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Electric Powered Compression: A Viable Approach For Meeting New Pipelines.

Growth in the U.S. pipeline industry follows the classic economic drivers: sustained demand served by a reliable supply. "Reliable" within the context of gas transmission and storage compression incorporates risk-related properties such as flexibility, availability, predictability and other characteristics that equate to "few surprises".

A recent article in P&GJ[1] focused on risks compressor operators could expect to encounter in meeting the projected 30 TCF annual demand for natural gas being forecast. In the article, four key emerging issues were identified:

* Meeting challenging service requirements of the new customers that will be dominating incremental gas demand.

* Achieving a high level of service in the face of continuing competitive market pressures.

* Developing least cost responses to pending or prospective environmental regulations.

* Developing a new generation of skilled dedicated employees.

When electric power cost and availability permit, electric motor-driven gas compression or the "electric option" can mitigate many of these risks. New pipeline demand and load profiles can be better served due to the inherent flexibility of the compressor drivers. Availability is enhanced and operating and maintenance costs are reduced through less complicated machinery and associated control systems. Adverse impacts on construction schedules and the attendant costs of installation are reduced through fewer issues influencing the environmental permit process. Finally, new technology associated with the electric option offers challenging and rewarding work to those responsible for the operation and maintenance of the compressor station. This article explores the relationship between the emerging challenges facing the pipeline industry and the potential benefits of using motor-driven compression.

Based upon publicly available data, there are more than one million horsepower of electric motor-driven compression operating in natural gas service in the United States and Canada. Much of this horsepower has been installed over the past ten years. Although, the product transported is slightly different, virtually all the pumps on liquid pipelines are powered by electric motors which attests to the reliability and efficiency of the prime mover technology. The electric option is not only conceptually viable but has a proven track record that justifies serious consideration as an alternative for reliably powering the pipeline.

There have been many excellent, published articles and papers[2] which concern the role the electric option has played and is playing in gas transmission and storage applications. These publications have explored many factors concerning the technology, the advantages of which may be summarized as follows:

* Gas transmission system efficiency is improved.

* Station power output is relatively insensitive to ambient conditions.

* There is a potentially broader range of compressor operation possible due to improved and extended compressor speed control and quicker response to load changes.

* Operating and maintenance labor and expenses are significantly reduced.

* Capital costs can be significantly reduced.

* Site-specific environmental impacts are practically eliminated.

The relationship between these factors and the four challenges described at the beginning of this article have convinced some pipeline operators to employ the electric option to meet new demand, or to re-power existing facilities to serve current loads. Significant changes in the array of compression equipment, now available to the operator, justify a closer look at the unique characteristics of all types of compression machinery. Some pipeline operators may perceive the electric option viable only when environmental issues such as emission limits, clearly preclude the use of internal combustion prime movers, and/or when the electric power rate is less than "x" cents per kWh. While these two parameters represent real concerns, a more complete analysis may yield some surprising results that could swing the decision toward the electric option even if the power rates were higher, or the environmental issues were minor.

Options Have Changed

The options available to pipeline operators for compression equipment have changed over the past decade. Manufacturers of low-speed integral reciprocating engines significantly reduced their product offerings primarily due to reduced demand. This was the result of the relatively high capital costs for installation and the relatively high labor and material cost for operation and maintenance.

Occasionally, medium to high-speed separable units consisting of a gas-fueled engine connected to a reciprocating compressor frame are selected to replace the low-speed integral units. This solution is generally employed when: a) the operating conditions favor reciprocating compression, e.g. high compression ratios; b) a lower capital cost solution is required; or c) the operator favors reciprocating compressors due to familiarity and experience. Although the separable units are less costly to install, the higher speed can translate into higher operating and maintenance costs when compared to their low speed counterparts unless sufficient design margin has been incorporated into the engine, compressor, and auxiliary components. In some instances, a separate reciprocating prime mover can be connected through a speed increaser to a centrifugal compressor, but those applications are limited due to cost and complexity.

