Omaha District Hydropower Master Plan
Final Submittal Aug 2016 1 Team Omaha, I am pleased to present the Omaha District Hydropower Master Plan. The Hydropower Master Plan provides a guide for future development decisions. The plan outlines the future requirements that will sustain our hydropower mission capability. Our purpose is to develop a strategic master plan that will guide future programming and funding for all hydropower sustainment, rehabilitation, and modernization requirements in a way that provides predictable funding and maximizes efficiencies to ensure the long-term resilience and reliability of this critical national infrastructure. There are several key tasks essential to our success: Plan for the future with a comprehensive, feasible, and efficient master plan.
Program and secure predictable funding to sustain, rehabilitate, and modernize power plant infrastructure according to an established master plan.
Prioritize repairs and improvements through risk-informed decisions and communication.
Execute funding and complete programmed and funded projects according to contracts and agreements.
Our desired end state is to ensure Omaha District hydropower infrastructure is rehabilitated and modernized no later than 2035 to maximize resilience and provide renewable, reliable energy production to the nation for an additional 50 years. I encourage you to become familiar with this plan and to foster greater partnership with every organization whose activities impact the physical development of hydropower in support of the larger U.S. Army Corps of Engineers mission.
John W. Henderson, P.E. Colonel, Corps of Engineers District Commander
2
Charter
PARTNERING CHARTER
We are committed to work together through a positive, effective, and enduring partnership to ensure success of the ______goals and objectives as outlined in the Omaha District JOHN W. HENDERSON, STEVEN R. MILES Hydropower Master Plan. We believe that our partnership Colonel, Corps of Engineers Director, Hydroelectric Design Center will foster mutual cooperation, encourage collaboration, and District Commander Portland District promote open communication into the future. We commit to the following shared objectives: ______ Be open and honest in all business dealings TED H. STRECKFUSS DANIEL T. PAYTON Promote participation and consensus at all levels Deputy District Engineer General Manager Deliver quality products Omaha District Western States Power Corporation
Develop accurate cost estimates
Implement effective cost controls after contract award ______ Establish realistic schedules KEITH J. FINK ROBERT J. HARRIS Meet or exceed project milestones Chief, Operations Division Senior Vice President & UGP Regional Manager Western Area Power Administration Maintain accurate documentation Omaha District
Do the work safely Protect the environment ______ Maximize efficiencies and streamline processes FRANCES E. COFFEY JAY D. HODGES Chief, Program Support Division Acting Chief, Construction Division Be solution oriented, resolve problems quickly Northwestern Division Omaha District Benefit from lessons learned Showcase successes Strengthen and mature partnering relationships It is our intention to adhere to the principles of teamwork in order to lead, guide, and promote developing the Omaha District’s Hydropower infrastructure now and in the years to come.
3 Table of Contents
1 Introduction 3 Future Development Plan 1.1 Purpose ··············································· 1 3.1 Hydropower Modernization Initiative ········ 19 1.2 Process ················································ 1 3.2 Rehab Strategy ····································· 20 1.3 Authorization ········································ 2 3.3 Capital Improvement Plan ······················ 21 1.4 Goals and Objectives ······························· 3 3.4 Funding Considerations ························· 26 1.5 District Profile ······································· 4 1.6 Pick-Sloan History ·································· 5 4 Fort Peck Power Plant Development Plan 2 Existing Infrastructure, 4.1 Overview ············································ 27 Conditions, Opportunities 4.2 Hydropower ········································ 28 2.1 Overview of Hydropower ························· 7 4.3 Existing Conditions ······························· 30 2.2 USACE Hydropower ······························· 8 4.4 Five-Year Gantt Chart ··························· 31 2.3 NWO Project Operation ··························· 9 4.5 Capital Improvement Plan ······················ 32 2.4 Hydropower Asset Management Program ··· 11 2.5 Energy Replacement Costs ······················ 16 5 Garrison Power Plant Development Plan 5.1 Overview ············································ 33 5.2 Hydropower ········································ 34 5.3 Existing Conditions ······························· 36 5.4 Five-Year Gantt Chart ··························· 37 5.5 Capital Improvement Plan ······················ 38
4 Table of Contents
6 Oahe Power Plant 9 Gavins Point Power Plant Development Plan Development Plan 6.1 Overview ············································ 39 9.1 Overview ··········································· 57 6.2 Hydropower ········································ 40 9.2 Hydropower ······································· 58 6.3 Existing Conditions ······························· 42 9.3 Existing Conditions······························· 60 6.4 Five-Year Gantt Chart ··························· 43 9.4 Five-Year Gantt Chart ··························· 61 6.5 Capital Improvement Plan ······················· 44 9.5 Capital Improvement Plan ······················ 62
7 Big Bend Power Plant 10 Maintenance and Revision Development Plan 10.1 Roles and Responsibilities ······················ 63 10.2 Updating and Production ······················· 63 7.1 Overview ············································ 45 7.2 Hydropower ········································ 46 11 Appendices 7.3 Existing Conditions ······························· 48 7.4 Five-Year Gantt Chart ··························· 49 11.1 Acronyms ············································· i 7.5 Capital Improvement Plan ······················· 50 11.2 Acknowledgements ································ ii 11.3 Complete 5-Year Gantt Chart ···················· iv 8 Fort Randall Power Plant Development Plan 8.1 Overview ············································ 51 8.2 Hydropower ········································ 52 8.3 Existing Conditions ······························· 54 8.4 Five-Year Gantt Chart ··························· 55 8.5 Capital Improvement Plan ······················· 56
5 6 This page intentionally left blank Introduction
1.1 PURPOSE 1.2 PROCESS The purpose of this Hydropower Master Plan (HMP) is to This HMP was developed through collaboration at all stages guide the long-range sustainable development of Omaha among power plant users, stakeholder organizations, and the District hydropower facilities. To assist key decision-makers, district engineering staff. Collaboration included working stakeholders, and hydropower sponsors in understanding, sessions, interviews, site visits, and independent analyses of planning and conducting the District’s mission, the HMP power house requirements. Figure 1.1 depicts the three main provides current and future requirements, describes steps of the planning process to develop the HMP. constraints, and depicts future facility and infrastructure Identification: development plans. The initial step in the planning process focuses on outlining the project purpose, scope, and guiding principles. The vision, goals statement, and charter were established through interviews and a SWOT (strengths, weaknesses, opportunities, and threats) analysis from Omaha District leadership and Operations Project Managers. Existing conditions presented in the Hydropower Asset Management Program (hydroAMP) were analyzed to identify constraints and opportunities. Facility requirements submitted on Operations and Maintenance Work Requests (OMWRs) and the Hydropower Modernization Initiative (HMI) for power houses were used to create the lists of candidate projects for further evaluation. Evaluation: A preferred alternative was selected through evaluating and validating the obtained data. Alternatives were developed and analyzed through work sessions to select the final plan Garrison Project surge tanks elements to ensure requirements, project scope, and schedules were met.
1 Introduction
Implementation: the exception of Fort Peck, which was authorized by the River and delivers reliable, cost-based hydroelectric power for a 15- The plan is implemented by developing a project list, referred and Harbors Act of 1935 and the Fort Peck Power Act of 1938. state region of the central and western United States. WAPA to as the Capital Improvement Plan (CIP), which identifies a Other relevant legislation that has influenced the operational transmits this power to rural electric cooperatives, municipal phasing strategy. This CIP prioritizes requirements based on objectives include: Reclamation Act of 1902, River and entities, public-owned systems, Native American tribes, and the risk of costs due to a unit outage. Additionally, the CIP is Harbors Act of 1912, Fish and Wildlife Act of 1946 and 1958, federal/state agencies. used to present and secure a fiscal year project list and overall Federal Water Pollution Control Act of 1956 and 1972, the Section 212 of the Water Resources Development Act of 2000 program submittal. National Environmental Policy Act of 1969, and the 1973 (Public Law 106-541, Dec. 11, 2000) authorizes USACE to accept Endangered Species Act. These authorized USACE to operate customer funds to maintain and operate the hydroelectric 1.3 AUTHORIZATION the Missouri River main stem dams for the purpose of flood power plants. control, navigation, fish and wildlife, irrigation, hydropower Along the Missouri River, the U.S. Army Corps of Engineers generation, recreation, water supply and recreation. The U.S. Army Corps of Engineers entered into Contract No. (USACE) operates a total of 36 generator units capable of water used to produce electricity at Fort Peck Dam in Montana 04-UPGR-65 which provides for the Western States Upper Great producing approximately 2.4 million kilowatts of power. passes through five downstream power plants, each Plains (UGP) to contribute funds for activities necessary to Through many years of Federal water resource legislation, producing more electricity on its way to the ocean. This makes maintain the reliability and good operating condition of the several acts influenced or guided how the system has hydropower one of the most efficient forms of power power facilities to include operation, maintenance, replacement, developed and its regulation. The 1944 Flood Control Act, generation for use by the people of the Midwest. additions, and construction of features at USACE UGP Region commonly called the Pick-Sloan Program, authorized power plants where such activities will optimize the efficiency The Western Area Power Administration (WAPA) construction of all of the Missouri River System projects with markets of energy production or increase the capacity of the facility.
Figure 1.1 Steps in Hydropower Master Plan
2 Introduction
1.4 GOALS AND OBJECTIVES A key challenge of the HMP is that each power house has its own GOAL 3 – Prioritize repairs and improvements unique needs dependent upon the facility and the age of its through risk-informed decisions and equipment. The HMP seeks to optimize and reconcile these communication. requirements within the Omaha District. Utilize the Hydropower Modernization Initiative to To address this challenge, Omaha District has established four prioritize requirements based on risk analysis and fundamental goals and their objectives for hydropower benefit cost ratios. development. Integrate the objective analysis of asset investment tools with the expertise and needs of USACE’s business line GOAL 1 – Plan for the future with a comprehensive, managers. feasible, and efficient master plan. Implement currently programmed and planned projects to increase reliability. Maintain reliability of the power train and balance of plant equipment for another 50 years. Consolidate and standardize systems where appropriate to GOAL 4 – Execute funding and complete create commonality of equipment between projects. programmed and funded projects according to Fort Peck outlet tunnels, power house 2, and surge tanks Utilize 60 years worth of data to design-build replacement contracts and agreement. components at facilities reducing operation and Maintain effective schedules by coordinating designs, maintenance costs by better design. expending funds, and completing all scoped work. Manage project funds distribution between multiple GOAL 2 – Program and secure predictable funding execution accounts. to sustain, rehabilitate, and modernize power plant Analyze and report results/lessons learned to the infrastructure according to an established master sponsor on project funding and expenditures. plan. Utilize project management process and provide oversight of all construction contract activities. Follow asset management principles to evaluate assets by their consequence and probability of failure to orderly Coordinate and endorse annual review of the HMP. program and implement a CIP. Provide a 20-year forecast of requirements assessed under different funding scenarios. Review major power house requirements utilizing HydroAMP and Facilities and Equipment Maintenance condition assessments. Minimize outage time and maximize energy production by coordinating and combining different rehabilitation outages.
3 Introduction
1.5 DISTRICT PROFILE The Omaha District is a full-service district covering 700,000 Mission: The Omaha District serves the Armed Forces and the square miles. Over 1,200 employees execute a $1 billion-plus Nation in support of civil, military, and environmental program across 1,000 military construction projects in eight missions. Our three-quarters century history of distinguished states, civil work projects in nine states, and environmental service is marked by engineering excellence, outstanding restoration projects in 41 states. With incredible geographic technical support, and multi-disciplinary services. We deliver diversity, including the Rocky Mountains of Colorado, quality, timely products and services at a reasonable cost. Badlands of the Dakotas, lakes of Minnesota, and Great Plains Organization: The Omaha District is organized under six of the Midwest, the district is home to more than 24 Native divisions: Planning, Programs, and Project Management, American tribes and reservations. The district’s area of Contracting, Real Estate, Operations, Construction, and operations is depicted in Figure 1.2. The Omaha District Engineering. The organizational structure is depicted in specializes in protective design, transportation, rapid Figure 1.3. Each of the divisions are augmented by seven staff response, interior design, hydrant fuels, and maintains 27 offices that report directly to the executive office and provide dams, including six giant multipurpose dams and reservoirs. additional management and operational support to the Vision: To be the leading district in execution, innovation, and District and its mission. These offices include Internal Review, disciplined action, working in concert within the region and Safety and Occupational Health, Security and Law across USACE, to deliver premier engineering services by a Enforcement, Small Business, Counsel, Resource Management, Figure 1.2 Omaha District area of operations well-organized, professional and highly trained workforce and Public Affairs. able to provide support any time, any place.
Figure 1.3 Omaha District organizational chart 4 Introduction
1.6 PICK-SLOAN HISTORY Between 1932 and 1957, U.S. Army Corps of Engineers Omaha District built six main stem dams The USACE and Bureau Join Forces: and many smaller dams along Missouri River tributaries. These, along with a system of federal and private levees, provide flood risk reduction for urban and agricultural property. The Pick plan, with its emphasis on flood control and navigation, drew its strength from lower basin interests and their advocates in Congress. Support for Sloan’s plan for irrigation and In 1943 a spring thaw caused eight of the Missouri’s tributaries to spill over the banks. The hydroelectricity came from upriver and had congressional backing. main stem itself flooded between Pierre, SD, and Rulo, NE. A total of 700,000 acres were submerged with damages reaching almost $8 million. Both of the original plans proposed a series of big dams and reservoirs on the main stem above Sioux City. Both would develop hydropower, where feasible, after meeting primary demands Later that year, two separate downpours inundated 540,000 and 1.2 million acres. The for irrigation or navigation and flood control. The two agencies made major compromises on estimated damages amounted to $32 million. The floods interrupted wartime training, proposed main stem dams between Fort Peck and Sioux City. They agreed on five in the production, and ruined crops needed by American allies overseas. The combined torrents, Dakotas, which would impound 72 percent of the new water storage in the entire basin. The known as the “Flood of ‘43” had a long-term impact on the Missouri River basin. The flood USACE and the Bureau settled additional differences in the original proposal, bringing together became the catalyst in markedly changing the mission and program of the Civil Works program both groups through the Pick-Sloan Plan. within the Omaha District. On December 22, 1944, President Roosevelt approved the Flood Control Act, authorizing the Colonel Lewis A. Pick’s concern as Missouri River Division Engineer focused on flooding. Pick Pick-Sloan Plan. The legislation provided the framework for the development of water had served as the New Orleans District Engineer just after the record-breaking Mississippi River resources on the Missouri River and the basis for Omaha District major undertakings on the floods of 1927 and had served as the engineer assistant to Secretary of Commerce Herbert main stem in the years to come with eight authorized purposes: flood control, navigation, fish Hoover on the Relief Commission to the area. and wildlife, irrigation, hydropower generation, recreation, water supply, and water quality. Pick’s experience with the lower Mississippi River garnered credibility toward his 13-page proposal that addressed managing the Missouri River. Previous river developments in the valley had been oriented toward specific projects rather than a broad program. Pick’s plan shifted the emphasis from a single to multiple-purpose concept. It envisioned a vastly expanded federal water policy in the basin. Pick recommended that the USACE construct multiple-purpose dams in the Dakotas. These dams would store flood-producing water and use it to provide hydroelectric power, wildlife and recreation facilities, a navigable channel and irrigation, plus water for domestic and sanitary needs. He expected other benefits as well, including protecting lives and property, and stabilizing and encouraging economic development. His plan proposed a progressive development. Pick concluded that it would not be feasible to construct all the multiple-purpose units simultaneously. He recommended an orderly, four- phase approach as circumstances and funds permitted. Pick-Sloan Plan for Missouri River Basin Also focused on taming the Missouri was William G. Sloan, assistant director of the Region 6 office of the Bureau of Reclamation in Billings, MT. After the passage of the 1939 Reclamation Act, Sloan was assigned to prepare a basinwide water resources development plan in order to bring the greatest good to the greatest number of people. The Bureau’s report assumed that farming would remain the primary basis of the basin’s economy.
William G. Sloan, Assistant Director, Region 6 Bureau of Reclamation and Colonel Lewis Pick, Missouri River Division Engineer
5 6 This page intentionally left blank Existing Infrastructure, Conditions, Opportunities
2.1 OVERVIEW OF HYDROPOWER Hydroelectric power is currently the largest source of renewable power Hydropower Statistics Data2 in the U.S. The average American home uses about 10,500 kilowatt- hours of electric energy every year. Hydropower is an important The world’s electricity produced by Hydropower 21% source of that energy. It provides electricity to light our homes and to The U.S. energy supplied by Hydropower 9% run our appliances, televisions, computers, and many labor-saving Hydropower percent of all renewables 49% devices. Just as important is the electricity provided to our schools, Efficiency hydropower turbines can achieve 90% hospitals, stores, offices, farms, and factories. There are many ways to generate electricity, but hydropower has some characteristics that make it especially valuable to the community1: It’s renewable. Hydropower is the nation’s most productive source of renewable energy. The earth’s hydrologic cycle provides a continual supply of water from rainfall and snowmelt. In addition, hydroelectric energy saves scarce, non-renewable fossil fuels. It’s efficient. Hydropower plants convert about 90 percent of the energy in falling water into electric energy. This is much more efficient than fossil-fueled power plants, which lose more than half of the energy content of their fuel as waste heat and gases. It’s clean. Hydropower plants emit none of the waste gases, like carbon dioxide, that contribute to air pollution, acid rain, and global warming. They don’t cause noise pollution. No trucks, trains, barges, or pipelines are needed to bring fuel to the power plant site. It’s reliable. Hydropower plant machinery is relatively simple and runs at slow speeds. This makes it reliable and durable. It’s flexible. Hydropower units can start quickly and adjust rapidly 1/ Source: Hydropower Value to the Nation, 2009; Institute for Water Resources to changes in demand for electricity. This makes them valuable for 2/ Source: IEA, Interesting Energy, PEW Climate; http://www.statisticbrain.com/ meeting peak loads and for serving as reserve capacity to protect hydropower-statistics/ power system reliability and stability.
