Compression Machinery for Oil and Gas

Compression Machinery for Oil and Gas is the go-to source for all oil and gas compressors across the industry spectrum. Covering multiple topics from start to finish, this reference gives a complete guide to technology developments and their applications and implementation, including research trends. Including information on relevant standards and developments in subsea and downhole compression, this book aids engineers with a handy, single resource that will help them stay up-to-date on the compressors needed for today's oil and gas applications.

• Provides an overview of the latest technology, along with a detailed discussion of engineering
• Delivers on the efficiency, range and limit estimations for machines
• Pulls together multiple contributors to balance content from both academics and corporate research

• Language: English
• Publisher: Elsevier Science
• Release date: Nov 30, 2018
• ISBN: 9780128146842

Book preview

Compression Machinery for Oil and Gas

First Edition

Klaus Brun

Elliott Group, Jeannette, PA, United States

Rainer Kurz

Solar Turbines, San Diego, CA, United States

Table of Contents

Cover image

Title page

Copyright

Contributors

The Editors

Preface

Acknowledgments

Section I: Fundamentals of Compression

Chapter 1: Oil and Gas Compressor Basics

Abstract

Overview of Compressor Types

Basic Thermodynamics

Basic Machinery Dynamics

Chapter 2: Equipment Overview

Abstract

Types of Compression Equipment

Types of Applications

Factors to Consider When Selecting Compression Equipment

Section II: Types of Equipment

Chapter 3: Centrifugal Compressors

Abstract

Basics of Inline Centrifugal Compressors

Elements of an Inline Centrifugal Compressor

Auxiliary Systems/Supporting System

Special Considerations

Typical Compressor Types and Their Market Space

Maintenance Practices

Chapter 4: Integrally Geared Compressors

Abstract

Introduction

Comparison With Other Compressor Architectures

IGC Design Topics

IGC Applications

Summary

Chapter 5: Reciprocating Compressors

Abstract

Equipment Selection

Engineering Scope

Performance

Rotordynamics

Chapter 6: Screw Compressors

Abstract

Two Types of Screw Compressors

Working Principle of Screw Compressors

Comparison of Positive Displacement Machines (Screw Compressor, Reciprocating Compressor) Versus Centrifugal Compressors

Differences Between Dry Screws and Oil-Flooded Screws

Design Features

Typical Shaft Seal Arrangements

Thermodynamic Behavior

Operational Guidelines

Typical Design Range (Discharge Pressure, Pressure Ratio, Volume Flow, Driver Power, Molecular Weight)

Application Examples for Screw Compressors

Rotordynamics

Pulsation and Vibration

Chapter 7: Drivers

Abstract

Introduction

Gas Turbines

Reciprocating Engines

Electric Motors

Steam Turbines

Expanders

Section III: Applications

Chapter 8: Upstream Compression Applications

Abstract

Introduction

Chapter 9: Midstream

Abstract

Midstream Activities

Chapter 10: Downstream

Abstract

Introduction

Refinery Applications

LNG Production

Summary

Fuel Gas Compression (FGC)

Chapter 11: Compressor System Design and Analysis

Abstract

Introduction

Analysis Methods

Chapter 12: Compressor Testing

Abstract

Compressor Testing

Axial and Centrifugal Compressors

Reciprocating Compressors

Screw Compressors

Chapter 13: Standards and Codes

Abstract

Introduction

Machinery Specific Standards: Compressors

Reciprocating Compressors

Other Positive Displacement Compressors

Machinery Specific Standards: Drivers

Electric Motor Drives

Steam Turbines

Expanders

Reciprocating Engines

Machinery Specific Standards: Connecting Equipment

Gearboxes

Torque Convertors

Specific Component and System Standards

Lube and Control Oil Systems

Piping and Pressure Vessels

General Technical Topics (Not Machine Specific)

Health, Safety, and Fire

Additional Guidelines

Section IV: Technology Developments

Chapter 14: Wet Gas Compression

Abstract

Introduction

Definitions

Experimental Testing

Machine-Specific Effects of Wet Gas

Liquid Distribution

Overview of test data research

Chapter 15: Novel Machinery

Abstract

Introduction

Subsea Compression

Baker Hughes, a GE Company (BHGE): Blue-C™

MAN D&T: Subsea HOFIM

OneSubsea: WGC (Wet Gas Compressor)

Hermetically Sealed and Oil-Free Compression

High-Pressure Compression

High-Speed Drive Trains

Integrated Separator Centrifugal Compressor

Chapter 16: Novel Concepts & Research

Abstract

Cooled Diaphragms for Centrifugal Compressors

Subsurface Compression

Advanced Seals

Gas Bearings

Additive Manufacturing

Casing Treatment (Range Extension)

Gas Property Testing

Linear Motor Compressor

Advanced Pulsation Control for Reciprocating Compressors

Advanced Reciprocating Compressor Valve Technology

Surge Force Predictions

Liquid Packing Seals for Reciprocating Compressors

Index

Copyright

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Notices

Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary.

Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility.

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Contributors

Numbers in parentheses indicate the pages on which the authors' contributions begin.

Timothy C. Allison 3, 375, 543     Southwest Research Institute, San Antonio, TX, United States

Brian Bauer 309     Elliott Group, Jeannette, PA, United States

Urs Baumann 543     MAN Diesel & Turbo Schweiz AG, Zürich, Switzerland

Eugene Buddy Broerman 253, 569     Southwest Research Institute, San Antonio, TX, United States

Dirk Büche 31, 485     MAN Diesel & Turbo Schweiz AG, Zürich, Switzerland

Ryan Cater 485     Southwest Research Institute, San Antonio, TX, United States

Hector Delgado-Garibay 449     Southwest Research Institute, San Antonio, TX, United States

Kenneth Hall 309     Caterpiller Oil & Gas, Lafayette, IN, United States

Martin Hinchliff1 67, 309, 427     Dresser-Rand, Painted Post, NY, United States

Justin Hollingsworth 31, 167, 253     Southwest Research Institute, San Antonio, TX, United States

Kevin Hoopes 3     Southwest Research Institute, San Antonio, TX, United States

Min Ji 427     Solar Turbines, Inc., San Diego, CA, United States

Terry Kreuz 13, 387     National Fuel Gas, Williamsville, NY, United States

Chris Kulhanek 31, 167, 463     Southwest Research Institute, San Antonio, TX, United States

Rainer Kurz 3, 31, 309, 427, 449     Solar Turbines, Inc., San Diego, CA, United States

