Market and Technology Assessment

Natural Gas Compressors

U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Building Technologies Program

December 17, 2014
TABLE OF CONTENTS

1. INTRODUCTION .................................................................................................................. 4

1.1 Authority and Background.................................................................................... 5

1.2 Compressors Under Consideration........................................................................ 5

1.2.1 Compressor Types........................................................................................... 7

1.2.2 Prime Mover Types......................................................................................... 8

1.2.3 Compressor Systems....................................................................................... 8

1.3 Equipment Definitions.......................................................................................... 9

1.3.1 Natural Gas Compressor Package ................................................................... 9

1.3.2 Compression Unit............................................................................................ 9

1.3.3 Prime Mover.................................................................................................... 9

1.3.4 Reciprocating Natural Gas Compression Unit................................................ 9

1.3.5 Centrifugal Natural Gas Compression Unit .................................................. 10

1.3.6 Axial Natural Gas Compression Unit............................................................ 10

1.4 Efficiency Metrics............................................................................................... 10

1.4.1 Compressor Unit Efficiency.......................................................................... 10

1.4.2 Thermal Efficiency........................................................................................ 10

1.4.3 Heat Recovery............................................................................................... 11

1.4.4 Gas Efficiency............................................................................................... 11

1.5 Test Procedures................................................................................................... 11

1.6 Rulemaking Analyses Process Overview............................................................ 12

2. MARKET AND TECHNOLOGY ASSESSMENT............................................................. 15

2.1 Market Assessment ............................................................................................. 15

2.1.1 Manufacturers Participating in U.S. Market ................................................. 15

2.1.2 Small Businesses........................................................................................... 16

2.1.3 Packagers and Installers................................................................................ 16

2.1.4 Trade Associations........................................................................................ 17

2.1.5 Regulatory Programs..................................................................................... 18

2.1.6 Nonregulatory Programs............................................................................... 20

2.1.7 Shipments and Value..................................................................................... 21

2.2 Technology Assessment...................................................................................... 24

2.2.1 Overview of Compressor Technologies........................................................ 24

2.2.2 Compressor Package Efficiency................................................................... 31

2.2.3 Compressor Losses........................................................................................ 33

2.2.4 Technology Options for Improving Efficiency............................................. 38

3. SCREENING ANALYSIS ................................................................................................... 45

3.1 Technological Feasibility .................................................................................... 45

3.2 Practicability to Manufacture, Install, and Service ............................................. 45

3.3 Adverse Impacts on Product or Equipment Utility or Availability..................... 45

3.4 Adverse Impacts on Health or Safety.................................................................. 46

APPENDIX A - LIST OF ITEMS FOR COMMENT............................................................... 47

APPENDIX B - REFERENCES................................................................................................ 51
LIST OF TABLES AND FIGURES

Figure 1.1 Schematic Diagram of a Typical Compressor Package ................................................ 7

Table 1.1 Overview of Currently Available Compressor Test Procedures .................................. 12

Figure 1.2 Flow Diagram of Standards Rulemaking Process...................................................... 14

Table 2.1 Major Gas Compressor Manufacturers......................................................................... 15

Table 2.2 Summary of Natural Gas Sector Compressor Activity................................................. 21

Table 2.3 Annual Compressor Station Compressor Package Shipments by Year........................ 22

Table 2.4 Annual Compressor Station Compressor Package Shipments by HP Range for 2009 to 

2013...................................................................................................................................... 23

Table 2.5 2012 North American Reciprocating Engine Orders.................................................... 23

Table 2.6 Typical Performance Ranges – Reciprocating Compressors1 ..................................... 25

Table 2.7 Typical Performance Ranges – Centrifugal Compressors1.......................................... 26

Table 2.8 Typical Performance Ranges – Reciprocating Gas Engines1,14................................... 27

Table 2.9 Typical Performance Ranges – Gas Turbines1,14 ......................................................... 28

Table 2.10 Characteristic Electric Motor Efficiency14 ................................................................ 28

Table 2.11 Representative Efficiencies of Various Compressor Technologies1 .......................... 32

Figure 2.1 Prime Mover Efficiency by Rated Horsepower ......................................................... 33
LIST OF ACRONYMS

AEC annual energy consumption 

AEO Annual Energy Outlook

ANSI American National Standard Institute 

API American Petroleum Institute

BLS Bureau of Labor Statistics

BT Building Technologies Program

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CFD computational fluid dynamic 

CFR Code of Federal Regulations

CO2 carbon dioxide

DOE U.S. Department of Energy

DOJ U.S. Department of Justice

EERE Office of Energy Efficiency and Renewable Energy

EIA Energy Information Administration

EISA Energy Independence and Security Act of 2007 

EPA U.S. Environmental Protection Agency

EPCA Energy Policy and Conservation Act

EU European Union

FFC full-fuel cycle

FR Federal Register

GHG greenhouse gas

GREET Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation

GRIM Government Regulatory Impact Model

HAP hazardous air pollutant

Hg mercury

HI Hydraulic Institute 

HP horsepower

HVAC heating, ventilating, and air conditioning 

ImSET Impact of Sector Energy Technologies

ISO International Organization for Standardization

kg kilograms

kW kilowatt

LCC life-cycle cost

MPC manufacturer production cost

MSP manufacturer selling price 

MIA manufacturer impact analysis

NIA national impact analysis

NEMS National Energy Modeling System

NES national energy savings

NESHAPs national emissions standards for hazardous air pollutants

NOPR notice of proposed rulemaking

NOX oxides of nitrogen

NPV net present value
OEM original equipment manufacturer

OMB Office of Management and Budget

PBP payback period

PM particulate matter 

R&D research and development

RFI request for information

rpm revolutions per minute

SCC social cost of carbon 

SG&A selling, general, and administrative costs

SO2 sulfur dioxide

TSD technical support document

U.S. United States

U.S.C. United States Code

VSD variable speed drive

1. INTRODUCTION

The U.S. Department of Energy (DOE) Appliances and Equipment Standards Program, 

within the Office of Energy Efficiency and Renewable Energy’s Building Technologies Program 

(BT), develops and promulgates test procedures and energy conservation standards for certain 

consumer appliances and commercial and industrial equipment. The process for developing 

standards involves analysis, public notice and comment, and consultation with interested parties. 

Interested parties include manufacturers, consumers, energy conservation and environmental 

advocates, State and Federal agencies, and any other groups or individuals having an interest in 

these standards and test procedures.

To inform its decision making regarding the possibility of developing efficiency 

standards for new natural gas compressors, DOE issued a request for information, comment, and 

supporting data about the characteristics, applications and energy use of gas compressors (RFI). 

Following up on the RFI, this Market and Technology Assessment (MTA) document has two 

primary purposes. The first is to overview the preliminary information that DOE has gathered 

from the RFI and other sources concerning the market for and technology of compressors in 

advance of a public meeting to be held on December 17, 2014. At this meeting, DOE will invite 

interested parties to review information in this document, and to discuss the impact of potential 

standards to the industry and to the nation. The second aim of this MTA document is to describe

the legal context as well as some of the procedural and analytical approaches DOE uses in 

considering potential new energy conservation standards. As such, the document is intended to 

encourage and facilitate the input of interested parties and serves as the starting point for 

evaluating energy conservation standards or energy use standards. It is not a definitive statement 

on any issue to be determined in the rulemaking.

This document is organized in the following manner. Section 1 lays out a number of 

background issues, including DOE’s statutory authority with respect to compressors, the scope of 

coverage under consideration, definitions, metrics to describe compressor efficiency, test 

procedures to measure compressor efficiency, and DOE’s rulemaking process. Section 2
describes the market for compressors (section 2.1) and the technology related to compressor 

efficiency (section 2.2). Section 3 describes how DOE would evaluate technology options for 

improving compressor efficiency, including how factors such as safety, reliability, 

manufacturability, consumer utility, and other variables would be considered. Appendices A and 

B summarize areas that DOE plans to seek input, and sources cited in assembling this document.

DOE will maintain information about this rulemaking on its Office of Energy Efficiency 

and Renewable Energy (EERE) website at: 

http://www1.eere.energy.gov/buildings/appliance_standards/commercial/commercial_industrial_

compressors.html.

1.1 Authority and Background 

Title III of the Energy Policy and Conservation Act, 42 U.S.C. § 6291, et seq., (EPCA) 

sets forth a variety of provisions designed to improve the energy efficiency of products and 

commercial equipment. (All references to EPCA refer to the statute as amended through the 

American Energy Manufacturing Technical Corrections Act (AEMTCA 2012), Pub. L. 112-210 

(December 18, 2012)). Part C of Title III (42 U.S.C. §§ 6311−6317), which was subsequently redesignated as Part A–1 for editorial reasons, establishes an energy conservation program for 

certain industrial equipment, which includes compressors, the subject of today’s writing. (42 

U.S.C. § 6311(2)(B)(i)) Unlike some other types of equipment included in EPCA, the term 

“compressors” is undefined. 

Section 341 of EPCA, 42 U.S.C. § 6312, provides a general statement of purpose to 

improve the efficiency of a variety of industrial equipment to conserve the energy resources of 

the Nation. That provision permits the Secretary of Energy to classify by rule certain equipment 

as covered equipment if a determination is made that doing so is necessary to carry out the 

purposes of Part A-1 of EPCA. As a result, DOE is considering extending coverage to 

compressors used in the natural gas infrastructure, provided such compressors meet the general 

EPCA criteria for coverage.

1.2 Compressors Under Consideration

At the time of publication of this document, DOE is exploring the energy savings 

opportunity associated with natural gas compressors and has not established which, if any, 

compressors to consider regulating. DOE is aware that natural gas compressors appear in a wide 

variety of applications. As noted in the Request for Information (RFI) published on August 5, 

2014 (79 FR 25377), DOE believes the transmission and distribution of natural gas to be one of 

the largest applications for natural gas compressors. As a result, DOE has focused its initial 

research efforts on natural gas compressor technologies used in the national pipeline 

infrastructure for the transmission and distribution of natural gas. DOE remains committed to 

investigating opportunities throughout the natural gas supply chain including the gathering, 

processing, transmission and storage market segments.
Although DOE’s initial efforts have centered around transmission and distribution 

compressor equipment, increased industry focus on shale gas has led to increased installation of 

compressors used for extraction and process. Compressors used in the upstream, on average, are 

smaller in physical size and higher in operating speed than transmission compressors, and 

therefore inherently less efficient. More significantly, a sizeable portion of the upstream industry 

is serviced by contracted compressors that are designed to be versatile, readily available in short 

lead time, and reliable, but are not necessarily optimally sized for a given installation. Upstream 

compressors are generally not controlled as well as the larger transmission compressors that have 

more sophisticated control systems and load control means. Prevalent control methods are 

inefficient in that they recirculate flow or reduce pressure that has been previously compressed. 

Most upstream compressors are driven by natural gas engines, which use process gas as fuel, 

taken from the stream prior to the sales meter. Accordingly, upstream operators and are not 

incented to be concerned with compression efficiency, per se. Taking these factors into 

consideration, the upstream and process areas are believed to hold the greatest opportunity for 

efficiency improvement, especially when new compressors, rather than retrofits, are considered 

for future regulation. The Department remains committed to investigating opportunities 

throughout the natural gas supply chain including the gathering, processing, transmission and 

storage market segments.

The Appliances and Equipment Standards Program has the authority to regulate products 

on the basis of their physical and functional product definitions. Whereas there can be a strong 

correlation between a product’s physical attributes and the applications in which it is used, once 

these physical attributes are defined, the standards generally apply to the product regardless of 

the application in which it is ultimately used. Thus what would distinguish a “covered” gas 

compressor from one exempt from standards, is not where it is used but the specific physical and 

functional definition of the covered product. The sections that follow present general technology 

descriptions of compressors and compressor components. These descriptions are broad and 

would be tailored as necessary to regulate equipment when economically justified to do so.

Natural gas compressors have two primary components: the compression unit in which 

compression actually occurs, and the prime movers, which provide mechanical power to the 

compression unit. The compression units are typically reciprocating, centrifugal, or axial, while 

the prime movers are normally reciprocating gas engines, gas turbines, or electric motors. Figure 

1.1 illustrates the schematic diagram of a typical gas turbine-driven centrifugal compressor gas 

compression package. Sections 1.2.1 and 1.2.2 describe the compressor types and the prime 

movers most common to natural gas transmission and distribution.
Figure 1.1 Schematic Diagram of a Typical Compressor Package

1.2.1 Compressor Types

1.2.1.1 Reciprocating

Reciprocating compressors use pistons traveling linearly to compress a trapped volume of 

gas, which is then allowed to escape using check valves. Reciprocating compressors may be 

“integral” with or inseparable, i.e. “separable” from their prime mover. Relative to centrifugal or 

axial compressors, reciprocating compressors are thought to be more efficient across different 

output levels but to carry greater maintenance requirements. 1 13 Reciprocating compressors, 

whether integral or separable, are usually driven by reciprocating gas engines or electric motors.

1.2.1.2 Centrifugal

Centrifugal compressors use rotating impellers to compress gas perpendicularly to the 

direction of rotation against a stationary housing. Relative to reciprocating compressors, 

centrifugal compressors are thought to be less efficient across different output levels, but to offer 

reduced maintenance requirements.1 13 Relative to axial compressors, centrifugal compressors 

tend to exist in lower flow and higher pressure applications. Centrifugal compressors are usually 

driven by gas turbines or electric motors.

1.2.1.3 Axial

Axial compressors use rotating vanes to compress gas parallel to the axis of vane 

rotation. Relative to reciprocating compressors, axial compressors are thought to be less efficient 

across different output levels, but to offer reduced maintenance requirements.1 13 Relative to 

centrifugal compressors, axial compressors tend to exist in high flow and lower pressure 

applications. Axial compressors are usually driven by gas turbines or electric motors.
1.2.2 Prime Mover Types

INGAAError! Bookmark not defined. describes the more prevalent types of prime movers 

drivers) which are used in pipeline applications: reciprocating gas engines, gas turbines and 

electric motors. 