Continued development of the gas turbine powered compressor has been more responsive to market demands in terms of capital cost, size, operating efficiencies, and emission levels. Since nothing is free, however, the new generation of high efficiency, high output gas turbines operating at higher combustion pressures and temperatures requires exotic and costly metallurgy. This in turn requires a higher level of operating and maintenance attention to ensure the machine is operating within its design parameters. Turbine engine overhauls and periodic updates of materials comprising the combustion and rotating components can be very costly. Also, because of higher thermal stresses, frequent start/stop cycles can reduce the time intervals between inspections and overhauls.

Various compression machinery offerings using an electric motor as the prime mover have grown over the past ten years. Historically, motors driving reciprocating compressors through a direct connection, or driving centrifugal compressors through speed increasers, have been the typical machine configurations. Recent improvements in high-speed induction motor technology now allow for direct connection of a motor to a centrifugal compressor without requiring a speed increaser. Variable frequency drives and variable speed hydraulic couplings now affect a wider range of motor/compressor speed variation, thus expanding the operating range of the compressor. Finally, development of a machine where the motor is directly connected to the compressor and both components operate within a pressure vessel has proved to be a viable alternative to conventional compression arrays. This configuration not only eliminates the need for gas seals, but also affords the use of magnetic bearings, which in turn eliminates the lubrication system for both motor and compressor.

Evaluation Of Alternatives

Once an operator becomes comfortable with the prospects of motor-driven compression, the analysis of machine options requires a few new approaches to fairly evaluate the alternatives; particularly in the context of the challenges described at the beginning of this article.

The following discussion focuses on qualitative relationships between gas fueled and electric powered compression in the context of these challenges. It is up to the operator to evaluate both the cost and benefit of these factors.

Improvement In System Efficiencies

The amount of energy required to compress a volume of gas may be thought of as a "system efficiency" (expressed in terms of Btu/MMcf/d compressed). Components of this efficiency are: Btus of fuel energy BHP/hr of work developed by the power end, multiplied by the BHP/hrs required by the compressor to compress a million cubic feet of gas at a specific compression ratio. In the case of motor-driven compression, a different view of the "system" should be taken. A gas fueled electric power generation unit generally has a higher thermal efficiency than a gas fueled prime mover for a compressor, principally clue to size and the employmemt of waste heat recovery in power generation applications. For this reason, a cubic foot of fuel gas is more efficiently utilized through combustion in an electric power generation unit, and subsequent conversion to shaft work by an electric motor. This relationship holds even when factoring in electrical transmission losses and voltage conversion efficiencies. Also, the reduced need to transport compressor fuel frees up pipeline capacity, which can be utilized for incremental growth.

For low speed engine driven reciprocating compressors, the prime mover thermal efficiency is relatively high, and within the design range of the compressor, the compression efficiency is equally high. For medium/high speed engine driven reciprocating compressors, the prime mover thermal efficiency is relatively high and the compression efficiency can range from low to moderately high depending on the compressor cylinder design and the rotational speed. For gas turbine driven centrifugal compressors, the prime mover efficiency is moderate to high depending on cycle efficiency and the compression efficiency can range from low to high depending on the compressor wheel design and the operating pressure range.

For direct connected motor-driven reciprocating compressors, the prime mover thermal efficiency is very high based on electric power generation and electric transmission system efficiencies, and the compression efficiencies are similar to their gas engine driven counterparts. For direct connected motor-driven centrifugal compressors, the prime mover efficiency is similar to the unit described above, and the compression efficiency is comparable to the turbine driven counterparts. When speed increasers are installed between the motor and compressor, the losses associated with these components diminish the overall system efficiency.

Power Output Insensitive To Ambient Conditions

The power output of gas fueled prime movers is influenced by the mass flow of combustion air, which in turn is dependent upon combustion air temperature. As the air temperature increases, the mass flow decreases. Within the limits of the motor winding design, the electric motor-driven units are virtually insensitive to ambient temperature variations. There is no capacity reduction in the late spring and summer seasons when gas demand from power plants may be at maximum levels.

