advertisement
Exhibit JAW-2 PDC Transmission and Distribution Systems PUBLIC SERVICE ELECTRIC & GAS COMPANY ANALYSIS OF POTENTIAL 230-kV CABLE SYSTEMS AS ALTERNATIVES TO PROPOSED OVERHEAD LINES FOR THE NORTH CENTRAL RELIABILITY PROJECT REPORT MAY 19, 2011 . Prepared by Power Delivery Consultants, Inc. Ballston Lake NY Jay Williams 518 384‐1300 Page 0 PDC Transmission and Distribution Systems PUBLIC SERVICE ELECTRIC & GAS COMPANY ANALYSIS OF POTENTIAL 230-kV CABLE SYSTEMS AS ALTERNATIVES TO PROPOSED OVERHEAD LINES FOR THE NORTH CENTRAL RELIABILITY PROJECT REPORT MAY 19, 2011 TABLE OF CONTENTS 1.0 2.0 3.0 INTRODUCTION .................................................................................................................................. 2 ROUTE CONDITIONS ........................................................................................................................... 2 CABLE TYPE AND SIZE ......................................................................................................................... 3 3.1 Cable Type................................................................................................................................ 3 HPFF Cables........................................................................................................................................................... 3 Extruded-dielectric Cables...................................................................................................................................... 5 Self-contained Fluid-filled (SCFF) Cables ............................................................................................................. 6 4.0 5.0 5.0 6.0 7.0 8.0 3.2 Cable Type for North Central Reliability Project .................................................................... 7 3.3 Cable Size ................................................................................................................................ 8 INSTALLATION CONSIDERATIONS ........................................................................................... 8 4.1 Trenching ................................................................................................................................. 8 4.2 Manholes................................................................................................................................ 10 4.3 Cable Sheath Bonding............................................................................................................ 10 4.4 Terminations .......................................................................................................................... 10 CABLE INSTALLATION ............................................................................................................... 10 ENVIRONMENTAL CONCERNS ................................................................................................. 11 OPERATIONAL CONSIDERATIONS........................................................................................... 12 INSPECTION AND MAINTENANCE ........................................................................................... 12 COSTS.............................................................................................................................................. 13 Page 1 PDC Transmission and Distribution Systems PUBLIC SERVICE ELECTRIC & GAS COMPANY ANALYSIS OF POTENTIAL 230-kV CABLE SYSTEMS AS ALTERNATIVES TO PROPOSED OVERHEAD LINES FOR THE NORTH CENTRAL RELIABILITY PROJECT REPORT MAY 19, 2011 1.0 INTRODUCTION Public Service Electric & Gas Company (PSE&G) is proposing the upgrading of existing 138‐kV overhead lines to 230 kV, which involves using some existing structures, replacing other existing structures, and adding new structures as required. PSE&G requested Power Delivery Consultants, Inc. (PDC) to evaluate the potential cable options for this project. The length considered for undergrounding would be approximately 24.5 miles. The overhead lines will have steady‐state power transfer capability of 800 MVA and a cable system would be required to meet this capacity. PDC evaluated the cable system types that could be considered for this application, determined the cable size that would be required to match the ratings of the overhead lines, and prepared an analysis of the planning, construction, operation, and maintenance requirements for the a 230‐kV underground cable system. 2.0 ROUTE CONDITIONS The cable would follow the existing overhead line right‐of‐way for the full length. A summary of the route characteristics taken from the NCRP Siting Study Report, along with comments on installation implications, is given below. Portions of the route have high rock content and rock outcroppings, making excavation very slow and costly, and perhaps requiring blasting There would be approximately 115 road and railroad crossings, many of which may require horizontal auger boring or other trenchless installation methods The route has approximately 40 stream and river crossings, which can be very time consuming and costly for a buried cable system. The Passaic River crossings would Page 2 PDC Transmission and Distribution Systems require large horizontal directional drills, which need large staging areas on either side of the river, and which are very slow and costly. 