Tim Manthey 253     Aerzen USA, Coatesville, PA, United States

Franzisko Maywald 167     Burckhardt Compression AG, Winterthur, Switzerland

Cyrus Meher-Homji 309, 401     Bechtel, San Francisco, CA, United States

Kolja Metz 135     MAN Energy Solutions, Berlin, Germany

Harry Miller 543, 569     Dresser-Rand, A Siemens Business, Olean, NY, United States

J. Jeffrey Moore 463, 569     Southwest Research Institute, San Antonio, TX, United States

Dave Moss 401     UE Compression, Henderson, CO, United States

Grant Musgrove 309, 401, 485     Southwest Research Institute, San Antonio, TX, United States

Rob Pelton 135     Hanwha Power Systems Americas Inc., Houston, TX, United States

Brian Pettinato 31, 309     Elliott Group, Jeannette, PA, United States

Greg Phillippi 167, 449, 463     Ariel Corporation, Mount Vernon, OH, United States

Nathan Poerner 449     Southwest Research Institute, San Antonio, TX, United States

Aaron M. Rimpel 135, 167, 569     Southwest Research Institute, San Antonio, TX, United States

Dragan Ristanovic 309     Bechtel, San Francisco, CA, United States

Sarah Simons 387, 427, 569     Southwest Research Institute, San Antonio, TX, United States

Avneet Singh 375     Solar Turbines, Inc., San Diego, CA, United States

Natalie R. Smith 543     Southwest Research Institute, San Antonio, TX, United States

Matt Taher 31, 309, 463     Bechtel, San Francisco, CA, United States

George Talabisco 13, 31, 427     Dresser-Rand, Olean, NY, United States

Leif Arne Tonnessen 543     TechnipFMC, Kongsberg, Norway

Joseph Thorp 375     Saudi Aramco Energy Ventures - North America, Houston, TX, United States

Christian Wacker 135     MAN Energy Solutions, Berlin, Germany

Jürgen Wennemar 253     MAN Energy Solutions SE, Oberhausen, Germany

Ferdinand Werdecker 31     EagleBurgman, Houston, TX, United States

Benjamin White 13, 387, 427, 463     Southwest Research Institute, San Antonio, TX, United States

Jason Wilkes 31     Southwest Research Institute, San Antonio, TX, United States

Karl Wygant 135, 569     Hanwha Power Systems Americas Inc., Houston, TX, United States

Donghui Zhang 31, 449     Solar Turbines, Inc., San Diego, CA, United States

The Editors

Dr. Klaus Brun, Elliott Group, Jeannette, PA, United States

Dr. Brun is the director of Research & Development at Elliott Group where he leads a group of over 60 professionals in the development of turbomachinery and related systems for the energy industry. His past experience includes positions in product development, engineering, project management, and executive management at Southwest Research Institute, Solar Turbines, General Electric, and Alstom. He holds 9 patents, authored over 350 papers, and published 3 textbooks on energy systems and turbomachinery. Dr. Brun is a Fellow of the ASME and won an R&D 100 award in 2007 for his Semi-Active Valve invention. He also won the ASME Industrial Gas Turbine Award in 2016 and 11 individuals ASME Turbo Expo Best Paper awards. Dr. Brun is the chair of the 2020 Supercritical CO2 Power Cycles Symposium, past chair of the ASME-IGTI Board of Directors, the ASME Oil & Gas Applications Committee, and ASME sCO2 Power Cycle Committee. He is also a member of the API 616 Task Force, the ASME PTC-10 task force, the Asia Turbomachinery Symposiums Committee, and the Supercritical CO2 Symposium Advisory Committee. Dr. Brun is currently the executive correspondent of Turbomachinery International Magazine and Associate Editor of the ASME Journal of Gas Turbines for Power.

Dr. Rainer Kurz, Solar Turbines, San Diego, CA, United States

Dr. Rainer Kurz is the manager, Systems Analysis at Solar Turbines Incorporated, in San Diego, California. His organization is responsible for predicting compressor and gas turbine performance, for conducting application studies, and for field performance testing. Dr. Kurz attended the Universitaet der Bundeswehr in Hamburg, Germany, where he received the degree of a Dr.-Ing. in 1991. He joined Solar Turbines in 1993, and holds his current position since 1995. Dr. Kurz is the past chair of the ASME/IGTI Oil and Gas Applications Committee, a member of the Gas Machinery Research Council Project Supervisory Committee, the GMC Conference Organizing Committee, the Texas A&M Turbomachinery Symposium Advisory Committee, the Asian Turbomachinery Symposium Advisory Committee, and the SDSU Aerospace Engineering Advisory Committee. He was elected ASME Fellow in 2003. He has authored numerous publications on turbomachinery-related topics, with an emphasis on compressor applications, dynamic behavior, and gas turbine operation and degradation. Many of his publications were considered of archive quality and were accepted for publications in Engineering Journals. He has received several Best Paper and Best Tutorial Awards at the ASME TurboExpo Conferences and is the recipient of the 2013 Industrial Gas Turbine Technology award.

Preface

Oil and natural gas provides the world with high-density energy and feedstock for transportation, power generation, chemical processes, and many industrial and consumer products. The oil and gas industry produces these hydrocarbons and then processes, transports, and distributes them to users. Almost all aspects of the oil and gas industry require some gas compression and there are many applications where compression is the most critical part of the production and transport chain of hydrocarbons. For example, to transport natural gas from the production well to a power plant, within a city gas distribution system, or to a chemical plant, several compression facilities with complex machinery trains are necessary. Other production-related oil and gas compression applications include gas gathering, flash gas compression near the well, the use of the gas for enhanced oil recovery, the recompression of gas after processing in a gas plant, chemical plants and refineries processes, and even fuel gas compression at power plants. Further downstream in the hydrocarbon product chain, refrigeration compression is used to liquefy natural gas for ease of transport by ship, rail, or truck. Fundamentally, all natural gas must be compressed so that it can be efficiently transported, stored, or processed. Besides conventional hydrocarbon gases, such as natural gas, there are many other oil and gas applications where other nonhydrocarbon gasses such as carbon dioxide, nitrogen, or hydrogen have to be compressed.

Gas compression is thus vital for the transportation and processing of hydrocarbon and nonhydrocarbon gasses that are required by the oil and gas industry and their customers. For example, in North America alone there are over 9000 pipeline compression stations with nearly 40,000 individual compressors to transport natural gas from the producer to the consumer. Similarly, gas compressors are a critical part in the upstream production and downstream refining and distribution infrastructure.

