Summary
An investigation into gas carryover resulting from the downward flow of
water was conducted. Water accumulation in a gas well is responsible for
well-productivity decline and left untreated will eventually result in the well
loading up and ceasing to produce. Submersible pumps offer a viable means of
removing water from the well; however, gas interference can significantly
degrade pump performance and even result in pump failure. An effective means of
mitigating this problem is to place the pump below the producing interval,
effectively allowing gravity to separate the gas and water. The rule of thumb
(in this instance) is to limit the downward liquid velocity to values less than
0.5 ft/sec to ensure gas/water separation. High steel prices dictate smaller
casing strings be used where possible to enhance project economics in
operations such as coalbed methane. However, smaller pipe sizes result in
higher flow velocities for a corresponding surface flow rate. These higher flow
velocities reduce separation efficiency, which could jeopardize project
success. To quantify the relationship between gas-carryover and liquid
velocity, a full-scale model was built and actual gas carryover rates were
measured. Two sizes of annular flow geometries representative of those used in
the field were used in the test. The results were also confirmed with separate
measurements taken from a test-well facility. These studies show the
traditional rule-of-thumb value of 0.5 ft/sec to be conservative.
Multiphase-flow pattern maps also were integrated into the study as a
supplemental aid to the development of operation guidelines and to add insight
into operational practices of submersible pumps. As a result of this work,
smaller casing sizes were successfully used resulting in substantial project
cost savings.
Introduction
Rising steel prices and casing-size availability led to a re-evaluation of
the typical well setup. Smaller casing sizes that were readily available would
eliminate the drilling downturn when and where the typical 7-in. casing size
was in short supply. Additionally, smaller casing would allow smaller-diameter
wellbores to be drilled that would reduce drill time, cementing, and overall
well costs while enhancing project economics. Thus, motivation was strong to
determine whether a smaller casing size would create operational constraints
while producing under a wide range of gas and water rates.
Gas wells producing below the critical flow rate frequently accumulate
liquids in the bottom of the well. Liquid loading and critical flow rate issues
have been well documented in the literature (Lea et al. 2003). The liquid
accumulation phenomenon was discussed by Sutton et al. (2003), and a method was
developed to predict the resulting pressure gradient. An example is shown in
Fig. 1. This example shows the additional backpressure placed against the
producing formation, resulting in decreased productivity. Furthermore, water
can imbibe into the reservoir, resulting in decreased effective permeability
and well productivity (Christiansen et al. 2005; Mahadevan et al. 2007). Left
unchecked, production can decline and the well will load up and cease to
produce.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
28 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
29 March 2007
- Manuscript approved:
26 April 2007
- Version of record:
20 February 2008
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