3.0 CABLE TYPE AND SIZE 3.1 Cable Type Three types of cable could be considered for 230‐kV systems: High‐pressure fluid‐filled (HPFF) pipe‐type cable Cross‐linked Polyethylene insulated extruded‐dielectric (ED) cable (commonly called XLPE cable) Self‐contained Fluid‐filled (SCFF) cable Three other cable types exist, but are not considered suitable for this application: High‐pressure gas‐filled cable and ethylene‐propylene rubber (EPR) cables are only available for voltages through 138 kV. Compressed gas‐insulated cables, also called gas‐insulated lines (GIL) are available at 230 kV and higher voltages, but these systems are large and expensive, not amenable to burial, and are used almost exclusively for above‐ground applications on utility property. Descriptions of the three viable cable types are given below. HPFF Cables HPFF cables have been the dominant transmission cable type in the United States from the 1940’s through the start of this century. PSE&G has many HPFF cable circuits in urban areas. In the last five years, the number of miles of extruded‐dielectric cables worldwide has overtaken that of HPFF cables for new installations, primarily because of higher power transfer and the simpler accessories (splices and terminations) and the absence of dielectric liquid and the associated pressurizing plants. However, many miles of pipe‐type cables are still being installed at voltages through 345 kV. HPFF cables are insulated with helically‐wrapped Kraft paper or laminated paper‐polypropylene (LPP) tapes impregnated with high‐viscosity synthetic dielectric liquid. Stainless steel skid wires are wound helically around the cable to reduce friction between the cables and the pipe wall during cable installation. Three phases are drawn simultaneously into a mild steel pipe, typically 8.625‐in. OD, which has a high‐quality corrosion coating and is provided with cathodic protection to reduce the chance of corrosion. The space between cables and pipe is filled with a low‐ viscosity synthetic fluid (alkylbenzene or polybutene) which is pressurized to a minimum of 200 psig to improve the electric strength of the cable insulation. The use of LPP insulation in place of Kraft paper allows a reduced insulation wall and cable pipe diameter and an improved power Page 3 PDC Transmission and Distribution Systems transmission capacity. LPP is used for all new 345‐kV HPFF cable, and for most new 230‐kV HPFF cable. A fluid pressurizing plant is required at least at one end of a HPFF cable system to accept fluid expansion and contraction with temperature changes. The plant contains a reservoir tank that would be sized at about 10,000 gallons for the potential NCRP cables, plus pressurizing pumps, relief valves to maintain proper pressures, alarms, and controls. They are typically housed in an insulated enclosure resembling a large outdoor cooler. Dimensions are typically about 12 ft wide, 12 ft high, and 25‐40 ft long depending upon the size of the reservoir tank. Figure 3.1 compares the sizes of 345‐kV Kraft paper and LPP insulated HPFF systems with equal power transmission ratings. The left pipe is 10.75 in. OD, and the right pipe is the 8.625‐in. OD (the size that would be used for the North Central Reliability Project). At 230 kV, the Kraft paper insulation thickness would be about 0.605 inches and the LPP insulation thickness would be about 0.500 inches. The 230‐kv cable would be installed in an 8.625‐in. OD steel pipe. Figure 3.1 – 345‐kV Kraft paper and LPP HPFF cables (EPRI “Green Book”) The service record of HPFF cable has been good. A common‐mode failure typically in the splice area, thermo‐mechanical bending (TMB), has caused many outages on 230‐kv and 345‐kV cables. Splices were rebuilt with additional mechanical supports, and many miles of cable were replaced with a more TMB‐resistant cable, essentially eliminating this problem. TMB problems have appeared in the cable length between splices for both 230‐kV and 345‐kV cables. PSE&G has undertaken a major cable replacement project because of these failures. Page 4 PDC Transmission and Distribution Systems A few utilities in major metropolitan areas had many fluid leaks (with the number greatly reduced after careful attention to the corrosion protection system). Most leaks have been due to dig‐in, damage to corrosion coating when other subsurface utilities have been installed, or burn‐through due to a cable electrical fault. Extruded-dielectric Cables Extruded‐dielectric cables, also known as solid‐dielectric cables, use cross‐linked polyethylene (XLPE) insulation for 230‐kV operation. (Ethylene‐propylene rubber, EPR, is used up to 138 kV.) Transmission‐voltage extruded‐dielectric cables have been used extensively in North America at voltages 138 kV and higher since the mid‐1980s, and they have seen extensive use overseas since the 1970s. The first 230‐kV installation in the United States was in 1992, and California utilities have installed hundreds of circuit miles of 230‐kV XLPE cables in the last five years. Individual single‐phase cables are typically installed in PVC ducts, in concrete‐encased ductbanks for city street installation. Although direct burial might be permitted in rural installations, there are very few directly buried