The 1960s and 1970s were the heyday of underground transmission cables. Utilities installed hundreds of miles of 138-kV and 230-kV cables and put into service the first 345-kV cables. Almost all of these were high-pressure liquid-filled (HPLF) pipe-type cables installed in major metropolitan areas. While some utilities installed self-contained fluid-filled (SCFF) cables, several utilities were willing to buck the trend and install extruded-dielectric transmission cables.
The last four decades have seen the installation of many additional lines. More than 5000 miles (8047 km) of transmission cables stretch across the United States. During this period, extruded-dielectric cable assumed major importance, and today it accounts for a majority of new transmission cable installations up to and including 161 kV. In addition, more than 20 miles (32 km) of 230-kV extruded-dielectric cables are in operation in the United States. The first 345-kV extruded-dielectric cable in the United States was placed in service in the Boston, Massachusetts, area in late 2001.
Pipe-type cable still dominates at 345 kV and still has extensive use at 230 kV, but its percentage of new installations is diminishing. Introduction of laminated paper-polypropylene insulation in the 1980s greatly extended the applicability of this cable type. Today, utilities are installing very little SCFF cable and are replacing much of the existing 50- to 70-year-old cable, mostly as a result of sheath problems. Even submarine cable installations — traditionally an application for SCFF — increasingly use solid-type paper cable and polymeric cable.
A significant percentage of transmission cables installed are a result of independent power producers (IPPs) building lines to connect to existing overhead or underground circuits. The additional generation results in a significant increase in power transfer over lines that the local utility installed, owned and operated for decades. Both utilities and IPPs have a major challenge to transmit additional power efficiently without unduly affecting the cable system operation and reliability.
The simplest but most costly solution is to install new lines, leaving the existing cables unaffected. However, installing new transmission cables is difficult and time consuming, especially in congested city streets in major urban areas. Tony Tremonte, vice president, Pirelli High Voltage Cable Systems group, reports that more utilities are moving toward uprating existing facilities. Utilities find they can upgrade existing lines at a fraction of the cost and time of a new line, according to Tremonte.
Uprating is an increasingly attractive option. Over the years, several studies show that most cables are operating well below their design ratings. Additional power transfer is possible, but the utility must be comfortable that the ratings are accurate and long-term operation will not be compromised. Some utilities may even be willing to accept accelerated loss of life to increase power transfer during critical periods.
The first step in determining the acceptable rating is an “ampacity audit” in which cable auditors review available data on the transmission line, whether an extruded or fluid-filled design. The audit includes:
As-built plan and profile drawings that should have been updated as relocations were made and fill was added.
Present and expected operating conditions, especially daily and weekly load shapes. SCADA information often is available, providing hourly load readings for any time of the year. These data accurately determine load factors and loss factors (load factor of the I2R losses) for rating periods of interest such as summer and winter peak times.
Records of changes to the circuits and additions such as nearby duct banks.
Manufacturer's and utility's records on cable and installation characteristics.
Measured ambient earth temperatures. The estimated maximum summer and winter ambient earth temperature at a 4-ft (1.2-m) cable depth is the temperature at which most cables are rated. Nowadays, a simple “thermocouple tree” with thermocouples inserted into small-diameter borings at 2-, 4-, 8- and 12-ft (0.6-, 1.2-, 2.4- and 3.7-m) depths (or deeper if a directional drill is involved), and connected to a very small self-contained recorder, can provide inexpensive, accurate temperature data at those depths.
Soil thermal properties were not measured along the route of many existing cable circuits. A qualified contractor can conduct careful field tests and laboratory dryout curves. These data provide valuable site-specific information to help more accurately determine the cable rating under all ambient conditions. These data are then entered into one of several computer programs to accurately determine steady-state and emergency ratings.
Most of the time, an ampacity audit of an existing line shows the possibility of additional power transfer, while keeping the operating temperature within allowable levels.
Surveying Can Result in Lower Ratings
In some cases, the analysis shows the need to reduce the feeder rating. The cable may have been installed more deeply than was expected, additional fill was placed over the line because of highway construction, there was an area of thermally poor material that had not been known. The two most common causes of lower ratings are:
- Higher daily load factor
Because of the long thermal time constants, the daily load factor affects the underground cable rating. Load factors generally creep upward with local generation additions, different load types with flatter load shapes and as load management initiatives succeed. Although the daily energy transfer increases, the allowable peak load (the “rating” of the cable) decreases. It is uncomfortable for the cable engineer to tell the system operator the rating of his circuits dropped because the utility was successful in its load-management program.
- Nearby distribution circuits
In many instances, the utility-distribution department installed distribution duct banks near the transmission cable lines. The heating effect from (often heavily loaded) cables in the duct bank will raise the effective ambient earth temperature for the transmission cable, derating the transmission cable.
