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Suite 2, 105 Victoria Road,
Marrickville NSW 2204 Australia

Tel: +61 2 9519 8944
Fax: +61 2 9519 8533
Email: [email protected]


Silver Raven Pipeline Division - (Oil & Gas Mining)

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Wellhead Infield Gas Compression Retro Fit For Existing Coal Seam Gas Field Development

Driven by the world LNG 'gas' demand, recent large scale "Coal Seam Gas" (CSG) field developments in Queensland have been established by using large "Centralised Compressor Stations/Systems", (CCS) designed and constructed on conventional gas project guidelines.

The current Australian CSG gas gathering experience is different to the United States and Canadian system/s who have developed over more than five decades, a gathering system that is now considered to achieve the best CSG reservoir extraction performances and lifecycle costs, namely with low capital cost, low operating costs, flexible infrastructure and Wellhead/ Infield compression close to or at the well head/s.

The "Wellhead In-Field Compression" (WIGC) system offers CSG producers significant advantages over existing and expensive centralised compression systems.

The advantages are:

  • 14% to 28% more gas;

  • Higher flowrate with pressure profile to suit existing field pipeline gathering system;

  • Full economic reservoir drainage;

  • No Capital cost;

    • Mobile wellhead gas compressors units are relocated when gas depletes past its economic model and;

    • Full leasing and maintenance of compressors;

  • Reservoir and flexible Well performance enhanced and maintained with changing field conditions;

  • Ability to balance field CSG production and not shutdown poor performing wells;


Generally the design comprises a scalable, modular system of large Field Compressors (FCS) (normally multiple screw compressors of approximately 1,200BHP) ideally set out in a grid that can be replicated to suit any field size.

Each FCS receives "reservoir generated" low pressure gas from multiple wells with each well theoretically producing approximately 0.4Tj/d to 0.5Tj/d.

  • Each FCS compresses this gas to approximately 1,200Kpa to 1,500Kpa and;

  • Deliver's this "medium pressure" gas to a designated Booster Compressor Station (BCS) where;

  • The gas is dehydrated and measured;

  • This gas is then compressed into the LNG "high pressure" transit/trunk line to the LNG station.

Ideally each FCS produces from approximately:

  • 216 wells spaced 750 metres to 1,000 metres apart;

  • Each FCS gathering network is approximately 100 square kilometres to 150 square kilometres;

  • The gathering wells can be located from 0.5kms to 20kms from the FCS and the gas gathering lines are sized from 80/100mm diameter at the wellhead and progressively increase (as they blend/extend) up to 1 metre in diameter before reaching the suction manifold of the FCS;

  • The wells are "Free Flowing" therefore the field must be run at the lowest pressure of the worst performing well (due to either poor well performance and or distance from the compressor station);

  • This makes the manual or SCADA control of the field wells an extremely difficult way of extracting a uniform amount of gas from individual wells;

  • Due to opposing "Head Pressure/s" from adjacent wells (which will have different flow and pressure characteristics') combined with pipeline friction losses, due to the lengthy pipeline gathering system, there is approximately the potential of a 50% pressure loss over the whole field; 

  • In addition to the inherent low wellhead pressures now realised, low gas velocity and field management of the individual wells, there is also a major problem with water dropping out of the gas lines as the pressure reduces;

  • Numerous quantities of 'low point drains' have been installed which require constant monitoring and disposal of the produced water which has increased operation costs;

  • The FSC compresses the suction gas from approximately 200Kpa/250Kpa to approximately 1,500Kpa/1,600Kpa discharge pressure (due to compressor design and pipeline capability) and routes it to a Booster Compressor Station (BCS) where the gas is dehydrated through TEG plants, metered and then compressed via the booster compressors to the main delivery pipeline, delivering gas to the LNG plant/s some 400kms away;

  • By installing a Wellhead Compressors at each Wellhead, the discharge gas pressure will be maintained at each well and eliminates any pressure and flow decline if another adjacent well is producing more or less gas at a different pressure (discharge pressures (P2) can be maintained up to 1,500kPa if required);

  • The wellhead compressor will allow for variable inlet pressures (P1) as low as 5kpa on the reservoir until the flow reaches a state where it is no longer economical to produce any further.

