American Oil and Gas Reporter - July 2015 - 25

TECHCONNECTIONS
Authors Suggest
Technology To Control
Liquid Loading
As production begins to decline in mature gas wells, the presence of certain liquids in the wellbore can be a real headache for
operators. Liquid loading occurs when liquids being produced increase the flowing bottom-hole pressure, and can restrict gas production dramatically. Many of these liquids come in the form of
accumulated condensation from other portions of the well, or sometimes are produced directly in the wellbore.
In a paper titled "Solving Gas-Well Liquid Loading Problems
(SPE-72092)," James F. Lea from Texas Tech University and Henry V. Nickens with British Petroleum discuss effective treatments
for these types of situations. They suggest there are multiple actions one can take to reduce liquid loading in gas wells, including flowing the well at a higher velocity by using smaller tubing,
or by creating a lower wellhead pressure.
They also suggest pumping the liquids out of the well or even
foaming the liquids to allow the gas to lift the liquid from the well.
Additionally, they suggest pumping water into an underlying disposal zone, or preventing liquid production altogether by shutting off a water zone or using insulation to reduce the formation
of condensation.
Before selecting which option best suits his wells, an operator first must identify whether liquid loading is the culprit. Lea
and Nickens admit that identifying whether liquid loading is a problem can be difficult since many liquid-loaded wells will continue to produce for a very long time. The authors advise that if an
operator begins to see sharp dips in a well's decline curve or begins to see liquid slugs at the surface, liquid loading may be an
issue. They also say that a difference between the tubing and casing flowing pressures, or sharp changes on a pressure survey, indicate the operator should look into possible solutions to continue
a slow and regular production decline.
An operator faced with liquid loading has many options for
addressing the situation. However, one in particular has been popular in the United States: plunger lift. This economic solution has
been accepted widely by operators working in areas with mature
wells and largely depleted reservoirs. In his paper, "Plunger Lift
Applications: Challenges and Economics (SPE-164559)," Mohamed Hassouna from Lufkin Industries describes the process as
a very reliable and viable system that has matured in recent years.
Hassouna explains that the process uses a free-flowing
plunger within the tubing string to bring accumulated liquids from
the wellbore. This system allows the plunger to sit at the bottom
of the well on a bumper spring, and takes advantage of the well's
own energy by letting pressure build inside the well while shut
in. The plunger acts as a seal between the liquid above it and the
gas and tubing below. Once the well is opened, the pressure from
the well pushes the plunger to the wellhead and the liquid from
the wellbore.
With many operators wanting to optimize production, each operator needs to consider the pros and cons of various solutions.
Hassouna notes many wells require artificial lift to maintain production at a desired rate. However, when that rate begins to decline, it becomes difficult and cost prohibitive to maintain cer-

"To date, plunger lift appears
to be the most economical and
reliable system being used.

tain wells and they ultimately are abandoned. He says plunger lift
is a popular method because it increases the economic life of the
well and can help take a well to near depletion. Additionally, this
method requires a relatively low capital investment and operational costs, making it the preferred solution for many liquid-loaded
gas wells.
As these systems were embraced by operators across the country, there became a need for even more efficiencies and optimization of units among folks with large numbers of plunger lift
systems. In a paper titled "Well-Performance Diagnostics using
Smart Plunger Technology (SPE-120596)," Travis P. Gray
from Texas Tech describes the problem with having to "tune" individual systems to meet the needs of a changing reservoir.
As more and more units begin to be put on line, it becomes
necessary for operators to find an economical solution for making adjustments in the field. Gray highlights how technology has
helped to address the problem by using personal computers combined with programmable logic controllers. Through remote terminal units, it became possible to open and close valves remotely
for multiple wells from the home office. Additionally, by using
a smart plunger system, information can be sent to engineers, allowing them to make additional adjustments and "tune" the systems remotely.
There are multiple methods for addressing liquid loading in
gas wells. However, to date, plunger lift appears to be the most
economical and reliable system being used.
❒

JEREMY VISCOMI is the di-

rector of technology transfer
for the University of Kansas
Tertiary Oil Recovery Program and the PTTC Midcontinent Region office. He has
more than a decade of experience in developing and organizing technical conferences
and special events.
JULY 2015 25

American Oil and Gas Reporter - July 2015

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