With the increase of renewable energy into the power generation market, aggressive state renewable targets, and recently renewed production tax credit (PTC), wind power generation demand is positioned to increase significantly. This is good news not only for new wind projects but also for existing wind power infrastructure.
As the wind energy market and demand has grown quickly, so has the technology – better turbine controls, more efficient drivetrains, longer and lighter blade designs, and taller towers. Figure 1 shows that in 2000 wind turbines had an average nameplate capacity of slightly less then 1 MW and 30% capacity factors, while the average nameplate capacity in 2016 was 2.15 MW , with capacity factors near 40%. Blade lengths of 25 meters in 2000 are dwarfed by the more recent 50 meter blades (see Figure 2). Longer blades at higher hub heights and more efficient controls means that new wind projects can achieve more power generation capacity with half (or less) the number of turbines compared to 10-year-old projects.
A typical wind turbine is designed for 20-year operation. In 2017, most of the US wind turbine fleet is less than 10 years old, with 20% of the fleet between 10 and 16 years of age.
As wind turbines age and near their design life of 20 years, owners should start assessing their future options for continued operation:
The answers to these questions are project and site specific.
For existing projects, the recent PTC stated that a 10-year extension could be applicable if 80% of the turbine’s value is replaced by upgrades. This has led many owners/operators to consider partial repowering of their fleet. Partial repowering a wind turbine entails replacing up-tower components and equipment but keeping the existing foundation and tower intact. Partial repowering a 15-20 year old site would seem beneficial since permitting, grid connection and infrastructure is already in place. But the reality is that in many cases the existing balance of plant, foundation and tower will significantly limit the type of upgrades to the point that only a small increase in energy production will be achieved. This small increase in Annual Energy Production (AEP) will not offset the capital expenditures required to upgrade.
Figure 3 shows various upgrades available aftermarket with typical energy gains .
Re-powering (full) involves the same site but with full replacement of old turbines with state-of-the-art turbines with more generation capacity. At first glance, this option would seem like starting a new project, which in many aspects it is. But it has some advantages over starting a new greenfield site. The re-powered site has existing infrastructure such as access roads, grid connection, personnel, and the site conditions are well known which can save site permitting and wind assessment hurdles. A National Renewable Energy Laboratory (NREL) economic study on repowering suggested that repowering becomes more attractive relative to investing in a new site for projects after 20-25 years of operation. The goal of repowering is to increase power generation capacity that involves a substantial capital expense. The decision to repower lies mainly in the financial balance; on one side is the repowering return on investment, and on the other is the current project’s operations and maintenance (O&M) costs.
Another option is the continued operation of the wind turbines past their 20-year mark with minimal capital expenditure. Wind turbine life extension guidelines and standards are available not just for wind turbines (DNV-GL or UL) but for many other machinery applications (ISO 13822). For wind turbine life extension the owner needs to review actual wind loading conditions to date and how that compares with initial/design life estimates, assess the current condition of the turbines, then estimate the remaining useful life of the wind turbines, and then develop an appropriate O&M program for continued operation.
The process of evaluating the various options described above for continued operation depends on three different but related stages of wind turbine/component lifetime estimation. Figure 4 depicts the steps for different stages of wind turbine lifetime estimation, design life estimates, lifetime update, and lifetime extension.
Wind turbine designs following the International Electrical Commission (IEC) and DNV-GL design guidelines are based on specific IEC wind classification, with a total of four different wind classes. Each wind class assumes a nominal operating wind speed and certain frequency of extreme events. Table 1 is an extract from the IEC 64100-1 standard. Class I is considered high wind speeds and class III slow wind speed regimes. Wind turbine OEMs use these wind classes to design different turbine models and generally have several options for various wind speed ranges and hub heights. For lifetime (or fatigue) design, the IEC 64100-1 provides a general distribution for different scenarios. The technological trend has seen more offerings as modular turbine components can be mixed and matched to the specific site conditions. The final decision to purchase and install specific turbines/components falls on the project development team based on wind availability forecasts, component and turbine characteristics, and OEM contracts.
While wind availability forecast is a major driver for project feasibility, site assessment ultimately defines turbine life. During project development, wind availability forecasting is made by gathering met mast data and meteorological simulations, and extrapolating a trend from that data. For projects older than 15 years, the wind resource and site assessment process was not as developed as it is now, resulting in wind regime and wind loading histories with high uncertainties. With an “expected” wind loading and operation, site-specific design assessment for 20-year fatigue life can be performed for prospective wind turbines in the market.
After years of operation with local measurements such as local met masts, SCADA data, anemometer data, maintenance reports and/or condition monitoring systems (CMS), the fatigue life of the turbine can be updated. Figure 4 shows two possible scenarios that differ from the as-designed scenario.
An aggressive scenario such that wind loading, operation and environmental conditions were underestimated during development that could result in shorter than 20 year life-span; or the opposite where the wind loading and operation have been benign and the turbine is expected to survive past 20 years. For the aggressive scenario, where O&M expenses might start to impact the profitability of the project, it may be beneficial to consider repowering (either partial or full). For the benign scenario, the question now turns to how much longer can the turbines run safely and what will be the ongoing O&M program costs.
With accurate and current data gathered, a turbine and component risk prioritization/evaluation can be performed so that a risk based inspection program can be developed. Analytical estimates are based on models that have certain assumptions and uncertainties. Performing inspections for the higher risk (and/or high uncertainty) components could help reduce model uncertainty, and provide more accurate and current damage or degradation states. These inspections would span all components (but not all turbines in a project, nor all components within one turbine) and would include visual inspections (using drones for example), targeted non-destructive inspections (such as ultrasonic phased array, dye penetrant, thermography) and if necessary material testing (non-destructive if possible).
Following these inspections, any discovered degradation will serve as inputs to the damage propagation models, strength degradation models and fatigue analyses to get a remaining useful life for the component. There are two main methods for fatigue analysis; the fatigue cycle accumulation method which is typically used during design that does not depend on exact damage characteristics, and the damage propagation method that accounts for damage characteristics and local effects (within component/part) and loading. The fatigue cycle accumulation method is useful when the presence of damage is unknown.
But if damage has been discovered, the advantage of the latter method is that it results in targeted re-inspection and/or repair scheduling, rather than pre-defined interval inspections, which would minimize maintenance costs. The process of risk-based inspections plus remaining useful life assessments would build the wind project’s structural lifecycle asset integrity management program. Such a program incorporates condition-based maintenance that provides early warning of potential failure or future systematic failures and helps the optimization of resource allocation planning, allowing the project’s continued operation beyond the 20-year mark.
The process of risk-based inspections plus remaining useful life assessments would build the wind project’s structural lifecycle asset integrity management program. Such a program incorporates condition-based maintenance that provides early warning of potential failure or future systematic failures and helps the optimization of resource allocation planning, allowing the project’s continued operation beyond the 20-year mark.
Continued operation evaluations are not unique to the wind power industry. Nuclear, coal, natural gas and combined cycle plants have gone through similar evaluations and re-certifications. Many of these plants, have seen a transition from running at base load to more frequent start/stops (due to the integration of renewables), which is a considerable change from their design basis. For nuclear plants, the Nuclear Regulatory Commission (NRC) license renewal requires the analysis of aging components and for operators to establish suitable aging management programs. At Structural Integrity we have developed the expertise and tools to help our clients with component and system lifetime assessments, and to support the implementation of optimum maintenance programs for their safe continued operation.