1.2.2.1 Reciprocating Gas Engine

Reciprocating gas engines use pistons to harness energy from combusted gas in a trapped 

volume, which is then expelled using valves. Relative to gas turbines, reciprocating gas engines 

are thought to be more efficient across different output levels but to carry greater maintenance 

requirements. Reciprocating gas engines are typically used to drive reciprocating compressors.

1.2.2.2 Gas Turbine

Gas turbines use rotating vanes or impellers to harness energy from a flow of combusted 

gas. Relative to reciprocating gas engines, gas turbines are thought to be less efficient across 

different output levels, but to offer reduced maintenance requirements. Gas turbines are typically 

used to drive centrifugal or axial compressors.

1.2.2.3 Electric Motor

Electric motors use electrical energy to create magnetic fields that rotate a shaft. Electric 

motor efficiency is less straightforward to compare with that of reciprocating engines or gas 

turbines, because it requires knowledge of how the electricity was generated. Relative to other 

prime movers, electric motors offer the greatest efficiency across output levels and the lowest 

maintenance requirements. Additionally, electric motors generate no on-site emissions and little 

acoustic noise, and for those reasons may be preferred in populated areas where sufficient 

electric power is available.

1.2.3 Compressor Systems

There may be greater potential for energy savings if the energy conservation standards 

addressed compressors as a system of components. Compressor systems are subject to a variety 

of inefficiencies, and those inherent in the compressor unit are often among the smallest. As a 

result, addressing other system inefficiencies may offer the greatest opportunity for cost-effective 

energy savings.

DOE is considering the following options for regulation depending on how compressors 

are defined and sold:

1. Defining and establishing standards for the compressor unit exclusive of the prime 

mover. This option would likely involve a metric such as isentropic efficiency of 

compression.

2. Defining and establishing standards for packages shipped including both a compressor 

unit and a prime mover and, potentially, auxiliary equipment.
3. Defining and establishing design requirements for compressors or compressor packages, 

that mandate certain technology be used or avoided.

1.3 Equipment Definitions

The term “compressors” is undefined by EPCA. As part of a Department of Energy 

Request for Information (RFI) published on August 5, 2014 (79 FR 25377) and related to the air 

compressors rulemaking, DOE considered a variety of definitions for this term in order to help 

ensure a reasonable level of clarity with respect to the type of equipment that might be regulated. 

In its ongoing proceeding, DOE offered for comment the several definitions for “natural gas

compressors” to clarify the coverage of any potential test procedure or energy conservation 

standard.

However, DOE recognizes that air and natural gas compressors may have considerable 

technological differences, even when the categories (e.g., “reciprocating) used to describe them 

are apparently similar. For the purpose of this assessment, then, reciprocating and centrifugal 

compressors will be defined per the definitions below: 

1.3.1 Natural Gas Compressor Package

A “natural gas compressor package” is defined to be a set of equipment that is used to 

increase the pressure of natural gas and includes, but is not limited to, the compression unit, the 

prime mover, and associated auxiliary hardware including controls, sensors, vents, and measures 

for safety and maintenance.

1.3.2 Compression Unit

A “compression unit” is defined to be the assembly that uses mechanical input power to 

perform physical compression of natural gas. A compression unit is powered by a prime mover. 

In certain cases (e.g., integral reciprocating compressors) the compression unit and the prime 

mover may be part of the same assembly.

1.3.3 Prime Mover

A “prime mover” is defined to be the assembly that consumes electrical energy, thermal 

energy from natural gas combustion, or another source of input energy in order to supply the 

mechanical power used for natural gas compression. In certain cases (e.g., integral reciprocating 

compressors) the compression unit and the prime mover may be part of the same assembly.

1.3.4 Reciprocating Natural Gas Compression Unit

A “reciprocating compressor” is defined to be a natural gas compressor that performs 

compression on an enclosed volume of gas using a piston traveling linearly.
1.3.5 Centrifugal Natural Gas Compression Unit

A “centrifugal compressor” is a type of natural gas compressor in which the flow enters 

the compressor in an axial direction (parallel with the axis of rotation) and exits in the radial 

direction (perpendicular to the axis of rotation). Compression is achieved by first using a rotating

radial impeller to accelerate the gas and impart kinetic energy. Then a stationary diffuser is used 

to transform the increased kinetic energy into pressure rise. The diffuser may or may not contain 

fixed vanes. A centrifugal compressor may contain one or more sets (stages) of alternating 

impellers and diffusers, and these stages will be located within a static housing.

1.3.6 Axial Natural Gas Compression Unit

An “axial compressor” is a type of natural gas compressor in which the flow enters and 

exits the compressor in an axial direction (parallel with the axis of rotation). Compression is 

achieved by first using a row of rotating airfoils to accelerate the gas and impart kinetic energy. 

Then a row of stationary airfoils is used to diffuse the gas and transform the increased kinetic 

energy into pressure rise. An axial compressor may contain one or more sets (stages) of 

alternating rotating and stationary airfoils, and these stages will be located within a static 

housing.

1.4 Efficiency Metrics

To establish a metric that could be used to determine the efficiency of a gas compressor, 

DOE reviewed currently available metrics used within industry. DOE will continue to research 

and seek comment on efficiency metrics, along with additional metrics not in this section, with 

regard to their applicability to gas compressors and current use in industry. DOE recognizes that 

not all of the terms below may have agreed-upon metrics that would enable standards, but 

presents them to enable an organized discussion of energy-saving opportunities.

Compressor unit efficiency and thermal efficiency are discussed in INGAA’s Interstate 

Natural Gas Pipeline Efficiency, in relation to compressors and compressor drivers respectively, 

and are described as follows.

1.4.1 Compressor Unit Efficiency

As applied to natural gas compressor units, compressor efficiency measures how much 

energy is expended in compressing the gas compared to how much overall energy is used by the 

compressor. Inefficient compressors heat the gas more than do efficient compressors while 

raising its pressure and thus have lower efficiency values.2 This relationship may be expressed as 

isentropic efficiency, a dimensionless parameter reflecting how close a compressor comes to the 

theoretical physical maximum.

1.4.2 Thermal Efficiency

As applied to a prime mover (engine, turbine or motor) that drives a compressor, thermal 

efficiency measures how much of the potential energy of an input fuel or electric power is 

converted into useful energy that can be used to drive a compressor. The majority of energy that 
is not converted into useful energy is considered “waste heat” in the exhaust, cooling and 

lubrication systems.2

1.4.3 Heat Recovery

Both compressors and prime movers generate waste heat in compression and combustion, 

respectively. Using waste heat either directly or to generate electrical power may be economical, 

depending on compressor type and size. Heat recovery is sometimes lumped in compressor unit 

or prime mover efficiency values. Because the savings materialize remotely, where the heat or 

generated electrical power is consumed, it may be useful to consider that savings separately.

1.4.4 Gas Efficiency

As applied to a natural gas compressor or any of its subcomponents, gas efficiency 

reflects how effective a compressor is at retaining natural gas. Natural gas may escape in a 

variety of ways, including through seals or packing, uncombusted, in the exhaust stream, through 

valves, or any other hardware in the compressor package. DOE is not aware of an established 

metric to quantify gas efficiency. Logically, it could be represented as the mass flow of gas 

leaving the equipment divided by the mass flow of gas entering the equipment, discounting the 

gas used as fuel. Although not commonly discussed as efficiency, improving this parameter 

would enable a compressor to deliver more natural gas for a given energy consumption.

A special case of gas loss comes during compressor “blowdown,” when the unit is 

intentionally depressurized during periods of maintenance or low demand. The pressurized gas 

may be flared, stored, or simply vented to the atmosphere. The U.S. Department of 

Transportation, which is responsible for gas pipeline safety, currently requires that compressor 

emergency shutdown be tested annually, which also entails blowing down the unit. For units 

frequently blown downa (e.g., peak demand units), aggregate lost gas may be significant.

1.5 Test Procedures

Manufacturers must use a DOE prescribed test procedure to establish compliance if any 

standards are adopted and make representations of energy efficiency for gas compressors. DOE 

would also use that verify the performance of covered equipment if standards are established. 

Thus, in conjunction with considering setting standards for gas compressors, DOE is also 

considering whether to develop a test procedure that would be applied to all potentially covered 

gas compressors. The test procedure would likely include an efficiency descriptor and the 

methods necessary to adequately measure the performance of the compressor for the purposes of 

determining compliance with energy conservation standards.

When establishing or amending test procedures, DOE reviews existing industry test 

procedures currently used to measure the energy use or energy efficiency of the covered 

equipment. DOE then considers whether to: (1) adopt a test procedure(s) in its entirety, (2) adopt 

a I.e., having undergone blowdown, which is when a compressor intentionally depressurized during periods 

of maintenance or low demand. Blowdown usually results in a large amount of wasted gas and energy.

 
portions of a test procedure(s) with modification or additions, or (3) develop a new test 

procedure if existing test procedures do not provide necessary energy use or efficiency methods 

necessary to calculate DOE’s energy use or efficiency metrics. In addition, DOE’s test 

procedures consider a variety of factors, including ambient test conditions, repeatability and 

tolerances on test conditions and results, and test equipment calibration and accuracy. Table 1.1

shows a number of test procedures that relate to gas compressors for which DOE is considering 

establishing standards.

Table 1.1 Overview of Currently Available Compressor Test Procedures

Test Procedure Origin

API 617 Axial and Centrifugal Compressors 

and Expander-Compressors

U.S.

ASME PTC-10 Performance test Code on 

Compressors and Exhausters

U.S.

ASME PTC-09 Displacement Compressors, 

Vacuum Pumps And Blowers

U.S.

ISO1217:2009 Displacement Compressors –

Acceptance Tests

International

ISO5389:2005 Turbocompressors –

Performance test code

International

In addition to these test procedures, DOE is aware of guidelines published by the Gas 

Machinery Research Council and Southwest Research Institute, which provides suggested best 

practices for field testing of reciprocating, and centrifugal compressors 3

 4

DOE will review these test procedures, along with additional test procedures that may not 

be listed in Table 1.1. Additionally, DOE will seek comment on the appropriateness of adopting 

these procedures, either in whole or in part, as a basis for a DOE test procedure. If DOE adopts 

test procedures for gas compressors, it will seek to align these procedures to the greatest extent 

practicable with those that are already widely used by industry to limit manufacturer burdens. 

1.6 Rulemaking Analyses Process Overview

While DOE has not yet determined if it will be developing efficiency standards for new 

natural gas compressors, should it decide to do so, the process that it will follow is described 

below.
The analyses conducted in support of a rulemaking ensure that, if standards are 

established, DOE selects standards that achieve the maximum improvement in energy efficiency 

that is technologically feasible and economically justified and will result in significant energy 

savings, as required by EPCA. Economic justification includes the consideration of the factors 

set forth in EPCA, which encompass the economic impacts on domestic manufacturers and 

consumers, national benefits including environmental impacts, issues of consumer utility, and 

impacts from any lessening of competition. 

Error! Not a valid bookmark self-reference. summarizes the analytical components of 

the DOE standards-setting process. The analyses are presented in the center column. Each 

analysis has a set of key inputs, which are data and information required for the analysis. 

“Approaches” are the methods that DOE will use to obtain key inputs. The results of each 

analysis are key outputs, which feed directly into the rulemaking. Arrows indicate the flow of 

information between the various analyses. DOE ensures a consistent approach to its analyses 

throughout the rulemaking by considering each analysis as a part of the overall standard-setting 

framework.
Figure 1.2 Flow Diagram of Standards Rulemaking Process 
2. MARKET AND TECHNOLOGY ASSESSMENT

The market and technology assessment provides information about the natural gas

compressor industry and the performance attributes of this equipment. DOE may use this 

assessment to determine equipment classes and identify potential design options or efficiency 

levels for each equipment class.

2.1 Market Assessment

DOE’s market assessment identifies and characterizes the manufacturers of gas 

compressors, estimates market shares and trends, and addresses regulatory and non-regulatory 

initiatives intended to improve the energy efficiency or reduce the energy consumption of the gas 

compressors that DOE may consider regulating. 

The market assessment allows DOE to gather data that can help identify important issues 

(e.g., potential small business impacts, competitive disruptions, and other factors that may arise 

from enacting standards). For example, market structure data can be used to assess competitive 

impacts as part of the manufacturer impact analysis. 

DOE considers manufacturers, industry organizations, and other interested parties as 

potential sources of such information. In addition, DOE is considering examining national 

market reports or data collected in national energy use surveys, or extrapolating historical 

compressor sales data from the U.S. Census Bureau. In addition to these sources, DOE will seek 

comment on other sources of data that may help characterize the gas compressor market. 

2.1.1 Manufacturers Participating in U.S. Market

Nine manufacturers represent the majority of the natural gas compressor market within 

the scope of this assessment, and are listed in Table 2.1.

Table 2.1 Major Gas Compressor Manufacturers 

Manufacturer Compressor Types Manufactured

Reciprocating Centrifugal

Ariel Corporation X

Burckhardt Compressionb X

Cameron X

Dresser-Rand Group X X

G E Oil & Gas X X

Howden Compressors, Inc.

b X X

Neuman & Esser USA, Inc. X

Siemens AG X

Solar Turbines, Inc. X

b Burckhardt and Howden may be less active in the U.S. transmission/storage market and more active in the 

refining sectors. Because scope is still under consideration, however, they are retained here.

 
Several of the above manufacturers have diverse product offerings within other industries 

as well as the oil and gas industry. There is a mix of compressor types available from these 

manufacturers. Several exclusively manufacture reciprocating or centrifugal compressors, while 

others manufacture both types of equipment. 

DOE does not have empirical data on the market shares of particular manufacturers. 

However, based on information from the 2014 Compression Technology Sourcing Supplement., 

DOE believes that the nine companies in Table 2.1 supply over 95% of new compressors likely 

to be used in compressor stations.

c

2.1.2 Small Businesses

Natural gas compressors are primarily supplied by large manufacturers, and DOE is not 

aware of any manufacturers of natural gas compressors that qualify as a small business. 