systems in this country. Figure 3.2 shows a typical XLPE‐insulated cable. The XLPE insulation thickness is about one inch for 230‐kV operation. A lead or aluminum sheath, sometimes with additional copper or aluminum neutral wires, is used to prevent moisture ingress and carry fault currents. Page 5 PDC Transmission and Distribution Systems Figure 3.2‐ XLPE‐insulated cable (courtesy of Silec Cable). XLPE‐insulated cables are significantly larger and heavier than pipe‐type cables. Typical length between splices is shorter – 1800 feet versus 2500 feet. XLPE‐insulated cables do not have the long service history that HPFF cables do, but experience to date has been good. PSE&G has installed only short sections of XLPE‐insulated cable in substations and other controlled areas. Self-contained Fluid-filled (SCFF) Cables SCFF cables have seen extensive service worldwide in EHV ac transmission systems. The construction of SCFF cables is similar to that of an HPFF cable in that both employ a laminar dielectric, which can be either Kraft paper or LPP tapes, impregnated with a dielectric fluid that is maintained under pressure to improve its electrical strength. There are, however, several important differences as follows: The conductor has a central duct to allow the dielectric fluid to reach the taped insulation. During the expansions and contractions which accompany load variations, the fluid flows along the conductor duct to and from special fluid reservoirs via feed joints at Page 6 PDC Transmission and Distribution Systems intermediate points along the line. Very long lines have large pumping plants near the terminations at one or both ends of the line. The insulated conductor is contained in a metallic sheath that can either be corrugated aluminium or lead reinforced with metal tapes to resist the internal fluid pressure. The fact that this sheath is an integral part of the cable construction rather than a separate pipe is the origin of the term “self‐contained”. The metal sheath is provided with a high‐grade extruded polymeric jacket as protection against corrosion. This is most frequently a medium or high‐density polyethylene with a 2% addition of carbon black as a protection against UV deterioration. Figure 3.3 shows a typical SCFF cable. Figure 3.3 ‐ SCFF cable with corrugated aluminium sheath SCFF cables are used extensively for submarine cables laid on the water bottom or trenched‐in to the water bottom. Use for new land installations is uncommon; applications that were historically installed using SCFF cables now use XLPE‐insulated cables. We therefore did not evaluate SCFF cables for the North Central Reliability Project. 3.2 Cable Type for North Central Reliability Project A detailed analysis of the advantages and disadvantages of HPFF cable versus XLPE‐insulated cables, including relative costs, should be performed if the cable option were pursued further. Page 7 PDC Transmission and Distribution Systems However, based upon general characteristics and cable availability, we believe that an XLPE‐ insulated cable would be the preferred option – primarily because its electrical characteristics are better for system operation, its power rating is higher, and its maintenance requirements are lower. There are two suppliers of this cable in the United States, and another dozen suppliers overseas. 3.3 Cable Size PSE&G requires an 800‐MVA steady‐state power transfer on the cable system. PDC performed ampacity calculations to size the cable for assumed installation conditions. We determined that a 2500 kcmil, copper conductor, XLPE‐insulated cable should be adequate, with two cables per phase required to provide the 800 MVA transfer. 2500 kcmil is a common conductor size for these cables. For the one month or longer it would take to repair a cable failure, the remaining circuit would be able to carry about 565 MVA. This is larger than half of 800 MVA since the out‐of‐service cable would not be generating heat that would de‐rate the in‐ service cable. The physical size of each cable would be about 4.5 inches outside diameter. The weight would be about 20 pounds per foot, for a single cable. If the underground line were to proceed to detailed analysis, accurate rating studies may determine that a larger conductor size is required – e.g. for installations through swampy areas, to dip under existing services at street crossings, in deep horizontal directional drills, etc. 4.0 INSTALLATION CONSIDERATIONS 4.1 Trenching Figure 4‐1 shows a cross‐sectional view for a typical trench for these cables. The figure shows a concrete‐encased ductbank which is the preferred method for installing high‐voltage XLPE‐ insulated cables. Direct burial, which is slightly less expensive, might be feasible on a right‐of‐ way, but direct burial has significant disadvantages: If the cable has an electrical failure, the exact failure must be located, excavation performed, and repairs made at that location (for cable in a duct‐and‐manhole system, a failure is located within the 1500‐2000 foot section between manholes, and the entire section is replaced) If the cable ever has to be replaced, because of a design problem with the cable, need to reconductor to increase power transfer, etc., the entire length of the circuit must be re‐ Page 8 PDC Transmission