There are three basic problems which reduce the flow of gas from a well which has a sufficient gas pressure, porosity and permeability in the surrounding sand formation to sustain a much higher production rate:
1. Restriction to flow down hole such as occurs when sand covers the perforations in the casing.
2. Liquid loading of the production tubing with water and natural gasoline condensate.
3. Back-pressure on the wellhead tree caused by such factors as high pressure in the gas collection header piping.
These points can best be understood by referring to Figure 1-1. Simply observing the operation of a well does little to help differentiate the causes of diminished gas production. One of the questions asked by lease operators is how to calculate the incremental gas flow that can be expected from a well due to reduced lateral collection header pressure. The formula used to estimate this increase is:
While P1 and Q1 are known from the current operating data, and the lease operator will be able to estimate P2, (the final wellhead pressure) determining a reasonable value for the shut-in pressure (P3) and the slope of the wellhead performance curve (n) can be a challenge. After a well has been blocked-in, the pressure on the wellhead will increase for several hours, or even days. The reading on the wellhead tree pressure gauge after this pressure has stabilized, is termed the shut-in pressure.
There are several problems which interfere with obtaining a true wellhead shut-in pressure. One difficulty is that while one is waiting for the wellhead pressure to stabilize, the lease operator can lose one to three days of production. Or, liquids may be accumulating in the mile or two of tubing between the perforations and the wellhead. If a well accumulates 4,000 feet of condensate in the tubing during a shut-in test, then the wellhead pressure will be surpressed by 1,000 psig. For this case, the observed wellhead shut-in pressure is meaningless. When the well is put back on-line and resumes gas flow, the wellhead pressure will probably increase, rather than decrease! In many instances, the only practical way to determine a shut-in pressure is to search back over production records and find a time when the well was blocked-in for maintenance. Next, check the reported wellhead pressure immediately after flow from the well was resumed. If the flowing tube (i.e. wellhead) pressure is somewhat lower than the shut-in wellhead pressure, one may assume that a reasonable value for the shut-in pressure has been determined.
The numerical value for (n), the slope of the wellhead performance curve, can often be obtained from the initial performance test run on the well made immediately after completion. Usually (n) varies from .65 to .95. For troubleshooting type approximations, assuming that n = .8 will not introduce much of an error into the predicated increment of gas flow due to a reduction in collection header pressure.