7 Existing Infrastructure, Conditions, Opportunities
2.2 USACE HYDROPOWER Hydropower plants capture the energy of falling water to generate electricity. A dam impounds The U.S. Army Corps of Engineers is the largest owner/operator of hydroelectric power plants water to form a reservoir and raises the water level to create head. Head is the vertical distance in the United States and one of the largest in the world. The 75 USACE plants have a total the water falls as it passes through the dam (i.e. the difference in water level between the installed capacity of 20,475 megawatts and produce nearly 100 billion kilowatt-hours a year. reservoir and the river below the power plant). The water is directed through penstocks to This is nearly a third of the nation’s total hydropower output: enough energy to serve about ten turbines, which drive generators to produce electric power. Figures 2.1 and 2.2 show cross- million households, or roughly ten cities the size of Seattle, Washington. sections of the dam, intake, and power house. Hydropower is one of the products of developing rivers for multiple purposes. Over the years, Congress has directed USACE to build water resource projects to serve public needs such as flood control, water supply, and navigation. Where feasible, hydropower has also been included. The earliest hydropower plants at USACE projects were constructed at navigation dams as joint efforts with electric utility companies. The utilities built the power plants and USACE usually built the navigation locks. Later, Congress authorized USACE to construct its own power plants at dams being built for flood control, navigation, and other purposes. Most of these projects were placed in service during the decades following World War II. In the late 1970s, emphasis shifted back to allowing nonfederal hydropower development at Corps projects. More than 90 of these retrofits have now been completed by municipalities, electric utilities, and independent power producers. USACE is working hard to keep its power plants operating at peak efficiency and reliability. State-of-the-art equipment is used whenever possible to replace aging turbines, generators, and control systems.
Figure 2.1 Hydropower dam section The challenges facing USACE hydropower include: Aging infrastructure issues with growing investment needs; Pressures to reallocate reservoir storage to non-power uses; The need to restore aquatic ecosystems affected by Corps dams (environmental flows, water quality, endangered species management, etc.); An uncertain hydrologic future related to climate variability and change; Limited flexibility to react to opportunities for new development due to lack of Congressional authorities and/or appropriations; and Congressional appropriations are either stagnant or declining.
Figure 2.2 Cross-section view of an intake and power house
8 Existing Infrastructure, Conditions, Opportunities
2.3 NWO PROJECT OPERATION Despite these challenges, there are important new opportunities. These include: U.S. Army Corps of Engineers projects with hydropower generating facilities fall into two categories: storage and run-of-river projects. New recognition of the value of hydropower as a preferred source of renewable energy; Storage projects are usually located in the headwaters of river basins. Their purpose is to more A strong customer base that is showing increasing willingness to pay for modernization actions at Corps dams; evenly distribute the streamflow they release over the course of the year. In nature, river flow fluctuates widely. Streamflow is typically high during the rainy season and low in late summer Need for energy storage and flexible generation to provide ancillary benefits to the power and fall. In semi-arid regions, rivers become nearly dry in autumn. In many of the western river grid of the future; and basins, flows remain low all winter as snow accumulates in the mountains and then swell with Availability of new technologies that improve environmental and energy performance, snowmelt in the spring. opening the door to new energy development.3 Storage reservoirs capture river flow during the high runoff season and release it during the dry The best path forward for USACE hydropower in the Omaha District is a very active and periods. This creates a more dependable year-round flow for generating power. Keeping flows aggressive modernization process. However, this cannot be implemented unilaterally by the higher during the dry season also benefits other downstream river uses, like navigation, federal agency. Key elements of this path include working with Missouri River power fisheries, recreation, water quality, and municipal water supply. Also capturing part of the customers to fund the rehabilitation and replacement of power generating components over the runoff during high flow periods helps reduce flood damage downstream. In fact, flood damage next 20 years. The district will build on our existing working relationships with WAPA and reduction is one of the major purposes of all USACE storage projects. Because storage projects Western States Power Corporations (WSPC) to decide the types of upgrades in turbines or follow a seasonal pattern of releasing water during dry periods and refilling in the high runoff generators that are most cost effective. season, water levels in the reservoirs behind dams fluctuate. They are usually full in early summer, but once the dry season begins, there is a gradual drawdown. Fort Peck, Garrison, 3/Source: Hydropower Value to the Nation, 2009; Institute for Water Resources Oahe, and Fort Randall are considered storage projects. Key Messages Facts & Figures The other major type of dam is the run-of-river project. It has little or no storage. The most common example of USACE run-of-river project is the navigation lock and dam. Its purpose is USACE is the largest owner-operator of USACE operates 75 hydropower plants with a to raise the river level to provide enough depth for commercial navigation. Such dams would hydroelectric power plants in the United States rated capacity of 20,475 Megawatts (MW), and and one of the largest in the world. maximum capability of 22,900 MW. typically be located on the lower reaches of a navigable river. On the Missouri River, Gavins Point and Big Bend are considered run-of-river projects.4 USACE hydropower plants produce over 70 USACE owns and operates 353 hydroelectric billion kilowatt-hours of electricity annually. generating units that represent 24 percent of the 4/Source: Hydropower Value to the Nation, 2009; Institute for Water Resources nation’s hydropower capability and 3 percent of USACE hydropower is the largest producer of the total electric capability. renewable energy in the United States. USACE has 63 non-federal FERC-licensed USACE hydropower plants provide clean, low- hydropower plants operating on its facilities cost energy to rural America. with a total capacity of 2,360 MW.
9 Existing Infrastructure, Conditions, Opportunities
Below is a summary table of the power house statistics and performance by facility for fiscal year 2015. Figure 2.3 depicts the overall O&M costs per megawatt hour (MWh) by plant. Fort Peck has a higher cost per MWh due to being a peaking plant (generates only when there is high demand). Because it supplies power only occasionally, the power supplied is at a higher price per kilowatt hour than base load power. Also, Big Bend is double the amount of the average due to hydro paying 100% of the project joint costs and also being a peaking plant like Fort Peck. Figure 2.4 illustrates the power plant availability. The average plant availability in FY15 was 87%. Oahe was below the average due to a high number of forced outages from reliability issues with governors and thrust bearing coolers in the turbines. Both of those issues currently have funded capital improvement requirements. Big Bend is below average due to a high number of scheduled outages from an on-going transformer rehab project.
Summary Table Fiscal Year 2015 Statistics and Performance by Facility
Facility Generation Plant O&M Costs Forced Outage Scheduled Outage Availability
No. of Nameplate % of NWO No. of Unit Net Generation O&M Cost O&M Cost Total Hours Factor Total Hours Factor Yearly Hours Factor Units Capacity (MW) Capacity Starts (MWh) ($/MWh) ($/MW) No. Unavailable (%) No. Unavailable (%) Hours Available (%)
Fort Peck 5 185.3 7.4% 91 794,547 $11.71 $50,241 7 125 .3% 13 4,280 9.8% 43,800 39,395 89.9%
Garrison 5 583.3 23.3% 6 2,292,228 $4.85 $19,063 9 33 .1% 17 4,790 10.9% 43,800 38,977 89.0%
Oahe 7 786.0 31.4% 30 2,677,495 $3.41 $11,607 12 2385 3.9% 22 8,623 14.1% 61,320 50,312 82.0%
Big Bend 8 494.3 19.8% 1,541 980,657 $13.83 $27,445 6 148 .2% 45 12,130 17.3% 70,080 57,802 82.5%
Fort Randall 8 320.0 12.8% 59 1,780,722 $5.47 $30,464 26 106 .2% 36 6,778 9.7% 70,080 63,196 90.2%
Gavins Point 3 132.3 5.3% 20 794,276 $9.17 $55,044 0 0 0% 8 1,490 5.7% 26,280 24,790 94.3% Total/ 36 2,501.2 100.0% 1,747 9,319,925 $6.45 $24,047 60 2,797 .9% 141 38,090 12.1% 315,360 274,474 87.0% Average
Figure 2.3 O&M Costs ($/MWH) By Plant Figure 2.4 Power Plant Availability
10 Existing Infrastructure, Conditions, Opportunities
2.4 HYDROPOWER ASSET MANAGEMENT PROGRAM
The Omaha District manages 36 main generating units in 6 hydropower plants. It considers HydroAMP Condition Index thousands of equipment components in maintenance and investment program. Component condition is a key driver of maintenance and investment needs. Rating Condition Definition The HMP uses the Hydropower Asset Management Program (hydroAMP) to assess the Categories Index (CI) condition for power train and auxiliary hydropower plant components. Equipment within a There is a high level of confidence that the component will Good 8-10 hydroelectric power plant, no matter whether it is a part of a unit powertrain or provides perform well under normal operating conditions. support to the power plant and its operations, is appropriate for analysis under a condition assessment program. An unexpected failure can have a significant economic impact due to the There is a low to medium level of confidence that the component high cost of emergency repairs and replacement power costs during an extended forced outage. will perform well under normal operating conditions. Minimal restrictions to operation (6-8 CI); however, restricted operation Fair 3-8 HydroAMP evaluates equipment condition through a complementary two-tier assessment and/or non-routine maintenance may be necessary (3-6 CI). framework. An initial Tier 1 assessment uses condition indicators generally regarded by Repeat condition assessment on normal frequency. Major hydropower plant engineers as providing the initial basis for assessing equipment condition. upgrades or other repairs may be required within 10 years or less. These condition indicators are evaluated using inspections, tests, and measurements conducted by power house staff as part of routine maintenance activities. Generally, the following The component does not perform well under normal operating condition indicators are used to evaluate the equipment condition: conditions. Physical signs of serious damage or deterioration are Poor 0-3 present. Significant restrictions to operation and/or non-routine Age or Number of Operations maintenance are necessary. Major upgrades or other repairs may Operational Performance be required within one to five years. Maintenance History System Wide Major Power Train Component Conditions Physical Inspection The following subsections summarize major powertrain components of the power houses, their Test and Measurements current condition, pertinent requirements, and on-going modernization/repair efforts. The Condition ratings for each equipment type are based on a set of objective condition indicators table below provides a summary of the power train components that have the greatest potential related to operational performance, maintenance history, physical inspection, and age. to constrain the mission and their current condition or status described in the most recent Condition indicators are weighted and summed to derive a condition rating, ranging from hydroAMP assessments of those systems. 10 to 0. Numeric scores are further described qualitatively as follows: System Wide Major Power Train Component Conditions
Circuit Generator Generator Exciters Governors Turbines Transformers Breakers Rotor Stator
Mean 8.8 8.3 6.8 5.8 6.4 5.7 7.2
Median 9.7 7.7 6.4 4.3 6.1 5.8 6.9
11 Existing Infrastructure, Conditions, Opportunities
Circuit Breakers Exciters A circuit breaker is an automatically operated electrical switch designed to protect the Excitation systems are key power train components. The generator will not operate without a associated equipment (generator, transformer, transmission line) from damage by disconnecting properly functioning exciter. An excitation system comprises all the devices responsible for it from the electrical system. There are four different types of circuit breakers: air blast, oil tank, delivering the field current to a synchronous generator along with the equipment responsible SF6, and vacuum. The Missouri River power houses have replaced many of the original oil and for regulating the stator voltage, including the limiting and protecting functions. The air blast circuit breakers with modern SF6 and vacuum circuit breakers that provide better evaluation of condition considers age, operation & maintenance history, availability of spare protection with lower maintenance options. The circuit breakers are obtained from a variety of parts, power circuitry test, and control circuitry test. manufacturers, and there are a large variety of designs. During operation, excitation systems are continuously subjected to electrical, mechanical, thermal, and environmental stresses. Over time, these stresses deteriorate certain components Circuit Breaker Condition Index in the excitation system and can possibly lead to unexpected, catastrophic failure and forced outage. The average life expectancy of previous excitation systems was about 30 years; Power house Condition Index however, it is difficult to predict life expectancy for newer digital systems where computer Fort Peck 10.0 software/hardware may become obsolete in a few years and long-term experience with digital systems is not yet available. Garrison 10.0 Maintenance, performance, repair, or replacement schedules are usually specified in the Oahe 9.3 manufacturer’s instruction manual. In cases where elements are found to be deficient, repair or replacement of a single component may be the most appropriate solution, although replacement Fort Randall 6.7 of other components or entire systems may sometimes be appropriate. Big Bend 6.7 Gavins Point 10.0 Excitation System Condition Index Power house Condition Index Fort Peck 9.0 Garrison 10.0 Oahe 7.3 Fort Randall 9.9 Big Bend 6.4 Gavins Point 7.0
Oahe Project’s unit breaker project replaced the original Westinghouse airblast breakers with ABB SF6
12 Existing Infrastructure, Conditions, Opportunities
Operations has accordingly prioritized replacing exciters to raise the overall condition index. Generator Stator Oahe, Big Bend, and Gavins Point are all funded for replacement over the next five years. During operation, large synchronous generators are continuously subjected to electrical, The excitation systems at Gavins Point have experienced control section failures with increasing mechanical, thermal, and environmental stresses. These stresses act and interact in complex frequency. The Siemens line of exciters has been discontinued for the last 13 years and is only ways to degrade the machine’s components and reduce its useful life. Deterioration of the supported by two independent installers. These are one-man shops that could retire at any time. stator winding insulation is a leading factor for determining serviceability of hydroelectric Likewise, Siemens no longer supports their circuit boards which include a large number of generators. Unexpected stator winding failure can result in forced outages and costly analog and power electronics. While there are currently adequate spare parts available at the emergency repairs. The age of generator stator winding plays a significant factor when power house, the frequent card repairs are only available from two known independent identifying condition. The design life of a stator winding is typically 25 to 35 years. electronics shops doing reverse engineering and replacing components with aftermarket parts. This model and vintage of exciters have seen increasing problems over the last few years at the Generator Stator Condition Index Oahe and Big Bend Plants and throughout the Corps. The concern is that the frequency of exciter failures is increasing and the repairs are becoming more difficult. Power house Condition Index Fort Peck 5.6 Garrison 10.0 Oahe 3.9 Fort Randall 2.8 Big Bend 8.5 Gavins Point 4.7
Fort Randall Project’s exciters installed between 2011 and 2014
Big Bend power house rotor pulled for stator rewind
13 Existing Infrastructure, Conditions, Opportunities
Omaha District has an aggressive implementation strategy to improve stator windings. The The performance speed of a governor is one of the leading indicators in determining its stator windings at three plants (Fort Randall, Oahe, and Gavins Point) are beyond or condition. Factors considered in evaluating performance include: synchronization time, system approaching their end of life. While the likelihood of a stator failure at these plants is relatively stability, accuracy and repeatability in response to load change and system disturbance. low, a stator failure has a significant financial impact proportional to the time of the forced Omaha District’s capital improvement plan includes the recent award of a supply contract to outage. Given the time required to design a stator rewind, having rewind packages on the shelf procure digital governor systems under one single acquisition and award multiple install can significantly expedite a unit’s return to service. contracts over the next few years. Governors The governors at Oahe, Fort Randall, Big Bend, and Gavins Point are antiquated, difficult to Governors control the speed of the unit by operation of the wicket gates through a combination maintain calibration, require relatively high levels of maintenance and are experiencing control of hydraulic, mechanical, and electrical means. Hydraulic pumping units pressurize oil and issues with increasing frequency. Support for the governors is provided by one company that store it in a pressure tank to be directed for use by the governor. The governor is connected reconditions used parts. Since FY2010, Big Bend has experienced five forced outages (80 hrs electrically to the turbine’s speed through the permanent magnet generator (PMG). The downtime) and Oahe experienced four forced outages (85 hrs down time). The concern is that governor, through a series of mechanical and hydraulic linkages, directs the pressurized oil to the frequency of governor failures is increasing and the repairs are becoming more difficult. A the servomotor which opens and closes the wicket-gates and allows speed droop control. The governor that is out of calibration does not properly manage unit loading during frequency governors also use auxiliary equipment such as gate position limit switches, oil pressure relays, excursions. The governor operation is critical to system performance during load rejections and rectifier resistor pack, solenoid operated generator air brake valve, and continuous and intermittent brake timer control. The age of the governor is among the factors to consider when identifying candidates for mechanical rehabilitation, partial replacement (digital retrofit), or complete replacement. Age is one indicator of remaining life and upgrade potential to current state-of-the-art materials and design. As a governor ages, the mechanical parts become affected by wear and are more susceptible to internal leaks, thus affecting performance. In the same way, the electronic parts are subjected to more deterioration due to overheating, excessive vibration, or contamination. The average life for a governor control system varies from 15 to 40 years depending upon the type of control system.
