a result, the hydro outages can more easily be changed at the last minute in the event of an unexpected outage on the system.

Time duration is another important consideration in scheduling our maintenance outages. For instance, holiday periods can create low system demand and shortened work weeks. This combination can create an ideal outage window for a small outage on a large unit. We try to make effective use of available maintenance personnel, to avoid contracting as much as possible. We also look at availability of certain craft skills or contractors in certain time frames. And by sequencing all outages at the same station, we can reduce mobilization time and costs.

Station configuration plays a significant role. High-capacity stations or those located at river bottlenecks are more susceptible to heavy use in the spring and also are at greater risk during hurricane season. Because of this, these outages might be better-suited to May or November time slots. In addition, stations with multiple units and low capacity factors have a lower risk of spillage or lost revenue. These outages can be slotted during late spring (March/April). However, we always strive to avoid simultaneous multiple unit outages at the same station. We also take into account the effects of a major outage on upstream or downstream plants. For example, if a major unit upstream is already in an extended outage, available flows likely are restricted. Thus, the effect of taking a downstream unit out of service is reduced.

Other considerations include:

Tom McDermott: The principal factor that governs when maintenance outages are requested is the assurance that we can complete our megawatt commitment to the New York ISO on the day the outage is requested.

Marty Rojas: Factors affecting our maintenance outage timing include lost generation, seasonal generation load requirements, seasonal irrigation demands, river flow requirements, and electricity market competition.

Elgin Smith: We have a rotating plan for unit maintenance, depending on the station. The turbine-generating units at 78-MW Pointe du Bois and 67-MW Slave Falls are on a two-year maintenance cycle, meaning we take each unit down every two years for maintenance. The units at 165-MW Seven Sisters, 133-MW Great Falls, and 88-MW Pine Falls have three-, six-, and 12-year maintenance cycles. This means the units are taken down for maintenance every three years, with a different maintenance package every three, six, and 12 years. The units at 55-MW McArthur Falls have a two-, four- and eight-year maintenance cycle.

Every five years, we must submit a plan for maintenance for the upcoming five years to the system control department. We schedule most maintenance for September, October, and November. The rationale is that we assume higher river flows in the spring. Therefore, we try to have all units available to generate electricity at that time. However, because of manpower and resources constraints, there is not enough time in the fall to complete all scheduled maintenance. Therefore, we schedule maintenance of some of the smaller units at McArthur Falls in the late winter and early spring.

If we have lower water flows in the spring, we will pull maintenance ahead into the spring. Usually, this is a simple matter of requesting the change with the system control department. This department will ensure the required generating capacity is still maintained, taking the change into consideration.

In general, we avoid maintenance in the winter and summer because we anticipate higher value for the electricity produced during these periods. We also have a high domestic load in the winter.

As the outage date nears, we will consider water flows, the price of electricity, and system requirements. We may advance or defer an outage if there is a substantial benefit. However, we will not defer unless we have a reasonable expectation of completing the outage within one year of the schedule date.


Major maintenance outages, such as those involving unit disassembly, must be timed to account for lost power generation and seasonal load, as well as environmental and river flow requirements.
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Small outages, such as exciter maintenance (six to eight hours), usually are scheduled during the day if water flows are lower. If flows are higher, we determine projected lost revenue for the outage during the day and subtract the projected lost revenue during the night. If the difference is more than twice the added labor cost, we will do the outage at night. There will be situations where system requirements, resources, or the urgency of an outage take precedence over revenue.

Ray Totten: The major factor affecting timing of maintenance outages at our hydro facilities is available water. Marketing issues run a close second because of the sale of short- and long-term contracts that our company has committed to. This may even involve spot market sales that can affect the outage within hours of its occurrence. The third factor is environmental issues, mostly concerning the many fish runs in our area. If we are looking for a specific run of steelhead or salmon to come through a project but they are not showing up because of poor conditions (low water, warm conditions, etc.), then the outage can be affected. Shutting down the unit and spilling water sometimes can adversely affect the way fish use our ladder systems.

Hydro Review: What analysis tools does your organization use for determining the best time for an outage?

Gourley: Routine repetitive maintenance is scheduled with Maximo software. The viability of the CRSP basin fund is frequently assessed by management to determine the extent of monies and human assets available for repetitive and extraordinary maintenance scheduling. This fund is a revolving fund financial vehicle the WAPA uses to collect and disperse money from the sales of hydroelectric power generated by the plants that participate in the CRSP.

