Wellhead Compression – Compressor Configuration

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Figure 4-1 illustrates a typical two-stage compressor. Machines of this type range from 30 to 300 horsepower. They are driven by a gas engine; fueled by natural gas. Engine speed is 250 to 450 rpm, with the compressor inter-cooler and after-cooler air fans driven by the engine. Such machines are rugged, reliable and flexible. To illustrate their flexibility, there are three principal modes of operation.

Two Stage (Tandum) Operation
Both compressor stages are fully operational. Note that the first-stage is called the “head-end” and that the second-stage is termed the “crank-end.

Head-End Operation
The compressor cylinder valves have been disabled in the crank-end (i.e. second-stage), so that only the head-end does compression work. This type of operation is summarized in Figure 4—1.

Crank-End Operation
The compressor cylinder valves have been disabled in the head-end (i.e. first-stage), so that only the crank-end does compression work.

Note that the head-end cylinder’s volumetric capacity is much greater than that of the crank-end. However, the volumetric capacity of the head-end can be adjusted with the cylinder clearance valve (see Figure 4-1), whereas the volumetric capacity of the crank-end is fixed.

In addition to these permutations, the compressor speed can be varied over a wide range, the suction flow may be throttled, engine fuel can be drawn from either the suction or discharge, and the discharge, and the discharge cooler may be by-passed.

Reducing the surface pressure by compression reduces the gas pressure in the tubing at the level of the perforations and hence increases the flow of gas from the formation through the casing perforations. The incremental flow of gas obtained from a well by surface compression is a function of many complex variables.

A wellhead compressor, two stage, gas driven set-up for "headend only" operation.

Gas wells that have become water-logged may double or triple production when joined to a properly sized and operated field compressor. For example, a well was producing gas at a rate of 300,000 SCFD with a compressor suction (i.e. wellhead pressure) of 400 PSIG. The compressor configuration was altered from crank-end operation to head-end operation. In effect, the volumetric capacity of the machine was doubled. Consequently, the wellhead pressure was reduced to 280 PSIG, and gas flow rose to a rate of 350,000 SFCD.

After operating for a short time in this manner, slugs of water began to pass up through the wellhead valves. The hammering sound of water entering a wellhead tree is called “water hits”. As the slugs of water raced up the tubing, the weight of water suppressing gas flow was removed (i.e. the well unloaded). Both the wellhead pressure and the flow increased. Hours later, the well performance stabilized at 780,000 SCFD and a 350 PSIG compressor suction pressure.

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