The Small Business Administration (SBA) defines a small business for “Air and Gas 

Compressor Manufacturing” as a company with 500 or fewer employees. The number of 

employees in a small business is rolled up with the total employees of the parent company; it 

does not represent the division manufacturing natural gas compressors. SBA lists small business 

size standards for industries as they are described in the North American Industry Classification 

System (NAICS). For natural gas compressors, the size standard is matched to NAICS code 

333912, Air and Gas Compressor Manufacturing.d

2.1.3 Packagers and Installers

Natural gas compressors are most often custom designed for a specific application, and 

are inherently large and expensive machines. Due to these barriers there are no known pure 

assemblerse of natural gas compressors, and manufacturers are often heavily involved in the 

selection and design of equipment. In certain cases, “packagers” or “integrators” may design and 

fabricate compressor packages, purchasing a (either standard or custom) compressor and a driver 

and then combing them with other equipment and auxiliaries into a packaged system. Some 

packagers also install the equipment.

Typically an engineering firm or the owner of a pipeline or compressor station will 

specify the technical requirements of the compressor to be installed on a project. Depending on 

contractual agreements the engineering firm or compressor station owner will purchase the 

compressor, and then typically the OEM or EPC (engineering, procurement, and construction) 

contractor will install the compressor. The owner of the compressor station will be responsible 

for operating the compressor.

c Compressors stations use reciprocating and centrifugal compressors, usually rated above 1,000 hp. d See https://www.sba.gov/content/north-american-industry-classification-system-codes-and-smallbusiness-size-standards. e I.e., businesses offering the service of assembly alone

 
2.1.4 Trade Associations

To gain insight into the natural gas compressor industry, DOE researched various 

associations within the industry. Due to the large number of stakeholders in the natural gas 

industry, not all the trade associations researched have members who manufacture natural gas 

compressors, as some focus on areas closely related to natural gas compressors such as natural 

gas pipeline operation.

2.1.4.1 Gas Compressor Association

The Gas Compressor Association (GCA) represents companies that manufacture, lease, 

and service natural gas compressors. GCA is organized into six committees -- education, 

environmental, health and safety, membership, program and expo, and statistics.

f A majority of 

the nine manufacturers identified in this report are members.

The environmental and statistics committee are the most relevant to this market 

assessment. The environmental committee educates GCA members on upcoming regulations 

that may affect the membership, as well as facilitates communication between members on 

compliance challenges. The statistics committee provides guidance for the collection and 

publication of natural gas compression industry specific data for members. Data are compiled 

and published by an independent third-party, and members use these data for various purposes –

e.g. business expansion efforts.

2.1.4.2 Gas Machinery Research Council

The Gas Machinery Research Council (GMRC) was established as a subsidiary of the 

Southern Gas Association in 1952 as a not-for-profit research corporation to provide member 

companies and industry with the benefits of research directed towards reliability and cost 

effectiveness of the design construction and operation of mechanical and fluid systems, including 

natural gas compressors. A majority of the nine manufacturers identified in this report are 

membersg

GMRC research includes pipeline and compressor technology projects, which currently 

include, noise mitigation/suppression, piping stiffness, mechanical vibration issues, predicting 

power cost of reciprocating compressors, and the performance impact of acoustical impedance 

on centrifugal compressors. Research is published as technical papers and is available to 

members and to the public for a fee.

2.1.4.3 Interstate Natural Gas Association of America

The Interstate Natural Gas Association of America (INGAA) is a trade organization that 

advocates regulatory and legislative positions of importance to the natural gas pipeline industry 

in North America. Membership consists of pipeline operators who operate approximately 

200,000 miles of natural gas pipelines, which is a majority of the interstate pipeline 

infrastructure.

h

f See http://www.gascompressor.org/ g See http://www.gmrc.org/ h See http://www.ingaa.org/

 
In 1990 INGAA established INGAA Foundation Inc. which has more than 150 members 

consisting of natural gas pipeline companies, construction companies, engineering firms, IT 

service providers, and other companies that provide goods and services to the natural gas 

pipeline industry. Five of the nine major manufacturers listed in this assessment are members of 

the INGAA Foundation. The INGAA Foundation facilitates the safe, efficient, reliable and 

environmentally responsible design, construction, operation and maintenance of the North 

American natural gas transmission system through activities such as analysis, and providing a 

forum for dialogue and collaboration. 

2.1.4.4 American Petroleum Institute

American Petroleum Institute (API) represents all aspects of the American oil and gas 

industry including production, refinement, distribution, and suppliers. Their mission is to 

influence public policy in support of a strong U.S. oil and gas industry. They carry out this 

mission through work in advocacy, research, statistics, standards, certification and educationi

. 

API has two standardsj

that cover the minimum requirements and test procedures for 

different types of compressors which are listed below: 

• API 617, Axial and Centrifugal Compressors and Expander-Compressors for Petroleum, 

Chemical and Gas Industry Services. 

• API 618, Reciprocating Compressors for Petroleum, Chemical and Gas Industry 

Services.k

2.1.4.5 Gas Processors Association

Gas Processors Association (GPA) represents the “midstream” pipeline industry, which is 

primarily composed of pipelines, and storage of natural gas. Its members operate approximately 

190,000 miles of natural gas pipeline, which is over half of the total pipeline mileage in the 

contiguous United States. GPA provides membership with several services, including working 

with legislators for a safe and viable industry, providing forums to develop standards, conducting

research, educating the workforce, and improving safety. Although none of the major 

manufacturers of natural gas compressors are members of GPA, the membership is often the 

purchasers (and ultimately the users) of natural gas compressors.

l

2.1.5 Regulatory Programs

There are currently no Federal energy conservation standards for natural gas 

compressors. However, the following sections detail regulations that may impact selection, 

construction, and operation of natural gas compressors. There are additional regulations 

regarding areas such as pricing, safety, historic and environmental preservation, and transparency 

i

See http://www.api.org/

j

Which were adopted by American National Standards Institute (ANSI) k This specification does not cover performance testing, but material testing, hydrostatic testing and other 

forms of mechanical testing, critical to the integrity and reliability of the compressor and system. l

See https://www.gpaglobal.org/

 
that are not detailed in this assessment as they have a significantly lesser effect on the 

manufacture, sale or operation of a natural gas compressor than the regulations detailed below.

2.1.5.1 Clean Air Act

Various portions of the Clean Air Act (CAA) (42 U.S.C. § 7401, et seq.) may apply to the 

construction and operation of natural gas compressors, including the New Source Review (NSR) 

program, Prevention of Significant Deterioration (PSD), and permitting under Title V of the 

CAA.

5

The NSR program and PSD apply to both new construction and major modifications of 

existing industrial facilities. The NSR program applies to “non-attainment” areas (i.e., areas that 

do not comply with National Ambient Air Quality Standards), and PSD requirements apply to 

“attainment” areas (i.e., areas that comply with National Ambient Air Quality Standards). In 

either case, a pre-construction review of emissions and proposed control measures is conducted 

for any “major sources” of pollutants that exceed certain thresholds. 

Title V of the CAA also applies to “major sources” of air pollutants and requires them to 

obtain operating permits, which are usually issued by state authorities. Permitting requirements 

vary based on the amount and type of pollutant. 

Additionally the construction of a natural gas compressor facility may be reviewed by a 

State Implementation Plan (SIP), which is a plan for CAA compliance. 

For natural gas compressor stations, requirements of the CAA are usually focused on 

emissions from the prime mover of a natural gas compressor, as it is typically the largest source 

of emissions at the station. Different natural gas compressors and associated prime movers will 

require different levels of pollution mitigation for compliance with the CAA. Therefore 

compliance strategies, and associated costs, for natural gas compressor technologies are 

considered when selecting equipment.

2.1.5.2 FERC

The Natural Gas Act (NGA) was the first federal regulation of the natural gas industry 

and was enacted in 1938. In 1977, the Department of Energy Organization Act created the 

Federal Energy Regulatory Commission (FERC), which uses much of the authority from the 

NGA.

5

In 1986 FERC Order 436 restructured the natural gas pipeline industry into transportation 

only businesses. Prior to this order pipelines transported and sold natural gas to customers.5

In 1992 FERC Order 636 required pipelines to provide “equal in quality” transportation 

services regardless of the customer. Part of this order also encourages the use of natural gas 

market centers, and imposed new rate designs which were intended to promote competition.5

Additional FERC Orders have further changed rights to capacity agreements, and pricing 

structures, such as encouraging peak/off-peak rate structures, which has ultimately increased 
competition among pipelines. This increased competition provides an incentive to increase 

pipeline efficiency, which in part is driven by natural gas compressor efficiency.

2

2.1.5.3 NEPA

The National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. § 4331 ET SEQ.) 

requires federal agencies to conduct an Environmental Impact Statement (EIS) for any proposed 

action. FERC was designated as the lead agency for compliance with NEPA by the Energy 

Policy Act of 2005, which amended the NGA.

5

FERC reviews proposed natural gas pipeline projects, which often include natural gas 

compressor station construction or modification. Part of this review includes evaluating 

alternative options that may have a lower environmental impact. However, alternative options 

may be eliminated from consideration due to various factors such as high cost and not meeting 

the operational requirements of the proposed pipeline project.

2.1.5.4 U.S. Department of Transportation

The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety 

Administration (PHMSA) has oversight authority over the safety of the natural gas pipeline 

infrastructurem. PHMSA’s responsibilities were expanded by the Pipeline Safety Improvement 

Act of 2002 to include requiring pipeline operators to have integrity management programs for 

“High Consequence Areas”, qualification programs for employees who perform sensitive tasks, 

publicly available pipeline maps and operator contact information. Other congressional acts have 

also changed the responsibilities of PHMSA. Other PHMSA rules and regulations are based on 

consensus standards and focus on areas such as manufacturing, shipping of pipe material, 

construction techniques, operating procedures, emergency response, and abandonment.5

2.1.6 Nonregulatory Programs

The EPA Natural Gas STAR program is a voluntary partnership that encourages 

members, oil and gas companies involved in all sectors of the industry, to improve efficiency and 

reduce methane emissions. According to Gas STAR, the transmission and storage sector, where 

natural gas pipeline compressors are used, accounts for 27% of the industry’s methane 

emissions.

Since 1993 the 26 partners in the transmission sector have reduced a cumulative 255.9 

Bcf of methane emissions, including 10 Bcf of methane emissions in 2012. According to Gas 

STAR data, the top methane reduction technologies used in 2012 were pipeline pump-downn

techniques, use of turbines at compressor station, and installing electric compressors.

6

m See http://www.phmsa.dot.gov/ n The term “pump-down” refers to lowering the pressure of a pipeline section before performing 

maintenance in order to minimize or eliminate venting gas to the atmosphere

 
2.1.7 Shipments and Value

There are over 300,000 miles7 of natural gas transmission pipeline in the United States 

and more than 1,700 compressor stations maintaining pressure on it.

8 Typically there are 

multiple compressors at one compressor station, estimated to be about four compressors per 

station.7 A recent EPA white paper estimates that industry operates approximately 7,235 natural 

gas-fired reciprocating engines, and 725 natural gas-fired combustion turbines at compressor 

stations.8 ). The EPA report did not have an estimate for electric motors, because it was focused 

on on-site emissions, but a 2010 INGAA publication had an estimate of 200 electric motors in 

operation to drive compressors.

2 Compressor stations may have motors for other purposes (e.g., 

pumps, ventilation, etc.) but the primary drivers in these estimates are driving natural gas 

compressors.

Natural gas compressors are commonly used in many natural gas industry segments. 

Table 2.2 presents EPA estimates for the number of reciprocating and centrifugal compressors in 

use in several segments. 

Table 2.2 Summary of Natural Gas Sector Compressor Activityo

Industry Segment Active Compressor 

Units

Production

Reciprocating 36,066

Processing

Reciprocating 5,624

Centrifugal 906

Transmission

Reciprocating 7,235

Centrifugal 725

Storage

Reciprocating 1,012

Centrifugal 99

LNG Storage

Reciprocating 270

Centrifugal 64

LNG Import Terminal

Reciprocating 37

Centrifugal 7

 Source: EPA, 2014, Table 3-9. 

Expansion of the natural gas infrastructure has required construction of additional 

compressor stations. From 1996 to 2006 154 compressor stations were added, a 15% rise in the 

o These figures do not include rotary screw compressors, of which there are several thousand active. 

However, they tend to be used in gathering and refrigeration, and not transmission or distribution.

 
total number of stations in service. During this same period, a total of 3.5 million horsepower of

compressor capacity was added, which is a 26% increase in installed horsepower.7

Compressor capacity is usually determined by project requirements, and in 2004 

reciprocating gas engines in operation averaged 1,700 horsepower while gas turbines were 

larger, averaged 6,600 horsepower.9

Annual shipments of natural gas compressors were estimated by analyzing completed 

natural gas pipeline projects in EIA’s Natural Gas Pipeline Project Spreadsheet.

8 Associated 

FERC Docket numbers were used to look up information regarding the projects, such as 

environmental impact assessments, and determine data for each new compressor installed. 

Projects that were under state authority were left out due to insufficient data, and represented 8% 

of all projects from the EIA spreadsheet for the years estimates were available. Therefore, the 

actual total shipments of natural gas compressors are likely larger than the estimates shown 

below. These estimates are only for compressors at compressor stations and do not include other 

areas of gas compressor use such as storage, and field compressors for gathering systems.

Annual shipment estimates for natural gas compressor packages installed at compressor 

stations from 2009 to 2013 are shown in Table 2.3. During this five year period estimates 

indicate that natural-gas-fueled reciprocating compressors had the highest market share – totaling 

45% of shipments. Natural-gas-fueled centrifugal compressors were estimated to have the next 

highest market share with 40%. Electric motors driven centrifugal compressors compose the 

smallest amount of shipments during this period of 16%.