Governor Condition Index Power house Condition Index Fort Peck 8.7 Garrison 10.0 Oahe 4.9 Fort Randall 4.9 Big Bend 6.1 Gavins Point 5.8
Big Bend Project’s existing mechanical governor cabinet
14 Existing Infrastructure, Conditions, Opportunities
is receiving increased scrutiny from NERC (North American Electric Reliability Corporation). Big Bend is experiencing cavitation maintenance issues on a much greater scale than they have The Garrison power house governors that received digital conversions ten years ago have been seen before. Maintenance has seen a 400-600% increase in the amount of welding wire needed to performing very well. complete cavitation repairs. Big Bend project staff normally performs turbine maintenance Existing governors are from different manufacturers and vintage. The district plans to upgrade every other year; however, they are having difficulty completing the required maintenance in all existing systems to a single type of manufacturer. This allows the District to provide a the allotted timeframe. Big Bend is having issues with the wicket gate operating rings, wicket programmatic upgrade of the governors and develop a family of governor controls with gate seals, wicket gate bushings and blade wedges. The quality of the gate seals has a direct common parts and maintenance. The simultaneous procurement of the similar system impact on condensing operations and number of blow-down cycles experienced. replacements will provide for an economy of scale, efficient installation and shared parts and Gavins Point Power Plant is also experiencing significantly increased cavitation maintenance on knowledge for future installation. both the turbine and the throat. They normally perform two weeks of cavitation maintenance Rehabilitation or upgrade of governor systems is identified as one of the top items in the Corps every third year, and are again having difficulty completing the work done in the time allotted. of Engineers HMI program for investments that provide the greatest return on investment, control risk exposure, and provide a strategy for maintaining long-term reliability, efficiency and safety of the assets. Turbines The Omaha District has both Francis and Kaplan hydraulic turbines. Age is an important factor to consider when identifying candidates for turbine runner replacement or refurbishment. As a turbine ages, it becomes affected by fatigue and becomes susceptible to cracks. The effect of weld repairs over the years can be cumulative, increasing the likelihood of failure. The intent of age criterion for the turbine condition assessment is to indicate performance degradation. The surface condition of the waterway is important, especially since it affects the efficiency Big Bend Project and capacity of the machine. Areas in the waterway that see the highest velocities will have wedge corrosion the largest effects on efficiency. The surface condition of metal components may deteriorate and cavitation damage over time due to erosion, corrosion, operating in rough zones, cavitation, cracking damage, and repairs.
Turbine Condition Index Power house Condition Index
Fort Peck 5.3 Garrison 9.6 Oahe 6.5 Fort Randall 4.1 Big Bend 5.8 Gavins Point Gavins Point 3.3 Project cavitation damage to discharge ring 15 Existing Infrastructure, Conditions, Opportunities
2.5 ENERGY REPLACEMENT COSTS Transformers A key aspect in evaluating future projects is understanding the energy replacement costs for each plant. By quantifying the consequences of unit outages, the district can: Omaha District has 70 large power transformers including 56 generator step-up transformers (GSU). In 2008, HDC conducted a thorough analysis of the system that has provided the Prioritize asset replacement based on avoided consequence due to unit outages; strategy for replacement. The condition of a transformer is evaluated upon four factors: oil Schedule maintenance to minimize costs; and analysis, power factor and excitation current tests, operation & maintenance history, and age. Justify capital improvement projects.
Transformer Condition Index The energy replacement values are meant to describe the cost of energy from alternative resources used to replace lost hydropower generation due to outages. The method of Power house Condition Index calculating the cost considers both the cost due to lost generation and the cost due to changes Fort Peck 6.9 in generation mix (shifting peak to off-peak outages). It quantifies the consequences of unit outages by the number of units out. Garrison 10 Figure 2.5 below shows the average replacement cost for the first three unit outages at each of Oahe 6.2 the six power houses. Typically no more than two outages would occur at any one time. The Fort Randall 6.9 graph indicates the cost of a single unit outage at Gavins Point and Oahe are significantly more expensive than at the other plants. Big Bend 8.6
Gavins Point 6.3
Gavins Point GSU new transformer yard
Oahe spare GSU single phase Figure 2.5 Average replacement cost ($/Day) transformer
16 Existing Infrastructure, Conditions, Opportunities
Additionally, there is a substantial difference of the energy cost replacement throughout the year by plant. Figure 2.6 below shows the seasonal energy replacement cost per day of each power house production for one unit outage. All plants have their highest energy replacement costs during the summer. Gavins Point and Oahe have over double the cost during this time period. This information helps guide our future development plans considering the execution schedule that require outages.
Figure 2.6 Seasonal replacement cost per day for 1 unit outage
17 18 This page intentionally left blank Future Development Plan
3.1 HYDROPOWER MODERNIZATION INITIATIVE Across the U.S. Army Corps of Engineers, many hydropower The AIP tool was developed to efficiently execute this process. infrastructure assets are approaching the end of their original design or The AIP tool incorporates asset age, equipment condition, service life. Without major investments in renewals and replacements facility operations, risk analyses and financial analyses to of critical equipment, the USACE will be exposed to increasing risk of provide the overall economic benefits and risk reductions asset component failures resulting in significant losses in energy resulting from varying user-defined funding strategies over a production over the next 20 years. To address this risk, the USACE twenty-year planning horizon (currently 2018 to 2037). The created the HMI, a risk-based asset management decision tool for major AIP tool evaluates and analyzes the power train assets from 54 capital investment. USACE hydropower facilities, comprising more than 1,200 The HMI uses asset management principles to develop analyses to power train asset components. Power train assets include: support decisions in modernization investments that provide the Major Components greatest economic benefit, control the USACE’s risk exposure, and Turbines create a coordinated, USACE-wide long-term strategy for Generators maintaining the reliability, efficiency and safety of these assets. Auxiliary Components The HMI objective is to assess and prioritize the investment needs at Governors USACE hydropower projects using asset management principles. To Exciters achieve this, an asset investment planning process, methodology, and Main unit transformers supporting Asset Investment Planning (AIP) tool were developed. The Main unit circuit breakers AIP tool was designed to: Once the asset information is loaded in the AIP tool via the Review key power train assets and corresponding key attributes. inputs described above, it calculates metrics used for Analyze and prioritize asset investment projects by year based on prioritizing potential investments. These calculations are factors including benefit-cost ratio, net present value and risk. based on a risk management approach, following the Prioritize the allocation of annual budget dollars to maximize fundamental concept that risk is equal to the product of the economic benefit and reduce the risk of the asset portfolio. likelihood of an asset’s failure and the consequence of that asset’s failure.
19 Future Development Plan
3.2 REHAB STRATEGY Risk = Probability of Failure * Consequence of Failure Implementation of the future development plan is a long-term effort that will be achieved incrementally based on funding, outage constraints, and mission requirements. Probability of Failure = Age and Condition HydroAMP is used to capture trends in performance and condition indicators through periodic Consequence of Failure = Replacement Cost of Component + Energy Replacement Value inspection to develop a condition index. Unit rewinds are anticipated to occur every 30 to 50 Probability of failure is based on 50 years of asset retirement data collected from the USACE, years as units reach or exceed their design life. As a unit reaches its expected life, physical signs Bureau of Reclamation, and the Tennessee Valley Authority. The data are used to fit a Weibull of deterioration are present, and operational restrictions are deemed necessary, USACE will Hazard function that utilizes hydroAMP condition and age. conduct a unit and powertrain assessment evaluating the fatigue and efficiency. Designers will The consequence of failure is the sum of two components, asset replacement cost and the energy coordinate with WAPA on forecasted load growth and division water management on flows to replacement value for the asset failing. The replacement cost is defined as the estimated cost to determine if additional power production can be achieved from level adjustments. A business replace the failed asset using historic cost data. The energy replacement value is defined as the case justification will be created evaluating risk of failure from fatigue issues, gains in efficiency, loss of generation that would be experienced if the component fails1. A review of the district’s and payback periods. energy replacement cost by power house can be found in Section 2.5 of this document. HMI and AIP tools provide the foundation of extent and timeline by which a long-term strategy Figure 3.1 shows the output of the AIP tool’s cumulative risk for Omaha District and the impact is developed utilizing USACE Asset Management Principles. In developing the prioritization of various funding alternatives. The figure displays the effect of funding alternatives to reduce and fiscal year accomplishment, WAPA’s constraints for outages are twofold. One is that no risk. The model indicates a reduction of risk does not occur until $40 to $50 million dollars more than one third of generation or regulating resources shall be unavailable at any given time comes into the program annually. This HMP utilizes this information to determine the at any one plant so that transmission voltage can be maintained at required levels. The other is minimum level of funding to sustain operations and reduce risks of failure. that the associated plant transmission outages will be dependent on coordination with the Reliability Coordinator and may be restricted by the coordination process conducted by WAPA.2 1/Source: Hydropower Modernization Initiative Implementation Strategy for FY2018 Budget Development; 2016 2/Source: WAPA review of Draft HMP, May 2016
20-Year Rehab and Major Repair Project Overview 2017-2020 2021-2025 2026-2030 2031-2035 Design units 4 & 5 Award units 4 & End rewind Award units rewind 5 rewind Design turbines 1 & 3 turbine Fort Peck Design & award Award 1 & 3 switchyard 1 switchyard 2 Garrison End rehab Study rehab Update rehab Award rehab Oahe requirements design Design & award End cavitation Study/design Big Bend cavitation repair repair rehab
Fort Design major Award phases 1 Award phase 3 End rehab Randall rehab & 2 rehab rehab Gavins Design & award Study/update Award rewind End rewind cavitation repair design rewind Figure 3.1 Omaha District cumulative risk over a 20-year period Point
20 Future Development Plan
The Omaha District will work closely with WAPA and WSPC to decide the actual types of upgrades in turbines or generators. The 20-Year Rehab and Major Repair Project Overview table on the previous page provides an outline of the strategy that is further discussed in each power plant development plan. Omaha District will complete the rehabs of Garrison and Fort Randall over this time period and then prepare for a possible award of Oahe rehab at the end of this period following assessment of the powertrain and units conditions. Approximately 80 percent of the power generated on the Missouri River comes from these three plants. At the same time, based on the condition of the three other plants projects are identified that will sustain their reliability on key components. This outline provides a road map of district execution prioritization and execution of the next 20 years to achieve reliable energy to the system based on the HMI prioritization, a $40- 50M funding need, and an initial evaluation of implementing the projects with operational/ funding constraints.
3.3 CAPITAL IMPROVEMENT PLAN SHORT MEDIUM LONG The strategy of the capital improvement plan and its implementation is Power Plant/ 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 divided into the following four phases: Fiscal Year In-Process: Projects that have been funded and currently being Fort Peck executed. Short Range: Projects that will begin execution in the next two years from Switchyard 1 A Fiscal Year 2017-2018. These projects are under budget and execution Unit 4 & 5 A evaluation. Medium Range: Projects that will be executed in the next three to ten Switchyard 2 A years from Fiscal Year 2019-2025. These projects are being scoped or being Unit 1 & 3 A designed. Long Range: Projects that will likely be executed at least ten years or Garrison more in the future. These projects have been identified as long-term needs. Oahe Figure 3.2 provides an execution timeline for the rehabilitation and major Rehab A repair projects identified in the previous table. “A” refers to the anticipated fiscal year the requirement would be awarded based on the need and the Big Bend funding strategy. The black filled boxes following the award year represent the expected time period for the construction to be complete. This is to be Cavitation Repair A used for planning purposes to anticipate construction periods and outage Fort Randall timelines. The actual schedule will require additional analysis and coordination as the requirement is refined. Ph 1 Rehab A Ph 2 Rehab A Ph 3 Rehab A Gavins Point
Cavitation Repair A
Rewind A Figure 3.2 Execution timeline for Missouri River main stem dam rehabs and major repairs
21 Future Development Plan
IN-PROGRESS PROJECTS Table 3-1 lists projects that have been funded and currently being executed. PH=power house location, FY=fiscal year, PA=program amount, Status= phase.
Table 3-1: In-Progress Consolidated Project CIP Matrix Project Project PH Project Title FY PA ($K) Status PH Project Title FY PA ($K) Status Number Number IN-PROGRESS IN-PROGRESS FP 405213/514 Station service interior transformers 13 $370 Awarded BB 122957/355 Generator rewinds 09 $15,391 Closeout FP Multiple Rehab unit 2 and install high resistance grounding 15 $7,857 Construction BB 399793/510 Transformer oil containment 13 $1,125 Award FP 454556/552 Install generator relays 15 $600 Awarded BB 399792/501 Rehab generator step up transformers 13 $1,400 Award FP 449565/556 Replace emergency gate hoist wire rope 15 $1,200 Construction BB 456669/503 Replace programmable logic controllers 16 $600 Award FP 405212/517 Rehab emergency gate control system 14 $1,355 Construction BB 399794/500 Replace generator excitation system 14 $6,567 Award FP Multiple Supply-install transformers and oil filled cable system 13,15 $5,510 Awarded BB 456035/561 Repair/replace intake gate hoist gear box assemblies 16 $1,800 Advertise FP 329337/531 Rehab draft tube bulkheads 14 $730 Advertising BB 406304/520 Design/install digital governor upgrades 15, 16 $4,250 Advertise FP 454554/554 Instrument transformer replacement (PT/CT) 15 $300 Advertising Replace raw water header, unwatering valves, station BB 499301/543 15 $2,350 Design FP 447127/532 Replace motor control center 14, 16 $2,314 Awarded drainage piping FP 405220/516 Rehab switchyard 1 16, 18 $4,700 Design 17 FR 449299/541 Design generator step up transformers 15 $200 Design FR 125884/476 Validation study 12 $200 Design FP 454557/553 Rewind/rehab units 4 and 5, and switchyard 2 16, 21 $20,000 Design 18 FR 399807/505 Rehab bridge cranes 13 $3,800 Award GA 18-1160 Repair intake structure roof 15 $4,000 Award-O&M FR 18-7609 Repair intake structure curtain walls and drains 16 $935 Award GA 105566 Major rehab $95,297 Construction FR 455996/564 Rehab 13.8kV outdoor station service equipment 15 $810 Advertise GA 456630/567 Replace programmable logic controllers 16 $600 Awarded FR 399806/504 Replace oil-filled cable 13 $11,700 Award GA 461090/589 Generator yard civil work 16 $3,000 Designing FR 449297/547 Purchase and install unwatering valves 15 $1,100 Award GA 18-1182 Upgrade intake crane 16, 17 $2,000 Design-O&M FR Multiple Upgrade switchyard 14 $15,950 Award OA 449302/526 Generator rewind design 15 $83 Designing FR 406244/521 Replace generator relays 14 $500 Award OA 399795/510 Tailrace deck transformer oil containment 13 $1,125 Construction FR 449300/542 Upgrade station service switchgear 15 $1,840 Design OA 456033/573 Repair thrust bearing cooler 16 $300 Designing FR 456029/566 Replace station service transformers 15 $920 Design OA 18-1178 Penstock dewatering piping in shale drain tunnel 16 $170 Awarded GP Multiple Replace and install generator step-up transformers 11, 12 $5,300 Closeout OA Multiple Upgrade 115 and 230 kV switchyard and autotransformers 11 $10,800 Construction GP 449303/545 Generator rewind design 15 $83 Design OA 399796/509 Replace generator exciters 13, 15 $5,567 Designing Replace station service 480V breakers and dry-type GP 449304/548 15 $1,600 Advertise OA 456034/570 Generator step-up transformer bushing 16 $1,200 Designing transformers OA 456480/571 Bridge crane rehab 16 $5,500 Designing GP 399797/507 Replace generator excitation systems 15,17 $2,500 Design OA 406268/518 Install digital governor retrofits 15,16 $3,933 Designing GP 456650 Install intake raw water isolation valves 16 $375 Design-O&M GP 406271/519 Install digital governor upgrades 15, 17 $2,383 Design
22 Future Development Plan
SHORT RANGE PROJECTS Table 3-2 lists projects that will begin execution in the next two years from Fiscal Year 2017-2018. These projects are under budget and execution evaluation. PH=power house location, FY=fiscal year, PA=Program Amount, Status= next level of effort.