Uprating High-Pressure Liquid-Filled Circuits
Carl Segneri, vice president of Transmission Engineering for ComEd (Chicago, Illinois, U.S.), reports that ComEd is now working on a joint HPLF forced-cooling project with Pirelli in Chicago that will save more than US$2 million. Pirelli has seen an increase in requests from utilities to revamp old workhorse pumping plants and circulating units that are the “heart” of many critical high-voltage HPLF underground circuits around the country.
Utilities have several methods to uprate these circuits:
- Slow fluid circulation
In many cases, the utility installed a pair of feeders between substations. The utility can make minor piping changes in the pressurizing plant to permit the pressurizing pump to run constantly, circulating dielectric liquid between the feeders at 5 to 10 gal/min (19 to 38 l/min). Slow circulation smooths out hot spots, increasing rating by 5% to 10%. If the utility installs only one feeder, it can oscillate fluid between reservoir tanks at either end of the feeder to provide thermal smoothing.
- Rapid fluid circulation
The utility adds a separate rapid-circulation pump to circulate the dielectric liquid at rates up to a few hundred gallons per minute. Although rapid circulation requires additional equipment, including baffles on the cable pipe to prevent impingement on the cable, significant ampacity increases may be possible as a result of temperature averaging over long distances and reducing the thermal resistance from the cable to the cable pipe. Increases from 10% to 20% are feasible.
- Add a heat exchanger
In combination with rapid fluid circulation, the utility can add air-cooled heat exchangers to remove heat from the dielectric liquid to further increase ampacity. To accomplish this, room is needed in the substations to accommodate the additional equipment. While the corresponding increase in noise levels may be a problem, the ratings increase by as much as 40%. A HPLF system installed before the 1980s may contain a high-viscosity dielectric liquid that must be replaced or “thinned” with a lower viscosity liquid to keep pressure drops within allowable values.
With any system circulating dielectric liquid, careful design is necessary to insure cable system integrity is not compromised during normal or contingency operation; this includes steady-state and transient pressures under all operating conditions and ambient temperatures. Ideally, a separate fluid-supply pipe would provide operation of a feeder independently from its companion, but the cost and time required to add the supply pipe could be prohibitive. However, if fluid flows up one cable pipe and down through the companion pipe, loss of one feeder as a result of an electrical or hydraulic incident would restrict the power transfer on the other feeder at the time when increased capacity is most important. If this happens and no alternative power-flow paths exist, power transfer would have to be curtailed.
Dynamic rating has major benefits for short-term ratings and increases the normal daily ratings. It applies mostly to HPLF cables, because fluid circulation can smooth unknown hot spots remote from the temperature sensors on the cable pipe, and the long thermal time constant compared to extruded-dielectric cables provides greater operating margin in event of overloads. In recent years, however, distributed fiber-optic temperature monitoring (See T&D World, June 2001) identified the hot spots anywhere along the line, and made dynamic rating feasible for all cable types.
Pipe-type cables enjoyed a low failure rate, and tests on 50-year-old cables removed from service show they are in excellent condition, perhaps even good for another 50 years. These cables generally operate at temperatures of 10°C to 20°C (18°F to 36°F) below their design values. If better knowledge of the feeder rating, combined with one of the uprating schemes described above, allows operation close to the design limit, the cable lifetime may fall below the expected 60 to 70-plus years, and maintenance/operation/repair expenses may increase.
Payment approaches for uprating and associated operational costs are evolving in the new transmission market. The organization providing the additional power may fund the capital improvements to increase the cable rating and allow the additional power to reach the market — but the utility may be stuck with the higher ongoing costs that may result, including substantially higher cost of losses as well as potential higher maintenance and repair costs.
Jay A. Williams is a principal engineer at Power Delivery Consultants Inc. (Ballston Lake, New York), which he cofounded in 1992. Williams has been designing, overseeing the construction of, and commissioning high-voltage underground cable systems for more than 30 years. He has developed industry-accepted ampacity programs, and teaches cable ampacity and cable project planning courses. Williams was the technical editor for the 1992 EPRI Underground Transmission Systems Reference Book, authoring the ampacity chapter. Previously, Williams was the underground manager at PTI and was in charge of the underground transmission cable group at Consolidated Edison. He is a senior member of IEEE and is past chairman of the Insulated Conductors Committee's Insulation Systems Subcommittee.
Editor's Note: Pipe-type cables are typically called high-pressure fluid-filled systems (HPFF). Most commonly the fluid is a liquid, so the specific terminology is high-pressure liquid-filled (HPLF). When nitrogen gas is used as the fluid, the cables are called high-pressure gas-filled (HPGF).