Sidney P. Santos
Series or Parallel Arrangement for a Compressor Station? - A Recurring Question that needs a Convincing Answer
Sidney Pereira dos Santos, PETROBRAS – Gas Business Unit
Copyright 2003, Pipeline Simulation Interest Group
This paper was prepared for presentation at the PSIG Annual Meeting held in Williamsburg, Virginia, 11 October – 13 October 2006.
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.
Long distance gas pipelines compressor stations play an important role in providing natural gas transportation
capacity at the same time that allow the pipeline capacity expansion in conjunction with the option of installing loop
lines along its length.
This subject has attracted the attention of many authors (Santos, 1997 and 2000; Kurz et all, 2003) with papers addressing the pros and cons of adopting a specific compressor station units arrangement, whether series, parallel or parallel-series, with conclusions not always comprehensive and converging.
This paper brings back this important subject to our attention and presents an evaluation of the best arrangement for a compressor station not as a theoretic and isolated design but as part of an entire gas transportation system.
A case study is presented base on the expansion design for the Bolivia-Brazil Gas Pipeline Project – Gasbol for the Station #5, in Brazil side. Gasbol pipeline has a design capacity of 30 MMm3/d (1,059 MMcfd) resulted from a ND 32", 1813 km ( 1127 miles) pipeline and 14 compressor stations with 4 units, each of them originally designed with 7000 hp ISO, starting at Rio Grande, Bolivia up to São Paulo, Brazil.
This paper also covers the Gasbol capacity expansion studies from 34 (1201) and then to 40 (1413), 50 (1766) and 68 MMm3/d (2402 MMcfd) by means of retrofitting its compressor stations and by adding looping on incremental basis.
The subject of which arrangement to adopt has been considered and simulated at the design phase of the project and was again performed by the time we started the expansion design. Such analysis has even considered the opportunity of using variable speed driver with electric motor as an alternative against gas turbine drivers (Santos, 2000). Failure analysis in transient mode was also performed to identify the pros and cons of the compressor station units arrangement This paper presents a technical and economic approach to help deciding on which compressor station arrangement to adopt.
When the Bolivia-Brazil Gas Pipeline design has started in 1993 there were some uncertainties to be addressed such as
the certified volumes for the gas reserve, closure of transportation agreements, creation and implementation of gas
distribution companies, gas selling agreements and market growth projections. The design started assuming a
transportation capacity of 16 MMcm/d (565 MMdfd) from a 28" pipeline diameter that proved to be unfeasible.
The design capacity was defined latter on to be 30 MMcm/d (1059 MMcfd) from a 32" pipeline diameter with extension of 1813 km (1127 miles) and 14 compressor stations. The expansion project based solely on new compressor stations design has improved the capacity from 30 (1059) to 34 MMm3/d (1201 MMcfd).
As part of the design phase we adopted a methodology that proved to be of fundamental importance for the project
success that includes the following steps:
1. Perform thermo-hydraulic simulation – steady state
2. Pre-select compressor units
3. Perform thermo-hydraulic simulation – transient state
4. Perform failure analysis
Thermo-hydraulic Simulation – Steady State
The pipeline was modeled using generic compressor with trans-thermal and steady state modes for each operation year and adopted the following steps:
• Simulation from maximum to minimum capacity
• Definition of compressor station quantity and spacing
Pre-selection of Equipment for Series and Parallel Arrangements
With the data collect from each operation year from steady state simulation for the compressor station we were able to pre-select the turbo-compressor units to be used in series or in parallel arrangement. We have favored the selection of larger units and fewer quantities per station since the concentration of power per unit drops the capital investment per station, presents higher thermodynamic performance and therefore enhances the project economics.
Thermo-hydraulic Simulation – Transient
With the performance maps defined from the pre-selection of the turbo-compressor units for series and parallel arrangements and with the flow demand profiles for each gas delivery points we run the transient analysis for each operation year to check the pipeline sizing (Santos, 1997 and 2000) and compressor station overall performance.
Another important step while designing a gas pipeline and selecting the compressor station, whether series or parallel, is the failure analysis. The failure analysis allows quantifying exactly which arrangement will present the higher transportation capacity under failure conditions and also allows identifying the one that will be more desirable in terms of reducing liabilities due ship-or-pay agreements clauses.