Table 3-2: Short Range Consolidated Project CIP Matrix Project Project PH Project Title FY PA ($K) Status PH Project Title FY PA ($K) Status Number Number SHORT RANGE 2017-2018 SHORT RANGE 2017-2018 FP TBD Replace programmable logic controllers 16 $600 Design 17 BB 18-1221/22 Rehab intake crane 17, 18 $2,400 Design 17 FP 458812/578 Modernize shaft building cranes 16 $1,000 Design 17 BB 18-1168 Power plant HVAC upgrade 18,19 $1,200 Design 18 Rehab depressing air/station service air FP 458814/577 Replace power house fire and security system 16 $250 Design 17 BB TBD 18,19 $1,275 Design 18 systems FP 458813/579 Bridge crane design and repair 16 $4,300 Design 17 FR TBD Replace programmable logic controllers 17 $633 Design 17 FP 18-2151 Replace draft tube stop logs 16 $1,000 Design 17 FR 18-1160 Rehab intake crane 17 $811 Design 17-O&M FP TBD Install digital governors 18, 19 $4,000 Design 18 FR Multiple Major rehab-study and design 17-21 $220,000 Study 17 GA 18-1159 Replace equalizing valves 17,18 $4,500 Design 17 FR 18-1169 Intake gate rehab 18, 19 $4,170 Design 18 GA 18-1108 Repaint/repair penstock gates and lifting beams 17,18 $5,300 Design 17 GP TBD Replace programmable logic controllers 17 $633 Design 17 OA TBD Replace programmable logic controllers 17 $633 Design 17 Replace CO2 fire suppression system in the Design 17- GP TBD 18 $365 Design 18 OA 18-1177 Replace intake motor controls 17 $650 power plant O&M GP 456032/568 Cavitation welding and coal tar coating repairs 16, 18 $10,000 Design 17 Replace monorail bridge crane at the emergency OA 18-1195 17, 18 $1,000 Design 17 spillway Replace outdoor station service switchgear and air OA 18-1091 17, 18 $1,200 Design 17 circuit breakers
23 Future Development Plan
MEDIUM RANGE PROJECTS Table 3-3 lists projects that will be executed in the next three to ten years from Fiscal Year 2019-2025. These projects are being scoped or being designed. PH=power house location, FY=fiscal year, PA=program amount.
Table 3-3: Medium Range Consolidated Project CIP Matrix Project Project PH Project Title FY PA ($K) PH Project Title FY PA ($K) Number Number MEDIUM RANGE PROJECTS 2019-2025 MEDIUM RANGE PROJECTS 2019-2025 FP 18-2139 Generator cooling water system replacement 18, 22 $2,500 BB TBD Replace MCCs/unit auxiliary panels 19, 20 $2,600 FP 18-2086 Seal joint on exterior power plant 1 18, 22 $1,500 BB TBD Replace generator breakers 19, 20 $4,000 FP 18-2131 Rehab butterfly valves 18, 23 $2,000 BB 18-1073 Recondition draft-tube liner, cavitation repair, paint turbines 20, 21 $20,700 FP 18-2122 Rehab stop log gantry cranes - $400 BB 18-1219/21 Rehab draft tube crane 20 $680 FP 18-2059 Modernize CO2 system in power plants 1 and 2 - $360 FP 18-7088 Clean, repair, and repaint corroded beams in power plant 1 - $365 BB TBD Replace unit vibration monitors - $400 FP 18-1026 Replace station service 4160 volt breakers power plant 2 - $500 BB 18-1195 Replace upstream monolith joint remedial water stops - $1,500 GA 18-1026 Replace power plant oil storage and oil purification CO2 systems - $270 BB TBD Recondition intake gates - $2,300 GA 18-1036 Paint walls on the generator and turbine floors - $335 BB TBD Trash rack rehab - $1,500 GA 18-7083 Paint three draft tube bulkheads - $240 BB TBD Handicapped access power house lobby and update displays - $300 GA 18-7629 Replace unit 3 penstock packing - $205 BB TBD Power house roof replacement - TBD GA 18-7082 Paint four intake bulkhead sections - $320 GA 18-1039 Intake structure asbestos abatement - $370 BB TBD Replace station and PPCS battery - TBD GA 18-7104 Paint intake structure bridge - $630 FR 18-1169 Intake gate rehab 18, 19 $4,170 GA 18-1014 Update generator carbon dioxide fire extinguishing system - $260 FR 18-1125 Replace power plant lobby displays - $350 GA 18-1038 Power plant asbestos abatement - $1,530 FR 18-1159 Rehab power house restrooms - $225 GA 18-7627 Repair power house tailrace deck cracks - $263 FR 18-1081 Rehab power plant entrance - $235 GA 18-1103 Repaint/repair the interior of the surge tanks & floors - $1,500 GP 18-1154 Refurbishment of tailrace draft tube gates 19, 20 $1,700 GA 18-1055 Repair power house parking lots and road - $2,400 GP TBD Switchyard instruments transformers and bus insulators (O&M) - TBD OA 18-1197 Tailrace bulkhead rehabilitation 19, 20 $1,800 OA TBD CO2 fire suppression upgrade 19, 20 $360 GP TBD Replace power plant roof - $250 OA 18-1110 Baseline security posture upgrade - $975 GP TBD Sectionalizer cabinets - $150 OA 18-1147 Switchyard Ph II, switchyard disconnect - $10,000 GP 18-1152 Upstream water stop repair/replacement at power house - $350 OA TBD Turbine and discharge ring cavitation repair - $4,500 GP TBD Tailrace stop logs sandblasting - $1,000 OA 18-1188 Remove asbestos containing material from structures - $200 GP TBD Corrosion control crane rehab intake & tail race - $500 OA 18-1059 B-FLOOR, surface rehab and wall painting - $200 GP TBD Upgrade HVAC system - $1,200 OA 18-1168 Expand 480 station service board - $500 GP TBD Piping epoxy liner - $200 OA TBD Replace station service battery - TBD OA TBD Replace plant unwatering pumps - TBD GP TBD Install switchyard switches - $265 OA 18-1168 480 station service, voltage regulator, and grounding - $1,300 GP TBD High impendence grounding - TBD
24 Future Development Plan
LONG RANGE PROJECTS Table 3-4 lists projects that will likely be executed at least ten years or more in the future. These projects have been identified as long-term needs. PH=power house location, FY=fiscal year, PA=program amount.
Table 3-4: Long Range Consolidated Project CIP Matrix Project PH Project Title FY PA ($K) Number LONG RANGE PROJECTS 2026-2035 FP 18-2103 Units 1 & 3 turbine replacement 31 $50,000 GA - Exciter replacement 31 $4,500 GA - Governor replacements 33 $4,000 GA - Generator rewind 35 TBD OA 18-1119 Turbine, generator, transformers replacement 35 $300,000 BB - Repair welds and repaint draft tube bulkheads - TBD BB - Station drainage system - TBD GP - Units 1-3 generator rewind 27 $73,000 GP - Replace circuit breaker vacuum - TBD GP - Replace compressed air system and blowers - TBD GP - Replace switchgear circuit breakers - TBD
25 Future Development Plan
3.4 FUNDING CONSIDERATIONS Based on HMI, reduction of risk and sustained reliability requires $40-50M annually put into the power houses. Figure 3.3 shows funding projections for the next 20 years. Annual requirements refer to the projects that will sustain, repair, and modernize power house components identified by the Operations Division. These projects typically include single components such as upgrading governors, replacing excitation systems, sustaining auxiliary components, and other power train repairs. Revolving is similar but specifically associated with all Fort Peck requirements in this plan. Rehab refers to the funds required to award the major projects in this plan that will repair multiple components such as turbine replacements, generator rewinds, and power house rehabs. After repairs are completed in the short to midterm, the HMP anticipates most efforts will focus on rehab requirements where $20-35M will be needed annually to award a single rehab effort.
Figure 3.3 Planned 20-year district funding requirements
26 Fort Peck Power Plant Development Plan
4.1 OVERVIEW The Old Fort Peck Trading Post, for which the project was named, was built in 1867 as a landing for steamboats traveling upstream. Construction of the Fort Peck Dam started in 1933 when Franklin D. Roosevelt authorized the project as part of the New Deal during the Great Depression. More than 40,000 people flooded to the area looking for work, creating 18 boomtowns featuring businesses and schools. The work force peaked in 1936, with 10,564 workers directly linked to the dam. The original purposes of the dam were flood control and navigation; however, Fort Peck later became a Pick-Sloan Missouri River Base Project authorized in the 1944 Flood LIFE’s First Cover Story: Control Act. Fort Peck Dam is the largest hydraulically-filled View of Fort Peck power houses with buffalo managed on project Building Fort Peck Dam, 1936 dam in the world. site
Location: Missouri River (Mile 1771.5) near Glasgow, Montana In-Service Date: July 1941-June 1961
Franklin D. Roosevelt speaks at Fort Peck Dam site
27 Fort Peck Power Plant Development Plan
4.2 HYDROPOWER Fiscal Year 2015 Performance Hydropower production at Fort Peck was approved by the Generation Fort Peck Power Act in 1938. Started in 1941, construction on No. of Unit Starts 91 the first power house was not completed until 1951 due to Net Generation (MWh) 79,547 shortages of supplies and materials during World War II. Peak Availability A second power house was later added to tunnel #2. No. of Outages 3 Construction on it began in 1958 and was completed in 1961. Hours Unavailable 1147 Today the two power houses average 1.1 billion kilowatt hours a year, or enough power to supply a town of 100,000 Factor (%) 94.8% people. Forced Outages Characteristics and Value Total No. 7 Hours Unavailable 125 Generators/Turbines 5 Francis Turbines, 129 rpm Factor (%) .3% Nameplate Capacity 185.3 MW Scheduled Outages units 1 & 3: 43.5 MW each Total No. 13 unit 2: 18.3 MW units 4 & 5: 40 MW each Hours Unavailable 4280 Factor (%) 9.8% Aerial view of Fort Peck power houses Percent of NWO Capacity 7.41% Availability Average Gross Head Available 194 ft Yearly Hours 43,800 Number & Size of Conduits No. 1-24.8 ft dia, No.2-22.4 ft dia Hours Available 39,395 Surge Tanks PH #1: 3-40 ft dia Factor (%) 89.9% PH #2: 2-65 ft dia Plant O&M Costs Discharge Capacity PH #1: units 1 & 3- 170 ft, O&M Costs $9,307,210 unit 2-140 ft at 8,800 cfs O&M Cost ($/MWh) $11.71 PH #2: units 4 & 5 -170 ft at O&M Cost ($/MW) $50,241 7,200 cfs
Average Annual Energy 1,048 M kWh powertrain work has included rewind/restack of unit 1 and Unit 3 in 2006/2004 respectively. Past work: Fort Peck received funding through the congressionally authorized Fort Peck Act that allows Present work: Ongoing work is dominated by the unit 2 rehab maintenance and capital improvements to the Fort Peck to rewind / restack the generator and install a new high Power Plant from the WAPA revolving fund. The oldest of efficiency turbine with characteristics to better match the Fort the Missouri River plants, Fort Peck began construction in Peck plant operations. Other works include replacement of Surge tanks over power house 2 under construction 1932 with the Plant 1 units (1, 2, & 3) going on-line between transformer banks 3 & 4 with a single 3-phase transformer and 1943 and 1950 and plant 2 units (4 & 5) going on-line in 1961. bank 2 with a second 3-phase transformer. Work inside the plant includes new motor control centers and new dry type Fort Peck had the lower end of the power tunnels, five transformers. The Fort Peck plant 1 generator relaying is penstocks and plant 1 trifurcation replaced in 1989. Other currently being designed for replacement.
28 Fort Peck Power Plant Development Plan
Fort Peck Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Out
1 $5,672 $4,820 $1,243 $349 $2,424 $2,651 $5,148 $5,011 $2,452 $1,682 $1,254 $1,056 $2,809 Power House Location 2 $23,459 $18,422 $4,597 $2,378 $8,043 $9,249 $17,027 $15,934 $6,662 $4,807 $5,575 $10,182 $10,513
3 $48,792 $39,219 $12,355 $10,496 $21,555 $26,578 $42,881 $39,027 $15,196 $10,876 $14,890 $26,697 $25,700
4 $79,007 $66,050 $30,623 $26,802 $40,234 $50,521 $76,363 $69,683 $31,104 $23,583 $28,990 $47,223 $47,507
5 $109,505 $93,701 $53,217 $45,330 $59,173 $74,562 $110,445 $100,909 $50,459 $40,910 $46,318 $68,293 $71,068
29 Fort Peck Power Plant Development Plan
4.3 EXISTING CONDITIONS The hydroAMP condition assessment indicates a variety of Power Train Conditions circumstances. It is anticipated that unit 2 condition will be moved to Good on a majority of power train equipment as the Unit Circuit Exciters Generator Generator Governors Turbines Transformer Transformer project completes. Breakers Rotor Stator Equip# Unit 1 10 10 7.7 10 8.7 5.3 AT2 7.8 The Fort Peck unit breakers reside in the original switchgear Unit 2 KV7A room which is problematic given the advanced age of the 10 10 7.7 3.3 8.7 5.3 10.0 equipment and the limited access and egress causing concern Unit 3 10 9.5 7.7 10 8.7 4.8 SS A Transformer 6.9 for electrical safety and arc flash hazards. The original air Unit 4 10 7.7 7.7 2.4 8.7 5.3 SS B Transformer 7.8 blast breakers were replaced in the mid 1980’s and are Unit 5 10 7.7 6.7 2.4 8.7 5.3 T2-895582 7.8 themselves due for replacement. The remaining bus work, T2-895583 7.8 insulators, and controls are original and well past their useful HydroAMP Condition T2-895584 3.6 life. The Fort Peck switchgear room should be replaced in its T2-895585 6.7 entirety with the majority of the complicated breaker scheme Rating Condition moved to a control building in switchyard no. 1. Categories Index T3-4616-1 4.8 Good 8-10 T3-4616-2 7.0 The Fort Peck turbines are all original (Unit 2 currently being T3-4616-3 replaced) and suffer from the design inefficiencies of their Fair 3-8 7.0 time. Units 1 and 3 turbines are sister units designed in the Poor 0-3 T4-894596 6.1 1940’s and installed in 1950. Unit 3 was the victim of an T4-894597 6.1 experiment in the 1970’s to improve the turbine efficiency by T4-894598 5.9 cutting a few inches from the trailing edge of each bucket. The T4-894599 5.1 severe cavitation witnessed after its return required an T5 9.2 immediate reversal of the procedure. Unit 3 turbine has never UT4 7.8 been the same and now requires double the cavitation repair of its inefficient sister unit. The units in power house 2 are UT5 7.8 currently being evaluated by HDC for rehab consideration. At a minimum the generators for units 4 and 5 will be rewound allowing capacity increase by replacing the original soft windings. The following capital improvement plan of the HMP intends to address the marginal conditions shown in hydroAMP: An on-going study of the switchyard and powertrain that supports both power houses is evaluating the actual extent of these requirements.
Finish unit 2 rehab Repair switchyard 1 Rewind units 4 and 5 Repair switchyard 2 Replace turbines 1 and 3 Fort Peck power house 1 30 Fort Peck Power Plant Development Plan
4.4 FIVE-YEAR GANTT CHART Table 4-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 4-1: Fort Peck Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 405213/514 Station service interior transformers $370,000 C C CMP Multiple Rehab unit 2 & install high resistance grounding $7,857,000 C C C C CMP 454556/552 Install generator relays $600,000 C C C C C CMP 449565/556 Replace emergency gate hoist wire rope $1,200,000 C C C C C CMP 405212/517 Rehab emergency gate control system $1,355,000 C C C C C CMP 329337/531 Rehab draft tube bulkheads $730,000 C C C C C C CMP 405211/515, Supply and install transformers, oil filled cable $5,510,000 D A A C C C C CMP 447128/533 system, and exterior oil-filled transformers 461482/591 Replace programmable logic controllers $600,000 D A A D A A CMP 454554/554 Instrument transformer replacement (PT/CT) $300,000 C C C C C C C CMP 447127/532 Replace motor control centers $2,314,025 C C C C C C C CMP 458812/578 Modernize shaft building cranes $1,000,000 D D D A A C C C C C CMP 458814/577 Replace power house fire and security system $250,000 D D D A A C C C CMP 458813/579 Bridge crane design and repair $4,300,000 D D D D A A C C C C C CMP 18-2151 Replace draft tube stop logs $1,000,000 D D A A C C C C C C CMP TBD Install digital governors $4,000,000 D D D D A A C C C C CMP 405220/516 Rehab switchyard 1 $4,700,000 D D D D D D A A C C C C C C C CMP
454557/553 Rewind/rehab units 4 and 5, and switchyard 2 $20,000,000 D D D D D D D A A C C
18-2139 Replace generator cooling water system $200,000 D D D 18-2131 Rehab butterfly valves $200,000 D D D Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 31 Fort Peck Power Plant Development Plan
4.5 CAPITAL IMPROVEMENT PLAN Table 4-2 identifies all capital improvement projects allowing systematic evaluation of all potential projects over a twenty-year period.