Lewis: Our analysis tools consist of system demand and system economic forecasting tools, as well as long-range weather forecasting tools, combined with experienced hydro and river management personnel.

McDermott: In requesting the outage, we factor in such parameters as other work activities that are locally scheduled – including other generator outages that might interfere with providing the New York ISO with our guaranteed capacity – as well as the availability of labor resources. The New York ISO will merge the individual request with others in the regional area that are pending or requested. The New York ISO will perform an evaluation based on a statistical model of load projection and generation availability, and make the decision if the outage can be granted.


Checking the surface of a thrust bearing is just one of the maintenance tasks performed at a hydro project that must be scheduled to minimize lost revenue.
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Smith: We have an Excel spreadsheet program that is populated with up-to-date forecasts for water flows and the projected price of electricity. When we are planning an outage, we can input the station, unit, start time, and end time of the outage for different times or days. The spreadsheet then will calculate the projected lost revenue for each option. From that information we can, if possible, select the most beneficial time for the outage. The system control department also will use such information as load forecasts and generation availability.

Totten: Things have certainly changed over the years. When I first came into the hydro group 15 years ago, I spoke with an operator who was just ending a 35-year career in that position. He used to base his machine outages on the annual migration of the local bird populations! Now we use many types of data in this process – such as water availability forecasts and environmental conditions, vibration data, various electrical tests, oil analysis, scheduling, and ferrography.

Our marketing folks have forecasting software they use. In January 2008, the hydro support group selected an Internet-based program called ePAC to replace a DOS-based computer maintenance program that was being used throughout the hydro projects.

Hydro Review: Who in your organization makes the decision to schedule a maintenance outage?

Gourley: Ultimately, the regional office power manager makes the decisions regarding obtaining funds and scheduling maintenance outages, through the fiscal year budgeting process. Each field division manager or facility manager participates in a process with the power manager to finalize budgeting and scheduling of operations and maintenance costs. Field division and facility managers use personnel assets at the office to plan details in accordance with the size of their individual division or facility.

Lewis: Outage planning is a function of the hydro planning and scheduling department, in coordination with our central hydro office and the system operating center.

McDermott: The resident manager, through the superintendent of operations, makes the initial request to our Energy Control Center. The center, in turn, contacts the New York ISO. The New York ISO provides the final acceptance of the outage.

Rojas: Anyone can request a maintenance outage, but the final decision is made by the central Power Control Center division or department manager, after consultation with all parties affected.

Smith: Decisions are made according to the five-year plan submitted to the system control department. However, decisions to advance or defer will be made by the station management team and the system control department.

Totten: The initial decision or “first cut” for a routine outage is made by the project managers. Then the engineering, environmental, and marketing groups review and make recommendations. For non-routine work, a ten-year asset management plan is used to help in the decision making.

Hydro Review: What goes into the process of making that decision?

Gourley: Our outages are either “scheduled” or “forced.” Outages are only denied when too many units are scheduled to be down at one time, not giving the system enough reserve to prevent expensive replacement power purchasing.

Lewis: We consider a variety of factors, including probable electricity prices, other outages on the system, availability of maintenance personnel, and time of year considerations. We try to weigh all these factors and determine what is the best outage to take for each individual time slot.

McDermott: The New York ISO will evaluate the expected load and the time requested to judge the advisability of taking the particular outage.

Rojas: Factors we consider when allowing or denying an outage request include system generation requirements, transmission/distribution line capacities, river/irrigation demands, and current or requested outages at other facilities.

Smith: System conditions – in that we must be able to supply the domestic load and export commitments with dependable power – is the ultimate deciding factor. Other considerations include revenue loss and whether it is the best time to do the outage or if another time would result in less lost revenue. However, long-term reliability of the equipment is paramount. In other words, we will never jeopardize long-term reliability for short-term gain or limiting lost revenue. At times, this comes down to a judgment by qualified people. Sometimes this even involves a negotiation between site personnel and the system control department because of the difference in responsibilities (i.e., site personnel are responsible for the equipment, and the system control department is responsible for the system requirements).

Totten: Many things go into the process – unit health, availability of spare parts, required personnel, cost of power and power contracts, other plant outages (both within and outside our company), forecasts in water conditions, snow pack, weather, stored water for irrigation and the usage forecasts, drinking water supplies, and the various fish migration runs through our systems.

Hydro Review: Once an outage is scheduled, what are you doing to take best advantage of the time allotted with regard to scheduling, getting needed parts and equipment in place, etc.?