and Distribution Systems excavated. For a duct‐and‐manhole system, the cable is replaced from manhole‐to‐ manhole with no need for excavation. Figure 4‐1. Typical trench cross‐section for 230‐kV XLPE‐insulated cable Every foot of the transmission cable route would have to be trenched, or more complex trenchless methods such as horizontal directional drilling would be used. A temporary construction road would be required along the length of the cable route; this would need to be a substantial road because it would need to carry heavy loads such as large excavation equipment, concrete trucks, tractor‐trailers with 80,000 lb manholes and 50,000 lb cable reels, etc. The cable lines would cross several creeks, highways, and railroads, where a trenched installation may not be permitted. Trenchless installation, such as horizontal auger boring, would be required. Horizontal directional drilling would be required for the crossings of the Passaic River. All of these trenchless methods are time consuming and expensive, and they carry a high risk. The route has extensive wetlands, which create substantial problems for an underground cable since it is generally not permitted or technically feasible to bring heavy equipment through the wetlands to install the cable. Horizontal directional drilling can bridge some wetlands, but the maximum feasible length is about 3,000 feet. Longer lengths through wetlands would probably require re‐routing the cables. Page 9 PDC Transmission and Distribution Systems Substantial portions of the potential cable route have high rock content and steep elevation changes, which make trenching and cable installation difficult and very costly. 4.2 Manholes Cable splices are placed in manholes, to provide a working space for the week or so it takes to splice cable sections together, and to allow access for maintenance. A manhole for a 230‐kV XLPE cable would be approximately 28 feet long, 8 feet wide, and 7 feet high and would weigh about 100,000 pounds (they are supplied to the job site in two sections). Only one of the two lines is permitted per manhole, to allow workers to safely repair an out‐of‐service line while the other one remains energized. Therefore, a 25 mile line would require approximately 130 of these large concrete structures. 4.3 Cable Sheath Bonding The currents flowing in the cable conductor can induce high voltages in the cable sheath. Although the cable jacket should protect the public from these voltages, utilities normally limit the voltages to a few hundred volts to provide protection to utility workers. An elaborate scheme to connect the cable sheaths in a method known as cross‐bonding can reduce the voltages to tolerable levels, but each splice location must have small surge arresters to protect the sheaths from overvoltages, and they are contained in a waterproof “link box” to allow reconnection and testing of the arresters and the cable jackets. These link boxes can be placed in a separate small manhole adjacent to the splicing manhole to allow easy access. 4.4 Terminations The terminations, which connect the cables to overhead bus, resemble transformer bushings and would be about 9.5 feet tall. They would be placed on steel structures in PSE&G substations or switching stations. Six of these terminations would be required at each location. 5.0 CABLE INSTALLATION The 230‐kV XLPE‐insulated cables would be provided on steel reels, with individual cables on individual reels, weighing approximately 50,000 pounds each. Special winches would be set up at one manhole, and the cable pulled from an adjacent manhole to the location with the winch. Once cable installation from both sides to the manhole is completed, the cables may be spliced together. Splicing is typically performed around the clock in the manhole, and the air is conditioned to maintain low humidity and clean conditions. Three splices for one of the lines would take about a week using highly trained and skilled splicers. Page 10 PDC Transmission and Distribution Systems Termination installation also requires extremely clean, dry conditions. Each termination would take one to two days to complete. There are several firms that have experience in installing these cables in the ducts and manholes, but splicing and terminating are typically performed by technicians from the cable supplier. 6.0 ENVIRONMENTAL CONCERNS Underground cable construction generally has more environmental intrusion than overhead line construction, for several reasons: Every foot of the route length must be excavated, or dug by trenchless means. Common construction concerns such as equipment movement, dust, noise, etc. will be a problem along the entire route. It is generally not possible to cross wetlands, creeks, rivers, highways, etc. by open trenching. If wetlands are present, they may be spanned by horizontal directional drilling if the length is less than a few thousand feet. If the length is longer, alternate routes must be found unless approval is granted to cross the wetlands. Since every foot of the length is trenched or otherwise excavated, the chance of encountering contaminated soils is higher than for tower foundations for overhead lines. Horizontal directional drilling requires a great deal of equipment, and requires using a “drilling