American Oil and Gas Reporter - January 2012 - 168

Production Technology
How can automation help optimize
the operation of steamflood systems and
the use of steam to heat the reservoirs
and their heavy oils to maximize recovery?
A particularly challenging area is the
steam-assisted gravity drainage (SAGD)
projects in ultraheavy oil fields in Canada
as well as in heavy oil areas in California.
The number of carbon dioxide floods
continues to increase, with the Permian
Basin leading the way in implementing
CO2 EOR projects. However, large CO2
floods require special automation approaches for effective management.
A large majority of new wells are
using horizontal completions to contact
more of the reservoir. This is especially
true for producing tight gas formations.
Many (perhaps most) of these wells require
artificial lift to recover the fluids used in
fracturing the formations and produce
formation water so gas can flow to the
surface. Automation plays a key role in
making these processes successful.
Gas lift systems are another challenging
area, and the industry has acquired much
experience with automating continuous
gas lift wells and systems. Relatively
new developments include new host software that couples real-time data with
nodal analysis to aid in the surveillance,
analysis and troubleshooting of gas-lifted
wells. In addition, such systems are able
to continuously update full-field network
models to adjust gas injection rates to
maintain the optimal allocation of lift
gas as conditions change. These systems
also leverage real-time data and modelbased techniques to aid in production allocation, loss reporting and production
forecasting.
There is less experience, but equal importance, with automating dual gas lift,
intermittent gas lift, and using gas lift for
gas well deliquification. These processes
are addressed in three API Recommended
Practices: API RP 19G9 for dual gas lift,
API RP 11V10 for intermittent gas lift,
and API RP 19G14 for gas wells. This
last one is still being developed.
Other Application Areas
In addition to steamfloods, CO2 EOR,
SAGD projects, horizontal wells and gas
lift, there are a number of other challenging
production application areas that can benefit
from automation technology. Ultralowpressure gas wells are a case in point.
Often there are significant gas reserves

left in reservoirs where the pressures have
depleted below levels that can sustain
using conventional recovery methods such
as chemicals and plungers. For these applications, low-cost pumping or gas lift
methods must be used. Automation is required to operate these methods economically.
Many wells have small-diameter bore
holes that can accommodate only small
casing and either very small or no tubing.
Producing these wells requires using
casing plungers, very small tubes to
extend flowing lives, small gas lift equipment, etc. These wells need automation
to keep them operating safely and economically.
Wells that produce high concentrations
of hydrogen sulfide need automation to
assure that the wells are produced safely
and that the associated production facilities
are safely operated. Often, these systems
must include special environmental capacities such as weather systems to address
leaks and warn people should they occur.
Moreover, some wells are completed
in highly sensitive areas where any leaks
could not only be a safety risk, but could
also endanger the environment. Here, automation is needed to provide special
leak detection capabilities and to permit
remote shut-ins of any wells or facilities
where there may be a risk to safety or the
environment. A particular example of
sensitive environments is one in which
contamination of near-surface or groundwater systems is a major concern. This
can occur as a result of surface spills,
casing leaks or other causes.
Automation also can be highly advantageous for wells with flow assurance
issues such as hydrates, asphaltenes,
waxes and scale. These wells have special
flow assurance issues, which if not properly detected and managed, may prevent
them from being produced. Automation
is needed for surveillance so any potential
occurrence of hydrate formation or deposition of asphaltenes, wax or scale is
detected and can be addressed before it
becomes serious enough to cause well
failures or production deferment.
Wells that produce large quantities of
sand can be challenging to manage and
produce, and there are successful automation systems for managing the operation of potentially sandy wells. If the
sand produced in these wells cannot be
contained with sand control systems (e.g.,

168 THE AMERICAN OIL & GAS REPORTER

gravel packs, sand consolidation, etc.),
the wells must be started and operated
slowly in a controlled manner to avoid
high rates of change of pressure drawdown
on the formation that can cause significant
sand influx.
Finally, there are fields where subsidence caused by shallow reservoir pressure
depletion is a major concern. In these applications, automation is needed to balance
pressure maintenance and production activities to permit the reservoirs to be produced while protecting the surface environment.
Automation Capabilities
Downhole gauges represent a vital
equipment component to enable the necessary automation and instrumentation
capabilities in these challenging production
applications. Using permanent electronic
downhole gauges is becoming increasingly
common and yields information that is
invaluable for managing artificial lift systems and driving a variety of production
surveillance workflows. Yet, using downhole gauges is still not the norm in the
majority of onshore wells, particularly
those in mature assets.
The widespread adoption of downhole
gauges in a majority of onshore applications has been slowed by a number of issues, including:
* Well bore geometries: Many wells
are completed with small well bores (e.g.,
41⁄2-inch casing or 27⁄8-inch monobore completions). In such applications, it may be
difficult to find a commercially available
gauge that will fit in the well bore.
* Equipment run life: As with many
new technologies, initial installations may
suffer from shortened run lives. In many
cases, this actually may be the result of
installation errors rather than problems
with the equipment or technology itself.
Nonetheless, operators need to feel comfortable that they can achieve reasonable
run lives before they will be willing to invest in any new technology for their wells.
* Cost, and the fact that downhole
gauges are often perceived as "nice-tohave" items rather than "must-have" items:
As such, operators often have a difficult
time justifying their cost, particularly in
mature assets with marginal economics.
Because of these limitations, operators
are constantly seeking alternatives to
permanent downhole gauges for their
low-rate wells. Such alternatives include

American Oil and Gas Reporter - January 2012

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