Gas turbine driven prime movers have the largest variation of power vs. ambient temperature above and below the 15 [degrees] C (59 [degrees] F) rating point. Gas turbine power development, being inversely proportional to ambient temperature can range from 80 percent of rated at ambient temperatures over 100 [degrees] F, to 125 percent of rated at 0 [degrees] F. Depending on the design of the turbine, there is a temperature below which the power level remains flat.

Turbocharged, 2-cycle and 4-cycle reciprocating engines have a moderate level of power variation, and naturally aspirated 4-cycle engines are the least sensitive of the gas-fueled units to ambient temperature variations. Some turbocharged units can develop up to 124 percent of rated power at ambient temperatures less than 40 [degrees] F. However, their output falls below rated at temperatures greater than 80 [degrees] F. Naturally aspirated units are rated at 100 [degrees] F ambient temperature, so their output capability is reasonably stable up to that level.

Broader Range Of Compressor Operation

The ability to vary the speed of the gas compressor over a wide range optimizes gas dispatch by more closely matching compressor output to market demand. Centrifugal compressor speed range is the greatest with electric motor-driven units fitted with either a VFD (Variable Frequency Drive) to control motor speed, or an adjustable hydraulic coupling to control compressor speed. For motor-driven reciprocating compression, the use of compressor clearance control may be an appropriate alternative to speed control, or depending on the application, may complement speed control.

Control of centrifugal compressors to 60 percent of rated speed can add a large dimension of flexibility, and can keep the unit operating at optimum efficiency as long as the head and flow conditions are within the compressor's design envelope. The need to take a motor-driven unit off line during periods of low demand is reduced, thereby stabilizing the operation of the pipeline.

The ability to reduce the speed of a gas turbine is somewhat limited, but generally a 20 percent reduction is achievable with split-shaft machines. This translates to an approximate 50 percent power reduction.

Turbocharged, reciprocating engines are generally limited to a 20 percent speed reduction, and naturally aspirated reciprocating engines are generally limited to a 40 percent speed reduction.

The time required for a motor-driven centrifugal compressor with magnetic bearings and dry gas seals to go from a dead stop to full power is generally less than three minutes. This is significantly shorter than engine or turbine driven machines that require additional time to establish lubrication, and achieve thermal stability before the load can be applied. Also, frequent start/stop cycles do not pose the same potential problems for motor-driven equipment as they do for engine or turbine driven equipment due to the motor's high tolerance for thermal cycling, and significantly fewer auxiliary systems involved with starts and stops.

Reduced Operating And Maintenance Expenses

The non-energy operating and maintenance cost component of a motor-driven compressor is the lowest of all alternatives. The primary reasons are fewer moving parts and minimal auxiliary systems. Based on industry statistics, Table 1 provides an order-of-magnitude relationship between non-energy operating expenses, and maintenance expenses for the compression alternatives. In both cases, expenses include labor and materials and supplies. As always, individual company records of these costs should be used, if available.

Table 1. Relative Operating (non-energy) and Maintenance Costs
Compressor Type ($/1000 BHP-HRS)

Separable, Gas Engine
Driven Reciprocating 34.2

Integral, Gas Engine
Driven Reciprocating 17.4

Gas Turbine
Driven Centrifugal 13.7

Reciprocating/Centrifugal 8.5

Reduced Capital Costs

Aside from the cost of extending the electric power line to the station site, constructing the substation and installing the switchgear, the cost of installing a motor-driven compressor unit can be significantly less than its engine or turbine driven counterparts. The scope of work for a motor-driven compressor is much less, beginning with the physical size of the property needed to establish a sound buffer area and extending to the size of the building, the design of the foundations and all the other structural elements. Depending on the type of compressor selected, oil, water and auxiliary system piping can be drastically reduced.

Reduced Environmental Impacts

One of the more obvious attributes of the electric option is the opportunity to install a truly benign facility in terms of environmental impact. The ability to transfer combustion process emissions from the compressor station to the power plant is well known. However, there are other potential environmental benefits of the electric option as well.