Table 4-2: Fort Peck Project CIP Matrix Project PA Project PA Project Title FY Status Project Title FY Number ($K) Number ($K) IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 405213/514 Station service interior transformers 13 $370 Awarded 18-2139 Generator cooling water system replacement 18, 22 $2,500 Multiple Rehab unit 2 and install high resistance grounding 15 $7,857 Construction 18-2086 Seal joint on exterior power plant 1 18, 22 $1,500 454556/552 Install generator relays 15 $600 Awarded 18-2131 Rehab butterfly valves 18, 23 $2,000 449565/556 Replace emergency gate hoist wire rope 15 $1,200 Construction 18-2122 Rehab stop log gantry cranes - $400 405212/517 Rehab emergency gate control system 14 $1,355 Construction 18-2059 Modernize CO2 system in power plants 1 and 2 - $360 Multiple Supply-install transformers and oil filled cable system 13,15 $5,510 Awarded 18-7088 Clean, repair, and repaint corroded beams in power plant 1 - $365 329337/531 Rehab draft tube bulkheads 14 $730 Advertising 18-1026 Replace station service 4160 volt breakers power plant 2 - $500 454554/554 Instrument transformer replacement (PT/CT) 15 $300 Advertising LONG RANGE PROJECTS 2026-2035 447127/532 Replace motor control center 14, 16 $2,314 Awarded 18-2103 Units 1 and 3 turbine replacement 31 $50,000 405220/516 Rehab switchyard 1 16, 18 $4,700 Design 17 454557/553 Rewind/rehab units 4 and 5, and switchyard 2 16, 21 $20,000 Design 18 SHORT RANGE 2017-2018 TBD Replace programmable logic controllers 16 $600 Design 17 458812/578 Modernize shaft building cranes 16 $1,000 Design 17 458814/577 Replace power house fire and security system 16 $250 Design 17 458813/579 Bridge crane design and repair 16 $4,300 Design 17 18-2151 Replace draft tube stop logs 16 $1,000 Design 17 TBD Install digital governors 18, 19 $4,000 Design 18
Fort Peck power houses at sunset 32 Garrison Power Plant Development Plan
5.1 OVERVIEW Garrison Dam is an earth-fill embankment dam on the Missouri River in central North Dakota. Construction of the $294 million dam project began in 1946 and closure of the embankment occurred in April 1953. With over two miles in length and standing 210 feet high, the dam is the fifth largest earthen dam in the world. The reservoir impounded by the dam, Lake Sakakawea is one of the largest man-made lakes in the United States, extending 178 miles from the dam northwest to Williston, North Dakota. Since its opening in 1960, Garrison Dam has provided the hydropower and flood control potential envisioned by Colonel Pick and others who directed its development. USACE has
Postcard produced during worked with the Bureau of Reclamation to use Garrison pool Garrison Dam construction to irrigate 250,000 acres. The Garrison Dam has also provided a steady flow of water for navigation as well as generating Aerial view of Garrison project site hydropower.
Location: Missouri River (Mile 1389.9) near Riverdale, North Dakota In-Service Date: January 1956-October 1960
33 Garrison Power Plant Development Plan
5.2 HYDROPOWER The power plant has five generating units that produce an Fiscal Year 2015 Performance annual average 2.6 million mega-watt hours of electricity, valued in excess of $39 million in revenue. Electricity is Generation transmitted from the power plant through seven transmission No. of Unit Starts 6 lines to various substations and is marketed by Western Area Net Generation (MWh) 2,292,228 Power Administration. Peak Availability No. of Outages 9 Characteristics and Value Hours Unavailable 2031 Generators/Turbines 5 Francis Turbines, 90 rpm Factor (%) 91% Nameplate Capacity 583.3 MW Forced Outages 3 units: 121.6 MW Total No. 9 2 units: 109.3 MW Hours Unavailable 33 Percent of NWO Capacity 23.32% Factor (%) .1% Average Gross Head Available 161 ft Scheduled Outages Number & Size of Conduits 5-29 ft dia.- 25 ft penstocks Total No. 17 Aerial view of Garrison Dam project, 1953 Hours Unavailable Surge Tanks 65 ft dia. - 2 per penstock 4,790 Factor (%) 10.9% Discharge Capacity 150 feet at 41,000 cfs Availability Average Annual Energy 2,259 M kWh Yearly Hours 43,800 Hours Available 38,977 Past work: The Garrison Power Plant received Construction Factor (%) 89% General (CG) funding to address a systemic turbine blade Plant O&M Costs cracking problem and grew to include generator replacements after stator winding failures occurred during the turbine O&M Costs $11,119,427 fabrications phase of the project. Unit alignment issues O&M Cost ($/MWh) $4.85 discovered during the unit unstack forced a complete unit O&M Cost ($/MW) $19,063 rehab into the project. Additionally, exciter, governor, station service, and switchyard replacements were included in the President Eisenhower dedication ceremony, 1953 project. In 2015 customer funding was provided for the Present work: The main work at Garrison is completing the rewind of the Garrison autotransformer. The only other major rehab requirement. Additionally a project to replace Customer work was relatively inexpensive projects to provide the intake structure roof and structural deck is under way. a system-wide transformer assessment, and to provide new PPCS servers to the plant.
34
Garrison Power Plant Development Plan
Garrison Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Out
1 $5,672 $4,820 $1,243 $349 $2,424 $2,651 $5,148 $5,011 $2,452 $1,682 $1,254 $1,056 $2,809
2 $23,459 $18,422 $4,597 $2,378 $8,043 $9,249 $17,027 $15,934 $6,662 $4,807 $5,575 $10,182 $10,513
3 $48,792 $39,219 $12,355 $10,496 $21,555 $26,578 $42,881 $39,027 $15,196 $10,876 $14,890 $26,697 $25,700
4 $79,007 $66,050 $30,623 $26,802 $40,234 $50,521 $76,363 $69,683 $31,104 $23,583 $28,990 $47,223 $47,507
5 $109,505 $93,701 $53,217 $45,330 $59,173 $74,562 $110,445 $100,909 $50,459 $40,910 $46,318 $68,293 $71,068 Power House Location
35 Garrison Power Plant Development Plan
5.3 EXISTING CONDITIONS The relatively recent operational history of Garrison identifies Power Train Conditions a plant in generally good condition as its rehab status would Unit Circuit Exciters Generator Generator Governors Turbines Transformer Transformer suggest. The new turbines require little if any maintenance. Breakers Rotor Stator Equip# Possible future projects include excitation replacements given Unit 1 Ata that equipment’s relatively short design life (~25yrs). 10 10 7.7 10 10 9.5 10 Additionally, minor upgrades to the digital governor may be Unit 2 10 10 7.7 10 10 9.5 ATb 10 considered to bring the Garrison equipment into alignment Unit 3 10 10 7.7 10 10 9.5 ATc 10 with the remaining Missouri River power house. The Unit 4 10 10 5.8 10 10 10 T1 10 Garrison stator windings are being monitored for the corona Unit 5 10 10 7.7 10 10 9.5 T2 10 effects that have been present since the unit rewinds. Coronal T3 10 issues were identified shortly after the first rewind with the T4 10 installer attempting to remedy the issues of future rewinds. HydroAMP Condition T5 10 Corona tends to be a slow degradation of winding life and Rating Condition often doesn’t play into the final end of life issues. Categories Index Assuming Garrison continues to be well maintained and carefully operated, it is expected that the plant will operate Good 8-10 with good reliability throughout its design life until 2045. Fair 3-8 Poor 0-3
Crane in action lifting rotor
Garrison power house with Lake Sakakawea
36 Garrison Power Plant Development Plan
5.4 FIVE-YEAR GANTT CHART Table 5-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 5-1: Garrison Gantt Chart Table 5-1: Garrison Gantt Chart Program PROGRAM ID ID Project Title PROJECT TITLE Q1 Q2 Q3 Q4 Q1Q1 Q2 Q2Q3 Q3Q4 Q1Q4 Q2Q1 Q3Q2Q4 Q3Q1 Q4Q2 Q3Q1 Q4Q2Q1 Q3Q2 Q4Q3 Q4Q1 Q1Q2Q2 Q3Q3 Q4Q4 Amount AMOUNT FY17 FY18 FY19 FY20 FY21 FY17 FY18 FY19 FY20 FY21 18-1160 Repair intake structure roof $4,000,000 CMP 18-1160 Repair intake structure roof $4,000,000 CMP 105566 Major Rehab $95,297,000 C C CMP 105566 Major rehab $95,297,000 C C CMP 456630/567 Replace programmable logic controllers $600,000 A C C CMP 456630/567 Replace programmable logic controllers $600,000 A C C CMP 461090/589 Generator yard civil work $3,000,000 A A C C C C CMP 461090/589 Generator yard civil work $3,000,000 A A C C C C CMP 18-1182 Upgrade intake crane $2,000,000 D A A C C C C CMP 18-1182 Upgrade intake crane $2,000,000 D A A C C C C CMP 18-1159 Replace equalizing valves $450,000 D D A A C C C C CMP
18-115918-1108 ReplaceRepaint/Repair equalizing Penstock valves Gates and Lifting Beams $450,000 $5,300,000D D A D A D CD AC A C C C C CMPC C C C C CMP
18-1108 Repaint/repair penstock gates and lifting beams $5,300,000 D D D A A C C C C C C C CMP
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 37 Garrison Power Plant Development Plan
5.5 CAPITAL IMPROVEMENT PLAN Table 5-2 identifies all capital projects allowing systematic evaluation of all potential projects over a twenty-year period. In the short-term, Garrison plans to conduct civil work on the switchyard and bring the intake bridge crane to current standards.
Table 5-2: Garrison Project Matrix Project PA Project PA Project Title FY Status Project Title FY Number ($K) Number ($K) IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 18-1160 Repair intake structure roof 15 $4,000 Award-O&M 18-1026 Replace power plant oil storage and oil purification CO2 systems - $270 105566 Major rehab $95,297 Construction 18-1036 Paint walls on the generator and turbine floors - $335 456630/567 Replace programmable logic controllers 16 $600 Awarded 18-7083 Paint three draft tube bulkheads - $240 461090/589 Generator yard civil work 16 $3,000 Designing 18-7629 Replace unit 3 penstock packing - $205 18-1182 Upgrade intake crane 16, 17 $2,000 Design-O&M 18-7082 Paint four intake bulkhead sections - $320 SHORT RANGE 2017-2018 18-1039 Intake structure asbestos abatement - $370 18-1159 Replace equalizing valves 17,18 $4,500 Design 17 18-7104 Paint intake structure bridge - $630 18-1108 Repaint/repair penstock gates and lifting beams 17,18 $5,300 Design 17 18-1014 Update generator carbon dioxide fire extinguishing system - $260 18-1038 Power plant asbestos abatement - $1,530 18-7627 Repair power house tailrace deck cracks - $263 18-1103 Repaint/repair the interior of the surge tanks and floors - $1,500 18-1055 Repair power house parking lots and road - $2,400 LONG RANGE PROJECTS 2026-2035 - Exciter replacement 31 $4,500 - Governor replacements 33 $4,000 - Generator rewind 35 TBD
Sunrise view of power house water release
38 Oahe Power Plant Development Plan
6.1 OVERVIEW Missouri River (Mile 1072.3) near Oahe was the third of the Pick-Sloan dams to be built on the Location: Pierre, South Dakota Missouri, constructed six miles north of Pierre, South Dakota. Its 91 million cubic yards of earth made Oahe, upon its In-Service Date: April 1962- June 1963 completion, the largest rolled earthfill dam in the world. Oahe Dam’s layout is unique in that the power house is on the left bank, the outlet works on the right bank, and the spillway is one mile beyond the outlet works. Contractors began earthwork in 1954 and by late 1957, the embankment had narrowed the Missouri’s channel at Oahe enough to begin planning closure. By 1961, contractors were wrapping up work on the six flood-control tunnels. Construction then moved forward on the intake control structures above the power tunnels and the power house substructure. Work on the power house superstructure and Program from Oahe power house surge tank bases required 800 men who worked in the three dedication ceremony, 1962 shifts around the clock. One of the main authorized purposes of Oahe Dam and Lake is to provide flood control to those living downstream. It can store up to 23.5 million acre-feet of water, making it the 4th- Aerial view of Oahe project site largest reservoir in the nation. Lake Oahe is one of the largest manmade lakes in the United States. With 2,250 miles of shoreline, it boasts more shoreline than the state of California.
39 Oahe Power Plant Development Plan
6.2 HYDROPOWER The first of the power house’s seven 89,500-kilovolt generators Fiscal Year 2015 Performance was put into operation in March 1962. On August 17, 1962, Generation President John F. Kennedy came to the dam and officially No. of Unit Starts 30 dedicated the two generators. The final generator went into operation in June 1963, completing the $340-million Oahe Net Generation 2,677,495 project. By 1966, Oahe Dam was generating over 2 billion (MWh) kilowatt-hours of electricity annually. Peak Availability No. of Outages 9 Oahe generators provide enough electricity to meet the annual Hours Unavailable 4510 needs of 259,000 homes. Factor (%) 85.3% Characteristics and Value Forced Outages Generators/Turbines 7 Francis Turbines, 100 rpm Total No. 12 Nameplate Capacity 786 MW/112.3 MW each Hours Unavailable 2384 Percent of NWO Capacity 31.43% Factor (%) 3.9% Average Gross Head Availa- 174 ft Scheduled Outages Total No. 22 ble View of Oahe generators Number & size of conduits 7-24 ft dia, imbedded Hours Unavailable 8,623 penstocks Factor (%) 14.1% Availability Surge Tanks 70 ft dia, 2 per penstock Yearly Hours 61,320 Discharge Capacity 185 ft at 54,000 cfs Hours Available 50,313 Average Annual Energy 2,641 M kWh Factor (%) 82.1% Past Work: The Oahe Customer funding began with the Plant O&M Costs switchyard breaker replacement project in 2007. Since that O&M Costs $9,123,413 project, Customer funding has addressed a number of O&M Cost ($/MWh) $3.41 maintenance, operational and reliability issues including new O&M Cost ($/MW) $11,607 turbine oil, generator air coolers, SCADA servers, and thrust bearing repairs. Equipment replacements have included the oil circuit breakers replaced with SF6 breakers, 1970’s electromechanical relays replaced with modern microprocessor relays, generator air blast unit breakers replaced with modern SF6 breakers, new PPCS SCADA servers, station service tap changer repairs, and generator step up (GSU) transformer repairs. President John F. Kennedy at Oahe dedication ceremony Present Work: Current Customer funded work includes the GSU oil containment, an additional auto transformer, switchyard configuration upgrade, excitation system replacement, governor system upgrade, and bridge crane rehab.
40 Oahe Power Plant Development Plan
Oahe Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Out
1 $2,263 $1,265 $1,697 $3,542 $4,689 $5,930 $14,415 $16,066 $7,954 $4,109 $5,780 $2,327 $5,874
2 $8,732 $5,534 $5,867 $10,424 $12,846 $19,424 $41,345 $46,050 $23,116 $11,888 $15,143 $8,249 $17,486
3 $22,843 $15,296 $15,192 $22,262 $27,201 $42,610 $82,720 $88,656 $45,324 $24,158 $28,899 $20,467 $36,492
4 $50,979 $36,715 $34,601 $41,407 $49,672 $75,983 $139,405 $143,571 $74,075 $42,707 $48,284 $42,012 $65,238
5 $97,691 $76,191 $66,065 $68,150 $78,543 $116,867 $205,757 $205,121 $108,045 $69,063 $73,259 $75,603 $103,715
6 $159,140 $131,220 $107,863 $101,333 $113,511 $163,380 $276,107 $269,871 $146,465 $101,233 $103,901 $117,979 $149,708 Power House Location 7 $224,702 $191,136 $155,890 $139,635 $152,809 $214,043 $348,768 $336,331 $187,643 $137,623 $139,635 $162,970 $199,650
41 Oahe Power Plant Development Plan
6.3 EXISTING CONDITIONS Power Train Conditions The hydroAMP condition of Oahe power train indicates the bulk of the equipment is generally in fair condition. The Circuit Exciters Generator Generator Governors Turbines Transformer Transformer present work to upgrade governors and replace exciters will Breakers Rotor Stator Equip# raise the power train condition for those components. Unit 1 6 7.4 6.1 4.0 6.3 Atb 5.5 The excitation systems at Oahe have experienced control Unit 2 10 7.0 6.1 4.0 6.3 Atc 4.4 section failures with increasing frequency. The Siemens line of Unit 3 9 7.4 6.7 4.0 6.3 T1 6.7 exciters has been discontinued for the last 11 years and is only Unit 4 10 7.4 6.1 4.0 6.3 T2a 6.7 supported by two independent installers. These are one-man Unit 5 10 7.4 6.1 3.3 6.9 T2b 4.8 shops that could retire at any time. Likewise, Siemens no Unit 6 10 7.4 6.1 4.0 6.9 T2c 6.7 longer supports their circuit boards which include a large Unit 7 10 7.4 6.1 4.0 6.9 T3a 4.4 number of analog and power electronics. While there are currently adequate spare parts available at the power houses, T3b 7.8 the frequent card repairs are only available from two known T3c 7.8 independent electronics shops doing reverse engineering and T4a 7.8 T4b 7.8 replacing components with aftermarket parts. Since FY2010, HydroAMP Condition Oahe has experienced 15 forced outages with 160 hours of Beyond the powertrain equipment, Oahe’s bridge crane T4c 4.4 downtime. The concern is that the frequency of exciter failures system is rated for 500 tons. The cranes have not picked a Rating Condition is increasing and the repairs are becoming more difficult. The rotor since the generators were rewound in the late 80’s. Each Categories Index district is currently executing designs to award a project that bridge crane is rated for 250 tons and they work in tandem will replace the static excitation at Oahe. when connected to a 450-ton lifting beam to lift the 420-ton Good 8-10 generator rotor. The controls are no longer in compliance with The existing governors are antiquated, difficult to maintain Fair 3-8 crane safety guidelines. The controls do not return to a neutral calibration, require relatively high levels of maintenance and position when released. Also, the latency period from the time Poor 0-3 are experiencing control issues with increasing frequency. the lever is returned to neutral and the relays all open allows Support for the governors is provided by one company that the movement of the bridge when it should be stopped. This reconditions used parts. A contract to install digital governor does not meet current crane safety guidelines. The different retrofits has been funded to purchase and configure the control stopping times between the two cranes causes control generator start/stop auxiliary controls. issues when operating them in tandem and is a safety hazard. Oahe stators were last rewound by a quality contractor with The bridge cranes have been funded for rehabilitation to hard windings in 1981 and have their original stator cores. To include replacing the existing control system with AC Variable date, the windings have not shown signs of impending failure; Frequency Drive (VFD) controllers, new VFD compatible hoist however, at 35 years old, they are approaching the end of their motors, a rehab of the main and auxiliary hoists including design life. Given the age, the strategy will be to conduct a drums, gear boxes, brakes, sheaves and hooks. The work will full evaluation in the mid-term to determine the appropriate also include new cab control station, upgraded trolley system, rehab strategy. and alignment of the crane rails if required.
