Design Alternatives for High Ratio Compressor Stations

Sidney P. Santos
Matt Lubomirsky
Rainer Kurz
- 2013

Copyright 2013, Pipeline Simulation Interest Group

This paper was prepared for presentation at the PSIG Annual Meeting held in Prague, Czech Republic, 16 April – 19 April 2013.

This paper was selected for presentation by the PSIG Board of Directors following review of information contained in an abstract submitted by the author(s). The material, as presented, does not necessarily reflect any position of the Pipeline Simulation Interest Group, its officers, or members. Papers presented at PSIG meetings are subject to publication review by Editorial Committees of the Pipeline Simulation Interest Group. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of PSIG is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, Pipeline Simulation Interest Group, P.O. Box 22625, Houston, TX 77227, U.S.A., fax 01-713-586-5955.


While the transmission compressor stations in pipelines normally operate at relatively low pressure ratios in the order of 1.2 to 1, there are applications that require significantly higher pressure ratios. This paper presents the results of a study conducted for a compressor station design where multiple pipelines feed into one new pipeline. One of the feeder pipelines is designed for significantly lower pressures than the other feeder and the transmission line. As a result, some operating conditions require a very high compression ratio, in some instances as high as 2.8 to 1. The purpose of the study is to select the best feasible turbocompressor unit for the project between two technical available options with different technologies: single compartment and dual compartment compressors. The methodology adopted is designing a (i) compressor station configuration for single compartment compressor technology with aftercooler and for (ii) dual compartment compressor technology with intercooler and aftercooler, pre-selecting the compressor units to address all operating conditions, perform thermohydraulic simulations, evaluate the gas fuel demand for each year of operation and then evaluate the economics for each alternative. The paper can serve as a guide line for compressor station designers to make decisions not only based on technical aspects – that could lead to higher project life cycle cost – but rather on overall technical and economic aspects that produces lower project life cycle cost.


The design philosophy for choosing a turbocompressor unit should includes the following items:

  • (a) Good efficiency over a wide range of operating conditions
  • (b) Maximum flexibility of configuration
  • (c) Low maintenance cost
  • (d) Low lifecycle cost
  • (e) Acceptable capital cost
  • (f) High availability


The methodology adopted for this case study considers the following steps:

  1. Identify the ambient temperatures to be adopted for the project based on Summer, Winter and Average weather conditions;
  2. Define technical assumptions for the project such as gas supply curves, gas compositions, capacity ramp up curve, suction and discharge pressures, suction temperatures, pressure drops at suction and discharge headers of the compressor station, coolers downstream controlled temperature, etc.;
  3. Identify possible alternatives for the compressor station turbocompressor configuration;
  4. Acquire from manufacturers the performance maps for centrifugal compressor and gas turbine;
  5. Model the turbocompressor units to be simulated by using a simulation software;
  6. Evaluate operation conditions for compressor and gas turbine;
  7. Obtain the equipment, maintenance and operation costs;
  8. Identify the economic assumptions for the feasibility study;
  9. Project’s final decision selecting the most feasible project configuration.

Case Study

This case study is based on a header compressor station that feeds a pipeline with natural gas up to 10 BNCMY (373 BSCFY) with two different gas supplies. Each gas supply has its characteristics supply curve. The compressor station is shown in figure-1 and the centrifugal compressor units has been evaluated in two alternatives as described below and shown in figure-2:

Alternative I:
Centrifugal compressor type:Single compartment
Gas supply:Source A + Source B 
Alternative II:
Centrifugal compressor type:Dual compartment with intercooler
Gas Supply:Source A + Source B

Technical Assumptions

Gas specific gravity:0.59 and 0.61 
Compressor Station
 Suction Pressure:
 Pipeline A: 3.50 MPag 
  (508 Psig)
 Pipeline B:5.00 to 7.00 MPag
  (725 to 1015 Psig)
Compressor Units
 Discharge pressure (flange):9.81 MPag
  (1423 Psig)
Compressor Driver
 Gas turbine:15000 kW ISO
  (20115 hp ISO)
Intercooler pressure drop:70 KPa (10.2 Psi)
Intercooler downstream temperature:53 C (127.4 F)
Site elevation0 meter (feet)
Site ambient temperature:25.0 C (77 F)
Quantity of standby compressor units: *1

* Note: As Santos (2009) the best definition of the quantity of standby compressor units takes into account operation conditions and makes use of Monte Carlo simulation.

Thermohydraulic Simulation

The thermohydraulic simulation studies have been performed using the software PipelineStudio from Energy-Solutions Inc. with Peng-78 (Peng and Robinson equation of state published in 1978) and in steady state mode. The thermohydraulic results for Alternatives I and II and for different capacities and average weather condition are presented in tables 1 and 2. Installation of required compressor station units is presented in tables 3 and 4. Fuel gas consumption is presented in table 5.