The design of compression systems for the oil and gas industry is challenging due to the environments in which these systems operate, the fact that the operating conditions may change significantly on all time scales, and the extremely cyclical operating demands. Additionally, the equipment is expected to operate for long-time intervals, often many years, without interruptions for maintenance, or unplanned shutdowns.

There are many different types of compressors and drivers that are being used for these applications, each with different features, limits, and capabilities. This book provides a comprehensive overview of the compression machinery that is utilized in the oil and gas industry. In the first section of this book the thermodynamic foundation of gas compression is explained (Chapter 1) and an overview over the different types of typical used oil and gas compression equipment is provided (Chapter 2).

The second section of this book provides a deeper look into this compression equipment including a discussion on the performance and aerodynamics of centrifugal compressors in Chapter 3, the performance of integrally geared compressors in Chapter 4, the performance of reciprocating compressors in Chapter 5, and screw compressors in Chapter 6. The section is concluded by a description of the different drivers for these compressors such as gas turbines, steam turbines, expanders, electric motors, and gas engines (Chapter 7).

The book’s third section highlights relevant application topics. Here, we discuss in Chapter 8 how compressors are applied in the upstream section, where compressors are used for gas gathering, gas lift, gas reinjection, and for compression in gas plants. Then, in Chapter 9, the typical midstream applications, such as pipeline compression, and gas storage are explained. In the downstream business (Chapter 10), compression needs in LNG facilities, refineries, and for fuel gas compression are covered. Important system design and analysis issues are discussed in Chapter 11, and the section is completed with a discussion of testing methods and requirements in Chapter 12, and relevant codes and standards in Chapter 13.

The final section (Section 4) gives an outlook to future challenges and technology developments in oil and gas compression. The important topic of wet gas compression is covered in detail in Chapter 14 and a description of new machinery concepts, such as subsea and downhole compression, or hermetically sealed compressors can be found in Chapter 15. Some leading edge concepts such as the use of linear motors, supersonic compression, and isothermal compression in Chapter 16 round out the topics in this book.

The topics covered in this book were selected to provide engineers and practitioners interested in the oil and gas industry and the relevant compression machinery utilized with a comprehensive technology and applications overview. Each chapter provides sufficient background material to stand alone, and can be used on its own, although we attempted to avoid duplication throughout this book.

We, the editors, are indebted to the chapter authors. They are all subject matter experts in their fields, who were selected from the engineering and scientific community based on their relevant contributions to the field. They represent a broad range of expertise, and come from a diverse range of backgrounds.

Klaus Brun

Rainer Kurz

Contributing authors (*Indicates chapter lead):

Timothy C. Allison (Chapters 1, 8*, 15)

Brian Bauer (Chapter 7)

Eugene Buddy Broerman (Chapters 6*, 16)

Dirk Buche (Chapters 3, 14)

Jon Bygrave (Chapter 3)

Ryan Cater (Chapter 14*)

Hector Delgado (Chapter 12*)

Kenneth Hall (Chapter 7)

Martin Hinchliff (Chapters 5, 7, 11)

Justin Hollingsworth (Chapters 3, 5*, 6)

Kevin Hoopes (Chapter 1*)

Min Ji (Chapter 11)

Terry Kreuz (Chapters 2, 9)

Chris Kulhanek (Chapters 3, 5, 13*)

Rainer Kurz (Chapters 1, 3, 7, 11, 12)

Tim Manthey (Chapter 6)

Franzisko Maywald (Chapter 5)

Cyrus Meher-Homji (Chapters 7, 10)

Kolja Metz (Chapter 4)

Harry Miller (Chapters 15, 16)

Jeff Moore (Chapters 13, 16)

Dave Moss (Chapter 10)

Grant Musgrove (Chapters 7*, 10*, 14)

Rob Pelton (Chapter 4)

Brian Petinato (Chapter 3*, 7)

Greg Phillippi (Chapters 5, 12, 13)

Nathan Poerner (Chapter 12)

Aaron M. Rimpel (Chapters 4*, 5, 16)

Dragan Ristanovic (Chapter 7)

Sarah Simons (Chapters 9, 11*, 16*)

Avneet Singh (Chapter 8)

Natalie Smith (Chapter 15*)

Matt Taher (Chapters 3, 7, 13)

George Talabisco (Chapters 2, 3, 11)

Leif Tonnessen (Chapter 15)

Christian Wacker (Chapter 4)

Jürgen Wennemar (Chapter 6)

Ferdinand Werdecker (Chapter 3)

Benjamin White (Chapters 2*, 9*, 11, 13)

Jason Wilkes (Chapter 3*)

Karl Wygant (Chapters 4, 16)

Donghui Zhang (Chapters 3, 12)

Acknowledgments

We would like to thank Dorothea Martinez for her tireless efforts and assistance while putting this book together.

Section I

Fundamentals of Compression

Chapter 1

Oil and Gas Compressor Basics

Kevin Hoopes⁎; Timothy C. Allison⁎; Rainer Kurz†    ⁎ Southwest Research Institute, San Antonio, TX, United States

† Solar Turbines, Inc., San Diego, CA, United States

Abstract

This chapter explains the basics of gas compressor operation starting with an overview of compressor types and the underlying thermodynamics. Other topics include the definition of compressor efficiency, the concept of an operating map including the explanation of stall, surge, and choke as well as the basics of compressor control and machine dynamics.

Keywords

Positive displacement compressor; Dynamic compressor; First law of thermodynamics; Intercooling; Equation of state; Stall; Choke; Rotordynamics

Overview of Compressor Types

Gas compressors operate by adding work to a gas to increase the pressure of that gas as it flows through them. They are used in many different applications from everyday items such as vacuum cleaners, automobiles, and air conditioners to large industrial scale compressors for chemical processing, jet engine propulsion, and natural gas processing and transmission. They are separated into two distinct groups: positive displacement compressors and dynamic compressors.

Positive Displacement Compressors

Positive displacement compressors operate by decreasing the volume of a gas in a trapped volume. Because they operate on a trapped volume of fluid, positive displacement machines operate on distinct portions of the fluid at a time; as such their mechanical behavior, operating speed, etc., is very different than dynamic machines. Examples of compressors of this type include reciprocating compressors, screw compressors, and scroll compressors.

