Hydrocarbon Compression

Ideas To Enhance Gas Flow

One of the more puzzling phenomenon I have observed in gas field production happened during my tenure as an operator of wellhead compressors. One would intuitively assume that the faster the wellhead compressor ran, the more gas would be delivered through the sales meter. Normally, as the compressor speed was increased by manually screwing open the governor speed control valve, the compressor suction pressure fell. Of course, this also reduced the wellhead pressure and the gas flow would be expected to increase according to the formula:

The above equation is really of little use to the field troubleshooter because C,n and PR are unknown for partially depleted wells. But,the equation does positively indicate that gas flow will never decrease as the wellhead pressure is dropped. Much to my surprise, I began to observe that as I dropped the wellhead pressure by speeding-up the wellhead compressors that:
• 30% of the wells did not exhibit any observable increase in gas flow.
• An additional 10% of the wells actually lost production as the wellhead pressure dropped.

If the reader will consult equation 1, of the previous article, he will note that when wells have relatively high stabilized shut-in pressures, as compared to their flowing wellhead pressure, that the incremental gas flow obtained from a further reduction in the flowing wellhead pressure may be quite small. It transpires that there is another factor which tends to negate the effects of decreased wellhead pressure. This factor is water.

Written by Jack

October 4th, 2009 at 7:46 pm

Posted in Enhance Gas Flow

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Why Has Gas Flow Dropped ?

We are assuming that the reservoir pressure and porosity are adequate — that is, there is a plentiful supply of gas in the ground for the well to draw on. Also, we are assuming that the permeability of the reservoir is sufficient to allow a relatively free flow of gas to the perforations in the casing. (Porosity and pressure are a measure of the amount of gas trapped in the sand formation; permeability is a measure of the resistance of the sand formation to gas flow).

We are concerned in this chapter with factors that interfere with gas flow from the sand formation immediately surrounding the casing perforations up through and into the gas collection header. In this regard then, what is the physical meaning of equation (1) above in the context of our everyday experience?

When the flowing tube pressure (i.e. the wellhead pressure during normal operation) is close to the shut-in pressure, a small reduction in the collection header pressure (with a concurrent drop in the wellhead pressure) causes a substantial increase in gas flow. On the other hand, when the flowing tube pressure at the wellhead is much less than the shut-in pressure, a small reduction in the wellhead pressure will not effect gas flow significantly.

To emphasize this critical concept, note that when wellhead flow is restricted by back pressure from the collection header piping, the shutin and flowing tube pressures will be similar. On the other hand, if gas flow is restricted by a discarded tool stuck 8,000 feet down in the tubing string, then the shut-in and flowing tube pressures will be far apart. Why is this? Because, if the errant tool was removed from the tubing, the shut-in pressure will not be effected, but the wellhead flowing tube pressure would greatly increase (assuming that flow from the well was choked back to maintain constant production).

This leads to an important troubleshooting principal: The first point to establish in troubleshooting a well for lost production is whether the problem is above or below the surface.

Written by Jack

October 3rd, 2009 at 6:38 am

Posted in Well Site Troubleshooting

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