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Revision as of 11:55, 17 September 2013
This page provides an overview of the primary categories of natural gas compressor services and a description of the different classifications and types of compressors available to the industry. Adiabatic and polytropic compression theory are discussed with supporting definition of terminology.
Contents
 1 Compression theory
 2 Oil and gas compressor uses
 3 Classification and types
 4 Compression theory
 4.1 Isentropic (adiabatic) compression
 4.2 Polytropic compression
 4.3 Head
 4.4 Adiabatic or isentropic efficiency
 4.5 Polytropic efficiency
 4.6 Compressibility factory
 4.7 Flow or capacity
 4.8 Compression ratio
 4.9 Intercooling
 4.10 Power requirement
 4.11 Compressor selection
 4.12 Number of stages of compression
 5 Nomenclature
 6 References
 7 Noteworthy papers in OnePetro
 8 External links
 9 See also
Compression theory
Specific topics relating to compression theory include:
 Power requirement
 Isentropic exponent
 Compressibility factor
 Intercooling
 Adiabatic and polytropic efficiency
 Actual and standard volume flow rates
 Mass flow rates
 Inlet and discharge pressures
 Inlet and discharge temperatures
 Adiabatic and polytropic head
Major components and construction features of centrifugal and reciprocating compressors are emphasized. Installation, safety, and maintenance considerations also are discussed in their erspective pages.
Oil and gas compressor uses
Compressors used in the oil and gas industry are divided into six groups according to their intended service. These are:
 Flash gas compressors
 Gas lift compressors
 Reinjection compressors
 Booster compressors
 Vaporrecovery compressors
 Casinghead compressors
Flash gas compressors
Flash gas compressors are used in oil handling facilities to compress gas that is “flashed” from a hydrocarbon liquid when the liquid flows from a higher pressure to a lower pressure separator. Flash gas compressors typically handle low flow rates and produce high compression ratios.
Gas lift compressors
Gas lift compressors are frequently used in oil handling facilities where compression of formation gases and gas lift gas is required. Gas lift compressor duty is frequently of low to medium throughput with high compression ratios. Many gas lift compressors are installed on offshore facilities.
Reinjection compressors
The reinjection of natural gas is employed to increase or to maintain oil production. Reinjection compressors can be required to deliver gas at discharge pressures in excess of 10,000 psi. Reinjection compressors also are used for underground storage of natural gas. Compressors, applied to these services, have large compression ratios, high power requirements, and low volume flow rates.
Booster compressors
Gas transmission through pipelines results in pressure drop because of friction losses. Booster compressors are used to restore the pressure drop from these losses. Selection of these compressors involves evaluating the economic tradeoff of distance between pipeline boosting stations and lifecycle cost of each compressor station. Booster compressors also are used in fields that are experiencing pressure decline. Most centrifugal pipeline booster compressors are gas turbine driven, although the use of variablespeed motor drives is becoming more prevalent. Lowspeed integral gas engine reciprocating compressors also are used for gas transmission applications. Booster compressors typically are designed for high throughput rates and low compression ratio. Many booster applications can be configured in a singlestage centrifugal compressor.
Vapor recovery compressors
Vapor recovery compressors are used to gather gas from tanks and other lowpressure equipment in the facility. Often the gas from a vapor recovery compressor is routed to a flash gas, gas lift, or booster compressor for further compression. Low suction pressures, high compression ratios, and low gas throughput rates characterize these compressors.
Casinghead compressors
Casinghead compressors are usually used with electric submersible pumps and rod pumps where formation gas is required to be separated downhole and then transported through the annulus. Often the compressor discharge is routed to either a booster or flash gas compressor or to a lowpressure gathering system. Like vapor recovery compressors, casinghead compressors operate with low suction pressures, high compression ratios, and low gas throughput rates.
Classification and types
Compressors are classified into two major categories:
Positive displacement compressors
Positive displacement compressors are further divided into:
Dynamic or kinetic compressors
Dynamic compressors are continuousflow machines in which a rapidly rotating element accelerates the gas as it passes through the element, converting the velocity head into pressure, partially in the rotating element and partially in stationary diffusers or blades. Dynamic compressors are further divided into:
 Centrifugal
 Axialflow
 Mixedflow types
Compression theory
Both positive displacement and dynamic compressors are governed by a few basic principles derived from the laws of thermodynamics. This section defines terminology and discusses the operating principles essential for understanding compressor design, operation, and maintenance.
Isentropic (adiabatic) compression
An adiabatic process is one in which no heat is added or removed from the system. Adiabatic compression is expressed by
where k = C_{p}/C_{v} = ratio of specific heats, dimensionless.
Although compressors are designed to remove as much heat as possible, some heat gain is inevitable. Nevertheless, the adiabatic compression cycle is rather closely approached by most positive displacement compressors and is generally the base to which they are referred.