Dynamic Compressors

Dynamic compressors operate by continuously increasing the momentum of a gas as it flows through them and do not rely on a trapped volume. Examples of compressors of this type include centrifugal (also called radial) compressors, axial compressors, and mixed flow compressors. The major distinctions between these categories come from how the fluid enters and exits the machine. In a centrifugal machine, the fluid flows into the machine parallel to the axis of rotation and out of the machine radially or perpendicular to the axis of rotation. In axial machines, the gas enters and exits the machine parallel to the axis of rotation. As their name suggests, mixed flow machines are a mixture between purely centrifugal and purely axial machines.

The appropriate type of compressor for a particular application is a function of the required flow rate and pressure ratio. A chart describing the approximate operating envelopes of different compressor types has been provided by the Natural Gas Processor Suppliers Association and is shown in Fig. 1.1. Although the exact capabilities of a particular compressor type may deviate from these conditions based on a specific design, the general trends are valid. In general, there is significant overlap between the three compressor types, although reciprocating compressors uniquely cover low-flow applications with high pressures and centrifugal compressors uniquely cover high-flow applications.

Fig. 1.1 Compressor types and application conditions. Modified from NGPSA Engineering Data Book, vol. 1, Revised tenth ed., 1994. Compiled and edited in cooperation with the Gas Processors Association. Copyright 1987 Gas Processors Association.

Basic Thermodynamics

The working principles of gas compressors can be understood by applying the basic laws of physics. Using the first and second law of thermodynamics together with basic laws of fluid dynamics, such as Bernoulli's law and Euler's law allows us to explain the fundamental working principles, and by extension, can increase the understanding of the operational behavior of gas compressors.

Most descriptions of compressors presented here are specifically geared toward pipeline applications. They are usually also applicable to many other gas compression applications. The general description of the thermodynamics of gas compression applies to any type of compressor, independent of its detailed working principles.

First Law

For a compressor receiving gas at a certain suction pressure and temperature, and delivering it at a certain output pressure, the isentropic head represents the energy input required by a reversible, adiabatic (thus isentropic) compression. The actual compressor will require a higher amount of energy input than needed for the ideal (isentropic) compression.

It is important to clarify certain properties at this time, and in particular find their connection to the first and second law of thermodynamics written for steady-state fluid flows. The first law (defining the conservation of energy) becomes:

with q = 0 for adiabatic processes and gz = 0 because changes in elevation are not significant for gas compressors. We can combine enthalpy and velocity into a total enthalpy by

where Wt12 is the amount of work we have to apply to affect the change in enthalpy in the gas. The work Wt12 is related to the required power, P, by multiplying it with the mass flow.

Power and enthalpy difference are thus related by

If we can find a relationship that combines enthalpy with the pressure and temperature of a gas, we have found the necessary tools to describe the gas compression process. For a perfect gas, with constant heat capacity, the relationship between enthalpy, pressures, and temperatures is

Because, for an isentropic compression, the discharge temperature is determined by the pressure ratio (with k = cp/cv):

We can, for an isentropic compression of a perfect gas, relate the isentropic head, temperature, and pressures by

For real gases (for which k and cp in the above equations become functions of temperature and pressure), the enthalpy of a gas h(p, T) is calculated in a more complicated way using equations of state [1]. They represent relationships that allow the calculation of the enthalpy of gas of known composition, if any two of its pressure, its temperature, or its entropy are known.

We therefore can calculate the actual head for the compression by

and the isentropic head by

The performance quality of a compressor can be assessed by comparing the actual head (which directly relates to the amount of power we need to spend for the compression) with the head that the ideal, isentropic compression would require. This defines the isentropic efficiency:

The second law tells us:

For adiabatic flows, where no heat q enters or leaves, the change in entropy simply describes the losses generated in the compression process. These losses come from the friction of gas with solid surfaces and the mixing of gas of different energy levels. An adiabatic, reversible compression process therefore does not change the entropy of the system, it is isentropic. Our equation for the actual head implicitly includes the entropy rise Δs, because

If cooling is applied during the compression process (e.g., with intercoolers between two compressors in series), then the increase in entropy is smaller than that for an uncooled process. Therefore, the power requirement will be reduced.

Using the polytropic process [2] for comparison reasons works fundamentally the same way as using the isentropic process for comparison reasons. The difference lies in the fact that the polytropic process uses the same discharge temperature as the actual process, while the isentropic process has a different (lower) discharge temperature than the actual process for the same compression task. In particular, both the isentropic and the polytropic process are reversible processes. In order to fully define the isentropic compression process for a given gas, suction pressure, suction temperature, and discharge pressures have to be known. To define the polytropic process, in addition either the polytropic compression efficiency, or the discharge temperature has to be known. The polytropic efficiency ηp is defined such that it is constant for any infinitesimally small compression step, which then allows to write

and

or, to define the polytropic efficiency:

For designers of compressors, the polytropic efficiency has an important advantage: If a compressor has five stages, and each stage has the same isentropic efficiency ηs, then the overall compressor efficiency will be lower than ηs. If, for the same example, we assume that each stage has the same polytropic efficiency ηp, then the polytropic efficency of the entire machine is also ηp.

Because the enthalpy definition above is on a per mass flow basis, the absorbed gas power Pg (i.e., the power that the compressor transferred into the gas) can be calculated as

The mechanical power P necessary to drive the compressor is the gas absorbed power increased by all mechanical losses (friction in the seals and bearings), expressed by a mechanical efficiency ηm (typically in the order of 1% or 2% of the total absorbed power):

We also encounter energy conservation on a different level in turbomachines: The aerodynamic function of a turbomachine relies on the capability to trade two forms of energy—kinetic energy (velocity energy) and potential energy (pressure energy). This will be discussed in a subsequent section.

Intercooling

A compression process where the gas is cooled as part of the compression is no longer adiabatic. It is thus not appropriate to state isentropic or polytropic processes for comparison. In some instances, an isothermal efficiency might be suitable to compare different configurations. Since the cooling process moves entropy from the compressed gas to the environment, the overall compression will consume less power than the same process without intercooling.

Equations of State

Understanding gas compression requires an understanding of the relationship between pressure, temperature, and density of a gas. An ideal gas exhibits the following behavior:

where R is the gas constant, and as such is constant as long as the gas composition is not changed. Any gas at very low pressures can be described by this equation.

For the elevated pressures we see in natural gas compression, this equation becomes inaccurate, and an additional variable, the compressibility factor Z, has to be added:

Unfortunately, the compressibility factor itself is a function of pressure, temperature, and gas composition.