42 Oahe Power Plant Development Plan
6.4 FIVE-YEAR GANTT CHART Table 6-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 6-1: Oahe Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 449302/526 Generator rewind design $83,334 CMP
399795/510 Tailrace deck transformer oil containment $1,125,000 C CMP
456033/573 Repair thrust bearing cooler $300,000 C C C CMP
18-1178 Penstock dewatering piping in shale drain tunnel $170,000 C C C C CMP
144043/ Upgrade 115 and 230 kV switchyard and $10,800,000 C C C C C C CMP 478 & 382 autotransformer replacement
TBD Replace programmable logic controllers TBD D A A D A A CMP
18-1177 Replace intake motor controls $650,000 D D D A A C C C CMP
399796/509 Replace generator exciters $5,566,667 A C C C C CMP
18-1195 Replace monorail bridge crane $1,000,000 D D A A C C C CMP
456034/570 Generator step-up transformer bushing $1,200,000 A C C C C CMP
456480/571 Bridge crane rehab $5,500,000 D A A C C C C C C C C CMP
406268/518 Install digital governor retrofits $3,933,334 D D A A C C C C C C CMP
18-1091 Replace outdoor station service switchgear $1,200,000 D D D A A A C C C C C C CMP
18-1197 Rehab tailrace bulkhead $1,800,000 D D D D A A C C C C
TBD Upgrade CO2 fire suppression $360,000 D D D D A A C C C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 43 Oahe Power Plant Development Plan
6.5 CAPITAL IMPROVEMENT PLAN Table 6-2 identifies capital improvement projects allowing systematic evaluation of all potential projects over a twenty-year period. The CIP has marked a future award of rehab in the long-term; however, the magnitude will be based on an evaluation of the fatigue, age, and efficiency.
Table 6-2: Oahe Project Matrix Project Project Project Title FY PA ($K) Status Project Title FY PA ($K) Number Number IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 449302/526 Generator rewind design 15 $83 Designing 18-1197 Tailrace bulkhead rehabilitation 19, 20 $1,800 399795/510 Tailrace deck transformer oil containment 13 $1,125 Construction TBD CO2 fire suppression upgrade 19, 20 $360 456033/573 Repair thrust bearing cooler 16 $300 Designing 18-1110 Baseline security posture upgrade - $975 18-1178 Penstock dewatering piping in shale drain tunnel 16 $170 Awarded 18-1147 Switchyard phase II, switchyard disconnect - $10,000 Upgrade 115 and 230 kV switchyard and TBD Turbine and discharge ring cavitation repair - $4,500 Multiple 11 $10,800 Construction autotransformer replacement 18-1188 Remove asbestos containing material from structures - $200 399796/509 Replace generator exciters 13, 15 $5,567 Designing 18-1059 B-FLOOR, surface rehab and wall painting - $200 456034/570 Generator step-up transformer bushing 16 $1,200 Designing 18-1168 Expand 480 station service board - $500 456480/571 Bridge crane rehab 16 $5,500 Designing TBD Replace station service battery - TBD 406268/518 Install digital governor retrofits 15,16 $3,933 Designing TBD Replace plant unwatering pumps - TBD SHORT RANGE 2017-2018 18-1168 480 station service, voltage regulator, and grounding - $1,300 TBD Replace programmable logic controllers 17 $633 Design 17 LONG RANGE PROJECTS 2026-2035 18-1177 Replace intake motor controls 17 $650 Design 17 18-1119 Turbine, generator, transformers replacement 35 $300,000 Replace monorail bridge crane at the emergency 18-1195 17, 18 $1,000 Design 17 spillway Replace outdoor station service switchgear and air 18-1091 17, 18 $1,200 Design 17 circuit breakers
View of Oahe power house and surge tanks 44 Big Bend Power Plant Development Plan
7.1 OVERVIEW Big Bend Dam is a major rolled earth dam, 95 feet high and 10,570 feet in length. The dam was constructed under the Pick -Sloan Plan for development of the Missouri River Basin authorized by the Flood Control Act of 1944. Construction on the project began in 1959 and closure of the embankment occurred in 1963. Power generation began at the facility in 1964 and the entire complex was completed in 1966 at a total cost of $107 million. Located near Fort Thompson, South Dakota, just south of a major bend in the Missouri River (from which the dam takes
The Big Bend project is known as its name), Big Bend Dam creates Lake Sharpe, named after the jewel on the Missouri River. South Dakota Governor Merril Q Sharpe. The lake extends for 80 miles (130 km) up the course of the Missouri River past Pierre to Oahe Dam. During the peak construction period, 1,300 people were involved in the construction of the dam. Today, approximately 80,000 acres of public lands and water provide a variety of benefits to the public including flood control, recreation, conservation of our natural resources, fish and Aerial of Big Bend project site wildlife habitat, irrigation, and hydropower production.
Missouri River (Mile 987.4) near Fort Location: Thompson, South Dakota
In-Service Date: October 1964-July 1966
45 Big Bend Power Plant Development Plan
7.2 HYDROPOWER Big Bend hydroelectric power plant is operated to meet peak Fiscal Year 2015 Performance demands for electricity in the Missouri River Basin. The Generation power plant houses eight units with combined maximum No. of Unit Starts 1,541 generation capacity of 494,320 kilowatts. This is enough power Net Generation (MWh) 980,657 for about 95,000 homes. The first unit went into operation in Peak Availability 1964 and by 1966 all eight generators were producing No. of Outages 22 commercial electricity. Hours Unavailable 6,679 The power plant itself is 757 feet long, 200 feet wide, and has a Factor (%) 80.9% height of 205 feet (Elevation 1,447 to 1,242 msl). Electrical Forced Outages power is transmitted through transmission lines and is Total No. 6 marketed by Western Area Power Administration. Hours Unavailable 148 A unique characteristic of Big Bend is that it is the only plant Factor (%) 0.21% where power pays 100% of the joint costs. Additionally, three Scheduled Outages of eight units are connected to the electric grid as synchronous Total No. 45 condensers for voltage and reactive power (VAR) support. Hours Unavailable 12,130 Factor (%) 17% With approximately 20% of the NWO generation capacity, Big Big Bend generators Availability Bend operates its large low head turbines in a peaking manner Yearly Hours 70,080 generating approximately 10% of the total Missouri River Present Work: Ongoing Customer funded work includes GSU Hours Available 57,802 production. transformer oil containment, new excitation systems, governor Factor (%) 82.5% upgrades, raw water headers and unit cooling repairs, intake Plant O&M Costs gate refurbishment, Programmable Logic Controller’s, and Characteristics and Value O&M Costs $13,566,643 investigating turbine cavitation issues. Generators/Turbines 8 -Fixed Blade Kaplan O&M Cost ($/MWh) $13.83 Turbines, 82 rpm O&M Cost ($/MW) $27,445 Operating Hours 2010 2011 2012 2013 2014 494 MW Past Work: Customer funding started with the Big Bend Generating Power 42% 66% 45% 34% 39% Nameplate Capacity 3 units: 67.3MW generator rewinds in 2003. Five of the eight generators have received new stator cores and windings correcting a rash of Synchronous 58% 34% 55% 66% 61% 5 units: 58.5 MW generator failures and long standing issues with stator out-of- Condensing Support Percent of NWO Capacity 19.8% round conditions. Other Customer funded work has included Average Gross Head 70 ft transmission line and generator relay replacements, generator Number & Size of Conduits None: Direct Intake mechanical repairs correcting worn shaft sleeves and packing boxes on two units, high pressure uplift systems, and bearing Surge Tanks None coolers on specific units exhibiting problems. Discharge Capacity 67 ft at 103,000 cfs Average Annual Energy 986 M kWh
46 Big Bend Power Plant Development Plan
Big Bend Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Out
1 $535 $42 $75 $110 $40 $109 $973 $215 $223 $190 $248 $146 $245
2 $1,409 $187 $274 $438 $271 $653 $2,877 $1,146 $999 $650 $814 $507 $859
3 $3,012 $713 $924 $1,179 $1,148 $2,246 $6,839 $4,576 $2,943 $1,735 $2,187 $1,438 $2,429 Power House 4 $6,059 $2,283 $2,462 $2,819 $3,326 $5,880 $14,797 $12,588 $7,176 $4,161 $5,361 $3,520 $5,905 Location 5 $12,319 $6,497 $6,123 $6,838 $8,193 $13,594 $29,192 $28,032 $16,019 $9,232 $11,428 $8,148 $13,032 6 $27,435 $18,209 $15,983 $16,331 $18,873 $29,095 $54,711 $54,366 $31,135 $19,307 $22,323 $19,525 $27,377 7 $59,604 $45,805 $36,245 $33,824 $36,933 $53,675 $92,738 $90,901 $52,536 $37,119 $39,970 $42,667 $51,959 8 $105,493 $85,955 $66,793 $58,067 $61,820 $85,537 $139,212 $134,791 $80,205 $62,292 $65,901 $74,739 $85,198
47 Big Bend Power Plant Development Plan
7.3 EXISTING CONDITIONS The hydroAMP condition assessment indicates the bulk of the Power Train Conditions equipment is generally in fair condition and capable of Unit Circuit Exciters Generator Generator Governors Turbines Transformer Transformer sustainable reliability into the future. Breakers Rotor Stator Equip# (unit #) The excitation systems at Big Bend are experiencing control Unit 1 6.7 6.5 7.7 6.1 6.1 4 T1 (1 & 2) 8.6 section failures with increasing frequency. Since October Unit 2 6.7 6.5 7.7 6.1 6.1 5.8 T2 (3 & 4) 8.6 2010, Big Bend has had 10 unscheduled exciter outages totaling 79.23 hours including 7 forced outages. The concern Unit 3 6.7 6.5 7.7 6.1 6.1 5.8 T3 (5 & 6) 8.6 is that the frequency of exciter failures is increasing and the Unit 4 6.7 6.5 7.7 10 6.1 5.8 T4 (7 &8) 8.6 repairs are becoming more difficult. Due to this, a project is being executed that will install a new static digital excitation Unit 5 6.7 6.5 7.7 10 6.1 5.8 system that will be able to meet the present day generator Unit 6 6.7 6.5 7.7 10 6.1 5.8 response requirements. Unit 7 6.7 5.6 7.7 10 6.1 2.8 The existing governors are original Pelton type mechanical- hydraulic cabinet actuator governors and are funded to be Unit 8 6.7 6.5 7.7 10 6.1 5.8 replaced with digital governor retrofits that will configure the HydroAMP Condition generator start/stop and auxiliary controls. The level of effort required for cavitation repair after the installation of the stainless overlay is The one problem area in the power train has been cavitation reduced to spot repairs on new regions of the blades. Replacing the wicket gate horizontal Rating Condition maintenance on the turbines. Welding required to complete seals, cleaning the vertical surfaces, replacing the shaft sleeves, and refurbishing the packing Categories Index repairs has increased substantially and issues with wicket boxes will help reduce the number of air receiver cycles during condensing. The waterway gates impact operations. This year HDC investigated the painting will halt corrosion of the watered turbine components. The wedge and bolt inspection Good 8-10 turbine condition and made recommendations for repair. In are needed for the safe future operation of the runners. Fair 3-8 this investigation HDC found the necessary work includes: The district plans to address the cavitation issue using HDC’s recommendation. The HMP Poor 0-3 Cavitation repair (by way of stainless steel ring overlay) captures this repair in the following capital improvement plan. Painting of welded components Blade wedge and bolt inspection New shaft sleeves and refurbish packing boxes (six units) Wicket gate upper and lower seal replacement HDC recommends installation of a stainless steel overlay on all eight units covering the discharge ring where the most severe cavitation is located. This method has been successfully implemented at other projects.
Typical runner cavitation on unit 7 Lower wicket gate seal
48 Big Bend Power Plant Development Plan
7.4 FIVE-YEAR GANTT CHART Table 7-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 7-1: Big Bend Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 122957/355 Generator rewinds $15,391,953 CMP
399793/510 Transformer oil containment $1,125,000 C CMP
399792/501 Rehab generator step up transformers $1,400,000 C C CMP
456669/503 Replace programmable logic controllers $600,000 A C CMP
399794/500 Replace generator excitation system $6,566,667 C C C C C C C CMP
456035/561 Repair/replace intake gate hoist gear box $1,800,000 A C C C C C C C C CMP
18-1221/22 Rehab intake crane $2,400,000 D D D D A A C C C CMP
406304/520 Design/install digital governor upgrades $4,250,000 A C C C C C C C C C C C CMP
18-1168 Power plant HVAC upgrade $1,200,000 D D D A C C CMP
Replace raw water header, unwatering valves, 499301/543 $2,350,000 D D D A A C C C C C C C CMP station drainage piping
TBD Rehab depressing air/station service air systems $1,275,000 D D D A A C C C C C C C C
TBD Replace MCCs/unit auxiliary panels $2,600,000 D D D A A C C C C C
TBD Replace generator breakers $5,000,000 D D D A A C C C C C
Recondition draft-tube liner, cavitation repair, 18-1073 $23,000,000 D D A A C C paint turbines
18-1219/21 Rehab draft tube crane $850,000 D D D A A C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 49 Big Bend Power Plant Development Plan
7.5 CAPITAL IMPROVEMENT PLAN Table 7-2 identifies capital projects allowing systematic evaluation of all potential projects over a twenty-year period. Due to the cavitation issues, a project is planned to recondition draft-tube liner and make repairs into the medium range. Auxiliary equipment such as motor control centers, cranes, and generator breakers are planned to be replaced in the next five years.
Table 7-2: Big Bend Project Matrix Project Project Project Title FY PA ($K) Status Project Title FY PA ($K) Number Number IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 122957/355 Generator rewinds 09 $15,391 Closeout TBD Replace MCCs/unit auxiliary panels 19, 20 $2,600 399793/510 Transformer oil containment 13 $1,125 Award TBD Replace generator breakers 19, 20 $4,000 399792/501 Rehab generator step up transformers 13 $1,400 Award 18-1073 Recondition draft-tube liner, cavitation repair, paint turbines 20, 21 $20,700 456669/503 Replace programmable logic controllers 16 $600 Award 18-1219/21 Rehab draft tube crane 20 $680 399794/500 Replace generator excitation system 14 $6,567 Award TBD Replace unit vibration monitors - $400 456035/561 Repair/replace intake gate hoist gear box assemblies 16 $1,800 Advertise 18-1195 Replace upstream monolith joint remedial water stops - $1,500 406304/520 Design/install digital governor upgrades 15, 16 $4,250 Advertise TBD Recondition intake gates - $2,300 Replace raw water header, unwatering valves, station TBD Trash rack rehab - $1,500 499301/543 15 $2,350 Design drainage piping TBD Handicapped access power house lobby and update displays - $300 SHORT RANGE 2017-2018 TBD Power house roof replacement - TBD 18-1221/22 Rehab intake crane 17, 18 $2,400 Design 17 TBD Replace station and PPCS battery - TBD 18-1168 Power plant HVAC upgrade 18,19 $1,200 Design 18 LONG RANGE PROJECTS 2026-2035 TBD Rehab depressing air/station service air systems 18,19 $1,275 Design 18 - Repair welds and repaint draft tube bulkheads - TBD - Station drainage system - TBD
Big Bend major spill 2011
50 Fort Randall Power Plant Development Plan
8.1 OVERVIEW Fort Randall was the first dam completed under the Pick- Sloan Plan by the Omaha District. In order to build the dam and the 150-mile long reservoir it would impound, USACE first had to provide access to the site for men, machines and materials. Lake Andes, South Dakota, located about eight miles from the damsite was the nearest town with rail and highway connections. Workers from USACE built a railroad to the damsite from the Chicago, Milwaukee, St. Paul and Pacific tracks at Lake Andes. Like Fort Peck and Garrison dams, Fort Randall Dam required a new town to house the people who would build and maintain it. From 1946 to 1950, the Omaha District built Pickstown, South Dakota, on a bluff east of the river at a cost Aerial view of Fort Randall project site of $9.5 million.