mud” that has the possibility of forcing its way to the surface in undesired locations Blasting may be required for substantial distances, especially if there are rock outcroppings A cleared area at least 50 feet wide is required the full length of the line to move equipment and materials, perform trenching, assemble duct, etc. An access road must be built along the entire length of the cable system. The road must be capable of supporting multiple trucks with weights approaching 100,000 pounds. Construction equipment and crews must be present for long periods of time – “a mile a month” is sometimes stated as a rule of thumb for installing the cable system. Equipment and personnel must be at manhole locations for additional time, to fabricate splices Although underground lines are not visible after construction, there are still environmental concerns: Page 11 PDC Transmission and Distribution Systems An access road is required along the route, for maintenance and possible repair operations. Personnel must travel to every manhole periodically for inspection of splices and link boxes. Woody vegetation is not permitted within ten feet of the cable trench The temperature at the earth’s surface is elevated several degrees above that of the surrounding area Magnetic fields right above the cable trench can be higher than those of overhead lines, but they attenuate more quickly with distance from the trench. 7.0 OPERATIONAL CONSIDERATIONS The electrical characteristics of underground cables are different from those of overhead lines, which can cause problems in system operation. Differences include: Cables are long distributed capacitors. The cable capacitance reduces the allowable flow of real power (MW), can cause instability in system operation, and cause overvoltages that may damage system components such as transformers. Cables of the ~24.5 mile length of the North Central Reliability Project can have reactive power levels high enough to require shunt reactors (device resembling large transformers) at the substation ends to control the reactive power. These shunt reactors have high electrical losses, and historically have not had a good reliability record. Utilities typically re‐close on an overhead line because most faults are transient. Re‐ closing on a circuit that contains an underground cable is not recommended since cable faults are permanent, and re‐closing can cause significant additional damage to the cable system – including launching manhole covers if the fault is in a splice. Utilities must plan on a failed cable being out of service for a month or longer, and must therefore make alternate provisions for power transfer until the cable is repaired. 8.0 INSPECTION AND MAINTENANCE Inspection and Maintenance requirements for underground cables are higher than those for overhead lines. The following maintenance items should be performed for XLPE‐insulated cables: Weekly substation walk‐through, to check for cracked insulators on the terminations, or leaks of insulating fluid from the terminations. Bi‐weekly patrol of the cable route, to look for any construction activity that might affect the buried cables Page 12 PDC Transmission and Distribution Systems Check of the sheath voltage limiters (the small surge arresters) in the link box, any time there is a fault on the cable or a through‐fault on the transmission line. If the link boxes are located in the manhole (the preferred location since leads from the splice to the link box should be as short as possible), then the manhole must be pumped of water and a safe atmosphere established before workers can enter. Jacket integrity test and check of link box connection and sheath voltage limiters every three years. These tests would require an outage for a week or longer depending upon the number of crews available. Manhole integrity would be checked at this time. Maintenance of the right‐of‐way to allow vehicle access along the full length and to insure no woody vegetation grows too close to the cable trench 9.0 COSTS AND SCHEDULE It is not possible to develop even a study‐grade cost estimate (accurate to +/‐ 25%) without detailed analysis of the route, evaluation of the amount of rock blasting, number of horizontal auger bores or horizontal directional drills, access road requirements, etc. Cost ratios depend upon the overhead line costs as well as underground line costs (i.e. the cost of UG to OH may vary by a factor of two or three for the same underground cost, depending upon the cost of overhead construction.) Cost ratios are often stated as 5‐10 to 1, with published values as high as 20/1 (CIGRE 2004). An underground project of this magnitude could typically be constructed in two to three years, after permits are in place and engineering design is completed. 10.0 CONCLUSIONS Underground cables are technically feasible for this 230‐kV application. Cross‐linked polyethylene (XLPE) cables would be the preferred cable type. However, route conditions would make cable installation very costly, disruptive, and time‐ consuming. Having these cables on the system would create operational difficulties for PSE&G that would not be present with overhead lines, and power transfer could be severely curtailed for longer than a month if there were a cable failure. Page 13