A similar situation arises when the enthalpy has to be calculated: For an ideal gas, we find

where Cp is only a function of temperature.

In a real gas, we get additional terms for the deviation between real gas behavior and ideal gas behavior (Poling et al., 2001):

The terms (h⁰ − h(p1))T1 and (h⁰ − h(p2))T2 are called departure functions, because they describe the deviation of the real gas behavior from the ideal gas behavior. They relate the enthalpy at some pressures and temperatures to a reference state at low pressure, but at the same temperature. The departure functions can be calculated solely from an equation of state, while the term ∫T1T2CpdT is evaluated in the ideal gas state. Fig. 1.2 shows the path of a calculation using an equation of state.

Fig. 1.2 Temperature-entropy diagram for a Brayton cycle.

Equations of state are semiempirical relationships that allow to calculate the compressibility factor, as well as, the departure functions. For gas compression applications, the most frequently used equations of state are Redlich-Kwong, Soave-Redlich-Kwong, Benedict-Webb-Rubin, Benedict-Webb-Rubin-Starling, and Lee-Kessler-Ploecker (Poling et al., 2001).

In general, all of these equations provide accurate results for typical applications in pipelines, that is, for gases with a high methane content, and at pressures below about 42 MPa. Kumar et al. [3] and Beinecke and Luedtke [2] have compared these equations of state regarding their accuracy for compression applications. It should be noted that the Redlich-Kwong equation of state is the most effective equation from a computational point of view (because the solution is found directly rather than through iteration).

p-h and T-s Diagrams

The state of any gas of known composition is fully defined if exactly two parameters are known. These parameters could be pressure and temperature, pressure and entropy, enthalpy and entropy, or specific volume and temperature. This fact allows the use of p-h (pressure-enthalpy) or T-s (temperature-entropy) diagrams to graphically describe thermodynamic processes such as the gas compression process, or thermodynamic cycles like the gas turbine Brayton cycle. Any gas or gas mixture can be displayed as a p-h or T-s diagram. A p-h diagram displays the same information that can be calculated by an equation of state. Typically, p-h diagrams show lines of constant pressure, constant volume, constant entropy, constant temperature, as well as, the two-phase areas. T-s diagrams, often show constant pressure or constant volume lines. For practical purposes, p-h and T-s diagrams are available for pure gases and air in many textbooks examples of which are shown in (Figs. 1.3 and 1.4).

Fig. 1.3 Pressure-enthalpy diagram for gas compression.

Fig. 1.4 Pressure enthalpy diagram for methane, with the path for actual and isentropic compression. The range where methane can be treated as an ideal gas (i.e., at low pressures, where enthalpy is only dependent on temperature, but not on pressure) is highlighted. From GPSA Handbook.

Basic Machinery Dynamics

Rotordynamics includes the lateral and torsional vibrations of machinery trains. Torsional analysis is typically required for both reciprocating and centrifugal compressors, but lateral analysis is often performed only for centrifugal compressors since they are not often a concern for reciprocating units due to their low operating speed and resulting frequency separation between lateral natural frequencies and excitation frequencies.

Regarding lateral rotordynamics, there are two types of vibration: forced response (typically from unbalance) and self-excited (usually referred to as stability). Rotordynamic stability in centrifugal compressors depends on forces in the bearings, seals, and secondary flow passages that can be stabilizing or destabilizing. The stabilizing forces include the bearing and seal damping which works to dissipate energy. The destabilizing forces arise from tangential forces that increase rotor vibration amplitudes. Assessing rotordynamic stability is an accounting exercise, quantifying the rotordynamic forces of each component on the stability of the overall rotor system. Destabilizing forces can be represented by cross-coupled stiffnesses, which will be described in more detail in a later chapter.

Destabilizing forces in compressors extract energy from the process gas and rotation to excite a rotor vibration mode (usually the first forward whirling mode). If these forces grow large enough and overcome the damping forces in the rotor system, the vibration amplitude of that mode will grow unbounded until a rotor-stator rub occurs. Vibration monitoring systems will shutdown the unit after an instability, but usually the vibration amplitude grows so quickly that seal rubbing will typically result. Further aggravating the situation is that many operators will restart the compressor and repeat the exercise many times before they realize they have a serious problem. The damage can go beyond just replacing the internal labyrinth seals and more serious damage to shafts, impellers, bearings, and diaphragms can result.

References

[1] Poling B.E., Prausnitz J.M., O’Connell J.P. The Properties of Gases and Liquids. McGraw-Hill; 2001.

[2] Beinecke D., Luedtke K. Die Auslegung von Turboverdichtern unter Beruecksichtigung des realen Gasverhaltens. VDI Berichte. 1983;487.

[3] Kumar S., Kurz R., O’Connell J.P. Equations of State for Compressor Design and Testing. 1999 ASME Paper 99-GT-12.

Chapter 2

Equipment Overview

Benjamin White*; Terry Kreuz†; George Talabisco‡    ⁎ Southwest Research Institute, San Antonio, TX, United States

† National Fuel Gas, Williamsville, NY, United States

‡ Dresser-Rand, Olean, NY, United States

Abstract

This chapter aims to provide a broad overview of various types of compression equipment and the types of applications that each is best suited for. A number of factors to consider when selecting compression equipment are also discussed.

Keywords

Compressor types; Compressor applications; Decision factors; Upstream; Midstream; Downstream; Flow rates; Pressures; Compression ratio; Temperatures; Drivers; Fuel source; Emissions; Noise; Safety; Physical environment; Operating costs; Maintenance costs; Service life; Controls; Air filtration; Packaging

Types of Compression Equipment

Compression equipment is available in a wide range of types and sizes for use in many different industry applications. Compressors are generally divided into two main categories: positive displacement compressors and dynamic compressors. Positive displacement compressors typically include reciprocating compressors (single acting, double acting, hyper), rotary compressors (screw, scroll, vane), and diaphragm compressors. Dynamic compressors include centrifugal compressors and axial compressors. A summary of compressor types is shown in Fig. 2.1.

Fig. 2.1 Family tree of compressor types [1]. https://commons.wikimedia.org/wiki/File:Compressor_Types.png.

