Estimating Flow Rates Required To Keep Gas Wells Unloaded
- Jack O. Duggan (Mobil Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1961
- Document Type
- Journal Paper
- 1,173 - 1,176
- 1961. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 5.3.2 Multiphase Flow, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 4.1.4 Gas Processing, 3 Production and Well Operations, 4.2.3 Materials and Corrosion, 4.6 Natural Gas, 4.1.5 Processing Equipment
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The empirical method of estimating the flow rate required to keep a gas well unloaded in various-sized flow strings is represented by a chart showing flow rate, in Texas State standard cubic feet per day, vs the wellhead flowing pressure. Each curve represents the Texas standard cubic feet required to have a wellhead linear velocity of 5 ft/sec at the stated pressures for several common sizes of flow strings.
The curve permits a field man to easily determine if his well is flowing hard enough to keep unloaded. The method is called empirical because the velocity of 5 ft/sec at the wellhead was selected by observing the flowing performance of a number of wells having various fluid contents and producing under a wide range of operating conditions.
The flow rate required to keep a gas well flowing in an unloaded condition is of major concern in natural-gas operations. It is difficult to obtain a fair GPM settlement test by the split-stream test method, or to obtain good flow tests unless the well is flowing unloaded. It is also important to have an unloaded well when using a top-hole shut-in pressure to calculate the bottom-hole pressure.
It has been argued that a flowing well cannot load up. Where would the fluid go? Any gas-condensate well, producing at a rate so low that the condensed liquids will not flow out of the wellbore at the same velocity as the gas, is subject to loading up. The extra liquid accumulated may never fall all the way to the bottom, but probably remains in suspension in ever-increasing quantities until a large- enough slug accumulates to be carried out at the surface. Any flowing process that will cause the column of gas to be heavier than the calculated combined well stream or that increases the friction factor will cause errors in the calculated bottom-hole flowing pressure. Any flowing process that will not permit the formation gas to reach the surface instantaneously with its condensed liquid can cause erratic GPM tests.
When conducting a back-pressure test on a gas well, one must select suitable flow rates to obtain a satisfactory open-flow-potential curve. The maximum flow rate is limited by the capacity of the test equipment or a desirable percentage of surface pressure drawdown. The minimum flow rate is usually based on experience -- experience which has taught that too low a flow rate is likely to produce a back-pressure point that will not line up on the curve. Often, a rule-of-thumb is used to select the minimum flow rate. One rule-of-thumb is 1 MMcf/D/1,000 lb for 2 1/2-in. tubing and 1 MMcf/D/1,500 lb for 2-in. tubing. However, there was no rule-of-thumb for selecting a proper flow rate for the annulus completion of a conventional dual.
Anyone calculating a deliverability study undoubtedly has been frustrated by the failure of an annulus completion to follow the engineering calculations of performance, while the tubing completions often follow the calculated performance very closely. Most engineering calculations are based on single-phase flow and ignore the effect of "loading up". An unloaded well can be defined as a well producing in a stabilized manner in which the condensed liquids continue to move up the flow string at the same, or very nearly the same, velocity as the gas. A "loaded-up" well is the term used in this paper to explain a well that has an appreciable amount of slippage (does not produce at a flow rate large enough to keep the condensed fluids moving at the same velocity as the gas). A loaded-up well will soon become a "dead" well unless the well has enough pressure to kick out the slugs of liquid as they accumulate. Loading up is not too much of a problem for normal producing operations in wells that have excess flowing pressure, but it is very much of a problem in wells with flowing wellhead pressures that approach line pressure.
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