There are currently more than 10,000 wind turbines rated at less than 250 kW operating in the U.S. with a total rated capacity of less than 1.2 GW. These turbines were typically installed more than 20 years ago. An additional 2.5 GW of turbines operating in the U.S. are rated between 250 kW and 750 kW, and these turbines are typically 10 to 15 years old.
While at first glance, the 20-year-old sites may seem to be obvious candidates for repowering with the more-efficient, higher-capacity turbines available today, a detailed financial analysis reveals this may not be the best solution in all cases – which is why many of these older turbines continue to operate.
In Figure 1, the sea-level power curves for two contemporary IEC Class II high-capacity turbines, the Siemens 2.3 MW-108m and GE 1.6 MW-100m, are compared with those of the Vestas V15-65 kW and V27-225 kW turbines, which were installed in large numbers in the U.S. in the 1980s and early 1990s.
Assuming a site is constrained by available maximum transmission capacity, it is possible to calculate the increase in annual energy production (AEP) that could be achieved by repowering a historical wind site using either of the aforementioned contemporary wind turbines. The results of this analysis for two California wind sites currently operating V15s and V27s with the newer turbine technology are summarized in Table 1. The results indicate that it is possible to increase the historical site energy production by 22% to 51% by repowering the site at the same maximum rated capacity by installing the higher-capacity factor turbines currently available. Note, this study assumes there are no obstacles to obtaining the necessary site permits to operate larger and taller wind turbines at the historical smaller turbine sites.
While it is clear that energy capture is significantly increased by repowering these two aging small wind sites, understanding the impact on project revenue is less straightforward. While the primary cost driver for operating older turbines is annual operations and maintenance (O&M), the primary expense for a repowered site is typically the debt service associated with buying and installing the new turbines. The net present value (NPV) of net revenue for both options is highly dependent on power purchase agreement (PPA) rates.
Figure 2 shows how PPA rates can significantly influence which project scenario is the most attractive – continuing to operate the less-efficient aging turbines or repowering the site.
Assumptions for the 20-year net revenue NPV calculations in Figure 2 include the following: a 10% cost of money (combined debt and equity), a production tax credit benefit for the new turbines of $0.023/kWh for the first 10 years, a nominal total installed capital equipment cost of $1.5 million/MW for the new turbines, O&M costs for the new turbines of $31,000/MW per year, and O&M costs of $4,500 per turbine per year for the stall-regulated V15 and $8,000 per turbine per year for the pitch-regulated V27s. Additionally, a total combined energy loss per project of 10% is assumed due to turbine availability, electrical line/transformer losses and array wake effects.
Figure 2 shows that with the low market PPA rate of $0.05/kWh, which has been prevalent in California in recent years, it remains attractive to continue to operate the existing turbines (shown by blue triangles and diamonds) for both sites – particularly for the site that operates the more-efficient, pitch-regulated V27 turbines.
At the higher PPA rate of $0.075/kWh, which some site operators are able to negotiate or anticipate in the future, the repowering option becomes more attractive for both projects. However, for the V27 site, the as-is V27 turbines still outperform the Siemens 2.3 MW-108m in terms of NPV and are on par with the GE 1.6 MW-100m repower turbines.
At the higher PPA rate of $0.10/kWh, the high-capacity factory GE 1.6 MW-100m turbine becomes more attractive for the V27 site, but the historical V27 turbines still outperform the Siemens 2.3 MW-108m turbine configuration in terms of 20-year net revenue NPV.
Installed capital equipment costs can vary significantly depending on dynamic commodity prices, site location and project size. (Large projects achieve beneficial economies of scale.) The sensitivity of the project 20-year NPV to the installed capital equipment cost per megawatt is shown in Figure 3. The nominal value of $1.5 million/MW that was used in Figure 2 is indicated by the large blue arrow. At a lower installed capital equipment cost of $1.3 million/MW, there is an increased benefit for project repowering relative to continuing to operate the older turbines, and there is a significantly decreased benefit when capital equipment costs increase to $1.8 million/MW. The NPV analysis in Figure 3 assumes a PPA rate of $0.075/kWh, a 10% cost of money and debt, and the aforementioned annual O&M costs.
Simply put, wind turbines are rotating machines that must endure extreme loads due to hurricane-force winds and the repetitive, cyclic fatigue loading that occurs from continuous operation. Current International Electrotechnical Commission and Germanischer Lloyd standards for wind turbine design require engineers to use 20 years as the minimum theoretical fatigue life when sizing components. Basic reliability theory indicates that after an initial period of “infant mortality” failure, a relatively low but steady rate of component failure is observed up until the time components start to wear out as they reach the end of their useful life.
The correct approach to optimizing the financial performance of an aging wind power plant is to determine which components are nearing the end of their operational life and invest as necessary in replacements or system upgrades. For the V15, V17 and V27 turbines, and other machines in the 65 kW-250 kW class installed between 1980 and 1995, areas of potential reliability issues that may need to be addressed through selective upgrades include the following:
- overspeed protection modules and sensors;
- brake/hydraulic systems;
- over-voltage protection;
- generator controls;
- yaw drives/slew ring gears;
- yaw vane/anemometer/wind trigger modules; and
- rotor blade tip flap mechanisms.
For machines in the 250 kW to 750 kW class deployed from 1995 through 2000, variable pitch and variable speed operation added additional complexity to the turbine designs to improve efficiency. These enhancements also created new reliability issues associated with more sophisticated hydraulic systems and power electronics. As a result, pitch system and power conversion system component replacements and selective upgrades may be necessary in addition to the above list in order for these machines to operate for an additional 20 years beyond their original design life.
While it may seem obvious that repowering older wind sites with modern, more-efficient wind turbines with higher capacity factors would result in a financial benefit to the owner/operator, this is not always the case. w
Industry At Large: Repowering
Does It Pay To Repower An Aging U.S. Wind Site?
By Craig Christenson & Sharon Donohoe
Despite technology advances, several factors indicate repowering is not always the best option.
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