Table 2.3 Annual Compressor Station Compressor Package Shipments by Year

Primary Driver Fuel Natural Gas Natural Gas Electric

Compressor Technology Reciprocating Centrifugal Centrifugal

Annual 

Shipments

2009 42 28 6

2010 34 23 4

2011 7 21 10

2012 16 12 9

2013 5 8 7

Cumulative Market Share 45% 40% 16%

The data showed a wide range of compressor horsepower ratings, from the smallest 

reciprocating unit of just over 1,000 hp to a large electric motor-driven 42,000 hp unit. Naturalgas-fueled reciprocating compressors were the smallest with an average of 4,880 hp, and no units 

were more than 8,180 hp. Natural gas centrifugal units covered the largest range of sizes from 

1,600 hp to 30,000 hp, with an average size of 12,022 hp. Electric motor driven centrifugal 

compressors tended to be the largest units and on average were 16,203 hp. Estimated shipments 

for various horsepower ranges are shown in Table 2.4.
Table 2.4 Annual Compressor Station Compressor Package Shipments by HP Range for 

2009 to 2013

Primary Driver Fuel Natural Gas Natural Gas Electric

Compressor Technology Reciprocating Centrifugal Centrifugal

Shipments by 

Horsepower 

Ranges

1,000-2,500 20 2 3

2,501-5,000 57 7 1

5,001-7,500 2 9 2

7,501-10,000 25 7 7

10,001-15,000 0 41 7

15,001-20,000 0 17 4

20,001-30,000 0 9 9

30,001-50,000 0 0 3

Average Horsepower 4,880 12,022 16,203

An additional data point for shipment estimates is the 2013 Mechanical Drive Order 

Survey published by COMPRESSORtech2. It uses annual surveys of manufacturers to show 

orders for mechanical drive equipment for the gas compressor marketplace received in 2012. In 

that year, 14 orders were received in North America for gas turbines used with centrifugal 

compressors. The turbines ranged from 40,230 to 80,461 hp (60.1 to 120 MW). These may 

include units larger than those used in natural gas transmission. Orders for Reciprocating engines 

during this time are shown in Table 2.5. The data provided global orders by fuel type and 

geographic region. The global percentage of engines fueled by natural gas was used to estimate 

the orders for natural gas engines in North America. The equipment orders in Table 2.5 are

greater than the estimates provided in Table 2.4 for several reasons. First, they include orders in 

Canada and Mexico, while estimates from EIA projects are only within the United States. 

Second, they include all applications of gas compressors including gathering, transmission, 

storage, and distribution while EIA data only has compressors located a compressor stations 

which is a subset of all natural gas compressors in use (12).

Table 2.5 2012 North American Reciprocating Engine Orders

Output Range Global Percent 

Natural Gas

North America Orders

(hp) (MW) Total Estimated Natural Gas

670 to 1,341 0.5 to 1.00 2% 2,307 40

1,342 to 2,682 1.01 to 2.00 24% 1,374 332

2,683 to 4,694 2.01 to 3.50 22% 128 28

Growth of the natural gas pipeline infrastructure is expected to continue. An INGAA 

publication had a projected expansion of an additional 4.38 million horsepower of pipeline 

compressors from 2014 to 2035. Additionally, DOE estimates that there will be 8.40 million 

horsepower of compressors on gathering pipelines during this time frame.

10
2.2 Technology Assessment

The technology assessment focuses on understanding how energy is used by natural gas

compressors and what potential technology changes to the design and construction of these 

compressors would improve their energy efficiency. Measures that improve the energy efficiency 

of the equipment are called “technology options.” These measures are based on existing 

technologies, as well as working prototypes. In consultation with interested parties, DOE will 

develop a list of technology options to consider in this rulemaking. Initially, this list will include 

all those options that may improve energy efficiency, including a max-tech design. DOE will 

consider each of these technology options against four screening criteria, as discussed in section 

3. Technology options that pass all the screening criteria are called “design options” and are 

analyzed in later analyses not within scope of this document.

To develop the list of technology options that could improve the efficiency of the 

compressors for which DOE is considering regulating, DOE is reviewing manufacturer catalogs, 

recent trade publications, and technical journals. DOE also intends to consult with interested 

parties to gather information on compressor designs and applications.

2.2.1 Overview of Compressor Technologies

Natural gas compressors consist of two main components: the compressor, in which the 

natural gas is actually compressed, and the prime mover, or the compressor driver. As noted in 

Section 1.2, there are several different equipment types for each component, and a natural gas 

compressor can be designed using multiple different combinations of components depending 

upon its specific application and performance requirements. The following is a description of the 

different individual equipment types for both components. 

2.2.1.1 Compressors 

The two major compressor types used in the transmission and distribution (T&D) of 

natural gas are reciprocating and dynamic. Dynamic compressors used in natural gas T&D can 

be further divided into centrifugal and axial compressors. 

Reciprocating Compressors

Reciprocating compressors are positive displacement devices, i.e., devices that add 

pressure by compressing the gas through mechanical displacement, typically with a cylinderpiston combination.

2 The number and size of the cylinders used can be changed to meet the 

required compression ratio and throughput. As such, reciprocating compressors provide the 

greatest flexibility in operating range for both discharge pressure and flow capacity. 

Higher discharge pressures can only be achieved using multiple-staging. The number of 

stages is determined by the overall compression ratio, as the compression ratio per stage is 

generally limited by the discharge temperature and usually does not exceed four. Multi-stage 

units are able to reach higher pressures by utilizing intercooling between stages to maintain the 

gas temperature within safe operating limits.11
Reciprocating compressors are typically driven by natural-gas powered reciprocating 

engines or electric motors and vary from fractional to more than 20,000 horsepower (hp) per 

unit.

11 In addition, reciprocating compressors are normally divided into separate categories based 

on the designed operating speed, slow (~200-400 rotations per minute (rpm)), medium (~500-

900 rpm), and high (~900-1800 rpm). Slow speed compressors generally come as an integrated 

package with the driver and are the most efficient compressor type, maintaining a higher 

efficiency over a wider bandwidth of operating pressure and gas flow conditions. Slow speed 

compressors were also the predominant equipment type used in transmission and distribution for 

decades.2 However, in recent years, the industry has begun to use high speed reciprocating 

compressors. While less efficient than other compressors, high speed compressors provide four 

to five times the power and run at two to three times the speed as slower compressors of the 

same size.12 As such, higher speed compressors are able to compress more gas and achieve 

higher throughputs using smaller units, resulting in significantly reduced installation costs that 

outweigh the increase in energy costs caused by using less efficient units.

2 The typical 

performance ranges for reciprocating compressors can be seen below:

Table 2.6 Typical Performance Ranges – Reciprocating Compressors2

Isentropic 

Efficiency

(Percent)

Inlet Flow

(cfm)

Discharge 

Pressure (psig)

Slow-speed Reciprocating 80-92

Medium-speed Reciprocating 75-90 0-2,500 3-80,000

High-speed Reciprocating 70-82

According to INGAA2, reciprocating compressors are more effective when used in 

situations with high and varying pressure ratios (i.e., when the ratio of discharge to suction 

pressure varies substantially) and low overall flow; CAGI lists the advantages of using a 

reciprocating compressor over other compressor types:

11

• Greater flexibility in capacity and pressure range.

• Higher compressor efficiency and lower power cost.

• Capability of delivering higher pressures.

• Capability of handling smaller volumes.

• Less sensitive to changes in gas composition and density.

Dynamic Compressors

Dynamic compressors are machines in which air or gas is compressed by the mechanical 

action of rotating vanes or impellers imparting velocity and pressure to the air or gas. There are 

two major types of dynamic compressors, axial and centrifugal.

11

Centrifugal Compressors

The centrifugal compressor is one of the simplest machines available for gas 

compression. Unlike a reciprocating compressor, which uses positive displacement, the 
centrifugal compressor is a continuous flow machine in which one or more rotating impellers add 

energy to the gas. The gas flow enters at the eye of the impeller and is discharged from the 

impeller tip at increased velocity and pressure. The gas flow then enters a diffuser where most of 

its remaining kinetic energy is converted to pressure rise. Centrifugal compressors have a more 

limited operating range than reciprocating compressors but are able to operate at significantly 

higher flow rates. For centrifugal compressors, the maximum discharge pressure achievable 

using a single-stage unit is limited by the impeller’s strength. In cases where the pressure 

requirement exceeds that strength, centrifugal compressors may be multi-staged.

11 The typical 

performance ranges for centrifugal compressors can be seen below:

Table 2.7 Typical Performance Ranges – Centrifugal Compressors2

Size (hp) Efficiency

(Percent)

Inlet Flow

(cfm)

Discharge Pressure 

(psig)

1,000-30,000 75-88 100-200,000 3-10,000

Centrifugal compressors are normally driven by gas turbines or electric motors and have 

a similar capacity range to reciprocating compressors. Unlike reciprocating compressors, 

centrifugal compressors develop pressure within the unit, independent of the load, resulting in 

constant discharge pressures over a considerable range of flows.11 As such, centrifugal 

compressors are more effective in situations with low/medium, relatively constant pressure ratios 

and high, mildly variable flow rates.2 Other advantages of using centrifugal compressors are 

listed by CAGI11 as follows:

• Lower installed first cost where pressure and volume conditions are favorable.

• Lower maintenance expense.

• Greater continuity of service and dependability.

• Less operating attention required.

• Greater volume capacity per unit of plot area.

• Adaptability to high-speed low-maintenance-cost drivers.

Axial compressors 

Axial compressors are also continuous flow machines in which one or more rotating 

series of blades set along a common shaft continuously add energy to the gas. However in an 

axial compressor, the gas flow enters and is discharged at increased pressure and velocity along 

the axis of the main shaft. Axial compressors are only capable of delivering low discharge 

pressures, less than 100 psig, which falls well outside the range of normal pipeline operations 

(900-1750 psig). As such, they are rarely used in transmission and distribution.

2.2.1.2 Compressor Prime Movers

Three primary types of prime movers (drivers) are used in pipeline applications: 

reciprocating gas engines, gas turbines, and electric motors.2 Compressor selection usually 

dictates the choice of the prime mover. Gas engines are generally limited to driving reciprocating 

compressors, while gas turbines generally drive centrifugal compressors. Electric motors, on the 

other hand, may be used with either compressor technology, but pipeline companies have begun 
using electric motors (possibly for reasons outlined later in section 2.2.1.2) to power centrifugal 

compressors on a more widespread basis than reciprocating compressors.

2

Reciprocating Gas Engines

The natural gas engine driver is currently the most common driver used in the oil and gas 

industry. 11 Reciprocating gas engines are similar to reciprocating compressors, using a cylinderpiston combination, but gas engine cylinders are filled with natural gas that is ignited and 

combusted to cause the piston to move. Gas engines are also divided into separate categories by 

speed, with the categories generally corresponding to those used for compressors, and are always 

combined with a compressor of corresponding speed.

2

Slow-speed compressors and gas engines normally come in an integrated package where 

the engine uses a common crankshaft to drive both the compressor and power cylinders. Medium 

and high speed engines come in separable packages and are connected to the compressor either 

directly or using a flexible coupling or, in smaller sizes, a belt-drive. Gas engines are also further 

divided by size into two different groups, small and large horsepower. Small horsepower engines 

are generally used for oil field services such as gas gathering, gas injection, and small gas 

processing plants. Large horsepower units are used in process plants, main line gas transmission, 

gas injection, and large gas plants. 11

Table 2.8 Typical Performance Ranges – Reciprocating Gas Engines2,11

Speed Range 

(rpm)

Size (hp) Efficiency 

Small Large (percent)

Slow speed engine 0-600 25-800 800-7000 30-43

Medium speed engine 600-900 5-400 400-3600 32-46

High speed engine 900-2100 5-400 400-3600 32-43

While modern gas engines are quite efficient, they do have power limitations, and can 

have high vibration issues that affect reliability. Also, certain components may require frequent 

maintenance, and the engine units require significant amounts of spare parts and service 

contracts.

Error! Bookmark not defined.

Gas turbines 

A gas turbine engine operates by drawing ambient air into an axial or centrifugal “high 

pressure compressor”, where work is performed and the pressure and density of the air increased. 

The high pressure air exits the compressor to a combustor, where it is mixed with natural gas and 

ignited. The high pressure exhaust from the combustion process is exhausted into the “high 

pressure turbine,” where it is expanded and used to drive the “high pressure compressor.” After 

passing through the “high pressure compressor,” the combusted air is expanded through a 

separate “low pressure turbine,” which used to drive external loads, such as a natural gas 

compression unit. Gas turbines tend to have poor efficiency at low loads, and so are most 

economically used in compressor stations with high volumes of gas flow.

11 As with most other 
technologies discussed here, gas turbines can be separated based on their size and power output 

capacity. 

Table 2.9 Typical Performance Ranges – Gas Turbines2,11

Size (hp) Power Output (MW) Efficiency (percent)

Small 600-6,000 0.5-5 24-31

Medium 6,000-25,000 5-20 27-36

Large 25,000-70,000 20-50 29-40

Electric motors 

Electric motors are the most widely used compressor drivers when considering air and 

process compressor applications, but they are the least commonly used driver for natural gas 

transmission and distribution, for two primary reasons:

1. Natural gas compressors must be able to operate at variable speeds, so most electric 

motors will require variable frequency drives, which significantly increase the initial 

purchase and maintenance costs.

2. Electric motors of the size used in natural gas applications require a reliable source of 

electric power supply, which is frequently not available and is costly to install. 

Despite these issues, electric motors are being used more frequently than before due to 

environmental considerations, because they do not have any (local) emissions.11 There are three 

major types of electric motors, induction, synchronous, and direct current (DC). Synchronous 

motors are the most commonly used motor type for compressor applications, because it is the 

most efficient of the three. However, DC motors are becoming more popular because they do not 

require a variable frequency drive to operate at different speeds, reducing operating cost.

Table 2.10 Characteristic Electric Motor Efficiency11

Efficiency (percent)

Induction 85-95

Synchronous 93-97

Direct Current 85-95

2.2.1.3 Compressor Selection Factors

Determining which compressor is technologically appropriate for an application requires 

consideration of several factors. Among them are pressure, flow, location, and demand profile. 