Missouri River (Mile 880) near Lake Location: Andes, South Dakota
Cross section of Fort Randall’s In-Service Date: March 1954-January 1956 waterwheel generator
Fort Randall power house entrance
51 Fort Randall Power Plant Development Plan
8.2 HYDROPOWER On March 15, 1954 President Dwight D. Eisenhower spoke Fiscal Year 2015 Performance over the radio from the White House to 600 people gathered in Generation the Fort Randall power house and then tapped a Western No. of Unit Starts 59 Union key to signal Governor Sigurd Anderson to start the Net Generation (MWh) 1,780,722 generators. Anderson spun the giant turbine, and the dam’s Peak Availability first generator began producing electricity. No. of Outages 26 By June 30, 1956, the Omaha District Engineer reported that Hours Unavailable 1,668 the Fort Randall project was 99 percent complete at a cost of Factor (%) 95% $183 million, almost 2.5 times as much as the original cost Forced Outages estimate. Within the preceding 12 months, the dam’s Total No. 26 generators had produced more than 1 billion kilowatt-hours of Hours Unavailable 106 electricity. By the early 1970’s, the dam was producing over 2 Factor (%) .15% billion kilowatt-hours of electric power annually. Scheduled Outages
Characteristics and Value Total No. 36 Generators/Turbines 8 Francis Turbines, 85.7 rpm Hours Unavailable 6,778 Factor (%) 9.7% Nameplate Capacity 320 MW/40 MW each Availability Percent of NWO Capacity 12.79% Yearly Hours 70,080 Fort Randall generators Average Gross Head 117 ft Hours Available 63,196 Available Factor (%) 90.2% Number & size of conduits 8-28 ft dia, 22 ft penstocks Plant O&M Costs Surge Tanks 59 ft dia, 2 per alternate O&M Costs $9,748,519 penstock O&M Cost ($/MWh) $5.47 Discharge Capacity 112 ft at 44,500 cfs O&M Cost ($/MW) $30,464 Average annual energy 1,733 M kWh replace and upgrade a substantial amount of antiquated, unreliable, and high maintenance equipment while allowing Past work: The Fort Randall unit breakers were replaced in an increase in power grid throughput capacity. 2001 using appropriations to replace the obsolete, failure Replacement of the original oil filled pipe type cables will prone, and maintenance intensive air blast breakers. create capacity increases to the circuits exiting the power Customer funding for the Fort Randall Power Plant began in house thus allowing for future unit uprates. Other on-going 2005 with the funding of replacement packing for two of the work includes generator relay replacements and replacement Fort Randall penstocks. It has since included the replacement of the original station’s service switchgear and transformers. of the generator excitation system and upgrades to modern Additionally the upgrade of the power house bridge cranes transmission line relays. will provide for reliable operation anticipating future major
Present work: The on-going Customer funded work includes maintenance activities. some large projects that will improve a significant portion of the Fort Randall power train. The switchyard work will
Fort Randall site post construction 52 Fort Randall Power Plant Development Plan
Fort Randall Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual Out 1 $15 $34 $438 $1,373 $1,463 $2,993 $4,744 $7,076 $4,809 $3,480 $2,997 $137 $2,477
2 $227 $444 $1,720 $3,632 $5,228 $10,068 $16,920 $20,470 $14,014 $9,978 $8,422 $1,304 $7,747
3 $2,348 $2,246 $5,509 $9,447 $15,154 $25,313 $40,190 $44,716 $29,385 $20,718 $15,734 $4,321 $18,030
4 $8,141 $6,690 $13,878 $20,296 $30,212 $46,453 $72,220 $75,540 $48,506 $34,321 $24,541 $9,951 $32,749
5 $21,757 $16,850 $27,218 $34,723 $48,193 $70,076 $107,376 $108,178 $68,672 $48,578 $34,800 $20,674 $50,853
6 $45,315 $35,349 $45,012 $51,651 $67,863 $95,090 $143,091 $141,368 $89,173 $63,762 $47,684 $37,724 $72,235 Power House 7 $76,182 $61,051 $66,905 $70,539 $88,490 $120,877 $178,942 $174,969 $109,706 $80,734 $63,647 $58,494 $96,216 Location
8 $108,217 $90,945 $91,864 $90,969 $109,578 $147,304 $215,495 $208,744 $130,241 $98,233 $80,446 $79,595 $121,312
53 Fort Randall Power Plant Development Plan
8.3 EXISTING CONDITIONS Power Train Conditions Fort Randall has 8 hydroelectric generators with a plant Circuit Generator Generator Transformer nameplate capacity of 320MW. Each unit has a 115% Unit Exciters Governors Turbines Transformer Breakers Rotor Stator Equip# continuous overload rating bringing the plant capacity to Unit 1 Aa 368MW. The units are sized identically although there are 6.7 10 6.1 2.8 4.9 3.3 6.9 shaft size differences between units 1-4 (33 inch shaft Unit 2 6.7 10 6.1 2.8 4.9 3.3 Ab 6.9 diameter) and Units 5-8 (34 inch shaft diameter). The units Unit 3 6.7 9.5 6.1 2.8 4.9 4.5 Ac 6.9 were placed in service between March 1954 and January 1956. Unit 4 6.7 10 6.1 2.8 4.9 4.5 AT Ea 6.9 The majority of the equipment is original and well past its Unit 5 6.7 10 5.1 2.8 4.9 3.3 At Eb 6.9 design life. Several powertrain components show excessive Unit 6 6.7 10 6.1 2.8 4.9 3.8 At Ec 6.9 wear as a result of continuously being in service. Given the Unit 7 6.7 10 6.1 2.8 4.9 4.5 At F 8.1 current condition of the original power train equipment, Unit 8 6.7 10 6.1 2.8 4.9 5.8 Ba 6.1 sustainable reliability twenty years into the future is doubtful. occasions where rotor pole failures have caused outages of Bb 6.9 The hydroAMP table shows the current degraded condition of significant duration (three occurrences at Oahe and two at HydroAMP Condition Bc 6.9 Fort Randall’s power train equipment. Garrison). The overall experience is that rotor windings are Rating Condition Ca 6.9 Fort Randall has the oldest stator windings of the 36 Missouri trending toward failure and should be strongly considered for Categories Index Cb 6.9 River generating units. Their units have been in service refurbishment / rewind during unit rehab activities. Good 8-10 Cc 6.9 without rewind or turbine modernization since the units went Da 6.9 There are a number of other plant and unit reliability issues. Fair 3-8 on-line. Over the years, the plant personnel have done an The units exhibit an alarming number of wicket gate shear pin Db 6.9 excellent job of operating and maintaining the units for Poor 0-3 failures. The original Fort Randall governors had a design Dc 6.9 longevity but the units are showing the expected signs of pressure that had to later be increased to provide satisfactory The poor design is obvious when noting that the unit deterioration for windings of this age and usage. Items such as operation. It has long been suspected that this pressure nameplate capacity (and typical operation) occurs well past asphalt drippings, wedge migration, insulation flaking, and increase has left the wicket gate operating system the peak efficiency. The Fort Randall units are most frequently high current absorption during DC ramps testing are all overpowered with respect to the wicket gate arms. Therefore operated at 40MW and 119 feet of head while the peak indications of the accumulated wear and tear seen by these shear pins, intended to save the gate arms, often fail. Wicket efficiency occurs at 103 feet of head and 31.5 MW (very close Units. These signs of damaged insulation along with the hours gate shear pin failures are rare at the other five power plants, to the upper cavitation limits). This results in operation at 4% of operation are what led to a stator condition rating of poor. but it is not unusual that dozens occur annually at Fort below the peak efficiency of the original turbines. This is Analysis of Fort Randall’s original Westinghouse stator cores Randall. Since January 2010, Fort Randall has experienced 147 compounded by the fact that the original turbines have lost identified a low radial rigidity contributing to the wear and shear pin failures requiring a delayed forced outage. efficiency over time due to weld repairs and, at their best, the material fatigue in the stator winding. Currently, the Additionally there have been 19 outages caused by thrust original turbines have poor efficiency when compared to a windings have limited remaining life and pose an increasing bearing issues or cooling water leaks resulting in 5621.5 hours modern turbine. There are design improvements with operational risk. valued at $580,000. modern turbines that will increase the efficiency another 4% The generator rotor poles are being identified for a rewind. over the existing. The poor turbine efficiency is made worse Fort Randall’s turbine condition rated fair indicates that major While hydroAMP scores reflect that all of the Fort Randall by designs that didn’t account for reservoir operations that upgrades or other repairs may be required within 10 years; rotors are in a marginal condition, Unit 5 has experienced lower the headwater (Lake Francis Case) by 30 feet in the therefore USACE’s Hydropower Design Center produced an intermittent shorted turns in the rotor pole windings. The only winter to allow peak operation of Oahe and Big Bend. The Economic Benefits Analysis for Turbine Runner Rehabilitation permanent repair for this situation is to rewind the rotor pole. combined effect is that efficiency improvements of nearly 10% to evaluate the benefit of component replacement. The These rotor pole windings use an archaic asbestos paper / are achievable with modern turbines. Put another way, the analysis found that the Fort Randall units have Omaha shellac insulation system which is in a generally degraded increase in turbine efficiency would allow an additional 10% District’s lowest efficiency as a result of a poor original turbine condition. Within Omaha District, there have been five energy output for the same water usage. design.
54 Fort Randall Power Plant Development Plan
8.4 FIVE YEAR GANTT CHART Table 8-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 8-1: Fort Randall Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 449299/541 Design generator step up transformers $200,000 CMP
125884/476 MRER validation study $200,000 CMP
399807/505 Rehab bridge cranes $3,800,000 C CMP
18-7609 Repair intake structure curtain walls and drains $935,000 C C CMP
455996/564 Rehab 13.8kV outdoor station service equipment $810,000 C C C C C CMP
399806/504 Replace oil-filled cable $11,700,000 C C C C C CMP
449297/547 Purchase and install unwatering valves $1,100,000 C C C C C C CMP 406730/523 125884/465 Upgrade switchyard $15,950,000 C C C C C C CMP 125884/475
406244/521 Replace generator relays $500,000 C C C C C C CMP
TBD Replace programmable logic controllers $633,333 D A A D A A CMP
449300/542 Upgrade station service switchgear $2,300,000 D A A C C C C C CMP
456029/566 Replace station service transformers $920,000 D A A C C C C C CMP
18-1160 Rehab intake crane $811,000 D D D A A C C C C CMP
Multiple Major rehab $220,000,000 D D D D D D D D A A A A A C C C
18-1169 Intake gate rehab $4,170,000 D D D A A C C C C C C C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 55 Fort Randall Power Plant Development Plan
8.5 CAPITAL IMPROVEMENT PLAN Table 8-2 allows systematic evaluation of all potential projects over a twenty-year period. To resolve the existing conditions identified in Section 8.3, the district intends to award in the medium term the rehabilitation of the eight turbine generator units at Fort Randall. The rehab will include the replacement of the existing turbine runners, new wicket gates, head cover and stay ring refurbishment, governor upgrades, new generator stator windings and stator cores, rotor refurbishment, and new generator step up transformers.
Table 8-2: Fort Randall Project Matrix Project Project Project Title FY PA ($K) Status Project Title FY PA ($K) Number Number IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 449299/541 Design generator step up transformers 15 $200 Design 18-1169 Intake gate rehab 18, 19 $4,170 125884/476 MRER validation study 12 $200 Design 18-1125 Replace power plant lobby displays - $350 399807/505 Rehab bridge cranes 13 $3,800 Award 18-1159 Rehab power house restrooms - $225 18-7609 Repair intake structure curtain walls and drains 16 $935 Award 18-1081 Rehab power plant entrance - $235 455996/564 Rehab 13.8kV outdoor station service equipment 15 $810 Advertise Multiple Major rehab-award and construct 21 TBD 399806/504 Replace oil-filled cable 13 $11,700 Award LONG RANGE PROJECTS 2026-2035 449297/547 Purchase and install unwatering valves 15 $1,100 Award Multiple Major rehab construction 26 TBD Multiple Upgrade Switchyard 14 $15,950 Award 406244/521 Replace generator relays 14 $500 Award 449300/542 Upgrade station service switchgear 15 $1,840 Design 456029/566 Replace station service transformers 15 $920 Design SHORT RANGE 2017-2018 TBD Replace programmable logic controllers 17 $633 Design 17 18-1160 Rehab intake crane 17 $811 Design 17-O&M Multiple Major rehab-study and design 17-21 $220,000 Study 17 18-1169 Intake gate rehab 18, 19 $4,170 Design 18
Fort Randall major spill 2011 56 Gavins Point Power Plant Development Plan
9.1 OVERVIEW Gavins Point Dam, authorized by Congress as part of the 1944 Pick-Sloan Plan, plays an important role in the successful operation of the six main stem dams and reservoirs on the Upper Missouri River Basin. The dam and power plant along with their associated facilities were completed in 1957 at a cost of $51 million. Water released from the five upstream dams is used at Gavins Point for production of hydroelectric power. Gavins Point generators provide enough electricity to meet the annual needs of 68,000 homes. Controlled releases from the dam enhance navigation and minimize erosion on the Missouri River to St. Louis, Missouri. Gavins Point Dam, along with Lewis and Clarke Lake, provide $61 million in benefits to the public annually. The stretch of Missouri River immediately downstream of the dam is the only significant section of non-channelized meandering Aerial view of Gavins Point Dam and power house stream on the lower portion of the river.
Missouri River (Mile 811.1) near Location: Yankton, South Dakota
In-Service Date: September 1956- January 1957
57 Gavins Point Power Plant Development Plan
9.2 HYDROPOWER Fiscal Year 2015 Performance While most of the Missouri River plants are used for peaking Generation or semi-peaking purposes, which means they generate more energy during the hours of highest demand, Gavins Point Dam No. of Unit Starts 20 is the only dam consistently used for baseload production, Net Generation (MWh) 794,276 which means the plant provides a continuous energy supply. Peak Availability No. of Outages 3 Hours Unavailable 215
Characteristics and Value Factor (%) 98.9% Generators/Turbines 3- Variable Pitch, Kaplan Forced Outages Turbines, 75 rpm Total No. 0 Nameplate Capacity 132.3 MW/44.1 MW each Hours Unavailable 0 Percent of NWO Capacity 5.3% Factor (%) 0% Average Gross Head 48 ft Scheduled Outages Number & size of conduits None: direct intake Total No. 8 Surge Tanks None Hours Unavailable 1,489 Discharge Capacity 48 ft at 36,000 cfs Factor (%) 5.7% Average annual energy 726 M kWh Historic photo of control room Availability Yearly Hours 26,280 Past work: Over the last 11 years Customer funding has Hours Available 24,790 addressed a number of maintenance, operational and Factor (%) 94.3% reliability issues at the Gavins Point power plant. Equipment Plant O&M Costs replacements have included the oil circuit breakers replaced O&M Costs $7,282,368 with SF6 breakers, 1970’s electromechanical relays replaced O&M Cost ($/MWh) $9.17 with modern microprocessor relays, generator air blast unit breakers replaced with modern vacuum breakers, new PPCS O&M Cost ($/MW) $55,044 SCADA servers, new unwatering and vacuum eliminator valves, new power plant electrical switchgear including original motor control centers, panelboards, and exterior station service switchgear. Customer funding has also funded repairs to the intake trash racks, installed power system stabilizers, and investigated the stator out-of-round condition. Present work: Currently, projects are being executed to replace the original generator step-up transformers with new higher capacity transformers, upgrading the transformer yard, and adding transformer oil containment. Other projects include retrofitting 480 volt breaker, replacing station service transformers, upgrading to digital governors, replacing static excitation systems, designing generator emergency rewinds, and investigating turbine cavitation issues. Gavins Point power house Gavins Point generators
58 Gavins Point Power Plant Development Plan
Gavins Point Consequence of Failure Monthly Analysis of Energy Replacement Cost ($/day)
# of Average Units Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Out Annual
1 $851 $1,616 $3,372 $4,038 $6,622 $9,865 $16,000 $16,660 $11,053 $9,355 $6,821 $1,727 $7,372 Power House 2 $14,426 $13,169 $16,153 $16,963 $22,375 $29,442 $45,467 $44,917 $28,807 $22,564 $16,447 $11,533 $23,614 Location 3 $46,011 $40,892 $37,618 $34,592 $40,255 $51,790 $76,702 $74,109 $47,164 $38,856 $32,828 $33,218 $46,263 Power House Location
59 Gavins Point Power Plant Development Plan
9.3 EXISTING CONDITIONS HydroAMP condition assessment indicates the bulk of the Power Train Conditions equipment is generally in fair condition and capable of Circuit Generator Generator Transformer Unit Exciters Governors Turbines Transformer sustainable reliability into the future. Breakers Rotor Stator Equip# Since being rewound in 1987, the project has not experienced Unit 1 10 6.5 6.1 4.7 4.7 3.3 T1 - unit 1 7.8 any significant failures of the stator windings. Corona has Unit 2 10 6.8 6.1 4.7 6.3 3.3 T2 –unit 2 6.1 been noted, and ozone is also present especially when the units are cold. The existing winding is coil with three turns Unit 3 10 7.7 6.1 4.7 6.3 3.3 T3 – unit 3 6.1 per coil and three parallels per phase. The stator core has been T4 3.4 measured to be out-of-round due to concrete expansion HydroAMP Condition driving the fair power train condition. Given this condition Rating Condition T5 3.4 Categories Index and age, an on-the shelf specification package is being created T6 8.6 in case a failure occurs prior to the next planned rewind in the Good 8-10 medium term of this HMP. T7 8.6 Fair 3-8 Similar to Big Bend, the condition assessment for turbine is Poor 0-3 3.3, marginal because of increased cavitation repair of the turbines. In 2016, turbomachinery engineers at HDC completed a turbine inspection. Due to the condition of the blades, hub, and discharge ring they recommended these repairs be programmed to sustain reliability and extend the life of the turbine system: Discharge ring stainless steel overlay Cavitation repair of hub and blades Sandblast and painting of units
Unit 3 turbine installation Generators during construction
60
Gavins Point Power Plant Development Plan
9.4 FIVE-YEAR GANTT CHART Table 9-1 shows in detail the current execution strategy for the next five years. This is to be used for planning purposes and will change as the projects are executed.
