American Oil and Gas Reporter - January 2012 - 171

Production Technology
calculated intake pressures from rod
pump controllers, acoustic fluid levels,
nodal analysis-based calculations, and a
variety of other techniques.
The instrumentation that is required to
perform effective surveillance will vary
greatly by lift type, but generally consists
of data such as pressures, temperatures,
rates and certain electrical parameters.
While a detailed description of all instrumentation requirements for each form of
lift is beyond the scope of this article, a
comprehensive guide to instrumentation
requirements can be found in chapter 15
of Gas Well Deliquification, Second Edition
by James F. Lea, Henry Nickens, and
Mike Wells.
Type Of Metering
The type of automation metering required varies based on the nature of the
application. For example, conventional
orifice and turbine meters may not work
well for measuring flow rates in wells
that produce wet gas. However, there are
effective techniques for metering wet gas
production that can be implemented as
part of an automation system. These are
needed to determine the rate/volume of
gas production and to manage the techniques needed to treat the wet gas.
Production of retrograde condensates,
such as the fluids produced from the
Eagle Ford Shale, can provide additional
challenges beyond those for wet gas. In
a retrograde condensate, the produced
fluids may change from a gas to a liquid
and back to a gas again as they make
their journey from the sand face to the
sales point. This can create additional
challenges in metering and production
allocation. The metering technologies
and techniques selected for these applications need to be flexible enough to
provide reliable results over a range of
flow regimes.
What about wells with high water cuts
or wells in waterfloods? Often, highwater cut wells do not produce significant
amounts of gas. It is possible to monitor
the production of these wells on a continuous basis using coriolis meters integrated with an automation system. The
oil and water production rates of each
well can be monitored and trended on a
continuous basis, and the production rate
can be integrated over time to determine
the daily oil and water production volumes
for each well.

There are also economical techniques
for continuously estimating the liquid
production rates from wells that produce
both gas and liquid. These methods, when
integrated with an automation system,
can give continuous estimates of liquid
production rates, which can be integrated
over time to give daily production volumes
for wells that produce gas, oil and water.
For wells in CO2 floods, the challenge
is to determine the amount of CO2 being
injected into each well. Carbon dioxide
can be a liquid, a gas or a "critical fluid,"
depending on its pressure and temperature.
An automation system can contain a special "CO2 properties" program to continuously determine the amount of carbon
dioxide injected into each well.
For wells in steamfloods, the challenge
is to determine the quality of the steam
being injected into each well, and therefore,
its heat content. Also, the flashing of liquids in the well bore must be avoided to
prevent excess sand influx from the reservoir. An automation system can contain
a special program to continuously determine steam quality and heat content, and
therefore, the amount of heat injected
into each portion of the reservoir. It can
monitor the bottom-hole temperature,
with the right instruments, to detect potential liquid flashing.
Typically, wells produce to a central
facility where production from each well
can be tested and metered. But what
about wells that lack central processing
facilities? If a well does not produce to a
central facility, the sales point may be at
the wellhead. Here, an electronic flow
meter is needed to accurately measure
production.
Automation Controls
With respect to the kinds of automated
controls that are needed, a major opportunity for optimization exists with all artificial lift systems. To be optimized, a
process must be measured and controlled
by an automation system. There are effective measurement, control and optimization processes for sucker rod pumping
wells, electrical submersible pumping
wells, progressing cavity pumping wells,
gas-lifted wells, and others.
There are also advantages to automated
gathering and processing of well test data.
There are two modes of automatic well
testing: fully automatic, where wells are
automatically switched into and out of

testing and the production rates are measured during the test; and semi-automatic,
where the wells are switched manually,
but the measurements are automated.
Automatic switching is a labor-saving
capability and permits gathering more
well tests within a period. Other advantages
of automated well testing include more
accurate data processing, integrating well
test data with data from the artificial lift
system, and evaluating whether the well
test is "good" and can be used.
With the development of intelligent
completion technology, it is now possible
to selectively control injection into or production from multiple zones within the
same well bore. Since the systems were
introduced in the mid-1990s, a variety of
intelligent completion components have
been developed by several manufacturers.
As the technology has matured, systems
have become increasingly reliable and are
now commonly used in an array of applications. Examples include optimizing production from the various legs of a multilateral well, using an upper gas zone to
"auto gas lift" a lower oil-producing zone,
managing injection within several zones
of a water injector well, etc.
Should control be autonomous? Is
closed-loop optimization a desirable thing?
Is there a need for "bounded" control?
Throughout the history of oil field automation, operators always have expressed
concerns about the level of control that
should be given to the automation system.
While closed-loop automation exists and
is even common in certain applications
(e.g., beam pumping and plunger lift), it
has been frowned on in others. For instance,
operators have been reluctant to allow an
integrated production model to update injection rates for a field of gas lift wells
without some form of human intervention.
This has given rise to the concept of
bounded control, where the automation
system is allowed to make certain decisions
and make changes on its own, but only
within defined limits. Once those limits
are exceeded, human intervention is required.
Another issue for operators is deciding
whether control logic should reside at
the well site through remote terminal
units, programmable logic controllers or
variable frequency drives, or in the host
system? However, this is not an either/or
question. Some control should be at the
wellhead if and when possible. The wellJANUARY 2012 171

American Oil and Gas Reporter - January 2012

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2012