Polytropic compression
A polytropic process is one in which changes in gas characteristics during compression are considered. Dynamic compressors generally follow the polytropic cycle as defined by the formula
where n = polytropic exponent.
The polytropic exponent n is experimentally determined for a given type of machine and may be lower or higher than the adiabatic exponent k. Because the value of n changes during the compression process, an average value is used.
When inlet and discharge pressures and temperatures are known, the polytropic exponent can be determined from the relationship
Head
Head is simply the work expressed in foot pounds per pound of gas or Nm/kg. At a given compressor speed and capacity, the head developed by a centrifugal compressor is the same regardless of the nature of the gas being compressed. The pressure rise produced by the given amount of head varies with the density of the gas.
Isentropic (adiabatic) head
In an isentropic compression process, head is calculated by Eq. 4.
where
H_{is}  =  isentropic head, ftlbf/lbm, 
z_{avg}  =  average compressibility factor, dimensionless, 
T_{s}  =  suction temperature, °R, 
S  =  gas specificgravity (standard atmospheric air = 1.00), 
P_{d}  =  discharge pressure, psia, 
and  
P_{s}  =  suction pressure, psia. 
Polytropic head
In a polytropic compression process, head is defined by
where
H_{p}  =  polytropic head, ftlbf/lbm, 
and  
η_{p}  =  polytropic efficiency. 
Adiabatic or isentropic efficiency
Adiabatic efficiency is defined as the ratio of work output for an ideal isentropic compression process to the work input to develop the required head.
For a given compressor operating point, the actual or predicted isentropic efficiency can be calculated with Eq. 6.
where
η_{is}  =  isentropic efficiency, 
T_{s}  =  suction temperature, °R, 
T_{d}  =  discharge temperature (actual or predicted), °R, 
and  
k  =  ratio of specific heats, C_{p}/C_{v}. 
Polytropic efficiency
The efficiency of the polytropic compression process is given by
where η_{p} = polytropic efficiency.
Compressibility factory
The perfect gas equation derived from Charles’ and Boyle’s laws makes it possible to determine the weight of a given gas as determined by the equation
where
P  =  pressure, 
V  =  volume, 
N  =  number of moles, 
R  =  constant for a specific gas, 
and  
T  =  temperature. 
In reality, all gases deviate from the ideal gas laws to some degree. This deviation is defined as a compressibility factor, z , applied as a multiplier to the basic formula. Therefore, Eq. 8 is modified to include the compressibility factor as shown next.
Flow or capacity
Compressor flow (capacity) can be specified in three ways:
 Mass (weight) flow
 Standard volume flow
 Actual (inlet) volume flow
Mass or weight flow
Mass flow is expressed as mass per unit of time, most often poundsmass per minute (lbm/min) or kilograms per minute (kg/min). Mass flow is a specific value independent of gas properties and compressor inlet conditions. Mass flow can be specified on either a wet (water vapor included) or dry basis.
Standard volume flow
Standard volume flow is the most common term used by the industry to describe volumetric flow because it is independent of actual gas pressures or temperatures. It is the volume per unit of time using pressures and temperatures that have been corrected to "standard" conditions. These conditions apply to pressure, temperature, molecular weight, and compressibility. The standards must be known and held constant. For purposes of this text, the standard conditions used are
pressure  =  14.7 psia, 
temperature  =  60 °F, 
compressibility  =  1.00, 
and  
molecular weight  =  MW of subject gas. 
Standard volume flow is usually dry and expressed in millions of standard cubic feet per day (MMScf/D).
Actual inlet volume flow
Actual volume flow is defined as the amount of volume per unit of time at the inlet to the compressor. Actual volume flow is normally expressed in actual cubic feet per minute (ACFM) or actual cubic meters per hour (m^{3}/hr). When gas composition and pressure and temperature are known, the specification of actual volume is appropriate because the fundamental performance characteristic of the compressor is sensitive only to actual volume flow at the inlet.
Mass flow can be converted to actual volume flow with Eq. 10.
where
W  =  mass flow, lbm/min., 
R  =  universal gas constant = 1,545, 
MW  =  molecular weight, 
T_{s}  =  suction temperature, °R, 
z_{s}  =  compressibility at inlet, 
and  
P_{s}  =  absolute suction pressure, psia. 
Standard volume flow can be converted to actual volume flow with Eq. 11.
where Q_{g} = standard volume flow, MMscf/D.
Compression ratio
Compression ratio, R_{c}, is simply the absolute discharge pressure divided by the absolute suction pressure. As expressed in Eq. 3, temperature ratio increases with pressure ratio. Temperature limits related to the mechanical design of compressors often will dictate the maximum pressure ratio that can be achieved in a stage of compression. (Refer to section on intercooling below.)
Intercooling
Where large pressure ratios are needed, splitting the compression duty into one or more stages with intercooling between stages can be the most energy efficient arrangement. The energy savings must be compared with the capital and maintenance investment necessary to provide the cooling. In addition to the thermodynamic benefit, intercooled compression systems result in lower discharge temperatures, which reduce the need for special compressor materials.
