manual choke valve
changes, the valve’s
flow rate is
altered—even
though the valve
position is fixed.
Field data has
shown that these
fluctuations in flow
rate in a manual
choke valve can
vary by as much as
40% of desired flow
rate. As with any
process dependent
on flow rates, the
potential impact of
this wide variation and subsequent upset
is significant. These swings in pressure
can be due to compressors going up or
down, wells being shut in or started up,
and other anomalies that periodic manu-
al manipulation cannot account for.
If the pressure shifts far enough, the
gas-lift poppet valve may close until the
pressure builds and relieves. When this
happens in spurts, it causes surging and
intermittent flow. Following a gas burp,
the well then begins to flow with a slug
of liquid—a process that is repeated constantly until the pressures change or the
manual choke valve position is reset. The
result is a migration from optimal liquid
flow rates as well as inefficient use of
natural gas. Excessive slugging also can
cause pressure spikes in the well strata,
culminating in damage to the well.
Over the long term, manual control
results in a wide variance of natural gas
injected into the well (Figure 3). The
barrels of oil produced will vary significantly over time (Figure 4), and surging
(intermittent flow) from shifting gas
injection rates can also occur. These conditions lead to excessive use of natural
gas, which increases costs and reduces
oil production, thereby decreasing revenue.
Figure 2. Injection vs. recovery
As the gas injection rate increases, so
does the liquid recovery rate. However,
there is a point of diminishing return
(Figure 2). While the recovery rate
climbs beyond this point with additional
gas injection, the amount of gas (and
therefore energy) required rises rapidly,
while the recovery rate increases only
minimally. This situation results also
because the ratio of the gas being recovered becomes excessive and displaces the
oil, causing fundamental changes in the
flow inside the tubing. The goal in this
application is to operate at the knee of
the curve, at which point a maximum
amount of oil can be retrieved using a
minimum amount of gas.
In a manual gas-lift system, the manual choke valve is semi-fixed, meaning
that an operator sets it periodically, usually with a handwheel. As the inlet gas
pressure or the back pressure to the
AUTOMATIC CONTROL
IMPROVES ON MANUAL
An operating oil field is a dynamic,
interwoven system—what happens in
one well impacts every well in the field.
If one well is shut down, idled or brought
online, the dynamics of the entire system
can change. Consequently, to maximize
oil production, each gas-lift system now
requires different pressure or flow rate.
To achieve smooth, efficient operation,
the change in down-hole gas injection
must be seamless. This is why balancing
a field at optimal performance with
manual valves is impossible—each
change that occurs results in changes to
every other well in the system.
One way to smooth out the process of
controlling the flow of injection gas in
gas-lift applications is to use automatic
control coupled with a conventional system of sensors, an automatic control
valve and a controller.
The heart of a conventional automated system is a control valve (Figure 5),
which automates the process of setting
the injection rate. The control valve is
coupled with an automation package
that consists of a flowmeter, a pressure
Figure 3. Long-term variance of natural gas produced
Figure 4. Long-term variance of oil produced