Economic Evaluation

The economic evaluation for the compressor station configurations (alternative I and II) takes into account only what is different between the alternatives such as CAPEX and OPEX for the turbocompressor units including intercoolers. All that is the same, for both alternatives, e.g. compressor housing, gas turbine drivers, facilities, suction and discharge headers with scrubbers, piping, valves and also operation personnel, was not accounted for in the analysis.

To support the economic evaluation the following assumptions were considered:

Economic Assumptions

Construction schedule: 1 year
Single Compartment Compressor Unit:2.450 MMUS$
Dual Compartment Compressor Unit
with valves, piping and fittings:  2.854 MMUS$
Installed Intercooler (Dual Comp.)
with valves, piping and fittings:  1.540 MMUS$
Compressor station operating units:4
Standby compressor unit:1
Compressor station Incremental CAPEX for Dual Compartment Compressors
(Atl. II) due to larger ffotprint area: 0.120 MMUS$
O&M (without Fuel):5% of CAPEX
Depreciation:30 years
Fuel price, US$/1000 SCM:170
Discount rate:12% a year
Economic life:30 years

Note: Investments on required equipment assumed to be done 1 year before they come into operation.

Economic Results

The economic results based on the CAPEX, OPEX and Fuel Gas Expenses schedule (tables 6 and 7) for Alternatives I (Single Compartment Compressors) and II (Dual Compartment Compressors) are measure based on the Present Value (PV) of each alternative.

To support selecting the best alternative we have adopted the following criteria based on the lowest Present Value based on the economic assumptions previously defined and the CAPEX, OPEX and Fuel Gas expenses presented in table 7:

  1. The lowest Present Value of CAPEX + OPEX + Fuel Gas (from table 7):
    • Alternative I (Single): PV = -145.26
    • Alternative II (Dual): PV = -157.50
  2. The lowest Present Value for CAPEX only (from table 7):
    • Alternative I (Single): PV = -10.41
    • Alternative II (Dual): PV = -18.46

Based on the results of items (1) and (2) above we select Alternative I (Single Compartment Compressors) as the optimum alternative with a saving of 12.24 MMUS$ in Present Value of CAPEX + OPEX + Fuel Gas and with a saving of 8.05 MMUS$ in Present Value of CAPEX only.

Best Criteria Selection

Whenever Compressor Station designer needs to select compressor units he should keep in mind this rule of thumb that will – most of the time – favor single compartment compressor selection for gas pipeline compressor station:

  • Simplicity of installation: lower CAPEX;
  • Simplicity of operation and maintenance: lower OPEX;
  • High efficiencies: lower OPEX;
  • Wide range of operation: increased operation flexibility;

When Dual Compartment May Be Required

Dual compartment centrifugal compressor may be required whenever discharge temperature is higher than the practical value of 135 C (275 F) as established by Gas Processors Suppliers Association – GPSA. Above this value it would cause carbonization, risk of fire and/or packing life reduction. A limit of 148.8 C (300 F) or 176.7 C (350 F) is suggested by GPSA when there is no oxygen in the gas stream. Use of intercooler will guarantee that the compressor unit discharge temperature will be lower than maximum allowed.

ASME B16.5 – Pipe Flanges and Flanged Fittings specifies that at operating temperature range from -29 up to 150 C the working pressure is up to 100.3 barg (10.03 MPag) under Class 600# and above 150 up to 200 C class 900# should be adopted for flanges, accessories and auxiliary equipment such as intercoolers and aftercoolers with negative impact in CAPEX.

If operation conditions (gas composition, suction temperature and compression ratio) will not cause compressor unit discharge temperature go above 135 or 150 C there is no reason to justify selecting dual compartment compressor but single compressor will be a much better technical and economical selection.

Dual Compartment Disadvantages in comparison to Single Compartment:

  • Incremental CAPEX due to more complex compressor;
  • Incremental CAPEX due to additional required equipment such as intercooler, valves, fittings, piping and instrumentation;
  • Larger footprint area due to bigger and heavier compressors and consequently bigger and costly concrete base and compressor housing, increasing CAPEX;
  • Higher probability of unscheduled outages due to more components e.g. intercooler, valves, piping and instrumentation and control, negatively affecting compressor station availability exposing Operation Company to potential losses of revenue and to contractual penalties for not delivering the agreed upon gas volumes;
  • More items to maintain, increasing OPEX;
  • More costly commissioning, increasing OPEX;
  • More complex operation, increasing OPEX;

Higher probability of gas leakage due to more flanged connections, increasing operation risks and OPEX.

Sensitivity Analysis

In order to verify the advantages of the single compressor design (figure 3) versus dual compressor design (figure 4), where both equipment can fulfill operation requirements for a projet, we ran design set of operation conditions to quantify such advantages using two approaches.

