Transporting electricity as virtual energy

Transporting electricity as virtual energy

Schmeal, W Richard

Utilities find ways to partner for improved service

Once competitors with longstanding biases against one other, the natural gas and electric industries are joining forces to efficiently meet customer needs while improving the environment.

This convergence was prompted by a restructuring mandated in Federal Energy Regulatory Commission (FERC) orders such as 636 and proposed order 888. The restructuring has led to increased electric compression technology use on gas pipelines, which improves energy efficiency and reduces environmental impact in transporting gas to customers.

Electricity typically cannot be stored efficiently. But natural gas can be compressed and decompressed to store in pipelines. Combining electricity with a gas system, electric compressors, using gas to generate power, can move electricity in the gas pipeline as “virtual energy.”

In the past, the pipelines used the gas that is transported in the pipe to power the compressors. More than 4% of natural gas produced has been used this way.

Electric compressors are more efficient than gas compressors, even when considering energy losses in power generation. Also, electric compressors may be operated primarily during off-peak times of day or seasons, when electric generation prices are lowest.

Electric compression

Pipelines travel thousands of miles from oil and gas fields in Alberta, Canada, Texas and its neighboring states to California, the Midwest and Northeast. Besides heating homes and providing heat and power for industry, natural gas is used to generate electricity.

More than 16 million hp of operating compression exists on the interstate pipeline network. The total compression used by the U.S. natural gas industry is more than double this amount of horsepower when the intrastate pipeline grid, gathering systems, processing plants and gas storage facilities are included. A large percentage of the compression that uses gas as fuel is nearing obsolescence and needs upgrading or replacement.

Thousands of horsepower are being installed in new compression facilities annually. Electric motors that power gas compressors have environmental advantages and can be less costly than conventional drives such as internal combustion engines or gas turbine drives. Electric-driven compressors offer:

* energy efficiency;

* ease of dispatch;

* the potential for zero emissions on site;

* little noise.

Adjustable speed drives allow motors to maintain high efficiency in various conditions. Motors can be operated from remote stations and adjusted for a range of operating conditions.

Efficiency benefits

Gas combustion engines or turbines that drive compressors have thermal efficiencies of 20% to 35%, which vary based on the model year and type of driver.

Large power generating plants convert fuel to useful energy at thermal efficiency rates of 40% to 55%. Electric motor drive systems produce applied horsepower at efficiency rates of more than 95%. Even with the combined efficiencies and transmission line losses, electric motor drive systems consume less energy to produce the same amount of gas compression as a gas combustion engine or turbine.

Electric motor-driven compression also provides more operational flexibility than gas combustion engine-drive or gas combustion turbine-drive compression systems. Electric motors can be operated remotely with minimal investment in control systems.

Maintenance benefits

Electric motor maintenance may be up to 75% less than for a comparable gas combustion engine and up to 60% less than a comparable gas combustion turbine. Electric motors require less variable-cost expenses as they may be cycled on and off without degradation, have fewer moving mechanical parts and require minimal lubrication. Also, few costs are incurred to stock an inventory of parts due to the simple mechanics of the electric motor.

When the electric motor is not being used, the unit-station control system may be programmed to periodically lubricate bearings and roll the motor, reducing fixed-cost manual labor. Some applications can use non-lube, magnetic bearings.

Maintenance of a gas combustion engine or turbine is more than that of an electric motor because they are complex mechanical devices that must be routinely exercised. Each time a unit is put through a start-up and shutdown heat cycle, thermal stresses degrade the driver.

An inventory of spare parts and specialty tools is costly due to the complex nature of gas combustion drivers. Manual labor is increased because the units must be continually lubricated and tuned-up to ensure reliability.

Capital benefits

Capital investment to install an electric motor driven compressor station is roughly 10% to 25% less than for comparable gas combustion engine or turbine driven compressor stations. The capital investment varies based on the operating company, type of station, redundancy of systems, site amenities, control and communication systems.

Environmental benefits

Natural gas combustion in engines or turbines produces carbon dioxide, volatile organic compounds and nitrogen oxides emissions. These emissions are not created by electric motors because they have no combustion sources. Noise and environmental problems are also lacking at the electric compression station site, which can ease and speed the permit process for faster project implementation.

The Rutledge Compressor Station of Columbia Gas Transmission Corp., Fallston, Maryland, houses three motor/compressor units in a building conforming to the architectural standards of its surrounding neighborhood. Vibration and noise are virtually eliminated by new technology, allowing nearby wetlands and neighbors to remain undisturbed.

Because magnetic bearings are used, there is no lube oil system and no problems with oil leaks or disposal. A side stream of discharge gas in the pipe cools the motor and magnetic bearings so there is no need for seal oil. The automated station can be operated from Charleston, West Virginia.

“Virtual energy” in pipelines

Gas may be converted to electricity at a power plant at the beginning of a pipeline and the electricity used for compression on the gas pipeline. This electricity is converted back to gas by displacement because no gas is needed for compression. The displaced gas is transported to market where it may be converted back into electricity.

Typically, electric utilities and natural gas pipelines have seasonal load profiles that peak at different times of the year. For many utilities, peak demand is in summer to meet air conditioning demands. In other areas, utilities also peak in the winter for heating. Natural gas pipelines generally peak in winter and have a transmission grid capacity to the northeastern United States designed for the three coldest days of winter.

Because the pipeline transmission systems are designed for winter peaks, they are used less the rest of the year and can serve as horizontal storage reservoirs. Gas pipelines use a pack-and-draft technique to create gas storage within the pipe. This technique is often used in winter to prepare for peak gas demand in early morning.

Compression is at a fully loaded condition throughout the night, compressing more natural gas than demanded, increasing systems pressures and storing the gas in the pipeline. In the early morning, the line pack is opened to release the stored natural gas and line pressures are reduced. Compression is adjusted for reduced loading, while other units may be idled or shut down.

Using pack-and-draft, gas pipelines can capture intra-day, basis or location price spreads between electricity and gas.

The electric compressor is finding its niche in gas transportation. It is often more energy efficient than gas drive alternatives and allows natural gas and electricity to be interchanged as “virtual energy.”

W. Richard Schmeal is natural gas program manager at EPRI Chemicals, Petroleum, Sr Natural Gas Center, 1800 St. James Place, Suite 303, Houston, TX 77056, USA; 713-963-9306, fax 713-963-9304, epricpc@ix.netcom com.

Copyright American Society of Agricultural Engineers Apr 1998

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