Each compressor type is usually best suited for a particular range of flow rates, pressures, and fluid types. However, there is also a lot of overlap in some applications. For industrial oil and gas applications, the two most common compressor types are reciprocating and centrifugal compressors. In very broad terms, reciprocating compressors are usually best for applications with low-to-medium flow and low-to-high pressures. Reciprocating compressors also tend to be very flexible in terms of varying flow rates, gas compositions, and fluid densities. Multistage reciprocating compressors can generate very high-pressure ratios across a single machine. Centrifugal compressors are usually best for applications with medium-to-high flow and low-to-medium pressures. Centrifugal compressors typically have smaller physical footprints for a given power rating, lower maintenance costs, and longer run times between maintenance intervals. Centrifugal compressors also have lower unbalanced forces and are typically much less susceptible to pulsation and vibration-related issues.

However, as discussed later in this chapter, there are also many other factors to consider when selecting the ideal compressor for a particular application. Fig. 2.2 shows typical coverage ranges for various types of compressors. These range from axial compressors which can produce very high flow rates with limited pressure ratio and discharge pressure capabilities, to diaphragm compressors that produce very limited flow rates with usually very high discharge pressures. The others compressors listed cover parts of the displayed pressures and flow ranges. As a type, reciprocating compressors generally cover the broadest area of the range. Detailed information on each compressor type and driver options can also be found in ⁎⁎⁎Chapters 3–7.

Fig. 2.2 Compressor coverage chart [2]. Courtesy of Southwest Research Institute

Types of Applications

There are a wide variety of different compression applications, typically divided into three main categories: Upstream, Midstream, and Downstream. Note that this section is just a brief summary of what types of equipment would commonly be used in each application. Refer to Chapters 8–10 for more detail.

Upstream

1.Gas gathering application can typically utilize screw, rotary vane, reciprocating, and centrifugal compressors to collect gas at producing wellheads and move the gas to a central location for processing and/or transport through a series of various pipelines.

2.Export compression increases the pressure of processed gas to be suitable for exporting from a processing facility to a pipeline for use by downstream consumers. Typical compressors used are centrifugal and reciprocating.

3.Gas lift is a process where high-pressure gas is reinjected into the well riser to mix with the fluid, thus helping with lifting oil from a well by making the weight of the fluid column lighter in weight. This helps to maintain or enhance production from a well. Both centrifugal and reciprocating can be utilized in this process.

4.Gas reinjection can utilize centrifugal and reciprocating compressors to maintain or enhance production in an oil reservoir that contains both oil and gas. In this process the gas is injected into the reservoir to maintain pressure and thus oil production rate.

5.Vapor recovery units—in vapor recovery, gas that separates from oil in a storage system (tank or vessel) is recovered by removing the gas that collects on the top of a vessel thus reducing the pressure within a storage tank and capturing the gas for use elsewhere. Reciprocating, rotary screw, rotary vane, or centrifugal compressors are typically employed as the compression equipment for this application process.

6.Subsea compression equipment located in a subsea environment is used to maintain reservoir production by reinjection into a well formation. Centrifugal compressors with direct coupled high-speed motors are typically used for this application.

7.Enhanced oil recovery (EOR) can include gas injection, water flood, and chemical or steam injection. EOR is used to maintain reservoir pressure by injection of gas either recycled from the reservoir itself or from an alternate source using a different fluid like carbon dioxide (CO2), nitrogen, or other gas streams can be injected. Typical compression equipment used can be reciprocating and centrifugal compression.

Midstream

1.Pipeline transmission compression is the transportation of natural gas from the source (wells) to the distribution system. This is a typical application for centrifugal and reciprocating compression systems.

2.Gas storage injection/withdrawal: old well formations are sometimes used as peaking storage locations for natural gas transmission and distribution systems. They are used to provide additional capacity at various locations where peak demand can exceed capability of existing pipelines to provide the necessary product at the required pressure levels. Typical compression equipment consists of both reciprocating and centrifugal compressors that are used to inject the gas into the storage formation and to boost the pressure during removal to meet pipeline pressure requirements.

3.Natural gas processing: this application removes unwanted components from raw and untreated natural gas to make it suitable to be classified as pipeline quality gas. Centrifugal and reciprocating compressors can be used in this application.

Downstream

1.Refinery/process applications: compressors constitute an important part of the mechanical equipment in oil and gas refineries and petrochemical plants. Compressors are used for different applications in the main and auxiliary process cycles:

a.Recycling compressors designed to provide a steady flow of process gas through a closed circuit in order to maintain the required process parameters in the plant units (e.g., hydrogen-rich gas recycling in a hydrotreater)

b.Feed compressors supplying process gas to reactor

c.Booster compressors

d.Sales gas compressors (e.g., methane)

e.Electrically driven reciprocating and centrifugal compressors are most commonly used in oil and gas refining facilities

2.Ethylene/Low-density polyethylene (LDPE): due to the extremely high discharge pressures required in these applications, large horizontal opposed reciprocating compressors for the highest discharge pressures are required (aka hyper compressors). This type of compressor is used in the LDPE production process (low-density polyethylene) as a secondary compressor in combination with a process gas compressor used as a booster/primary compressor.

3.CNG (compressed natural gas) is a fuel for vehicles or other commercial applications made by compressing natural gas or biogas to less than 1% of its uncompressed volume. Compressors are used to boost the pressure of the gas and they are the primary equipment of a CNG refueling station for vehicles. This application involves suction pressures ranging from a slight vacuum to more than 5.2 MPa, with discharge pressures exceeding 31 MPa, thus requiring multistaged compressor technologies. Typical compression types utilized include two-to-five stage reciprocating piston compressors.

4.LNG (liquefied natural gas) is a growing application with increasing demands for use in industry and domestic heating making it necessary to use huge quantities of gas from far away production sources which create the need to transport natural gas in its liquid form via ships and tank trucks. Among the equipment required for this technology, centrifugal compressors and rotary machines prove to be very versatile for use in gathering produced gas, as well as, in later stages of pipeline transportation, liquefaction, and regasification/expansion at the point of use by residential, commercial, and industrial consumers.

5.Industrial gases (hydrogen/CO2/ammonia) hydrogen compression is applied to reduce the volume resulting in compressed hydrogen or liquid hydrogen. The compressor reduces the volume of hydrogen gas, to allow the liquid hydrogen to be transported elsewhere. A proven method to compress hydrogen is to apply reciprocating piston compressors. Nonlubricated compressors are preferred to avoid oil contamination of the hydrogen.

