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Gas engine driven compressors may seem a good solution for gas gathering and gas compression applications, particularly nodal gas compressors (compressors installed at nodes within the gas collection network to gather gas) or field compression units. However, there are certain issues which discourage the use of gas engine drivers and favor electric motors.
• Relatively high maintenance and lower reliability of gas engines
• The higher cost of gas engines compared to electric motors of similar power ratings
• The lower efficiency of gas engines compared to electric motor (considering that electric power would typically be generated in highly efficient centralized power plants)
• The large size, weight and presence of high dynamic or shaking forces in gas engines (thus their requirement of a large foundation and various accessories).
As a rule of thumb, the cost of a gas engine driven compressor in the 1 MW to 3 MW application range is around 25% to 40% higher. Sizing of turbomachinery Some engineers do not believe in economies of scale, preferring to specify smaller units instead of one large unit. But the economic realities, often refute that opinion.
The cost of turbomachinery reduces slowly with size. Usually, the cost per MW is around 1.2 to 1.6 times for turbomachinery that is half the size. In other words, using two machines with half the capacity of a single unit (e.g., two 1 MW units instead of a single 2 MW machine) can result in a cost increase of 20% to 60%). In addition, the price for accessories and auxiliaries, such as foundation, piping and supports, and operation and maintenance are more as more units are employed.
The actual turbomachinery cost depends on the vendor price point, design of the package, and other complex factors. Compressor type Reciprocating compressors have low reliability, unscheduled shutdowns and high maintenance costs. That is why they are generally not recommended for gas gathering facilities, field compression units and wellhead gas compressors.
The same is true for screw compressors. These issues open market for turbocompressors. The optimum turbocompressor selection and design is based on: Identical turbocompressor packages; a minimum number of compressor stations; and large compressor sizes, requiring fewer compressor trains overall. In the presence of low suction pressure events or suction pressure variations, a positive displacement compressor has traditionally been a more popular option.
However, modern centrifugal compressors can also handle these conditions. Noise generation can be a critical issue for a gas gathering or field compressors depending on the location, local rules and nearby inhabitants. A noise limit of 30 dB(A) or lower at the recipient may be specified in some place, compared to 85 dB(A) at one mile for most facilities.
Compressors can be installed within enclosures but they are not popular because of access problems, ventilation issues, potential risk and safety concerns. A more convenient noise control option is local insulation or coverage for the compressor, and insulation of the piping and accessories.
Another important issue is compressor availability. The availability of a small wellhead facility is often as low as 90%. However, gas gathering compressors usually target availability above 96%. Wellhead compressors There have been some applications for fan-type or blower-type (small) wellhead compressors with relatively low capacity and a differential pressure of around 1 or 2 Bar.
This could be considered as a last resort for companies that sold gas on a long-term contract basis (usually for a competitive price) and now face rapid pressure drop in their gas wells. In such a situation, a costly and complex wellhead compressor network should be considered, as there is no other option. Electrical power distribution for such a complex network of compressors is costly; this is particularly true considering that the rated power of wellhead compressors is much more than that of many wellhead facilities.
Non-API compressors cannot offer the required availability and reliability for unmanned wellhead units, but cost up to four times less. Economic analysis rarely comes out in favor of the deployment of many small wellhead compressors distributed in a relatively large area. Therefore, it is recommended that gas gathering compressors (or field compressors) be designed with a low suction pressure capability to facilitate gas collection for the lowest possible well pressure.
For a large gas gathering project, the traditional design is 17 nodal compressors (using oil-flooded screw compressors) and four large hub centrifugal compressors. Nodal compression modules for compression from 1 Barg to 17 Barg and hub compression units increase the pressure to around 110 Barg. However, this design is not feasible due to high costs. A redesign called for the elimination of the nodal screw compression units. It featured medium-sized hub compression units with each compressor station using a single or two identical centrifugal compressor trains, instead of large hub compression units. In total, eight hub compression stations increased the pressure from around 1 Barg to 110 Barg. The same centrifugal compressor model was used for all stations, with some requiring only one unit and others needed two. This greatly reduced costs and eased maintenance.
A series of unconventional gas gathering facilities in an area of around 12 km × 12 km contained about 240 wells. The wellhead gas pressure was around 2 to 4 Barg. Based on initial sizing, the best arrangement was to have one 6.5 MW centrifugal field compressor for every 120 wells. Both field compressors are in the middle of the area to limit pressure drop. The furthest distance to remote wells is around 6 km, equivalent to a pressure drop of 0.6 Bar. Therefore, the minimum suction pressure is about 1.4 Barg.