Sound levels from the air inlet as well as the exhaust systems of both engines and turbines must be within regulatory limits. While the sound levels can be attenuated to varying degrees with bolt-on equipment, the degree of silencing may or may not consistently meet the requirements due to degradation of the silencing equipment. Also, passive silencers create power loss due to pressure drops. With motor-driven equipment, increases in property line sound levels can be imperceptible due to the ability to contain all the machinery sounds within an enclosure.

If motor-driven equipment with magnetic bearings and dry-gas seals is chosen, the need for lubricant and waste oil storage and disposal, and the attendant potential for a spill is eliminated.

Finally, the overall appearance and presence of the compression facility from a community perspective can be better disguised with motor-driven equipment since there are fewer projections of equipment beyond the building walls.

Developing A New Generation Of Skilled Employees

The on-going exodus of a skilled, field-labor workforce is something that operating companies must continue to address. Fortunately, persons with basic mechanical skills who are comfortable with the fundamentals of electricity and computer-based control systems can handle a large measure of the work required to support a motor-driven compressor. Centrifugal machines with dry gas seals and magnetic bearings do not have lubrication and seal oil systems, so a great deal of complex mechanical and piping systems are eliminated. If a motor is used instead of a reciprocating or gas turbine prime mover, a myriad of specialized engine or turbine auxiliary systems are eliminated. It should be easier to attract new employees who are comfortable with computerized control systems than someone who is familiar with heavy machinery, turbochargers, ignition and combustion systems, or air/fuel control equipment.


While the cost and availability of energy and the emissions issues play a large part in any compressor unit selection process, the items discussed in this article should be given strong consideration in view of the projected operational challenges. For example, what is the value to the customer of being able to see the effects of a compressor unit online and operating at full power in 5 minutes or less? Once on line, what is the value of being able to operate at power levels between 20 percent and 100 percent, regardless of ambient temperature? Is there an advantage to operating for a few hours when customer demands are high, or energy costs are low; shutting down when opposite conditions occur, and repeating the cycle a number of times in 24 hours without machine damage? What are the financial benefits of being able to construct a compressor station in a community setting without facing complex issues of vibration or noise, surface pollution, or aesthetics? Finally, what is the value of having compression equipment, which can be highly automated, yet offer challenging and meaningful work to newly hired station personnel? These questions would not have been nearly as important 10 years ago but they are now. Utilities and contractors making the decisions to install compression equipment for 20 plus years of service must consider the new operating environment.

[1] Michael P. Whelan, Gas Research Institute, "Issues for Compressor Station Operators: Year 2000 and Beyond," Pipeline and Gas Journal, June 2000.

[2] John C. Rama and Albert Gieseke ,Robicon Corp. "High Speed Electric Drives: Technology and Opportunity," 1995 IEEE IAS Petroleum and Chemical Industry Conference. Note: this paper incorporates references from 25 additional sources.

[3] PRCI Report #15-9529, "Compressor Station Maintenance Costs," Prepared for PRCI by Southwest Research Institute.

[4] EPRI Report CR-106689, "Megadrive Model for Evaluating Gas Compressor Drive Options."

[5] FERC Form 2 data from selected compressor stations, 1997 and 1998.


K. Frederick Wrenn, Jr has over 40 years experience in the natural gas transmission industry, with principal involvement in gas compression. After retiring from Columbia Gas Transmission Corp in 1998 as a Field Services Vice President, he established Wrentech Services, LLC in Charleston, West Virginia to provide technical services to the energy industry. He is a co-founder of the EPRI Gas-Electric Partnership, past member of the PRCI Compressor and Executive Committees, and a current member of ASME B31.8 Gas Transmission and Distribution Piping Systems Code Committee. He has a degree in Mechanical Engineering from the University of Cincinnati and is a registered Professional Engineer.
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Comment:Electric Powered Compression: A Viable Approach For Meeting New Pipelines.
Author:Wrenn, K. Frederick Jr.
Publication:Pipeline & Gas Journal
Geographic Code:1USA
Date:Oct 1, 2000
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