6.Ammonia compression to manufacture ammonia is a part of a complex chemical refinery process wherein the synthesis gas needs to be compressed to extremely high pressures, ranging from 100 to 250 bars (1500–4000 psi) for ammonia synthesis. Modern plants employ centrifugal compressors which are usually driven by steam turbines that use the steam produced from excess process heat. Ammonia is also used as a process fluid for refrigeration systems, the most common type of refrigerating system is a vapor-compression refrigerator. This approach uses anhydrous ammonia as a refrigerant as the means of moving heat around.

7.CO2 compression: CO2 is often used as an inexpensive, nonflammable pressurized gas and it is one of the most commonly used compressed gases for pneumatic (pressurized gas) systems in portable pressure tools. CO2 gas producing process plants produce CO2 in mainly two forms—liquid and solid. Solid CO2 is also known as dry ice and is used as a refrigerant in food industry and for small shipments. CO2 is widely utilized during the storage and shipping of ice cream and other frozen foods. CO2 is also used as an atmosphere for welding. CO2 is compressed to the desired usage pressure using a gas compressor or is liquefied at lower pressures by using compressor driven refrigeration systems and then pumped to the desired pressure for bulk storage for CO2 capture or large-scale industrial uses. Large-scale CO2 compressors are responsible for a large portion of the enormous capital and operating cost penalties expected with any carbon capture and sequestration (CCS) systems. The compressor power requirements for gas-phase compression of CO2 range from 1.7 to 15.27 MPa versus CO2 liquefaction at 1.7 MPa and pumping that liquid CO2 to 15.27 MPa.

8.Distribution: After natural gas has been produced and cleaned, it must be pumped/compressed and stored for consumption by a multitude of residential, commercial and industrial users primarily for residential heat and industrial processes. To maximize capacity and deliverability to midstream and transmission pipelines feeding lower pressure gas distribution systems, gas is typically compressed to higher pressures ranging 3.4–10 MPa. The required boosting compression function power is delivered using a mix of reciprocating engines, turbines, and electric motors. The prime power devices are used to drive a mix of reciprocating piston, centrifugal, and screw compressors.

Factors to Consider When Selecting Compression Equipment

Selecting the ideal compressor for a given application should include consideration for a wide variety of complex factors. Many of these key considerations are presented in the following.

Flow Rates and Absolute Pressures

The maximum flow of a reciprocating compressor is limited by the cylinder size (bore and stroke), the number of compressor cylinders, and the operating speed. The maximum flow of a centrifugal compressor is typically limited by driver power or some choke point internal to the compressor where the flow velocity nears the speed of sound of the fluid.

Both reciprocating and centrifugal compressors can reach maximum discharge pressures in the range of 70–100 MPa. However, discharge pressures of approximately 10 MPa or less are most common. Special hyper reciprocating compressors, often used in low-density polyethylene production, can reach discharge pressures up to 340 MPa.

Fig. 2.3 provides an overview comparison of typical ranges of flow rates and discharge pressures that can be attained with different types of compressors. These criteria are a good starting point for selecting a compressor type. However, when multiple compressor types overlap for a given application, the following factors should be considered.

Fig. 2.3 Comparison of prime movers [3].

Compression Ratio and Maximum Temperatures

For a single-stage reciprocating compressor, the compression ratio typically varies from 1.1 up to 4.0. The maximum compression ratio is usually limited by a goal of preventing discharge temperatures from reaching no more than approximately 296.33 °F. However, multistage reciprocating compressors with interstage cooling of the process gas can achieve much higher overall compression ratios.

Single-stage centrifugal compressors are typically designed to operate with compression ratios in the range of 1.1–1.4.

Gas Type (Sour Gas, Wet Gas, etc.)

Many natural gas streams carry contaminants in varying amounts warranting careful consideration to the design, installation, and maintenance of adequate gas cleaning facilities upstream of compression equipment to adequately protect them from serious problems resulting from operating with dirt, wet, or sour gas. Wet or dirty gas entrained with contaminates in reciprocating compressors can result in compressor valve damage and accelerated wear of compressor pistons by wiping lubrication from critical areas of the compressor. Worst case, entrained liquids could fill the compressor cylinders resulting in serious damage of compressor rods, bolting mechanisms, or catastrophic failure of the unit. Contaminants in centrifugal compressors can quickly cause erosion of impellers, volutes, diaphragms and shaft, and pressure seals. For all of these reasons gas contaminants must be removed to avoid efficiency losses, breakdowns, and high maintenance costs.

For wet gas (primarily water), a well-designed system consisting of a combination of separators, scrubbers, filters, and gas dehydrators are the industry standard to provide a palatable gas quality upstream of the compression process so as to not risk wet gas detriments. Wet gas can also refer to unprocessed gas streams containing higher quantities of hydrocarbon liquids that require more advanced processing and treatment equipment to process out or strip these liquids prior to the gas compression process to reduce fallout of liquids in the compression cycle.

Corrosive gases (aka sour gas) such as sulfur rich or hydrogen sulfide compounds may be present in some raw production gas streams. This always requires special treatment and added design and protection to the compressor's internal steel and sealing materials to withstand the corrosive gas streams as much as technically possible. Industry standard treatment systems for corrosive gases include wetting the gas stream with specialized chemicals (amine or similar) in contactor towers then separating the liquid from the gas stream with separators. Specialized dry chemical absorbents are also commonly used to remove corrosive gases in lower flow designs.

Driver Type and Fuel Source

There are generally three main types of prime movers, which include reciprocating engines, gas turbines, and electric motors. Steam turbines are also used in process applications where steam is generally available for other process reasons. Reciprocating engines are typically used to drive reciprocating compressors and they can often be subdivided into slow speed (≤ 600 rpm) and medium-to-high speed (600–1800 rpm) classifications. These engines can have two-stroke or four-stroke cycles and may or may not be turbo-charged. These slow speed engines are often used in an integral configuration where the compressor and engine share a common crankshaft. Separable systems have physically separate drivers and compressors connected by a gearbox or coupling.

Gas turbines can be industrial type or aeroderivative type (based on designs originally intended for aviation applications). Gas turbines operate at much higher operating speeds and are well suited for operation with centrifugal compressors or where minimizing weight is a priority (such as offshore).

Electric motors can be induction, synchronous, or DC, with induction being the most common. Electric motor drives pair well with reciprocating compressors based on their similar operating speeds, but electric motors can also be paired with centrifugal compressors.

One key factor in determining the preferred driver type will be the available fuel sources. Both gas engines and gas turbines can often run off of fuel gas pulled from the main process gas. However, electric motors obviously require an uninterrupted source of electrical power. Other factors such as installation cost, operating and maintenance costs, efficiency, noise, emissions, reliability, etc. should also be considered.

