60 Pipeline & Gas Journal / June 2008 / www.pgjonline.com

Basic Guide to Pipeline Compressor Stations

s natural gas moves through a pipeline, the pressure decreases due to friction of the gas along the pipe wall and the gas must be recompressed to maintain

the flow. Gas compressor stations are installed at optimum locations along the pipeline as the load profile changes and are sized to sufficiently boost the gas pressure and maintain flow through the pipeline. Compressor stations may be small, situ-ated on gathering lines (Figure 1) or laterals, or large on major trunk line transmission systems. However, all are built up from the same functional blocks of equipment. Each functional element (Figure 2) plays a role in the work of the station and the design and sizing of each is essential to the efficient and safe operation of the plant.

The functional elements include gas scrub-bing and liquid removal, compressor and driver

units, aftercoolers, pipes and valves. Controls including Supervisory Control And Data Acquisition (SCADA) system, monitoring and data recording, alarms and shut down proce-dures, both routine and emergency are an integral part of the station. Provision also has to be made for venting the compressor and driver housing and buildings, complete with ventila-tion and fire protection, and safety equipment.

The financial elements include cost-of-ser-vice calculations which include the installed cost of the equipment, fuel, maintenance and operating costs for the expected project life (typically 10 25 years). A risk simulated dis-counted-cash-flow (DCF), rate-of-return (ROR) method of investment (Santos, 2003) analysis is recommended. Fuel cost is the major item in this calculation and the projection for escalation

forms an important consider-ation and must be included in the risk simulation analysis.

Inlet ReceivingThe gas in a main transmis-

sion line is nominally clean and dry while that in gas gathering lines may contain liquids prior to processing, but in all cases there can be entrained liquids

By Saeid Mokhatab, Greg Lamberson and Sidney Pereira dos Santos

and particulates which have to be removed before compression to maintain efficiency and integrity. Efficient and safe handling of the liquids collected from the scrubbers in a compressor station is one of the keys to a good design. Individual scrubbers (with or without standby unit) may be installed for each stage of compression for each compressor unit.

A common scrubber should be considered for multiple units on a common suction line. Filter/separators may also be used to remove smaller liquid droplets and/or solid particles. In the case of reciprocating compressors being used in the transmission system a coalescer filter is of capital importance to guarantee that cylinder lubricating oil will not enter the pipe-line and affect gas specification. Poor handling of these liquids can be the major source of operating and maintenance problems and have a significant impact on station economics. The suction scrubber should be equipped with a mesh type mist elimination section to avoid liq-uid entrainment into the compressor. Scrubbers can take several forms, inertial with or with-out demister pads or the horizontal cyclonic type. The latter are commonly used on mainline transmission stations.

There are three main concerns that should be addressed in the liquid-handling design for any compressor station: safety, environmental impact, and economics. Another consideration should be operability, which includes issues like hydrate formation (when water is present in the gas composition), failure consequences, etc.

The gas compressor stations inlet receiv-ing facilities consist of pig receivers and a slug catcher to remove large solid and liquid contaminants followed by filter coalescers to remove fine solids and hydrocarbon mist. A filter coalescer also cleans the gas in each fuel supply to the turbines and gas engines. Removed liquids flow to a hydrocarbon storage tank where they are separated by gravity and then transported by truck as saleable hydrocar-bon liquid or disposed of as waste product.

Design PressuresThe design pressure for station gas piping

should at least equal the MAOP of the pipeline. For single-stage stations, the suction and dis-charge piping should have the same design pres-sure. For multi-stage stations, the suction piping design pressure should at least equal the highest attainable suction pressure under all operating and startup modes, and the interstage and dis-charge piping design pressures should at least equal the maximum discharge pressure. Multi-pressure systems must be designed to ensure that each system is not over-pressured during normal operation and is protected to the appropriate pressure level during upset conditions.

It is a general rule to use design pressures to accommodate use of a standard ANSI Class rating for compressor station piping compo-nents. The cost to increase design pressure to a standard ANSI Class is minimal and will provide greater flexibility in future use of the equipment and materials.

CompressionThe gas pressure in the pipelines is increased

by a combination of one or more compres-sors connected in parallel or in series to the

Figure 1: Cabiunas Terminal - Onshore Gas Gathering Compressor Station. (source: PETROBRAS - Rio de Janeiro Brazil)Figure 2: Typical Compressor Station P&I Diagram (Mokhatab et al., 2007).