The discussion that follows identifies issues that DOE will likely consider in its screening 

analysis, described in section 3. Areas of concern include: technological feasibility; practicability 

to manufacture, install, and service; adverse impacts on product utility or product availability to 

consumers, and; adverse impacts on health or safety. Selection factors based on solely economic 

criteria (such as first cost) are considered elsewhere in the rulemaking analysis.
Pressure

The natural gas distribution network operates at a wide range of pressure levels. Because 

different compressor technologies are physically more efficient at different pressure levels, they 

may be more attractive to operators at different points on the grid. In general, reciprocating 

compressors offer the greatest single-unit pressure rise capability, followed by centrifugal 

compressors, and then by axial compressors.

Making generalization more difficult is the practice of staging, or putting compressors in 

series to multiply the pressure rise of each unit. Centrifugal compressors are regularly strung

together (“compressor chain”) to achieve higher net pressure ratios than could be practically 

achieved by each unit alone. In certain cases, centrifugal compressors may be retrofitted with 

modified impellers if an operator expects prevailing pressure levels to be different than those 

anticipated when the unit was installed. This may improve overall pipeline efficiency.

Reciprocating compressors can be similarly operated in series to achieve greater overall 

pressure rises. Some products are built modularly, so that an operator whose desired pressure 

level changes can retrofit the unit to do exactly this. Additionally, certain reciprocating 

compressors are capable of changing pressure ratio by varying effective displacement, 

commonly by modifying the head end of the cylinder. This changes the ratio of swept to unswept

volume – the primary determinant of flow rate in reciprocating compressors.

One subtlety inherent in discussing pressure is the difference between pressure ratio and 

absolute output pressure. Energy consumption is driven more by pressure ratio, which reflects 

how much work the compressor performs on a gas. All compressors within the scope of this 

discussion, however, operate relative to a roughly constant ambient pressure, which may drive 

secondary design specifications. For example, a compressor operating at high pressure may need 

to be constructed more durably than one at lower pressure to withstand the negative (relatively) 

pressure of the atmosphere, even if both units are imparting identical pressure rises to the natural 

gas.

Output Flow

Gas flow requirements strongly influence compressor selection. For a given power level, 

lower pressure rise implies greater output flow. As with pressure, certain technologies operate 

more efficiently at different flow rates.

Complicating the consideration is the ability to operate compressor units in parallel, 

which linearly multiplies output flow. In some cases, operators may opt to employ smaller units 

in parallel when a larger unit may be more efficient at full load, both to create redundancy in the 

event of failure of one unit and so that the station may operate more efficiently at reduced load 

levels by switching off one unit or the other. In In that case, one or more compressors may be 

turned off until needed.

A special case of paralleling compressors comes with hybrid stations, when compressor 

units of different types may be operated together so that the station exhibits relative benefits of 

each technology. For example, a high-reliability centrifugal compressor may be paired with a 
reciprocating compressor with a flatter efficiency/load characteristic. In that case, the centrifugal 

unit would be used to meet base load demand, and the reciprocating would be used to trim up or 

down in response to time-localized demand variations.

Reciprocating compressors are capable of changing flow by varying the effective 

displacement, commonly accomplished by adding clearance volume to the head end of a cylinder

or to the crank/frame end of a cylinder, deactivating one end of a cylinder, or with various 

combinations of these methods applied to cylinder operating in parallel.

Reliability and Maintenance

In infrastructure applications, reliability is paramount. Operators are incentivized by 

regulation and by finances to ensure that compressor stations are always able to meet end-user 

demand. 

There is interplay with location and environment. Temperature, humidity, and prevailing 

weather patterns may further increase the important of reliability. Certain locations in the 

network may also have less inherent redundancy and, therefore, require added reliability. 

Additionally, remote locations with lower service latency may also justify greater weighting of 

reliability among selection criteria.

Conceptually separate from reliability, or “unplanned maintenance,” is scheduled 

maintenance intervals. Maintenance carries a cost that is a primarily consideration in equipment 

selection.

In general, centrifugal and axial compressors are thought to require more frequent service 

than reciprocating, although the degree and expense of the maintenance may be still lower than 

that of reciprocating compressors.

13

In some cases, there may be an interplay between maintenance and efficiency. Certain 

types of seals and packing may be more efficient in terms of friction and gas leakage. But if they 

require more frequent maintenance (planned or unplanned) for example, the overall impact to 

operational efficiency may be less obvious.

Location and Environment

Compressor selection may be influenced by environmental factors, such as temperature, 

humidity, altitude, and weather patterns. Beyond those, location requires several other 

considerations.

Proximity to population may set limits on emissions, or on acoustic noise created by the 

compressor that would be less important for remote stations. Proximity to electrical power, and 

the ability to sell cogenerated electricity to the grid, is foremost in evaluating the suitability of 

electric motors as prime movers and implementing heat recovery (see section 2.2.4.3) 

technology. Because population centers tend to be less tolerant of emissions and acoustic noise 

and because they tend to have greater availability of electrical service, electric motors are more 

commonly found closer to metropolitan areas.
Security and resistance to damage is an important consideration in compressor station 

planning. This damage may be accidental (e.g., from construction) or intentional (e.g., terrorism). 

Security, however, may be less important when selecting specific compressor technologies

compared to the design of the overall station.

Another location-driven consideration in compressor selection may be physical space 

occupied by the unit. Dresser-Rand suggests that reciprocating compressors may occupy roughly 

triple the volume occupied by a centrifugal compressor. Because compressor stations tend to be 

located well outside of cities, however, space may be at less of a premium.13

Demand Profile

Demand profile refers to the pressure and flow outputs expected of a compressor as a 

function of time. All compressors see some variation in pressure and flow requirements, much of 

it driven by daily and seasonal demand patterns

2.2.2 Compressor Package Efficiency

It is difficult to assign operational efficiency values to compressor technologies without 

knowledge of the compressor’s unique application. However, DOE outlines some representative 

values of prime mover efficiency, compressor unit efficiency, and overall package efficiency 

(sometimes inclusive of heat recovery) in Table 2.11. For the purposes of the table, “LSR” 

means “low-speed reciprocating” and refers to speeds of 200-400 rpm, “MSR” means “mediumspeed reciprocating” and refers to speeds of 500-900 rpm, “HSR” means “high-speed 

reciprocating” and refers to speeds of 900-1200 rpm, “SEM” means “synchronous electric 

motor,” “SGT” means “small gas turbine” and refers to outputs below 6700 HP, “MGT” means 

“medium gas turbine” and refers to outputs between 6700 and 26800 HP, and “LGT” means 

“large gas turbine” and refers to outputs above 26800 HP. “SCC” means “small capacity 

centrifugal,” “MCC” means “medium capacity centrifugal,” and “LCC” means “large capacity 

centrifugal.” Electric motor efficiency contains embedded assumptions about the generation 

source and correspondingly vary based on the generation technology. Efficiency of the electric 

motor, itself, can exceed 95%, depending on power factor.

14 One factor not reflected in this table 

is efficiency across loading levels.

Three observations emerge from these data. First, the efficiency advantage enjoyed by 

low-speed reciprocating compressor units may be partially offset by the slightly lower efficiency 

of their prime movers, though this may not hold in all cases. Second, the relative advantage of 

reciprocating compressors in certain cases may be diminished at higher power levels, where 

centrifugal compressor efficiency rises. The third observation is that adding heat recovery

capability to compressors, generally only considered economic when applied to large 

compressors, appears to yield the highest overall combined efficiencies.

Table 2.11 displays characteristic efficiency values for various compressor package 

combinations, two with heat recovery.
Figure 2.1 plots prime mover efficiency as a function of horsepower based on publicly 

available catalog data for both reciprocating and centrifugal/turbine drivers.

Table 2.11 Representative Efficiencies of Various Compressor Technologies2

Compressor Unit Prime Mover Heat Recovery

CU 

Efficiency 

(%)

PM 

Efficiency

(%)

Combined 

Efficiency 

(%)

LSR LSR None 80-92 30-43 24-40

LSR SEM None 80-92 25-46 20-42

MSR MSR None 75-90 32-46 24-39

HSR HSR None 70-82 32-43 22-35

SCC SGT None 75-88 24-31 18-27

MCC MGT None 75-88 27-36 20-32

LCC LGT None 80-88 29-40 23-35

LCC LGT Organic Rankine 80-88 33-47 26-41

LCC LGT Steam Rankine 80-88 34-55 26-48

LCC SEM None 80-88 25-46 20-40
Figure 2.1 Prime Mover Efficiency by Rated Horsepower15

2.2.3 Compressor Losses

Compressor efficiency is affected by many design elements. The discussion that follows 

describes the major sources of losses which contribute to reduce a compressor’s efficiency. The

following descriptions for both reciprocating and dynamic compressors preface the discussion of 

technology options that can improve compressor efficiency – see section 2.2.4. Major sources

and mechanisms of losses are discussed primarily as they apply to reciprocating and centrifugal 

compressors.

2.2.3.1 Reciprocating Compressor Losses

Valve Losses

Of all components, valves play perhaps the largest role in determining compressor 

efficiency and reliability. Because valves are small relative to the overall cylinder, they impede

exhaust and intake flow. Additionally, valves are passive check valves. They do not open and 

close with perfect crispness, which leads to lost gas during the actuation interval (i.e., when the 

0%

10%

20%

30%

40%

50%

60%

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

Efficiency (Lower Heating Value)

Rated Horsepower

Prime Mover Efficiency (Lower Heating Value) 

vs. Rated Horsepower

Reciprocating

Centrifugal
valves are opened and closed). Finally, valves may not seat crisply when closed, but ring or 

flutter and allow small amounts of gas to pass them.16

Passage Losses

Although valves are typically the smallest diameter orifice in the flow pathway, the flow 

restriction of the cylinder itself can also contribute almost as much to total pressure drop. When 

the piston is at top dead center, the gas has only the clearance volume in which to flow. That 

clearance volume is typically small relative to the cylinder swept volume. In addition to the 

valves themselves, the pressure losses associated with the hardware needed to support and 

actuate the valves is not negligible. Finally, another flow restriction results from the location of 

the valves which are positioned on the swept volume of the cylinders (as opposed to on the 

unswept end) 16 and are often partially masked by the piston while they are flowing gas.

Pulsation Losses

As gas is drawn into and expelled from the compression chamber, pressure waves are 

created in the intake and exhaust manifolds. These waves, and their harmonics, are reflected by 

the geometry of the manifold and eventually return to the valve. Depending on when the valve 

opens next, the propagating wave can aid or hinder the intake or expulsion of gas. For example, 

the high pressure wave created by the compressor discharge will reflect and return to the cylinder 

exhaust valve. If the pressure peaks when the exhaust valve opens, the prime mover will work 

harder to expel gas (or expel less gas for the same work). Conversely, if the exhaust valve 

opening coincides with the arrival of a pressure trough, the gas will more easily flow out. 16

The dampening of pulsations, which must be done to control time-variant pressure forces 

to safe levels on compressor manifolds, piping and pressure vessels in both the intake (suction) 

and exhaust (discharge) segments of the reciprocating compressor system, cause pressure losses 

that must be overcome by the compressor. Dampening is typically accomplished with 

combinations of expansion bottles, choke tubes, choke-volume filters, and orifice plates, all of 

which create static and dynamic pressure drop. The dynamic pressure loss is a more significant 

factor on the higher speed reciprocating compressors that are prevalent today.

Heat Transfer Losses

Compressors are not perfect adiabatic devices, and in practice heat transfer occurs. As the 

compressor operates and rises in temperature, heat is conducted through the body and into the 

suction passage. Cool gas entering the passage begins to draw heat from the passage wall, 

reducing gas density and compromising efficiency. This process continues as the gas is drawn 

into the cylinder, where it is further heated by the relatively warmer discharge end of the cylinder 

which is also heated by the frequent outflow of hot, pressurized gas.16

Leakage Losses

Reciprocating compressors use seals to physically separate the high-pressure area from 

the atmosphere. How tightly the seals and rings should hug the shaft and piston is an engineering 

challenge. Too tight, and the shaft will experience more friction. Too lose, and gas more quickly 
leaks. In addition, valves do not seat instantaneously or perfectly and, therefore, permit some 

escape of gas. When gas leaks, whatever energy was used to compress it also disappears. 

Furthermore, capacity is reduced by the amount of compressed gas that leaked instead of making 

its way into the outgoing pipeline section.

On the suction side, there is a further penalty. In addition to the capacity-reduction effect 

just mentioned, gas leaking through the suction port will be hotter than the gas it finds on the 

other side. As the cool gas heats, it loses density and becomes more difficult to compress. The 

compressor, then, must perform more work for lower output.

Leakage around piston rings is straightforward in a single-acting scheme, where the gas is 

merely wasted. In a double-acting compressor, the piston functions similarly to a valve in that it 

seals off high-pressure from low-pressure. Leaking gas, therefore, drops pressure in the high side 

(where it is desired), boosts pressure in the low side (where it is not desired), and also creates the 

undesirable heat transfer present in the case of the suction valve. Compressor capacity falls, 

required work rises, and efficiency is negatively affected.

Flow Control Losses

Reciprocating compressor flow is frequently controlled by suction pressure throttling, 

especially in upstream applications, but also in transmission stations. In this case the pressure 

into the compressor cylinder is intentionally reduced by a throttling valve. This reduces the 

density and therefore the flow rate of the cylinder. Depending on the cylinder compression 

(pressure) ratio, throttling may decrease or increase the required compression power, but it 

always reduces the efficiency. 

Gas recycling is the process of taking a side stream off the discharge line from the 

compressor and, after cooling the gas, connects it back to the compressor suction. The amount of 

gas recycle is controlled by a recycle valve. This process controls the flow from a unit or station, 

however it is extremely inefficient as almost all of the work input in compressing the recycled 

gas is wasted energy. Gas recycling is common on process compressor applications, but less 

prevalent in transmission applications.