The case study is based on the Expansion Project of the Bolivia-Brazil Gas Pipeline – Gasbol that we have applied all
the aforementioned procedures. This case study considers an evaluation of two parallel arrangements and one series
arrangement as described below:
• Two centrifugal compressor per station
• Four centrifugal compressor per station
• Two centrifugal compressors per station
Gas Specific Gravity 0.6
Diameter: DN 32"
Design code: ANSI B31.8
Max. Allowed Working Pres. – MAOP: 1440 PSIG
Pipe material: API 5L X70
Pipe internal roughness (epoxy painted): 350 minches
Pipeline Inlet Pressure: 1420 psig
Minimum Pipeline Delivery Pressure: 700 psig
Pipeline overall heat transfer: 0.39 Btu/h.ft2.F
Soil temperature: 61 to 86 F
Depth of burial: 3 feet
Maximum Compression ratio: 1.6
Suction and Discharge Header pressure drop: 5 psi
After cooler pressure drop: 5 psi
After cooler outside temperature: 127 F
Site elevation 341 feet
Site Temperature 82 F
Flow Equation: Colebrook
Centrifugal Compressors - Performance Maps
• Two Units in Series – 2 x 15000 hp ISO, figure 1
• Two Units in Parallel – 2 x 15000 hp ISO, figure 1
• Four Units in Parallel – 4 x 7800 hp ISO, figure 1
Thermo-Hydraulic Simulation Results for the Station Configurations
The simulations results for all the arrangements can be seen on table 1.
For the purpose of this case study the compressor station has been considered as a business unit (see figure 2) with
contractual obligations to guarantee the nominal transportation capacity. In this model the Service Co is a company
that holds property of the compressor station and provides a compression service under an agreement with the
transportation company – TransCo.
Based on gas turbine reliability of 97.5% we can anticipate a down time of 219 hour or 9.125 days per year per unit assumed that the failures may happen to one unit at a time. We also considered that the station have 1 (one) spare driver that would be used as a replacement. The replacement time was taken as 48 hours. The detrimental effect on capacity reduction is associated with loss of revenue and contractual liabilities assumed as the same amount as the revenue losses as detailed onward.
As can be seen from the graphic show on figure 3 the parallel arrangement with 4 compressor units is the one that presents a much better result along the 48 hours of failure.
The effect of one unit failure in Station #5 over the Station #6 can be observed on figure 4 for all arrangements under analysis. Figures 5 to 11 explain the amount of capacity recovered as a function of the operation variables of the remaining compressors such as available power and maximum speed. In some cases we can observe that the compressor power or speed goes to maximum and as a consequence discharge pressure can no longer be maintained at the set pressure of 99.84 kgf/cm2g (1420 psig). For the purpose of this case study Station #6 was considered as 4 x 7800 hp ISO and all downstream part of the gaspipeline was maintained unchangeable for all the cases analysed so as not to affect the comparative avaluation of Station #5. For the series arrangement (2 x 15000 hp ISO) one unit failure analysis, figure 6 shows the recycling time that the remaining compressor unit will run until its compression ratio overcomes the station compression ratio. During this recycling time the station flow will be zero. This situation was modeled by shuting down both units and starting one unit thereafter. This effect is not observed in figure 5 since graphic time scale is larger and this effect is very short in time.
With the tabular format (see table 2) from the previous graphic for failure analysis we can quantify the capacity loss for each configuration, in MMm3/d as shown in
Capacity Loss due to Failure
The capacity loss per year is equal to the failure days per unit/year times the number of units times the average capacity loss. The result must be doubled to allow for contractual liabilities (see table 3).
Technical and economic evaluation is necessary to support the decision on which arrangement to adopt since there are
some items that affect significantly the overall result of the analysis. The economic evaluation assumed the
compression station #5 as a Business Unit under a compression service contract with a Shipper on 100% availability.
The spreadsheet (see figure 12) calculation considered the following assumptions and is shown below:
• Capital investment requirements for each configuration
• Investment done in two years time – 50% each year.
• O&M cost (overhaul and spare parts included) as 5% of the total station investment
• Compression rate for each Station arrangement in US$/MMBTU
• Fuel price @ 1.25 US$/MMBTU
• Pipeline capacity under failure analysis
• Taxes of 40%
• Return rate of 12% a year un-leveraged.
• Project life of 10 and 15 years
Capital Investment and O&M
The compressor station capital investment shown on the table 4 represents the expected costs and includes engineering, importation, taxes and construction and assembling and may vary from country to country. Reader should get the accurate figures for his own project configuration prior to apply the methodology presented in this paper.
Economic Evaluation – Table of Results
The economic evaluations have been made for the station with and without stand by units and the results are shown on table 5. With all the information for each configuration the compression service rate was calculated to recover all the capital expenditure - Capex and operation expenditures - Opex using the economic assumptions defined previously.
