By Daniel P. Breig
Southern California Edison (SCE, Rosemead, CA, the U.S.A.) is leading California’s charge to meet the country’s most ambitious Renewable Portfolio Standard (RPS) targets, 20% by 2010 and 33% by 2020. For example, during 2010 SCE delivered to customers more electricity generated with renewable energy sources than any U.S. utility.
To satisfy these aggressive targets, SCE has begun adding new utility owned PV resources to our system. While PV is a recognized and well-understood renewable resource, its development and deployment as a distributed generation resource at massive-scale installed on rooftops is an emerging and evolving practice.
SCE’s program to install one to six MW PV generators was approved with modifications by the California Public Utilities Commission (CPUC) in June 2009. The CPUC also approved 250 MW of rooftop PV, owned by third parties, to be sold to SCE via Power Purchase Agreements (PPAs) chosen through competitive auctions.
These PV generating units inject their energy directly into SCE’s distribution grid, thereby speeding up the deployment of solar generation projects. SCE is also supporting the development of larger, remote solar installations by building the nation’s largest transmission project designed primarily to carry renewable generation to market.
SCE’s first installation was a 2.44 MW (dc) unit installed on a ProLogis rooftop in Fontana, CA. the U.S.A. As the first SCE owned multi megawatt rooftop PV installation, it serves as a comparison to SCE’s later rooftop PV designs. Figure 1 is a photo of SCE’s first rooftop PV unit. The building is 607,000 square feet. in size, and used 33,732 First Solar thin-film PV modules.
SCE’s initial rooftop installation was designed by First Solar, and used First Solar thin-film PV panels. The array wiring had as many as four combiner boxes used for a single home run. Spring clip type fuse holders were used in master fuse boxes. Four inverters were used to convert the PV array’s dc power to ac. They were all located at one end of the host building, so as to not interfere with construction on one side of the building and the loading docks on the other two sides. Each inverter fed a 200/480 volt 500 kVa dry type transformer with 480 volt (ac) cables connected to a central 480 volt (ac) 4,000 amp switchgear bus and metering assembly. A second transformation step used a 480 volt/12kV oil filled transformer with 12 kV cables used to connect to the 12 kV distribution system. Cable specified by First Solar was thermoplastic THHN cable. The cable race way design used conduit. Figure 2 shows the conduit cable race way used on SCE’s first rooftop unit.
Using lessons learned through the design and construction of our first system, improvements were developed to save money and time, and improve operability and maintainability.
One of the first was to change the race way design from conduit to cable trays. This change saved time during installation, will save time during maintenance, is better able to address thermal expansion on the roof, and weighs much less than conduit. The cable used was changed from thermoplastic THHN, to a thermosetting type RHW/RHH/Use2 rated cable. Figure 3 shows the cable tray race way currently used.
There were numerous improvements to the dc electrical design. In the combiner boxes, we now use string fuse holders that have a blown fuse indicator. We have adjusted the locations of the terminals inside of the box to allow the wire to be trained better from a bend radius perspective. We also specified a dc disconnect switch in each combiner box, and in each home run at the master fuse box. This allows maintenance without completely securing the entire inverter, and also allows the master fuses to be changed without isolating every string fuse. We have plans to switch from fuses to dc rated molded case circuit breakers. For reliability and maintainability, we have specified cable terminals that allow long barrel two hole lugs to be used on home run cables rather than screw type mechanical lugs. The double crimp, long barrel lugs provide a robust connection resistant to the stresses of the daily cycling of a PV plant. We have changed the master fuse box design from spring type fuse clips to bolted fuses for better, more reliable connections. Due to limited and inconvenient roof access, we specified a dc disconnect in each home run on the ground to allow operation and maintenance flexibility.
Where feasible, we locate the inverters dispersed around host buildings, rather than at one end, to reduce cable lengths and reduce voltage drop. Connections to the inverter were designed to need fewer cables, so there would be less congestion in the inverter dc terminal box. We also worked with the inverter manufacturer, and modified the design of the fuse box to inverter cables to allow adequate space for cable terminations.
We designed the ac electrical system to allow the use of oil filled transformers like those used throughout our utility distribution system. Another design change was to use a single step-up from the inverter’s 208 volt (ac) output to the distribution system voltage, rather than using an intermediate 480 volt (ac) step. The high voltage interconnection allowed a single conduit to carry the power rather than the cable trench required for the 480 volt cables at 4000 amps. The SCE standard utility distribution transformers have terminals to allow the 12 kV cables to loop through the cabinetry with a coil switch and a loop switch for the maintenance isolation. Figure 4 shows the electrical single line of the interconnection of SCE’s first unit, and the single line of the current design.
The design of the PV module racking system for the first three demonstration sites using First Solar modules evolved to three different versions, each an improvement over the previous. Wind tunnel tests aided this process. The racking designs were improved by making the racking lighter in weight, and by reducing its resistance to wind uplift.
Many of SCE’s solar stations are built on large commercial rooftops that pose inherent challenges. As-found condition of the rooftops often requires preventative maintenance prior to PV system installation, even if the roof is new. Cracks and wrinkles in the roof membrane can cause drainage problems. Nails and stapes often poke through the roof membrane. Where needed, roof coatings are applied prior to PV system installation, to retard roof aging. Landlords often reject the use of roof penetrating type rack mounting systems needed to resist wind uplift, out of concern for the roof warranty. Other roofs are not structurally adequate to support the PV modules, racks, and ballast. Original design and construction of the warehouses often left very little structural margin for the solar system, and later revisions to the building structural codes sometimes foreclose the potential for PV development.
Leasing roof space from building owners is a new concept with a market that is not well established, so there are no standard practices. Negotiations are quite lengthy.
The building tenants have no desire to let a landlord lease roof space to a solar system owner. Typical tenant responses run the gamut from outright rejection of the proposed solar facility, to asking the solar owner to insure their business operations.
Each city and county can approach permitting of solar projects very differently. Some waive fees to encourage solar development. Others tax the project heavily to gain revenue. Requirements vary widely, though most are more concerned with the appearance of the ground equipment from the street. In general, permitting agencies have little sense of urgency.
Third parties have long complained about the interface between them and the utility. Examples of challenging processes requiring utility interface include compliance with the electrical service requirements, and the Wholesale Distribution Access Tariff (WDAT) requirements to interconnect with the utility grid. These two complex processes can contain unclear requirements, and are handled by different groups within the utility with no single point of contact and schedule accountability. Overcoming institutionalized inertia has been a challenge for our group as well, even from within the utility.
With this Solar PV Program, SCE has broken new ground, and made great strides, in the development of utility-scale, utility-owned PV. The Solar PV Program’s early units are providing valuable lessons learned. We anticipate applying these lessons learned to further improve the design and execution of the remaining systems, allow better integration of the intermittent renewable resource into utility operations, and to improve and streamline associated administrative processes.
Daniel P. Breig is the Director of the Project Development Division for Southern California Edison (www.sce.com) in Rosemead, CA, the U.S.A., leading the utility owned department of the Solar PV Program. During his 39 year career, he has managed engineering, construction, operation and maintenance of transmission, nuclear, renewable and fossil fueled generation. He was Station Manager at San Onofre Nuclear Generating Station. He is a registered Professional Engineer in the Electrical, Mechanical, and Nuclear disciplines.
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