Advantages Of WIGC Over CCS:

Optimal Reservoir Performance:

The greatest benefit to producers is the system's capability for well head/reservoir pressure reduction during:

  • Early flow;

  • Sustained flow;

  • Declined flow.

Decreasing the flowing wellhead gas pressure at early and sustained flow from 500 kPa (calculated unimpeded flow) to 10 kPa (system flow) with a variable but fixed discharge pressure, enables more gas to be extracted, particularly tail gas, therefore increasing total recoverable gas by approximately 14% to 28% which enhances the commercial model.

In the study model of 216 wells producing 1.5Pj, a 10% increase in production, with a wellhead gas price of $4.00Gj, equates to additional revenue/s of $130 million per FCS section.

Environmental and Commercial Benefits:

The WIGC model when combined with CCS makes a significantly smaller impact on the environment and local communities by;

  • Reducing windscreen hours;

  • Low point drain water collection frequencies which minimises field operation and maintenance.

This simple, mobile and seamless retrofit, low infrastructure development enables more gas to be extracted from the local resource.

Safety Benefits:

Operator driving time is reduced with decreased water pickup from low point drains and therefore time can be delegated to centrally-located critical components.

Zero Capital Costs:

Additional advantages include time and cost savings on the retrofit and ability to relocate the units to new sustaining wells in the future. There is no design engineering, no required civil engineering, and a 'cookie cutter' development model that can be easily replicated on future projects.

Lower Operating Costs:

The single biggest operating cost for any compression system is fuel gas/electrical power, which is directly related to BHP.

For the 100TJ/d model, incorporating Wellhead Gas Compressors in the WIGC system means that the FCS uses significantly less BHP (due to increased suction pressures (P1) from the field), which means less operating overhead cost.


Juxtaposed with the inflexibility of centralised systems together with increased flow and pressure problems (as sustaining wells are drilled further away from the FCS) is the adjustable nature of the WIGC system

Compressors are mobile and can be positioned anywhere within the field design to accommodate restraints of the physical terrain, existing infrastructure or landowner/regulatory requirements.

Compressors can be banked for additional compression, or cost-effectively relocated as the field reservoir changes over time.

The compressors will be explosion proof, skid mounted crash framed, with bypass, controllable, with emergency shutdown integrated with existing systems and will operate under 75dba.

The units are designed to comply with and will meet all required Australian Codes and Standards.

Wellhead Compressor Design Considerations & Operations:

The Compression units had to be small enough in size to enable easy installation and removal within two to four hours by a suitably skilled team of operators.

The units designed will have three process stages:

  • Start of life, when the well is initially opened, but only after the gas has started the desorption process and starts to peak;

  • Middle of life, when the gas flow has peaked and is starting to decline;

  • End of life, when the gas is at a stage that the viability of continuous production is getting to be sub economic.

  • These variant flowrates will be able to be handled by the compressor unit/s all using a variable speed drive and intelligent control.

The compressor units will be manufactured in Europe, packaged in Singapore under Australian Codes and standards and electrically completed in Australia in accordance with AS3000


The compressors, with electrically operated Variable Speed Drives (VSG) will operated between the range of 150Kw, to 35Kw to undertake the different flow regimes described above.

The installation will be completed with-in two to four hours:

  • The compressors suction will be connected to the gas discharge flange of the Wellhead Separator and all existing process monitoring and shutdown devices will remain active and be reported through the SCADA system;

  • The compressor discharge line will tie-in to the gas line leaving the Separator through a designed interface piece made from high pressure composite pipe – there is a manual diverting valve installed to bypass the separator gas discharge, including a process operated PSD diverting valve;

  • All electrical, mechanical interfaces will be designed for the retro-fit to enable a seamless bypass and diversion of the wellhead gas to the compressor inlet flange;

  • Any compressor shutdown will automatically open the divert bypass valve and allow gas to flow normally – without compression.


In North America, lean, decentralised compression systems produce vastly superior economic, environmental and social outcomes than large scale centralised systems.

The WIGC system has the ability to restore and recover value in the Australian CSG upstream gas gathering system and enable more gas to be recovered for the market.

Re-engineering is not an economic option, new innovation and new engineering is required and has now been developed as a truly fit for purpose design

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    Tel: +61 2 9519 8944
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    Email: [email protected]

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    Level 3, 349 Coronation Drive,
    Milton, QLD, 4064

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