Pipeline & Gas Journal / June 2008 / www.pgjonline.com 61

pipelines by the station piping. Typically for mainline stations, gas turbine-driven centrifu-gal compressors are used as the base units to compress the majority of the flow. These are compressor drivers that are turbine engines using natural gas for fuel.

Compressor selection is based on detailed analysis of the operating conditions in terms of flow and pressure ratio needed by the pipeline hydraulics. Frequently these conditions will vary over time and the compressor selection will have to have flexibility, by restaging if necessary, to accommodate all the expected conditions. From transient analysis based on predicted ramp-p gas demand and flow profiles a set of values is defined that will be used to pre-select compres-sor units, depending on the installation layout, whether series or parallel (Santos, 1997; 2004).

Typically the conditions for most mainline stations will require compressors with one or two stages, and the compressor design may be of the overhung rotor or barrel design. The determination of operating conditions and hence the development of the compressor characteristics will have to take into account the gas characteristics, suction and discharge pressure, and suction temperatures, usually involving equations of state for the particular gas composition, and the process environment (i.e., climate, altitude, location, etc.).

The pipeline and station designer will make sure that the equipment selection and arrange-ment including maintenance strategy and level of availability will be subject to a feasibility study (Santos, 2004).

Compressor power will be determined from the compressor characteristics and thus the driver BHP can be calculated. Driver selection is principally influenced by energy consump-tion (fuel used) and power capability to drive the compressor. Since gas turbines do not come in an affinity of ratings, it is usually necessary to select the nearest match for power above the maximum requirement. The optimum selection of compressor and driver is a complex process, involving much negotiation with the suppliers, and is beyond the scope of this article.

It is recommended that all potential areas of pipe stress be evaluated very carefully due to the large temperature variations present in compressor system piping and the stresses occurring in large-diameter piping. Particular care should be taken to ensure that pipe stresses do not impart excessive forces on compres-sor nozzles. Shaft misalignment with resulting vibration and/or excessive wear can be caused if high loads from the piping are transmitted to the compressor case. Compressor manufactur-ers will provide the maximum allowable loads. A complete pipe stress analysis should be performed on compressor gas piping systems if operating temperatures are greater than 200F.

Mostly in the case of a gas gathering system, gas compressor station inlet receiving facilities consist of pig receivers and a slug catcher to remove large solid and liquid contaminants, fol-lowed by filter coalescers to remove fine solids and hydrocarbon mist to reciprocating compres-sor cylinder and valves protection. A pig refers to a device that is pushed by the gas through the pipe either to clean the pipe of obstructive mate-rial or inspect the pipe for defects (roundness or

thickness reduction from corrosion process).A slug refers to volumes of hydrocarbon liq-

uids and water that accumulate in the pipeline as entrained liquids in saturated natural gas con-dense. Slugs also occur from cleaning solutions injected into the pipeline for integrity mainte-nance pigging. Normal gas flow by-passes the slug catcher to reduce pressure losses. Flow is switched through the slug catcher for as-needed use. Where liquid slugs may be received, the station should include a slug-catching system with adequate storage capacity for the largest expected slug. Typical slug catchers are con-structed of pipe and fittings and create a change of direction of the gas stream, allowing dropout of the liquid slug (Figure 3).

Some facilities, (e.g. gas-fired power plants) use natural gas reciprocating booster com-pressors. Turbine manufactures may require carryover limited to 0.1 to 0.003 ppm (wt.) range. A downstream coalescer filter will pre-vent lubricating oil from compressor cylinders affecting turbine integrity. Filter and turbine manufactures specifications and also field experience should be considered to guarantee proper equipment selection.

The compressor foundation should also be designed taking vibration into consideration. Pressure drop in the compressor suction, interstage or discharge piping system including scrubbers, valves and related items in each system should be no more than 3 psi per stage or system (excluding coolers and any gas treating facilities).

Station ControlControl functions are typically based on

personnel safety, the operating parameters of the station, and the types and number of compressor units installed at the station.

Compressor station controls can be divid-ed into two sections, unit control and sta-tion control. Digital technology is now used throughout both systems. The unit control utilizes a microprocessor which will control the turbine compressor unit to run to set points under the direction of the operator or the station control system. The set points can be flow or pressure. Commonly, a flow or suction pressure will be the control parameter with discharge pressure and/or suction pres-sure as overrides. The control protocol will include limits to ensure safe operation. These limits will include pressure and temperatures on discharge and suction on the compressor as well as speed and flow and pressure ratio in relation to surge.

