Page 53 - Handbook of Natural Gas Transmission and Processing Principles and Practices

FIGURE 1.9 Well deliverability.

Calculation of the TPC is based on the friction and hydrostatic pressure drop calculations
outlined in Chapter 3. In general, for a single phase flow of gas, the bigger the tubing diameter the
larger the operating point flow rate, and the choice of tubing diameter is straightforward and is
directly linked to the cost of tubing. However, many gas wells produce gas and liquids (water or
condensate). Multiphase calculations are complex and often show that the operating point rate can
be increased by “reducing” the tubing diameter.
When a gas well produces liquids, care must be taken to efficiently remove all the liquids,
otherwise, they accumulate in the wellbore, and eventually the increasing hydrostatic back pressure
“kills” the well. Various mechanisms exist for removing the liquids. These range from “siphon
strings” (small diameter tubing) to “plunger lift,” to reducing the wellhead pressure, to bottomhole
pumps. Many gas wells stop producing (die), even though there is still a lot of gas left in the
reservoir. They die simply because it is not economically viable to remove the liquids from the
wellbore.
The production rate of a gas well decreases with time, because the reservoir pressure depletes.
Eventually, the flow rate becomes uneconomic and the well is abandoned. Typically, to maintain a
gas supply contract, additional wells are drilled over time to supplement the decreasing
deliverability of the wells.

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