2.2.3.2 Dynamic Compressor Losses

The key aerodynamic components in the centrifugal compressor are the inlet, inlet guide 

vane, impeller, diffuser, return channel, volute, and sidestream.17 All new energy enters the 

compressor via the impeller, making it the heart of the system.

18 The impeller is the rotating 

component that applies torque, accelerates the gas and imparts kinetic energy in the way of 

velocity and potential energy in the form of pressure. The inlet inducer is a section of the 

impeller that transforms axial flow at the inlet to radial flow. Inlet guide vanes direct the flow to 

the inducer at the right rotor inlet angle.

The diffusers are the second most important aerodynamic component in a compressor.17

As gas leaves the rotor it enters the diffuser at an angle that depends on the rotor’s geometry and 

velocity. The primary purpose of the diffuser is to convert kinetic energy into more potential 

energy and to efficiently increase the static pressure.18 Centrifugal compressor diffusers can be 
vaned on vaneless.17 A vaneless diffuser is generally a simple flow channel with parallel walls 

and without a means to guide the flow. In contrast, vaned diffusers are designed to guide the gas 

flow to achieve specific operating conditions.

18 Vane design involves balancing efficiency with 

operational flexibility. Vaneless diffusers generally exhibit a wider range of operating flows 

whereas vaned diffusers allow a compressor to reach higher levels of peak efficiency.17

Superior aerodynamic designs are the key to reducing losses in centrifugal compressors.

Three-dimensional Computational Fluid Dynamics (CFD) codes are the most rigorous analytical 

techniques that can be used to calculate the flow through aerodynamic components such as 

impellers and diffusers. One important aspect in this process is the correct simulation of the 

various losses.19

The estimation of centrifugal compressor performance and of the potential benefit of 

design improvements necessitates a rigorous examination of the various types of losses that exist 

within a compressor. These losses are typically expressed in terms of a reduction in total 

pressure.18 Botha and Moolman categorized the primary sources of loss in centrifugal 

compressors, dividing loss mechanisms into two main groups, (1) internal loss mechanisms and 

(2) parasitic loss mechanisms. Internal loss mechanisms are associated with losses emanating 

from the main flow through the compressor, which impacts both the efficiency and the pressure 

ratio that can be achieved by the compressor. Internal losses include the incidence loss at 

impeller entry, impeller flow losses (i.e. the blade loading loss, skin friction loss and clearance 

loss) and the mixing loss at the impeller exit. The main parasitic losses include the (1) disc 

friction loss, (2) recirculation loss and (3) leakage loss.19

Internal Loss Mechanisms

The details of the impeller geometry or shape are crucial to achieving good efficiency. 

One such factor is the blade leading edge angles or, more specifically, the blade leading edge 

incidence. Incidence is defined as the difference between the relative flow angle of the gas as it 

approaches the rotating impeller blade and the impeller blade angle. The incidence loss occurs 

when the relative fluid flow angle of the fluid entering the impeller deviates from the actual 

blade inlet angle. This means that the fluid has to change direction immediately, resulting in a 

significant loss in energy.19

Three groups of losses result from fluid movement over the impeller. The blade loading 

loss results from the momentum loss due to boundary-layer build-up on the blade surfaces19

causing the flowing fluid to experience a smaller exit area.18 The skin friction loss is the loss 

experienced due to the adhesive forces between the channel surfaces and the fluid. The channel 

surfaces are those surfaces created by the hub, blades and shroud. Clearance losses arise from the 

need to allow free rotation by means of a finite clearance between the impeller and the stationary 

casing. Typically fluid will leak through this gap (between the blade tip and casing) from the 

higher pressure on the pressure side of the blade to the lower pressure on the suction side of the 

blade. This mixing of the two fluid flows results in the formation of a loss-inducing small vortex 

on the suction side (low pressure region) of the impeller vane outer tip.19

After the flow has left the impeller, the primary (flow proceeding directly from the 

impeller) and secondary (flow traveling along the direction of the housing, having separated 
from the impeller at an earlier point in time) flows mix, but not with perfect smoothness, 

resulting in lost energy referred to as the “mixing loss”. In a centrifugal compressor impeller this 

is traditionally called slip, as it appears that the flow field has slipped against the direction of 

rotation from the pressure to the suction side. Whether the compressor has a vaned diffuser or 

not, there is always a vaneless space directly following the impeller where the flow is diffused.. 

As a result of friction and other factors, a loss, referred to as the vaneless diffuser loss, is 

experienced.19 Compressors featuring vaned diffusers will also experience vaned diffuser losses, 

which occur as a result of skin friction and incidence losses due to the vanes.18

Parasitic Losses

Disc friction is a major source of parasitic loss. Disc friction loss in a centrifugal 

compressor is caused by the friction in the gas flowing in the gap between the impeller back wall 

and the casing wall. Other major parasitic losses include: the losses in the seals, the bearings, and 

the gear box. Often, these losses and disc friction are referred to collectively as “external loss.”

18

Another type of parasitic loss is recirculation. Recirculation losses occur as the flow turns 

around after leaving the impeller and recirculates back into the impeller section.19 Some of the 

flow exiting the impeller leaks through the clearance gaps and seals to the lower pressure regions 

of the compressor, causing the leakage loss.19

Botha and Moolman simulated losses over a typical mass flow range. They found the 

mixing and the vaneless diffuser losses dominating the internal losses. These losses were 

followed in importance by skin friction, clearance and leakage losses.19

Flow Control Losses

Centrifugal compressor operation is characterized by an operating map that has a 

minimum permissible flow rate at each speed and head or pressure ratio combination in order to 

avoid operating the compressor in surge. Surge is an unstable flow phenomenon that damages 

the compressor internal components. Surge is most commonly avoided in centrifugal 

compressors, by recycling gas when the flow rate is nearing the minimum safe level. Gas 

recycling is the process of taking a side stream off the discharge line from the compressor and, 

after cooling the gas, connecting it back to the compressor suction. The amount of gas recycle is 

controlled by a recycle valve. This process is extremely inefficient as almost all of the work 

input in compressing the recycled gas is wasted energy.

Centrifugal compressor flow may also be controlled by suction pressure throttling. In this 

case the pressure into the compressor cylinder is intentionally reduced by a throttling valve. This 

reduces the density and therefore the flow rate of the compressor. Throttling increases the head 

required from the compressor for a given flow rate and therefore reduces the efficiency. 
2.2.4 Technology Options for Improving Efficiency

Compressor efficiency can be increased by improving the technology used in the design 

and manufacturing processes. Based on its preliminary review, DOE identified the following 

technology options as having the potential to improve compressor efficiency.

2.2.4.1 Improving Compressor Unit Efficiency

Valves (Reciprocating Compressors)

Reciprocating compressors rely upon a closed chamber to perform compression, but then 

must somehow expel the gas and intake new gas in order to repeat the process. Normally, this is 

done using valves. As the gas traverses the valve, however, it encounters flow resistance that 

causes pressure loss and requires the prime mover to work harder than if the valves were not 

required. Furthermore, valves are normally held closed using springs, which require energy to 

open. Finally, valves in practice do not open and close instantaneously and crisply, but may 

“bounce” and allow some gas to slip past what would ideally be a tight seal. Simple enlarging 

valves would seem to enhance flow. However, a practical limit is set by the fraction of the 

cylinder that can be dedicated to valves. Additionally, larger valves would tend to grow in mass, 

and exhibit larger losses in actuation and ringing.16

A number of efforts exist to improve valve performance. For example, Zahroof Valves 

claims to offer a 20% increase in valve efficiency (by allowing gas to flow with fewer changes of 

direction) and 10% reduction in compressor input power.

20 If so, it would suggest that valves 

account for a significant fraction of compressor power loss. However, these figures may pertain 

to retrofit applications on older units with valves less efficient than those on modern equipment.

Multistaging (All Technologies)

Although the objective of a compressor is to introduce pressure rise into a gas, 

accompanying temperature rise is inherent, even if the machine adds no heat energy. In practice, 

all compressors add some amount of heat energy. From that comes the practice of describing 

compressor efficiency relative to an ideal unit that adds no heat energy to the gas (i.e., an 

isentropic compressor). As compression is performed, each incremental bit of heat energy causes 

the rest of the compression process to become less efficient – the prime mover must work harder 

to overcome it. As a result, compression process efficiency could be enhanced by pausing 

midway, removing heat energy, and then completing the process.

This is essentially what occurs in multistage compression units, which are commonly 

intercooled (i.e., discard heat before the second compressor inlet). With intercooling, a 

compression process becomes mathematically closer to the physical ideal. The addition of two or 

more stages, each intercooled, is already a common practice used to increase compressor

efficiency. Without mentioning cost, however, the marginal benefit to doing so declines because 

of the inherently lower efficiency of smaller compressors and because each stage introduces new 

pumping losses as gas is routed from one stage to the next.16
In practice, adding additional compressors where not required by other aspects of an 

application may add cost, complexity, and maintenance that could deter an operator from opting 

for multistage units.

Pressure Wave Optimization (Reciprocating Only)

As gas is drawn into and expelled from the compression chamber, pressure waves are 

created in the intake and exhaust manifolds. Those waves, and their harmonics, are reflected by 

the geometry of the manifold and eventually return to the valve. Depending on when the valve 

next opens, the propagating wave can aid or hinder the intake or expulsion of gas. For example, 

the high pressure wave created by the compressor discharge will reflect and return to the cylinder 

exhaust valve. If the pressure peaks when the exhaust valve opens, the prime mover will work 

harder to expel gas (or expel less gas for the same work). Conversely, if the exhaust valve 

opening coincides with the arrival of a pressure trough, the gas will more easily flow out. 16

Complicating the design of such a system is geometric complexity of the manifolds, 

varying intake and exhaust pressures (that alter wave velocity), and variation in compressor 

speed which alters the time between valve openings. To address these factors, some groups have 

introduced actively-tuned manifolds that can vary their natural frequencies in response.

Pressure wave optimization can lower pipeline energy costs by over 20%,21 though it is 

unclear how much of that savings is in the compressor, itself. Additionally, it is unclear whether 

that figure applies to retrofits only, or whether new compressors would also see benefits from the 

technology.

Operating Speed (Reciprocating)

Reciprocating compressors are designed to operate at a range of speeds, usually described 

as crankshaft revolutions per minute (rpm). Although high-speed (roughly, above 900 rpm) 

reciprocating compressors can be smaller for a given power output (and may have an 

accompanying lower installed cost), some sources suggest that it may come at a cost to

efficiency.13

One reason for this is increased pumping losses. If faster, smaller units have 

correspondingly smaller valves, gas flow will be restricted. Compounding that effect is the fact 

that gas must enter and leave the cylinder more quickly, and flow at higher velocities. Because 

fluid flow resistance rises on the order of velocity squared, even a modest increase in gas 

velocity may increase pumping losses significantly. CAGI suggests that the valve losses alone 

may rise 20% relative to slower units, though it acknowledges that value may be imprecise.

11

Beyond pumping losses, higher-speed units may be more prone to vibration issues, and 

require that additional balancing measures be added to mitigate that vibration. In certain cases, 

these measures may come at the expense of efficiency.13

Variable Vane Geometry (Centrifugal)
One limitation of centrifugal compressors relative to reciprocating units is reduced 

tolerance of off-speed operation. At low flow rates, compressors can “surge,” wherein pressure 

from the discharge causes flow to reverse, which can damage the unit. Additionally, a 

compressor at the upper limit of its flow capability can “choke,” and be unable to draw enough 

gas to function. Normally, large compressors like those used in pipeline applications contain 

equipment to prevent damage to the unit. However, off-speed operation, even short of choke or 

surge, can result in inefficient gas flow.

One technology that has been developed to overcome this limitation is variable vanes. 

Vanes can be installed on either the inlet or the exhaust side of the compressor impeller, and 

serve to change the angle of gas flow so that it can be more efficiently handled by the impeller

and/or the diffuser. However, the angle at which peak efficiency is reached varies according to 

flow rate. Variable vane geometry allows that angle to be adjusted in step with compressor 

output; so that efficiency is boosted across the unit’s operating range. 17

Variable vane geometry does not necessarily improve peak efficiency of the unit (and 

may slightly decrease it). As a result, it may not be useful or economically justifiable for those

units operating at a fixed speed for a base loadp capacity.

Dry Gas Shaft Seals (Centrifugal)

Shaft seals in centrifugal compressors separate the high-pressure volume of the unit from 

the ambient. Seals must be tight enough to prevent gas leakage, but freely spinning to avoid 

harming compressor efficiency. Historically, most seals used oil as a lubricant and sealant. 

However, such seals require an oil circulating apparatus to remove gas that had dissolved into the 

oil and re-inject the oil into the seal. In contrast, dry gas seals replace oil with a high-pressure 

chamber of air or inert gas that resists the outflow of high-pressure natural gas from the 

compression chamber. Such seals are thought to carry reduced maintenance requirements in 

addition to reducing gas loss. In addition, they may bolster efficiency by exerting less drag on the 

spinning impeller.22

Intelligent Flow Control Systems (Reciprocating)

Reciprocating compressor flow can be controlled efficiently through the use of various 

hardware devices that automatically adjust clearance volume, adjust valve behavior, or 

deactivate ends of individual compressor cylinders. The operation of these devices in 

combinations one or more cylinders as pressure, temperature and speed conditions change must 

be done so as to optimize the efficiency, while simultaneously keeping the compressor operating 

within safe limits of rod load, pin reversal, power, volumetric efficiency, etc. This requires 

efficient “unloading” hardware and smart control systems in order to effectively manage the 

efficiency and safety of the compressor at all operating conditions. A number of hardware 

devices and at least one smart control are available for application to reciprocating compressors. 

This technology is applicable to upstream, transmission, storage and process reciprocating 

compressors of all sizes. It is more widely used in pipeline applications than elsewhere, being 

p Here, “base load” refers to the portion of consumer demand that varies little with time.

 
rather uncommon in the upstream applications where inefficient suction throttling and recycle 

operation is prevalent.