Gourley: We use many strategies involving scheduling, advance preparation, and material acquisition.
–Scheduling. Outage progress projects are assembled before the outage begins. These reports are formalized project management timeline tools that detail the specific tasks and the planned completion date associated with each task. These tasks are tracked to completion of the maintenance outage. Use of this tool allows us to schedule and complete all repetitive and extraordinary work items associated with each unit’s annual maintenance in the time allotted. These work items can include pre-shutdown inspection reports; placing the equipment in the safe locked-out, tagged-out condition; penstock condition assessment; electrical condition monitoring of the exciter, stator, rotor, breakers, buswork, and transformers; and governor and relay monitoring adjustments.
–Preparation ahead of time. Repetitive tasking man-hours are reviewed annually and resources allocated to match manpower and logistic scheduling.
–Getting needed parts and equipment in place. Individual supervisors review work orders in our Maximo computer system and acquisition plans to obtain needed parts and materials prior to each scheduled outage. Frequently need parts and materials are warehoused within our facilities. Critical spares are identified during system or equipment acquisition.

Lewis: Our strategies include:

McDermott: We have a comprehensive scheduling and planning initiative through our work management program (Maximo) that develops the required information. We use Maximo and scheduling software to balance the labor requirements with the available resources to analyze if the duration estimated for the outage, with the estimates of work needed to be done, can be accomplished. The information system also includes the materials and tools needed to execute the outage tasks.

Smith: When an outage is scheduled, our planning department creates a project in Microsoft Project that monitors the critical path at least four weeks in advance and considers manpower and all scheduled tasks to be completed. Some outages are considered routine and all resources are inherently available for the outage, so there will be little or no prep time. Other non-routine outages will have prep time scheduled. However, it will not be part of the outage project created in Microsoft Project. On all outages, the manpower will be adjusted for things like number of people or overtime required, depending on lost revenue being incurred during the outage. We generally avoid adjusting the tasks, as we assume all scheduled maintenance is required for the long-term reliability of the equipment.

Totten: Once the decision has been made to perform an outage, a lead person is assigned to that project. A schedule may be written for more involved outages. Routine outages are simply given to the work crews, who order their own parts and work out their own schedules. Our support group is always available to help in the event that the outage work scope changes or the crews run into unexpected problems. Most challenges stem from the use of vendors and their ability to get parts repaired and back to use in a timely manner. The lead person follows the vendor work and helps keep it on track. In many cases, we make recommendations on which shops may give us the best service.

We also check out the crane and have it load tested if we know we will be making a heavy lift and it has not been used in that manner for some time. We inspect our rigging and spare parts inventory. This means we go out and put our hands on the spare thrust bearing shoes or wicket gate shear pins.

If we think we are going to change out a journal bearing, we pull out the spare and measure it for proper fit. We also check to see if the resistance temperature detectors will fit in their holes, etc. We write special weld specifications that may be needed. We order cribbing and make up any special jigs or fixtures needed to set or hold the equipment being disassembled.

We also check vacation schedules for our crafts personnel. Most of our outages occur during hunting season, so this has become a routine factor when reviewing our coverage come outage time.


Mr. Gourley may be reached at Bureau of Reclamation, U.S. Department of the Interior, Glen Canyon Field Division, P.O. Box 1477, Page, AZ 86040; (1) 928-645-2481; E-mail: lgourley@uc. usbr.gov. Mr. Lewis may be reached at Duke Energy Corporation, 526 South Church Street, P.O. Box 1006, Charlotte, NC 28201; (1) 704-382-1247; E-mail: gdlewis@duke-energy.com. Mr. McDermott may be reached at New York Power Authority, 123 Main Street, White Plains, NY 10601; (1) 914-681-6454; E-mail: thomas.mcdermott@nypa.gov. Mr. Rojas may be reached at Turlock Irrigation District, 901 North Broadway, Turlock, CA 95830; (1) 209-883-8290; E-mail: mlrojas@tid.org. Mr. Smith may be reached at Manitoba Hydro, Box 1479, Lac du Bonnet, Manitoba R0E 1A0 Canada; (1) 204-345-3494; E-mail: esmith@hydro.mb.ca. Mr. Totten may be reached at Portland General Electric, 121 Southwest Salmon Street, 3WTC BR04, Portland, OR 97204; (1) 503-464-8257; E-mail: ray.totten@pgn.com.


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