Table 9-1: Gavins Point Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 336713/467 Replace generator step up transformers $3,500,000 CMP
336713/477 Install generator step up transformers $1,800,000 CMP
449303/545 Generator rewinds design $83,333 CMP
Replace station service 480V breakers and dry- 449304/548 $1,600,000 C C C C C CMP type transformers
399797/507 Replace generator excitation systems $2,500,000 A C C C CMP
456650 Install intake raw water isolation valves $375,000 C C C C CMP
17-5030 Replace programmable logic controllers $633,333 D A A D A A CMP
406271/519 Install digital governor upgrades $2,383,333 D D A A C C C C CMP
TBD Replace CO2 fire suppression system $365,000 D D A C C CMP
Cavitation repair and stainless steel discharge 456032/568 $10,000,000 D D D A A C C C C C C C C CMP ring overlay
18-1154 Refurbishment of tailrace draft tube gates $1,700,000 D D D D A A C C C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) 61 Gavins Point Power Plant Development Plan
9.5 CAPITAL IMPROVEMENT PLAN Table 9-2 identifies capital improvement projects allowing systematic evaluation of all potential projects over a twenty-year period. Auxiliary equipment such as programmable logic controllers, refurbing tailrace draft tube gates, and fire suppression are planned for execution in the next five years. Following the turbine repairs, the HMP captures the requirement to evaluate and budget for the rewind/restack of generators. In the mid-term the district will study and make recommendations based on the fatigue and efficiency of the units. A placeholder project to award the rewind is captured in the long-range capital improvement plan.
Table 9-2: Gavins Pont Project Matrix Project Project Project Title FY PA ($K) Status Project Title FY PA ($K) Number Number IN-PROGRESS MEDIUM RANGE PROJECTS 2019-2025 Multiple Replace and install generator step-up transformers 11, 12 $5,300 Closeout 18-1154 Refurbishment of tailrace draft tube gates 19, 20 $1,700 449303 Generator rewind design 15 $83 Design TBD Switchyard instruments transformers and bus insulators - TBD 449304 Replace station service 480V breakers and dry-type transformers 15 $1,600 Advertise TBD Replace power plant roof - $250 399797 Replace generator excitation systems 15,17 $2,500 Design TBD Sectionalizer cabinets - $150 456650 Install intake raw water isolation valves 16 $375 Design-O&M 18-1152 Upstream water stop repair/replacement - $350 406271/ Install digital governor upgrades 15, 17 $2,383 Design TBD Tailrace stop logs sandblasting - $1,000 SHORT RANGE 2017-2018 TBD Corrosion control crane rehab intake and tail race - $500 TBD Replace programmable logic controllers 17 $633 Design 17 TBD Upgrade HVAC system - $1,200 TBD Replace CO2 fire suppression system in the power plant 18 $365 Design 18 TBD Piping epoxy liner - $200 456032 Cavitation welding and coal tar coating repairs 16, 18 $10,000 Design 17 TBD Install switchyard switches - $265 TBD High impendence grounding - TBD LONG RANGE PROJECTS 2026-2035 - Units 1-3 generator rewind 27 $73,000 - Replace circuit breaker vacuum - TBD - Replace compressed air system and blowers - TBD - Replace switchgear circuit breakers - TBD
Gavins Point spillway 2011
62 Maintenance and Revision
10.1 ROLES AND RESPONSIBILITIES 10.2 UPDATING AND PRODUCTION The proponent of this HMP is the Omaha District Operations A Program Manager is responsible for the annual update of Division. The maintenance engineering staff oversees the the HMP. Those pages requiring changes will be developed, review effort working with the six power houses to identify reproduced and inserted into the HMP. and prioritize requirements. Project Management will execute The HMP will be updated annually parallel with the existing the requirements and report results to stakeholders. actions that occur for the hydropower program. The table The Hydroelectric Design Center will provide the technical below provides a recommended timeline to conduct HMP guidance on condition and modernization priorities as well. actions highlighted in green by quarter. They will use the forecast of district needs to resource design staff to support execution. 1st 2nd 3rd 4th Action Western Area Power Association will review and provide Qtr. Qtr. Qtr. Qtr. input on cash requirements and advise on the impact of Plants review conditions, updates scheduled outages. hydroAMP, and submits new/revised Western States Power Corporation will provide input on requirements (OMWR). funding forecasts and decide to support annual funding District and HDC review HMI and request. OMWRs. District prioritizes requirements. HMP draft update complete, reviews with customer and WAPA. Corrections, changes, additional information or other data pertinent MOU meeting, long-term work plan to the Hydropower Master Plan will be directed to: update to members. Andrew Wright Submit draft funding schedule and justification sheets for next fiscal year’s CENWO-PM-C projects. 1616 Capitol Avenue Submit final exhibits and funding Omaha, NE 68102-4901 schedule. (402) 995-2506 WSPC’s approved project and contract [email protected] revision is signed.
63 Appendix 11.1 Acronyms and Abbreviations
AIP Asset Investment Planning USACE United States Army Corps of Engineers BB Big Bend WAPA Western Area Power Association CG Construction General WSPC Western States Power Corporation CIP Capital Improvement Plan FP Fort Peck FR Fort Randall FY Fiscal Year GA Garrison GP Gavins Point GSU Generator Step-Up HDC Hydroelectric Design Center HMI Hydropower Modernization Initiative HMP Hydropower Master Plan Hrs. Hours hydroAMP Hydropower Asset Management Program OM Operations and Maintenance OMWR Operations and Maintenance Work Request MWh Megawatt hour No. Number NWD Northwest Division NWO Northwest Omaha District OA Oahe PA Programmed Amount PH Power House PPCS Peer-to-Peer Client/Server SCADA Supervisory Control and Data Acquisition SF6 Sulfur Hexafluoride TBD to be determined UGP Upper Great Plains
I Appendix 11.2 Acknowledgments
THE FOLLOWING PEOPLE WERE INSTRUMENTAL IN THE DEVELOPMENT OF THE HYDROPOWER MASTER PLAN: United States Army Corps of Engineers David Becker, Gavins Point Operations Project Manager Jeremy Bell, Omaha District ACE-IT Visual Information Specialist Laura Bentley, Omaha District Civil Works Project Manager Jerry Cheek, Hydroelectric Design Center Product Coordinator Kris Cleveland, Oahe Technical Section Chief Frances Coffey, Northwest Division Program Support Division Chief Tom Curran, Fort Randall Operations Project Manager John Daggett, Fort Peck Operations Project Manager Kayla Eckert Uptmor, Omaha District Civil Works Branch Chief Dale Evenson, Garrison Maintenance and Operations Manager Keith Fink, Omaha District Operations Division Chief Steve Graf, Omaha District Construction Management Section Chief John Henderson, Col., Omaha District Commander Gary Hinkle, Omaha District Maintenance Engineer Chief Jay Hodges, Omaha District Construction Division Acting Chief Darren Horiuchi, Hydropower Analysis Center Trinity Houska, Big Bend Chief of Technical Support Dawn Kinsey, Fort Randall Program Analyst Lucas Kirkpatrick, Omaha District Electrical Engineer Tammy Kortum, Gavins Point and Oahe Program Analyst Melissa Kurtz, Omaha District Electrical Engineer Nile Limbach, Omaha District Electrical Engineer Todd Lindquist, Garrison Operations Project Manager Adonica Marshall, Hydroelectric Design Center Product Coordinator Trevor McDonald, Big Bend Electrical Engineer Greg Mellema, Maintenance Engineering and Management Support Branch Chief Steve Miles, Hydroelectric Design Center Director Alsoufi Mohammed, Omaha District Mechanical Engineer John Palensky, Omaha District Civil Works Project Manager Mark Parrish, Hydropower Analysis Center Mike Posovich, Hydroelectric Design Center Product Coordinator Chief Dale Pugh, Fort Peck Maintenance and Operations Specialist Scott Ross, Northwest Division Hydropower Design Business Line Manager Jody Ruckman, Omaha District Asset Program Manager Kammau Sadiki, National Hydropower Business Line Manager Jennifer Salak, Omaha District Outreach Specialist II Appendix 11.2 Acknowledgments
Brian Shenk, Hydropower Analysis Center Chief Kate Schenk, Omaha District Operations Division Chief Michael Schenkel, Fort Randall Operations and Maintenance Manager Eric Stasch, Oahe Operations Project Manager Ken Stratton, Omaha District Management Support Section Chief Ted Streckfuss, Omaha District Deputy District Engineer Tom Stiver, Big Bend Project Operations and Maintenance Manager Wayne Todd, Northwest Division Hydropower Design Business Line Manager Jerry Truelsen, ACE-IT Print Specialist Michael Welch, Gavins Point Power Plant Superintendent Shelby Whitmer, Fort Peck Power Plant Superintendent Teresa Wieczorek, Big Bend Program Analyst Eileen Williamson, Omaha District Public Affairs Specialist Marilyn Wilson, Fort Peck Program Analyst Andrew Wright, Omaha District Civil Works Project Manager
Western Area Power Association Traci Albright, Upper Great Plains Budget Analyst Linda Cady-Hoffman, Rate Manager Robert Harris, Senior Vice President and Upper Great Plans Regional Manager Gale Nansel, Upper Great Plains Transmission Planning Manager Jody Sundsted, VP of Power Marketing for Upper Great Plains Region
Western States Power Corporation Dan Peyton, General Manager Jeff Peters, Director
Mid-West Electric Consumers Association Bill Drummond, Executive Director
III Appendix 11.3 Complete 5-Year Gantt Chart
Fort Peck Project Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 405213/514 Station service interior transformers $370,000 C C CMP Multiple Rehab unit 2 and install high resistance ground- $7,857,000 C C C C CMP 454556/552 Install generator relays $600,000 C C C C C CMP 449565/556 Replace emergency gate hoist wire rope $1,200,000 C C C C C CMP 405212/517 Rehab emergency gate control system $1,355,000 C C C C C CMP 329337/531 Rehab draft tube bulkheads $730,000 C C C C C C CMP 405211/515, Supply and install transformers, oil filled cable $5,510,000 D A A C C C C CMP 447128/533 system, and exterior oil-filled transformers 461482/591 Replace programmable logic controllers $600,000 D A A D A A CMP 454554/554 Instrument transformer replacement (PT/CT) $300,000 C C C C C C C CMP 447127/532 Replace motor control centers $2,314,025 C C C C C C C CMP 458812/578 Modernize shaft building cranes $1,000,000 D D D A A C C C C C CMP 458814/577 Replace power house fire and security system $250,000 D D D A A C C C CMP 458813/579 Bridge crane design and repair $4,300,000 D D D D A A C C C C C CMP 18-2151 Replace draft tube stop logs $1,000,000 D D A A C C C C C C CMP TBD Install digital governors $4,000,000 D D D D A A C C C C CMP 405220/516 Rehab switchyard 1 $4,700,000 D D D D D D A A C C C C C C C CMP 454557/553 Rewind/rehab units 4 and 5, and switchyard 2 $20,000,000 D D D D D D D A A C C
18-2139 Replace generator cooling water system $200,000 D D D 18-2131 Rehab butterfly valves $200,000 D D D
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) IV Appendix 11.3 Complete 5-Year Gantt Chart
Garrison Project Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 18-1160 Repair intake structure roof $4,000,000 CMP 105566 Major rehab $95,297,000 C C CMP 456630/567 Replace programmable logic controllers $600,000 A C C CMP 461090/589 Generator yard civil work $3,000,000 A A C C C C CMP 18-1182 Upgrade intake crane $2,000,000 D A A C C C C CMP
18-1159 Replace equalizing valves $450,000 D D A A C C C C CMP
18-1108 Repaint/repair penstock gates and lifting beams $5,300,000 D D D A A C C C C C C C CMP
Oahe Project Gantt Chart 449302/526 Generator rewind design $83,334 CMP 399795/510 Tailrace deck transformer oil containment $1,125,000 C CMP
456033/573 Repair thrust bearing cooler $300,000 C C C CMP
18-1178 Penstock dewatering piping in shale drain tunnel $170,000 C C C C CMP 144043/ Upgrade 115 and 230 kV switchyard and $10,800,000 C C C C C C CMP 478 & 382 autotransformer replacement
TBD Replace programmable logic controllers TBD D A A D A A CMP 18-1177 Replace intake motor controls $650,000 D D D A A C C C CMP 399796/509 Replace generator exciters $5,566,667 A C C C C CMP
18-1195 Replace monorail bridge crane $1,000,000 D D A A C C C CMP 456034/570 Generator step-up transformer bushing $1,200,000 A C C C C CMP 456480/571 Bridge crane rehab $5,500,000 D A A C C C C C C C C CMP 406268/518 Install digital governor retrofits $3,933,334 D D A A C C C C C C CMP
18-1091 Replace outdoor station service switchgear $1,200,000 D D D A A A C C C C C C CMP
18-1197 Rehab tailrace bulkhead $1,800,000 D D D D A A C C C C
TBD Upgrade CO2 fire suppression $360,000 D D D D A A C C C C
V Appendix 11.3 Complete 5-Year Gantt Chart
Big Bend Project Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 122957/355 Generator rewinds $15,391,953 CMP
399793/510 Transformer oil containment $1,125,000 C CMP
399792/501 Rehab generator step up transformers $1,400,000 C C CMP
456669/503 Replace programmable logic controllers $600,000 A C CMP
399794/500 Replace generator excitation system $6,566,667 C C C C C C C CMP
456035/561 Repair/replace intake gate hoist gear box $1,800,000 A C C C C C C C C CMP
18-1221/22 Rehab intake crane $2,400,000 D D D D A A C C C CMP
406304/520 Design/install digital governor upgrades $4,250,000 A C C C C C C C C C C C CMP
18-1168 Power plant HVAC upgrade $1,200,000 D D D A C C CMP
Replace raw water header, unwatering valves, 499301/543 $2,350,000 D D D A A C C C C C C C CMP station drainage piping
TBD Rehab depressing air/station service air systems $1,275,000 D D D A A C C C C C C C C
TBD Replace MCCs/unit auxiliary panels $2,600,000 D D D A A C C C C C
TBD Replace generator breakers $5,000,000 D D D A A C C C C C
Recondition draft-tube liner, cavitation repair, 18-1073 $23,000,000 D D A A C C paint turbines
18-1219/21 Rehab draft tube crane $850,000 D D D A A C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) VI Appendix 11.3 Complete 5-Year Gantt Chart
Fort Randall Project Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 449299/541 Design generator step up transformers $200,000 CMP
125884/476 Validation study $200,000 CMP
399807/505 Rehab bridge cranes $3,800,000 C CMP
18-7609 Repair intake structure curtain walls and drains $935,000 C C CMP
455996/564 Rehab 13.8kV outdoor station service equipment $810,000 C C C C C CMP
399806/504 Replace oil-filled cable $11,700,000 C C C C C CMP
449297/547 Purchase and install unwatering valves $1,100,000 C C C C C C CMP 406730/523 125884/465 Upgrade switchyard $15,950,000 C C C C C C CMP 125884/475
406244/521 Replace generator relays $500,000 C C C C C C CMP
TBD Replace programmable logic controllers $633,333 D A A D A A CMP
449300/542 Upgrade station service switchgear $2,300,000 D A A C C C C C CMP
456029/566 Replace station service transformers $920,000 D A A C C C C C CMP
18-1160 Rehab intake crane $811,000 D D D A A C C C C CMP
Multiple Major rehab $220,000,000 D D D D D D D D A A A A A C C C
18-1169 Intake gate rehab $4,170,000 D D D A A C C C C C C C C
VII
Appendix 11.3 Complete 5-Year Gantt Chart
Gavins Point Project Gantt Chart Program ID Project Title Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Amount FY17 FY18 FY19 FY20 FY21 336713/467 Replace generator step up transformers $3,500,000 CMP
336713/477 Install generator step up transformers $1,800,000 CMP
449303/545 Generator rewinds design $83,333 CMP
Replace station service 480V breakers and dry- 449304/548 $1,600,000 C C C C C CMP type transformers
399797/507 Replace generator excitation systems $2,500,000 A C C C CMP
456650 Install intake raw water isolation valves $375,000 C C C C CMP
17-5030 Replace programmable logic Controllers $633,333 D A A D A A CMP
406271/519 Install digital governor upgrades $2,383,333 D D A A C C C C CMP
TBD Replace CO2 fire suppression system $365,000 D D A C C CMP
Cavitation repair and stainless steel discharge 456032/568 $10,000,000 D D D A A C C C C C C C C CMP ring overlay
18-1154 Refurbishment of tailrace draft tube gates $1,700,000 D D D D A A C C C C
Gantt Chart Legend D Design Q1 1st Quarter of Fiscal Year (Oct, Nov, Dec) A Advertise/ Award Q2 2nd Quarter of Fiscal Year (Jan, Feb, Mar) C Construction Q3 3rd Quarter of Fiscal Year (Apr, May, Jun) CMP Complete Q4 4th Quarter of Fiscal Year (Jul, Aug, Sep) VIII IX