Efficient Pulsation Control (Reciprocating)

The GMRC and other sources have developed technologies that reduce or eliminate the 

pressure drop and efficiency losses associated with pulsation control. These involve technologies 

such as pulsation attenuation networks, tunable side branch absorbers and virtual orifices that 

cancel pulsation waves, rather than dampen them. Other technologies that have emerged are 

methods of dynamically changing the pulsation dampening orifice size as operating conditions 

change, which has the potential to optimize the trade-off between pulsation control and 

efficiency. All of these technologies are in the early stages of practical application in the field.

2.2.4.2 Improving Prime Mover Efficiency

Turbocharging (Reciprocating)

Turbochargers use smaller centrifugal compressors and turbines to enhance power output 

of reciprocating compressors. The turbine is installed in the exhaust stream and extracts energy 

from the flow, while the compressor pre-compresses ambient air before it enters the power 

cylinder. In addition to increasing unit power density, turbocharging may increase engine 

efficiency by utilizing heat that would be otherwise wasted.23 Conceptually, turbocharging is a 

form of heat recovery, though it is listed outside of that section because the recovered energy is 

fed directly into the engine.

Turbocharging may also buffer a compressor against reduced efficiency on hot days, 

when the less-dense ambient air diminishes the output power of the engine.

Higher Speed (Reciprocating)

In contrast to high-speed reciprocating compressors, high-speed reciprocating engines 

may tend to be more efficient than their low-speed and centrifugal counterparts.13 Less clear is 

whether this is inherent in the operating principles, or whether it is a result of manufacturers 

focusing on improving efficiency in high-speed units, which may carry greater appeal to 

customers for their (generally) lower cost. Nonetheless, Table 2.11 suggests that, at least at small 

capacities, high- and medium-speed engine efficiency may exceed that of low-speed engine 

technology.

Air/Fuel Controls (All Technologies)

One operating parameter for combustion engines is the air/fuel ratio. In general, low 

ratios produce more power for a given compressor size, but are less fuel efficient. Additionally, 

which ratio is optimum may vary based on the heat content of the fuel gas, which can differ 

significantly based on the gas origin. Adding air/fuel controls and exhaust sensors can enable 

compressors to operate more efficiently across different operating conditions. Rich-burn, highspeed reciprocating engines, in particular, may see the greatest benefit from such controls.24
Advanced Ignition Systems (Reciprocating)

Reciprocating engines rely on an ignition source to initiate combustion. Certain ignition 

strategies may offer the ability to accelerate combustion and ignite higher air/fuel ratios than 

would be possible with traditional ignition strategies. In general, higher air/fuel ratios offer 

reduced fuel consumption (and NOx production), perhaps as much as 3%.25

Inlet Air Cooling (Gas Turbine)

Higher ambient air temperatures reduce density of the air being ingested by a gas turbine, 

in turn diminishing power output and efficiency.9 Various inlet air cooling strategies have been 

developed for mitigating that effect, and keeping a turbine closer to its efficient operating point, 

including fogging, evaporation, vapor compression heat pumping, and (less commonly) 

adsorption. In addition to maintaining efficient operation in a turbine in service, inlet air cooling 

may enable specification of a smaller compressor. Instead of meeting peak demand with pure 

compressor capacity (and, in turn, operating off-design on colder days), turbine inlet cooling may 

be able to efficiently make up the difference in power output.26

2.2.4.3 Heat Recovery (Centrifugal and Reciprocating)

Both compressor units and prime movers alike expel waste heat while operating. 

Depending on the grade of the heat and location of the compressor, it may be economical to use 

waste heat directly or to generate electrical power. A variety of working fluids can be used for 

heat recovery cycles, including steam, pentane, and supercritical carbon dioxide.q

Heat recovery capability can be designed into compressor stations, or added later without 

disrupting compressor station function. INGAA suggests that heat recovery is more viable for 

large compressor stations with high annual load factors, and estimates that between 500 and 600 

MW of generation capacity would be possible.9 Both centrifugal and reciprocating compressors 

can be used with heat recovery. However, centrifugal compressor packages are usually more

economically attractive, as they are often paired with gas turbines, which typically have a higher 

exhaust temperature.

The savings potential can be considerable. One compressor station in Louisiana 

recovered 4.6 MW of electrical energy, which represented over 25% of the turbine’s rated 

power.9 As a point of reference, operators may realize a 3-year investment payback if able to sell 

generated electricity at 5 cents/kWh.27

Currently, a company called ORMAT claims to be the only provider of energy recovery 

systems on gas pipeline compressors.r However, other technologies that are heat-source neutral

could, in theory, be deployed in similar applications. Echogen Power Systems offers a heat 

recovery system using supercritical carbon dioxide, claimed to be suitable for a range of power 

and temperature levels that would include most natural gas compressors.28

q Here, “supercritical” refers to a realm of pressure and temperature wherein gases and liquids cease to be 

distinct and, therefore, no boiling or condensing can occur. This property can save energy in certain applications. r See Ormat Technologies, Inc.

 
Although electrical power generation from waste heat requires certain temperature levels 

to be practically efficient, it is possible to use lower-grade heat for space heating, water heating,

or various industrial processes that require it. Although straightforward to implement, direct heat 

use requires that there be a demand for the heat, which usually correlates to human population. 

Because many compressor stations (particularly larger ones, where heat recovery is more 

practical) are located away from population centers, direct heat use may not be commonly 

implemented on natural gas compressors.

2.2.4.4 Improving Gas Efficiency

Almost all compressors lose some fraction of the natural gas they process to the 

atmosphere. Although not directly measured in most efficiency metrics for compressors and 

prime movers, lost natural gas can be viewed as a form of inefficiency. When gas is lost, the 

energy used to compress and transport that gas is lost alongside it. In 1992, compressor station 

emissions accounted for 16% of natural gas emissions of the oil and gas industry, which, itself, 

accounted for 14% of global anthropogenic emissions.29

Reduce Blowdown Frequency

Whether blowdown meaningfully contributes to a compressor’s annual lost gas total 

depends directly on how frequently blowdown occurs. EPA suggests that for a typical 

transmission compressor (reciprocating), a blowdown roughly every two weeks would jettison a 

volume of gas equivalent to what is lost via rod packings annually.29 Blowdown normally occurs 

when a compressor is unneeded and switched off and when maintenance is required. Although 

the former event is largely a function of network factors external to the compressor, reducing the 

need for maintenance could contribute to gas efficiency by shrinking blowdown frequency.

Dresser-Rand suggests that motors offer the longest intervals between overhaul, followed 

by reciprocating compressors and then centrifugals.13 With respect to unscheduled maintenance, 

however, centrifugal units outperform reciprocating units.13 Service intervals and unscheduled 

maintenance may both be improved by using modern valvest

, magnetic bearingsu, and sensors 

that monitor vibration patterns and exhaust for signs of impending failure.v

When compressors are stopped but not required to blow down for maintenance, it is 

possible to maintain pressure until the unit is needed again. Reciprocating compressors in 

particular exhibit greater losses when stopped, but static sealing devices may be engaged to 

mitigate this loss.29 To a lesser degree, centrifugal compressors also lose gas when stopped.

Blowdown Gas Recovery

Eliminating blowdowns altogether is likely infeasible. However, it is possible to attempt 

to recover the gas blown down, either for storage until the compressor goes online or for 

s “Rod packing” is the material surrounding a piston rod in a reciprocating compressor that prevents gas 

from escaping around the rod. t

See Zahroof Valves. u See http://www.waukbearing.com/uploads/NAM_Canned_Magnetics_Case_Study_US_bleed.pdf. v See http://www.altronic-llc.com/detonation-sensor-monitoring.shtml.

 
reinjection into the incoming pipeline. Some sources suggest payback from implementation of 

such technology may fall between 1 and 3 years.30

Low-emission Rod Packing (Reciprocating)

Various rod packing technologies exist to reduce gas leakage along the shaft of a 

reciprocating compressor.31 Normally, the seals and rings are made from advanced materials, for 

example, carbon-impregnated Teflon in place of bronze.32 One manufacturer claims to have 

developed an oil-flooded system that virtually eliminates packing leakage, and to have 

successfully demonstrated this system at several sites in Europe successfully for 30,000 

operating hours.33

Dry Shaft Seals (Centrifugal)

Shaft seals in centrifugal compressors separate the high-pressure volume of the unit from 

the ambient atmospheric pressure. Seals must be tight enough to prevent gas leakage, but freely 

spinning to avoid harming compressor efficiency. Historically, most seals used oil as a lubricant 

and sealant. However, such seals required an oil circulating apparatus to remove gas that had 

dissolved into the oil and re-inject the oil into the seal. In contrast, dry gas seals replace oil with 

a high-pressure chamber of air or inert gas that resists the outflow of high-pressure natural gas 

from the compression chamber. Such seals are thought to carry reduced maintenance 

requirements in addition to reducing gas loss.1622 Therefore, compressors with dry gas seals may 

need to be less frequently blown down for maintenance.

Non-seal Leak Sources

In addition to seal leakage, natural gas compressors emit uncombusted gas from other 

compressor componentry, including compressor isolation valves, pressure relief valves, valve 

stems, pump seals, and other connections and fittings. Nearly any joint, improperly installed or 

maintained, is a gas leak candidate. EPA suggests that these sources, in aggregate, may exceed 

seals in overall volume of leaked gas.29

Hermetic Sealing

Instead of replacing various compressor componentry with improved versions that leak 

less, some manufacturers offer outright hermetic sealing. This practice is common on small (nonnatural gas) compressors found (e.g.) in consumer appliances, but is not widespread for pipeline 

applications. MAN Diesel & Turbow and Dresser-Randx, however, advertise hermetic sealing 

with an electric motor prime mover specifically for pipeline applications, and claims the package 

produces no emissions whatsoever.

w See http://turbomachinery.man.eu/products/compressors/pipeline-compressors x See http://www.dresser-rand.com/products/turbo/datum/datumc.php

 
2.2.4.5 Auxiliary Technologies for Improving Compressor Efficiency

Fan and Pump Variable Frequency Drives

Compressors and prime movers often employ auxiliary hardware such as cooling fans 

and oil pumps to operate. Depending on operating conditions, including temperature, humidity, 

and load, demand for these auxiliary services may vary. Power fans and pumps with variable 

speed motors that can match output to demand may offer energy savings relative to lower-cost 

single-speed electric motors.

3. SCREENING ANALYSIS

The purpose of the screening analysis is to screen out technology options that DOE will 

not consider in its potential energy conservation standard rulemaking for natural gas

compressors. At the outset, DOE develops a list of technology options for consideration through 

its own research and in consultation with interested parties. Development of the list is based on 

the technologies described in section 2.2. The identified candidate technology options encompass 

all those technologies that may improve energy efficiency. 

DOE then reviews each technology option considering the following four criteria, as 

provided in sections 4(a)(4) and 5(b) of Procedures, Interpretations, and Policies for 

Consideration of New or Revised Energy Conservation Standards for Consumer Products (see 10 

CFR Part 430, Subpart C, Appendix A):

3.1 Technological Feasibility

DOE does not further consider technologies that are not incorporated in commercially 

available equipment or in working prototypes.

3.2 Practicability to Manufacture, Install, and Service

If DOE determines that the adoption of a particular technology at the mass production 

level for a given type of equipment, along with that technology’s reliable installation and 

servicing, cannot be achieved on the scale necessary to serve the relevant market by the time of 

the effective date of the standard, DOE does not consider that technology further.

3.3 Adverse Impacts on Product or Equipment Utility or Availability

If DOE determines that a technology will have a significant adverse impact on the utility 

of the equipment to significant subgroups of consumers, or result in the unavailability of any 

covered equipment type with performance characteristics (including reliability), features, size, 

capacities, and volumes that are substantially the same as equipment generally available in the 

United States at the time, it does not consider that technology further.
3.4 Adverse Impacts on Health or Safety

If DOE determines that a technology will have significant adverse impacts on health or 

safety, it does not consider that technology further.

DOE will fully document the reasons for eliminating any technology options during the 

screening analysis and solicit stakeholder comment.
APPENDIX A - LIST OF ITEMS FOR COMMENT

Item 3-1 Given the breadth of application of natural gas compressors, DOE requests 

comment on where potential cost-effective energy savings lie. Often, these exist 

where market forces do not incentivize the purchase of efficient equipment. 

Item 3-2 DOE requests comment on the scope of coverage specifically whether a gas 

compressor energy conservation standard should be inclusive or exclusive of the 

prime mover.

Item 4-1 DOE requests comment about test procedures that may be suitable for assessment 

of energy consumption in natural gas compressors. In addition to specifying 

which and how physical parameters must be measured, such a procedure should 

specify the conditions under which the measurements are taken and interpreted.

Item 4-2 DOE requests comment about whether the test procedures in ISO 1217:2009 and 

ISO 5389:2005, which address the testing of displacement and turbo compressors, 

respectively, would be appropriate for rating gas compressors. DOE also requests 

information about other applicable test procedures it should consider along with 

any deficiencies or issues that should be addressed prior to prescribing test 

procedure requirements to measure energy consumption.

Item 5-1 DOE is seeking both present and historical shipments data (specifically from 

2003-2013) for gas compressors, with further breakdowns, where available, 

including, but not limited to, equipment type (both compression principle and 

driver type), equipment size, and application. DOE is also interested in comments 

regarding how gas compressors are manufactured and shipped as original 

equipment from the manufacturer, for example, as a package (i.e., with both 

compressor and prime mover), or as a separate component, or both.

Item 5-2 DOE requests shipment information on upstream and gathering natural gas 

compressors, and how their numbers compare to those of natural gas compressors 

in other applications.

Item 5-3 DOE seeks comment on how an energy conservation standard for gas 

compressors might impact future equipment shipments.
Item 5-4 DOE is seeking comment about the types of equipment used in gas compressors. 