The discounted cash flow – DCF approach (Ross, Westerfield, 1999) was performed by using an excel spreadsheet to evaluate the net present value – NPV of each compressor station configuration. The series arrangements with 2 units of 15000 hp ISO with and without stand by unit were taken as reference arrangements and the correspondent compression service rates were calculated to zero the NPV. For the other configuration we kept the compression service rate as constant to evaluate the NPV effect due to changes in capital investment, capacity loss, fuel usage, O&M and depreciation.
The two reference arrangements, that are the 2 units in series with stand by units and 2 units in series without stand by units, had their compression service rate calculated to give NPV equal zero for comparison purpose. To keep a stand by unit the Shipper will have to pay for this operational compressor station availability increase that would affect the competitiveness of a compression service provider or the Business Unit we considered to apply for the Station #5 as reflected on the compression service rate of 0.0377 versus 0.0314 US$/MMBTU – 20.06% higher, for a economic life of 10 years.
Gas Pipeline Expansion
Gas pipeline expansion is something that we should expect to happen along the life of a project. As we acknowledge the
natural gas market potential growth studies has been made for incremental capacity expansion. The Bolivia-Brasil Gas
pipeline Project started with a capacity of 16 MMm3/d (565 MMcfd) then we decided on a design capacity of 30 MMm3/d
(1059 MMcfd). Later on we redesigned the compressor stations to increase capacity to 34 (1201), 40 (1413), 50 (1766)
and 68 MMm3/d (2402 MMcfd). Associated with the compressor station redesign we also considered the installation of
loop lines to the pipeline in incremental lengths of 1/3, 2/3 and finally doubling the gas pipeline section between
the compression stations. Up to 34 MMm3/d (1201 MMcfd) the expansion relied only on compressor station redesign
without loop lines.
The Compressor station arrangement whether series or parallel has attracted our attention in terms of having a configuration that would be flexible enough and that would minimize capital investment, fuel usage, O&M costs and therefore would maximize economic results for the project. The thermo-hydraulic simulation results from this analysis are presented on tables 6 and 7.
Parallel arrangement was adopted as the best selection for the project.
In case we start a project with a series arrangement and latter on we need to expand the capacity we must be aware of the limitations associated with the units capacity range since all the gas flow goes through each compressor and we also have the available power from the driver that may be just enough for the original design with no allowance to be used for the expansion and in that case the options would be a replacement for the units or to add parallel units that would be one unit or even two additional units in series as illustrated in figure 13, that shows an optimization scheme with suction and discharge headers and set of valves that allows a flexible parallel-series arrangement for a compressor station with just one unit (any unit) as a stand by.
As can be seen from the simulation results and confirmed by the economic evaluation for this case study, series
arrangements provides better results when compared with parallel arrangements when no stand by units is considered and
parallel units provides better results than series when stand by units is a requirement and more flexibility is
The impact of transportation capacity shortage and capital investment associated with the stand by unit play an important role on this kind of analysis and must be considered whenever a design selection is to be made.
The methodology presented if adopted accordingly will provide a convincing economic answer to the recurrent question related to the compressor station arrangement and therefore will allow a good decision making.
- Santos, S. P., 1997, "Transient Analysis – A Must in Gas Pipeline Design", Pipeline Simulation Interest Group
- Santos, S. P., 2000, "Series or Parallel – Tailor Made Design or a General Rule for a Compressor Station Arrangement?" Pipeline Simulation Interest Group
- Kurz, R., Ohanian, S. and Lubomirsky, M., 2003, "On Compressor Station Layout", Proceedings of ASME TURBOEXPO 2003.
- ROSS, S.A.; WESTERFIELD, R.W.; JAFFE, J.F. - Corporate Finance, fifth edition: The McGraw-Hill Companies, Inc., 1999.
The authors want to thank PETROBRAS for making this information available to the PSIG members and also Sebouh Ohanian, Senior Project Manager of Solar Turbines for reviewing the paper and providing pertinent comments.
About the author
Sidney Pereira dos Santos, the author, is a Senior Consultant at PETROBRAS Gas Business Unit, has a
BS in Mechanical Engineering and a MBA in Corporate Finance, and has 13 years of experience in shipbuilding design,
and also 14 years in the oil and gas pipeline design at PETROBRAS. He has been deeply involved in most of the gas
pipeline projects such as the Bolivia-Brazil project and the ongoing gas pipeline expansion in Brazil and has been
conducting technical and economic studies and conceptual design for the upcoming projects.
Phone: +55 21 8167-0134
e-mail: [email protected]