See additional discussion on drivers in Chapter 7.

Emissions, Noise, and Safety

Factors relating to emissions, noise, and safety must be considered in any new compression facility. There are numerous regulatory and permitting requirements that must be met in regard to these factors to protect the public health.

The operation of compression equipment will typically generate emissions to the air during the combustion process (depending on the type of driver) and will typically be subject to various emission regulations, such as the Clean Air Act. Planned and unplanned emissions tests are often conducted on a regular basis by local regulatory representatives.

Intentional or unintentional discharges of the process gas from the system should also be considered (leaks, blowdowns, etc.). Methane, the primary component in natural gas, is a known greenhouse gas. In addition, CO2 and nitrous oxides are natural by-products of the combustion process.

The common sources of air emissions include:

1.combustion gases,

2.boilers,

3.release of gas,

4.fugitive omissions,

5.gas vents,

6.gas leaks,

7.storage tanks,

8.reciprocating engines,

9.heaters,

10.dehydration,

11.blowdown,

12.crankcase vents of reciprocating compressors,

13.packing case vents for reciprocating compressors,

14.cooling system vents, and

15.other miscellaneous factors.

Given the proximity of many compressor stations to residential neighbors, noise generated by the compression equipment can be a factor, particularly when ambient noise conditions are low, such as at night in rural settings. Sources of noise could include the turbine or engine air intakes and exhaust systems, blowdown systems, gas coolers, auxiliary air compressors or generators, etc. Pulsation and vibration in the piping can also be similar irritant to nearby residential neighbors. Valves especially antisurge-recycle valves can be a source of noise and require noise attenuation trim along with acoustic insulation to minimize noise.

A maximum noise limit of 55 dB(A) is often required by FERC (Federal Energy Regulatory Commission), which can difficult to meet in some installations. Noise control is usually achieved by employing a combination of techniques including the installation of engine exhaust and inlet silencers, noise insulation on the piping, acoustically insulated building and enclosures, etc. A comprehensive noise assessment should be conducted at the design phase.

Compressor stations are required to be designed, constructed and operated in accordance with Pipeline and Hazardous Materials Safety Administration (PHMSA) safety standards. These standards are intended to minimize the risk of pipeline accidents and to protect the public safety. PHMSA conducts inspections during various phases of design, construction, and operation. State and local laws also apply, depending on the location of the facility. Surface and groundwater, as well as, local wildlife and vegetation, should be also protected as required by the EPA, US Bureau of Land Management, and other local agencies.

The safety and security at a compression facility can be enhanced by installed safety features such as fire and combustible gas detection, security systems, environmental monitoring systems, emergency shutdown systems, and overpressure protection systems. Initiating site-specific safety programs for on-site personnel are also critical.

Physical Environment

Compressor stations can vary in size from a few acres up to 20 or more.

The most common and important location attributes that should be considered in the selection of a compressor system site include:

•available utilities,

•accessibility to services and support,

•environmental conditions,

•depending on the application, other location variables may have to be considered as well, and

•the relative importance of the location variables should also be established to ensure that the best type and size of compressor is selected.

Operating and Maintenance Costs

Maintenance costs for compressor stations and systems are usually tracked and quantified as $/BHP-hr. Fuel and/or power costs to power the prime mover obviously represent a large part of the operating costs for engines and compressors.

Although fuel represents a portion of the operating cost for engines and compressors, maintenance and other consumables can be quite expensive. Comparing the cost of parts and consumables on dollars only can be misleading for different size engines and operating hours. Dollars per brake horsepower per hour is calculated by simply dividing maintenance costs by horsepower and by run hours. Maintenance costs are generally captured on a level designated by the operating company's accounting system at the most detailed level maintenance costs are tracked by.

Horsepower can be tracked based on an actual or rated basis. Either is okay as long as the same standard is used for all engines. Maintenance costs should be tracked over time (generally over several years). These costs are very useful when compared against other units and prime mover types (internal combustion engine, gas turbine, or electric motor). It can be used to identify best practices and opportunities for improvement.

Reliability is a relative percentage-based measure of planned versus unplanned downtime for a given compressor it measures how often the compressor is down unplanned for repairs, or planned to be preventatively maintained. Although each company defines it differently, annual reliability is most simply calculated as:

Availability is a slightly different measure of unscheduled downtime for a given compressor. It measures whether the compressor is ready for use when needed. Although each company defines it differently, annual availability is simply calculated as:

Generally, and as supported by industry studies, gas turbine or electrical driven centrifugal compressors have proven to be lower cost in overall maintenance and have higher reliability/availability factors than internal combustion engine driven reciprocating compressors.

The following are typical observational comparisons often used in operating gas turbines and centrifugal compressors:

1.output power versus control temperatures,

2.output power versus fuel flow rate or fuel pressure (increases in fuel flow rate or fuel pressure can be an indication of compressor fuel nozzle or meter calibration issues),

3.compressor discharge pressure versus percent gas producer speed (decreases in compressor discharge pressure at a given gas producer speed can indicate fouling of the compressor or an increase in turbine nozzle area),

4.vibration level (increases in vibration at constant operating conditions can indicate a number of problems such as compressor internals fouling, bearing damage, mechanical damage, and loose connections), and

5.exhaust temperature variation (variation across the exhaust collector can indicate: fuel distribution problems, combustor problems, or air/fuel mixing problems).

Factors that may adversely affect maintenance intervals on gas turbines include these factors:

1.starting/Stopping frequency (rule of thumb says one start/stop = 30 run hours equivalence),

2.frequent rapid load changes, and

3.condition of inlet air to the turbine

The highest impact operator and maintenance activities for gas turbine and centrifugal compressors include:

1.active fluids and mechanical analysis program,

2.ensuring the fuel system is free from contamination that will lead to nozzle or torch plugging,

3.the most common sources of contamination are: liquids, iron sulfide, and glycol,

4.clean inlet combustion air supply,

5.regular detergent washing of the combustion air compressor/air inlet turbine section of the package, and

6.eliminate frequent starts and stops.

Service Life

The key to extended service life of gas compressors and prime power movers is developing and maintaining a sound compressor maintenance program which includes:

1.regular original equipment manufacturer (OEM) recommended preventive maintenance (varies with the type and age of equipment),

2.load factor, use factor, and operating environment,

3.spare parts availability and maintenance,

4.personnel and training requirements, and

5.monitoring and inspection