The unit control will monitor the compres-

sor operation to ensure that it will not run into surge. If the operation of the compres-sor nears the surge line, the unit control will instruct the recycle valve to open and so maintain safe operation. Should the recycle condition continue for a time, and if coolers are not provided in the recycle line or com-pressor discharge, the unit will be shut down on high discharge temperature.

In addition to control and safety, the unit control will monitor key operating parame-ters and provide video output on demand and printout on a routine basis to provide a con-tinuous record of operation. These readouts and records can be used for troubleshooting and maintenance. The station control system will oversee the unit operation and also pro-vide the interface between the operators and the plant. It will provide video and print data recording of all key station parameters. It has become more common to operate stations and units remotely from central dispatch stations and the station-control systems will report to the central station via a SCADA link.

The overall control of a major gas pipe-line transportation system typically originates from a central Gas Control office that is remote from all of the compressor stations. Gas control monitors flow measurement for the total station throughput as well as each compressors throughput and fuel consump-tion. The programmable logic controller (PLC) in each compressor units control panel communicates to gas control the operating parameters for that compressor and the posi-tions of the valves controlling the gas flow through that compressor. This example sta-tion offers redundant communication using microwave, satellite, or conventional leased telephone systems. This station is designed for the option of completely unmanned oper-ation by Gas Control. The PLC compressor on/off operation, performance set points, and all station-critical valves may be remotely controlled. Gas Control may monitor all sta-tion alarms and shutdowns.

Gas turbine-driven centrifugal compressor unit panels typically include unit protective functions, local and remote starting, auto-matic unit valve operation and equipment and process monitoring instrumentation. If a multi-unit station is involved, a separate station panel may be used to automatically control station operation.

Acoustical TreatmentNoise is a significant environmental pol-

Figure 3:

62 Pipeline & Gas Journal / June 2008 / www.pgjonline.com

lutant and the reduction of noise is an essen-tial part of the design of a compressor sta-tion. The technology of noise reduction has reached the level that for most practical pur-poses a compressor station can be designed to contribute less than 3dB to the pre-existing background noise level. Local requirements should be taken into account for a proper design. The design of the unit enclosures, buildings, exhaust and inlet silencers are sub-ject to stringent specifications. Double-wall enclosures are frequently used to control unit noise emissions as afore mentioned.

Normally an acoustic simulation study is done. If an acoustic simulation study has not been conducted, the following requirements for the piping system are the minimum: the use of elbows in the piping should be minimized to the fewest number possible and elbows should be eliminated between compressor cylinders and pulsation suppres-sion devices.

Exhaust emissions from the gas turbines now have to meet the environmental limits of the location. Modern gas turbines are designed with low emission combustion systems to meet these requirements. These systems may be dry or wet low NOx and are now becoming the standard equipment for all gas turbines.

Silencing equipment incorporated into the engine air intake ducting and filters, engine exhaust systems, vent and blowdown exits, equipment enclosures, and piping insula-tion accomplish noise control for the sur-rounding community and station employees. Liners and baffles of noise reduction mate-rial are used inside the engine air intake ducting and filters, engine exhaust, and vent and blowdown exits. Acoustical lining on the internal walls and silenced ventilation systems reduce noise from the compressor buildings.

As much station gas piping as possible is installed below grade to provide addi-tional noise reduction. Above grade sta-tion gas piping is acoustically insulated. Internal noise-reduction modif ications are required in flow control valves. Fan tip speed limitations and low-noise fan drive designs are required for gas and oil cool-ers. Station noise control provides a day-night average sound level (Ldn) of less than 55 decibels per the A rating (dBA) of human response to noise at the nearest noise sensitive area. This complies with current U.S. Federal Energy Regulatory Commission regulations. Noise levels within a 3-foot distance from equipment for the employees average time of expo-sure is less than 85 dBA. This complies with current U.S. Occupational Safety and Health Administration requirements.

Site Selection And Aesthetics

Site selection is primarily defined from thermo-hydraulic simulation optimizing, fuel usage and transmission costs. Site selection depends upon pipeline hydraulic consider-ations and land availability. Consideration should be given to possible future expansion

of the facility. Access to the station shall be granted at any weather conditions or climate. When it is not possible or feasible to locate adjacent to a public road, which may occur due to remoteness of the pipeline route, pri-vate roads are used, providing an agreement has been made with the property owners for ingress and egress.