(i) First approach: Single compartment compressor operating at 100% duty and dual compartment compressor with exactly the same stages as the single compartment split up evenly between two compartments. Dual compartment compressor, performing the same service duty, required 1.3% more power. This power requirement increase is a cconsequence of one more exit conection (first compartment) and one more inlet connection (second compartment) that produces pressure drops as compressor gas leaves on compartment and enters into the other.

(ii) Second approach: Same as approach (i) but adding intercooler with downstream temperature set up at 10 Celcius degrees above ambient temperature. Compression power requirement in comparison to approach (i) was reduced down to 97.9%, providing only just over 2.1% power reduction compare to the single compartment design.

Since feasibility analysis for equipment selection takes into account technical and economical aspects – as developed in this paper – this small power reduction do not overcome the overall benefit from single compartment compressor with much lower CAPEX requirements as quantified previously in the Economic Evaluation paragraph and justified at Best Criteria Selection paragraph.


The technical and economical evaluation performed on this case study identifies Single Compartment Compressor (Alternative I) as the optimum technical and economical alternative for projects where discharge temperature is lower than 135 C (275 F).

This result is supported by some important advantages of Single Compartment Compressor against Dual Compartment compressor as listed below.

Advantages of Single Compartment Compressor:

  • Simple design;
  • Easy to install, commission, operate and maintain;
  • Lower CAPEX and OPEX;
  • High efficiency and flexible range of operation.

Disadvantages of Dual Compartment Compressor:

  • Complex design
  • More complex and costly installation since requires the installation of intercooler, two surge control systems, more valves, piping and fittings per compressor unit;
  • Compressor station commissioning and start up take more time, are more expensive and require more qualified professionals;
  • Higher CAPEX and OPEX for the compressor station;
  • Operation of Dual Compartment Compressors in parallel requires more qualified professionals, more accurate controls and more attention from operators with a narrower margin of operation (lower flexibility) in comparison with Single Compartment Compressors;
  • Higher probability of unscheduled outages due to more components e.g. intercooler, valves, piping and instrumentation and control, negatively affecting compressor station availability exposing Operation Company to potential losses of revenue and to contractual penalties (if applied) for not delivering the committed gas volumes;
  • More power demanding because the required intercooler with consequent negative impact on fuel gas demand;
  • More complex and expensive maintenance

The methodology presented in this paper serves as a guideline to compressor station designer to identify and quantify the most important equipment that affects compressor station projects – the compressor unit – and to provide reliable information to support the decision making process for an optimum compressor unit selection.


  1. SANTOS, S. P., “Monte Carlo Simulation – A Key for a Feasible Gas Pipeline Design” In: Pipeline Simulation Interest Group, 2009, Galveston, Texas, USA.

About the author

Sidney Pereira dos Santos is Executive director of At Work Rio Engineering and Consulting. Has a B.S. in Mechanical Engineering at FTESM in Rio de Janeiro, 1983; MBA at UFRJ-COOPEAD in Rio de Janeiro, 2002; Master in Logistics at PUC-RJ, 2008. Twenty five years experience in gas pipeline design including thermohydraulic simulation, economic studies and quantitative risk analysis. Has authored and presented papers in ASME-IPC and PSIG Seminars and has some articles published in international technical magazines as Pipeline & Gas Journal, Pipeline & Gas Technology and Elsevier Energy Policy Journal. He is a former Petrobras Senior Consultant.

Matt Lubomirsky is a Consulting Engineer, Systems Analysis at Solar Turbines Incorporated, in San Diego, California. He is responsible for predicting gas turbines and compressors performance, for conduction of applications studies that involve pipeline and compressor stations modeling. Matt Lubomirsky attended Leningrad Institute of technology in Saint Petersburg, Russia where he received Master Degree in Mechanical Engineering. He has authored numerous publications about turbomachinery and pipeline related topics.

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 was elected ASME Fellow in 2003 and has authored numerous publications about turbomachinery related topics, with an emphasis on compressor applications, dynamic behavior, and gas turbine operation and degradation.


Table 1 – Thermohydraulic Results for Single Compartment Compressor (Alternative I)
Table 2 – Thermohydraulic Results for Dual Compartment Compressor (Alternative II)
Table 3 – Installation Schedule of Required Compressor Units for Alternative I
Table 4 – Installation Schedule of Required Compressor Units for Alternative II
Table 5 – Fuel Gas Consumption for Single and Dual Compartments Compressors
Table 6 - CAPEX Schedule for Single and Dual Compartment Compressors
Table 7 - Cash Flow, in MMUS$, for CAPEX, OPEX and Fuel Gas Expences


Figure 1 – Compressor Station Configuration
Figure 2 – Alternative I (Single Compartment) and Alternative II (Dual Compartment)
Figure 3 – Single Compartment Compressor
Figure 4 – Single Compartment Compressor