Power requirement
The total power requirement of a compressor for a given duty is the sum of the gas power and the friction power. The gas power is directly proportional to head and mass flow and inversely proportional to efficiency. Mechanical losses in the bearings and, to a lesser extent, in the seals are the primary source of friction power.
For centrifugal compressors, the gas power can be calculated as
where
GHP  =  gas power, horsepower, 
W  =  mass flow, lbm/min., 
and  
H_{p}  =  polytropic head, ftlbf/lbm. 
For reciprocating compressors, the gas power can be calculated as
where
P_{1}  =  inlet pressure, psia, 
V_{1}  =  inlet volume, ACFM, 
P_{2}  =  discharge pressure, psia, 
and  
CE  =  compression efficiency (assume 0.85 for estimating purposes). 
Compressor selection
Proper selection of the compressor type and number of stages can be accomplished only after considering a number of factors. (For the purposes of this chapter, discussion is limited to centrifugal vs. reciprocating compressors.) Basic information needed for the proper selection includes:
 Volume and mass flow of gas to be compressed
 Suction pressure
 Discharge pressure
 Suction temperature
 Gas specific gravity
 Available types of drivers
The required volume flow and discharge pressure define a point on a graphic representation of compressor coverage, as shown in Fig. 6. Examination of this chart reveals that, in general, centrifugal compressors are appropriate for high flow applications, and reciprocating compressors are better suited to low flow rates.
Number of stages of compression
Using the specified overall pressure ratio and suction temperature (and an assumed efficiency), the discharge temperature for compression of gas with a known k value in a single stage can be estimated by rewriting Eq. 7.
where
T_{2}  =  estimated absolute discharge temperature, °R, 
T_{1}  =  specified absolute suction temperature, °R, 
P_{1}  =  specified absolute suction pressure, psia, 
P_{2}  =  specified absolute discharge pressure, psia, 
k  =  ratio of specific heats, 
η_{p}  =  assumed polytropic efficiency, 
≈  0.72 to 0.85 for centrifugal compressors,  
and  
≈  1.00 for reciprocating compressors. 
If the singlestage discharge temperature is too high (typical limit is 300 to 350 °F), it is necessary to configure the compression equipment in more than one stage. Calculating the compression ratio per stage with Eq. 15 does the evaluation of a multistage design.
where
R_{sect}  =  compression ratio per section, 
and  
n  =  number of sections. 
Using the previous equations and prudent assumptions, it is possible to determine the minimum number of stages required to accomplish a given overall compression ratio without exceeding temperature limits.
Nomenclature
k  =  C_{p}/C_{v} 
C_{p}/C_{v}  =  ratio of specific heats, dimensionless 
n  =  polytropic exponent 
H_{is}  =  isentropic head, ftlbf/lbm, 
z_{avg}  =  average compressibility factor, dimensionless, 
T_{s}  =  suction temperature, °R, 
S  =  gas specificgravity (standard atmospheric air = 1.00), 
P_{d}  =  discharge pressure, psia, 
P_{s}  =  suction pressure, psia 
H_{p}  =  polytropic head, ftlbf/lbm, 
η_{p}  =  polytropic efficiency 
η_{is}  =  isentropic efficiency, 
T_{s}  =  suction temperature, °R, 
T_{d}  =  discharge temperature (actual or predicted), °R, 
k  =  ratio of specific heats, C_{p}/C_{v} 
η_{p}  =  polytropic efficiency 
P  =  pressure, 
V  =  volume, 
N  =  number of moles, 
R  =  constant for a specific gas, 
T  =  temperature 
W  =  mass flow, lbm/min., 
R  =  universal gas constant = 1,545, 
MW  =  molecular weight, 
T_{s}  =  suction temperature, °R, 
z_{s}  =  compressibility at inlet, 
P_{s}  =  absolute suction pressure, psia 
Q_{g}  =  standard volume flow, MMscf/D 
GHP  =  gas power, horsepower, 
W  =  mass flow, lbm/min., 
H_{p}  =  polytropic head, ftlbf/lbm 
P_{1}  =  inlet pressure, psia, 
V_{1}  =  inlet volume, ACFM, 
P_{2}  =  discharge pressure, psia, 
CE  =  compression efficiency (assume 0.85 for estimating purposes) 
T_{2}  =  estimated absolute discharge temperature, °R, 
T_{1}  =  specified absolute suction temperature, °R, 
P_{1}  =  specified absolute suction pressure, psia, 
P_{2}  =  specified absolute discharge pressure, psia, 
k  =  ratio of specific heats, 
η_{p}  =  assumed polytropic efficiency, 
≈  0.72 to 0.85 for centrifugal compressors,  
and  
≈  1.00 for reciprocating compressors  
R_{sect}  =  compression ratio per section, 
n  =  number of sections 
References
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Noteworthy papers in OnePetro
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