Additional factors to consider in site selec-tion include proximity to the connecting pipeline and avoidance of crossing pipelines, especially foreign pipelines; prior land use (soil contamination, archaeological history, wildlife habitat, etc.; soil conditions (load bearing and stability, fill materials); topog-raphy (required cut and fill, drainage); avail-ability of required utilities (electric power, water, communications); and environmental permit and noise requirements - and if sour gas is present - the proximity to the public and prevailing wind.

Emissions And Environmental Rules

Equipment should be installed with provi-sions for containing leaks, spills and wash water as required to comply with federal, state and local regulations and permits. Tanks should be installed above ground unless spe-cific conditions require burial, and in either case, must comply with all environmental regulations and state and local permits. For tanks that contain fluids potentially damaging to the environment, proper spill containment is included.

Compressor station reliability and avail-ability are paramount to overall gas pipeline delivery dependability. Reliability consider-ations are incorporated into many areas of the facility. Some reliability considerations are listed below.

The total amount of installed compression (stand by units) must be more than the normal design requirement to allow for scheduled and unscheduled maintenance.

Spacing between compressors or compres-sor groups aims at preventing fire damage to one compressor from harming others and to ease maintenance work.

Using redundant and parallel f ilter coalescers prevents unexpected large amounts of contaminants from impeding the gas flow and allows filtration cartridge replacement without interrupting compressor operation.

Monitoring and trending of vibration, bearing temperatures, and other critical oper-ational parameters by the compressor PLC identify service needs to prevent catastrophic equipment failures.

Maintenance systems should be developed to manage all aspects of maintenance prior to station startup.

All below ground steel pipe, conduit and structures are coated with a corrosion protective and electrically insulating coat-ing. Additionally, steel pipe installed below ground is protected from external corrosion using cathodic protection.

Sufficient operational and capital spare parts inventories should be available based on reliability-availability-maintenance (RAM) analysis and life cycle cost considerations.

Equipment should be standardized as fea-sible to minimize spare parts requirements.

Good human factor practices should be used in evaluating access to and viewing of operating data, manipulation of controls, installation of isolation devices, and removal and replacement of equipment (e.g. equip-ment and personnel access and egress, lifting points, pull clearances, materials movement, etc.). P&GJ

Authors: Saeid Mokhatab is the process technology manager for Tehran Raymand Consulting Engineers, Iran, specializing in design and operations of natural gas trans-mission pipelines. He has participated as a senior consultant in several international gas-transmission pipelines EPCM projects, and published numerous academic and indus-try oriented papers and books.

Greg Lamberson is the principal consultant of International Construction Consulting, LLC, USA, with over 25 years experience in all phases of business, project, engineering, and construction management for upstream onshore and offshore oil, gas, and energy related facilities and pipelines in North, Central, and South America, the Caribbean, the Middle East, Central Asia, China, Russia, the Far East, and Africa.

Sidney Pereira dos Santos, is a senior con-sultant at Petrobras Gas & Energy, Brazil, with more than 20 years of experience in the design of most of the gas transmission pipe-lines/compressor stations in Brazil such as the Bolivia-Brazil Pipeline project. He has been conducting technical and economic studies with risk analysis and conceptual design for the upcoming gas pipeline expansion projects in Brazil, and has presented various interna-tional papers on related subjects.

REFERENCES Mokhatab, S., Santos, S.P., and Cleveland, T.,

Compressor Station Design Criteria, Pipeline & Gas Journal, p. 26-32 (June, 2007).

Santos, S.P., Transient Analysis A Must in Gas Pipeline Design, paper presented at the Pipeline Simulation Interest Group, Arizona, USA (1997).

Santos, S.P., Compression Service Contract When Is It Worth? paper presented at the Pipeline Simulation Interest Group, Bern, Switzerland (2003).

Santos, S.P., Gas Compressor Service with Turbo Compressors, paper presented at the ASME International Pipeline Conference, Alberta, Canada (2004).

Santos, S.P., Series or Parallel Arrangement for a Compressor Station A Recurring Question that Needs a Convincing Answer, paper presented at the Pipeline Simulation Interest Group, California, USA (2004).