Specifically, DOE is interested in information regarding the compression 

principles (e.g., positive-displacement or dynamic compressors) and primary 

driver types (e.g., natural gas or steam turbines or electric motors) used in gas 

compressors, as well as what design, construction, and performance 

characteristics would be attributed to each type. DOE is also interested in 

information regarding the compression principles and driver types used in gas 

compressors based on application type.

Item 5-5 DOE is also seeking comment about how gas compressors are sized (e.g., by 

brake horsepower, input/output pressure, or delivered gas volume) and the general 

sizes of gas compressors based on both equipment and application type.

Item 5-6 DOE requests input on ways to characterize gas compressor sizing and selection 

practices for different equipment and end use applications. 

Item 5-7 DOE requests comment on the degree of gas compressor oversizing that is 

prevalent under current industry practices. Specifically, the degree to which this 

oversizing may be a factor for different end-use applications.

Item 5-8 Are gas compressors marketed and sold on the basis of efficiency? Do certain 

customers tend to purchase certain compressor types or efficiency levels? What 

makes compressors more or less efficient?

Item 5-9 DOE seeks information on any voluntary efforts by manufacturers that are already 

in place to improve the energy efficiency of gas compressors and what type of 

voluntary efforts to improve efficiency, if any, are likely to occur in the near 

future.

Item 5-10 DOE requests comment on how compressors are marketed, sold, shipped, and 

assembled, and on the various distribution channels through which gas 

compressors pass through from the manufacturer to the final end-user.

Item 5-11 DOE seeks comment on the different agents involved in the sale and installation 

of a typical gas compressor for each distribution channel. 

Item 5-12 DOE seeks comment on the share of industry shipments for each different 

distribution channel, and any differences in gas compressor design that may 

apply.

Item 5-13 DOE seeks comment of what consumer populations would be disproportionately 

affected if DOE were to adopt new energy conservation standards.
Item 6-1 DOE is aware that an important application of gas compressors is in the 

transportation, production, and processing of natural gas. DOE seeks comment on 

other major applications (e.g., injection, withdrawal, lifting, or filling) in which 

gas compressors are used. 

Item 6-2 DOE also seeks information regarding any particular characteristics or features 

that are unique to each of these different applications.

Item 6-3 DOE seeks input on gas leakage by equipment type, and on data that may help 

characterize the amount of leakage by specific source.

Item 6-4 DOE seeks input on technologies available to reduce gas leakage, including the 

cost effectiveness and applicability of each. 

Item 6-5 DOE requests specific comment on compressor blowdown, including estimated 

leak volume, technologies able to reduce blowdown frequency and capture the gas 

blown down.

Item 6-6 DOE seeks comment regarding the typical energy use of gas compressors broken 

down by, where available, application type, equipment type, and equipment size.

Item 6-7 DOE seeks recommendations on sources of data, or analysis methods that would 

provide demand profiles for gas compressors and their end-use applications. 

Further, DOE seeks comment on what gas compressor design features would 

affect their typical demand profile.

Item 6-8 DOE seeks recommendations on sources of data or analysis on the fraction of 

time, in hours, per year that gas compressors spend at off-design (efficiencies 

other than the specified design point) operation under normal operating 

conditions.

Item 6-9 DOE seeks comment on the types, and rate of adoption, of different control 

systems that are employed to adjust a gas compressor’s output to meet end-use 

application demands during off-design operation.

Item 6-10 DOE is interested in information about the typical range in efficiency levels of 

gas compressors broken down by equipment type and size, and why the range 

exists. For example, do more efficient compressors incorporate particular design 

features?

Item 6-11 DOE seeks comment about how gas compressor efficiency is likely to change 

over time in the absence of standards.

Item 6-12 DOE is interested in what opportunities, if any, for improving gas compressor 

energy efficiency are possible. 
Item 6-13 DOE requests comment about any compressor features that represent usefulness 

to the user, such as pressure, flow, fuel type, physical size, portability, 

serviceability, emissions, and acoustic noise, and on applications in which 

particular forms of utility may be especially important. Additionally, how would 

an effort to increase energy efficiency of a compressor affect these features?

Item 6-14 DOE seeks comment about whether installation costs for gas compressors change

with higher efficiency equipment. If so, DOE seeks comment about the reasons 

for, and the amount of, such an increase.

Item 6-15 DOE seeks comment about whether maintenance costs for gas compressors 

change with higher efficiency equipment. If so, DOE seeks comment about the 

reasons for, and the amount of, such a change.

Item 6-16 DOE seeks comment about whether repair costs for gas compressors changes with 

higher efficiency equipment. If so, DOE seeks comment about the reasons for, 

and the amount of such a change.

Item 6-17 DOE recognizes that gas compressors can have a very long mechanical lifetime 

(hours of operation). While many factors contribute to equipment lifetimes, DOE 

seeks data about the mechanical lifetimes for gas compressors under typical 

operating conditions. Further, DOE seeks comment about whether differences in 

equipment design or capacity would affect gas compressor lifetimes.

Item 6-18 DOE seeks recommendations on sources of data or analysis methods correlating 

gas compressor maintenance and repair with gas compressor lifetime and 

efficiency.

Item 7-1 DOE is interested in how efficiency improvements would impact equipment 

performance, features, utility or safety.
APPENDIX B - REFERENCES

1 Interstate Natural Gas Association of America. Interstate Natural Gas Pipeline Efficiency. 2010. 

Interstate Natural Gas Association of America: Washington, DC. 

http://www.ingaa.org/File.aspx?id=10929

2 Interstate Natural Gas Association of America. Interstate Natural Gas Pipeline Efficiency. 2010. 

Interstate Natural Gas Association of America: Washington, DC. 

http://www.ingaa.org/File.aspx?id=10929

3 Wilcox, Melissa, Klaus Brun, Ph.D. Guideline for Field Testing of Reciprocating Compressor 

Performance. 2009. Gas Machinery Research Council: Dallas, TX. 

https://www.gmrc.org/documents/GuidelineforFieldTestingofReciprocatingCompressorPerformance.p

df

4 Brun, Klaus, Ph.D., Marybeth G. Nored. Guideline for Field Testing of Gas Turbine and Centrifugal 

Compressor Performance. 2006. Gas Machinery Research Council: Dallas, TX. 

https://www.gmrc.org/documents/GuidelineforFieldTestingofCentrifugals.pdf

5 Interstate Natural Gas Association of America. Interstate Natural Gas Pipeline Desk Reference. 2009. 

Interstate Natural Gas Association of America: Washington, DC.

http://www.ingaa.org/File.aspx?id=6070

6 Environmental Protection Agency. Reduce Your Methane Emissions. 2014. Environmental Protection 

Agency: Washington, DC. http://www.epa.gov/gasstar/index.html

7 Energy Information Administration. About U.S. Natural Gas Pipelines – Transporting Natural Gas.

2007. Energy Information Administration, Office of Oil and Gas: Washington, DC. 

http://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/fullversi

on.pdf

8 U.S. Environmental Protection Agency Office of Air Quality Planning and Standards. Oil and Natural 

Gas Sector Compressors. 2014. Environmental Protection Agency: Washington, DC. 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415compressors.pdf

9 Hedman, Bruce. Waste Energy Recovery Opportunities for Interstate Natural Gas Pipelines. 2008. 

Interstate Natural Gas Association of America: Washington, DC. 

http://www.ingaa.org/File.aspx?id=6210

10 ICF International. North American Midstream Infrastructure through 2035: Capitalizing on Our Energy 

Abundance. 2014. INGAA Foundation: Washington, DC. http://www.ingaa.org/file.aspx?id=21498

11 Compressed Air and Gas Institute. Compressed Air and Gas Handbook, Ch. 7 – Gas and Processes.

2013. Compressed Air and Gas Institute: Cleveland, OH. 

http://www.cagi.org/education/handbook.aspx#

12 Deffenbaugh, Danny, Klaus Brun, Ph.D., Ralph Harris, Ph.D., J. Pete Harrell, Robert McKee, J. Jeffrey 

Moore, Ph.D., Steven Svedeman, Anthony Smalley, Ph.D., Eugene Broerman, Robert Hart, Marybeth 

Nored, Ryan Gernentz, and Shane Siebenaler. Advanced Reciprocating Compression Technology 

(ARCT). 2005. Southwest Research Institute: San Antonio, TX. 

http://www.netl.doe.gov/File%20Library/Research/Oil-Gas/Natural%20Gas/NT42269_FG093005.pdf

 
13 Potter, Randy. Don’t Retire... ReHire! The use of Integral Slow Speed Engines as Horsepower 

Expansion. 2005. Dresser-Rand: Houston, TX. https://www.dresser-rand.com/techpapers/tp141.pdf

14 WEG Electric Corp. Synchronous Motors. 2014. WEG Electric Corp: Sao Paolo, BR. 

http://ecatalog.weg.net/files/wegnet/WEG-synchronous-motors-technical-article-english.PDF

15 General Electric. Gas Compression & Mechanical Drive Products. 2014. General Electric. Fairfield, CT. 

https://www.ge-distributedpower.com/products/gas-compression-mechanical-drive , 

Solar Turbine. Gas Turbine Packages. 2014. Solar Turbines: San Diego, CA. 

https://mysolar.cat.com/cda/layout?m=35881&x=7

Caterpillar Oil & Gas. Engines for Gas Compression. 2014. Caterpillar Oil & Gas: Peoria, IL. 

https://catoilandgas.cat.com/products/engines

16 Hanlon, Paul. Compressor Handbook. 2001. McGraw Hill: New York, NY.

http://www.apvgn.pt/documentacao/compressor_handbook_hanlon.pdf

17 Dresser-Rand. Engineer’s Notebook. 2014. Dresser-Rand: Houston, TX. http://www.dresserrand.com/insights/winter10-11/insights_Winter10-11_EngNotebook.pdf

18 Boyce, Mehenvan P., Ph.D. Principles of Operation and Performance Estimation of Centrifigual 

Compressors. 1993. Texas A&M Engineering Experiment Station Turbomachinery Laboratory: 

College Station, TX. http://turbolab.tamu.edu/proc/turboproc/T22/T22161-177.pdf

19 Botha, Barend, Adriaan Moolman. Determining the Impact of the Different Losses on Centrifugal 

Compressor Design. 2005. South African Institution of Mechanical Engineering: Cape Town, South 

Africa. http://www.saimeche.org.za/resource/collection/1A689269-FE0A-4DC1-B1EC5ABFF5534FC1/Botha_and_Moolman-2005_11__600_dpi_-_2005__21_3___23-31.pdf

20 Zahroof Valves, Inc. Compressor Valves – Redefined. 2014. Zahroof Valves, Inc.: Houston, TX. 

http://zahroofvalves.com/

21 Slater, DJ. PAN Technology Ready for Field Test. In Compressortech2

. 2014. Waukesha, WI, June. 

Compressortech2

. Pp. 72-74.

http://www.ct2-digital.com/ct2/june_2014?sub_id=4IIMGiTXujSb&folio=72#pg77

22 Dresser-Rand. Dry Gas Seals. 2014. Dresser-Rand: Houston, TX. http://www.dresserrand.com/literature/turbo/85189-DryGasSeals.pdf

23 EPA Office of Air Quality Planning and Standards. Compilation of Air Pollutant Emission Factors, 

Volume I: Stationary Point and Area Sources. 2000. Environmental Protection Agency: Research 

Triangle Park, NC. http://www.epa.gov/ttnchie1/ap42/ch03/final/c03s02.pdf, Page 2

24 EPA. Install Automated Air/Fuel Ratio Controls. 2012. Environmental Protection Agency: Washington, 

DC. http://epa.gov/gasstar/documents/auto-air-fuel-ratio.pdf

25 Altronic, Inc. High Pressure Fuel Injection System for Large Gas Engines and Integral Compressors. 

2004. Altronic, Inc.: Girard. OH. http://www.altronicinc.com/pdf/engine-controls/form-HyperFuel-11-

04.pdf

26 Forsyth, John. Gas Turbine Inlet Air Chilling for LNG. 2013. Gas Technology Institute: Des Plaines, IL. 

http://www.gastechnology.org/Training/Documents/LNG17-proceedings/Mach-4-John_Forsyth.pdf

 
27 Engle, David. From Waste Heat to Power: Closed-loop, organic Rankine-cycle plants are adding 

multimegawatts – without additional fuel. In Distributed Energy, the Journal for Onsite Power 

Solutions. 2008. Forester Media: Santa Barbara, CA.

http://www.ormat.com/research/papers/waste-heat-power

28 Persichilli, Alex Kacludis, Edward Zdankiewicz, and Timothy Held. Supercritical CO2 Power Cycle 

Developments and Commercialization: Why sCO2 can Displace Steam. 2012. Echogen Power Systems 

LLC: Akron, OH. http://www.echogen.com/documents/why-sco2-can-displace-steam.pdf

29 Southern Research Institute. Greenhouse Gas (GHG) Verification Guideline Series: Natural Gas 

Compressor Leak Mitigation Technologies.1999. Environmental Protection Agency: Washington, DC. 

http://www.epa.gov/etv/pubs/03_vp_mitigation.pdf

30 EPA. Redesign Blowdown Systems and Alter ESD Practices. 2004. Environmental Protection Agency: 

Washington, DC. 

https://www.globalmethane.org/documents/m2mtool/docs/redesignblowdownsystems.pdf

31 T.F. Hudgins. Compressor Emission Controls. 2008. T.F. Hudgins: Houston, TX. 

http://www.tfhudgins.com/files/comm_id_21/EmissionsControl_SalesSheet.pdf

32 EPA. Reducing Methane Emissions from Compressor Rod Packing Systems. 2006. Environmental 

Protection Agency: Washington, DC. http://www.epa.gov/gasstar/documents/ll_rodpack.pdf

33 Lindner-Silwester, T. Consider true-zero-emission packing for reciprocating compressors. 2014. 

Hoerbiger Kompressortechnik Holding GmbH: Vienna, Austria. 

http://www.hydrocarbonprocessing.com/Article/3394995/Consider-true-zero-emission-packing-forreciprocating-compressors.html