For
decades the oil industry has used gas lift technology to coax oil from
under-pressured reservoirs. Most often these reservoirs have lost the
ability to flow on their own because the original gas that acted as the
pressure driving the oil has been produced over time. Often this gas
depletion occurs over a very short period of time stranding most of the
original oil in place.
Gas lift is the controlled injection of gas into the oil as it enters
the production tubing. As it does in nature, the gas lightens and
propels the liquid to the surface allowing oil in the reservoir to move
to the well and then to the surface. The key to gas lift is "control"
and much has been done to design systems that inject the gas, either
intermittently or continuously, at a rate sufficiently constrained to
prevent gas waste yet also in volumes large enough to optimize oil
production. Over time, systems have been devised to regulate the timing
of gas injection, the volume injected, and, through the use of gas lift
mandrels and valves situated along the tubing string, at what depth
those volumes are injected into the fluid column.
But these systems are far from efficient. It is no industry secret that
some gas-lifted wells are producing at a fraction of their capability
and that much gas is being wasted as it flows from injection point to
production line without actually affecting oil production.
Today, with the proliferation of computer technology and telemetric
monitoring of well behavior, as well as the perfection of multiphase
metering and pumping, gas lift efficiencies are poised to greatly
improve. The goal is to maximize the "gas lift cycle" by setting the
timing and volumes of gas injected into the well so as to optimally
affect oil production while minimizing gas usage.
"The trick is setting the timing," said Herb Meyer of Camco, a leading
industry supplier of gas lift systems. "The cycle could be four or five
times a minute or one every few minutes. That is where the man in the
pickup earns his money, by letting it cycle on a certain time and
checking production, then changing it and checking production to see if
it increased and on and on until it is optimum."
No longer satisfied with the limited kind of tweaking possible from even
the most experienced field hand, Camco and others are currently at work
to bring the process into the computer age, not only because of
inherent human inexactitude, but because even when a cycle is set,
changing well conditions quickly render it inefficient. The problem is
particularly challenging to a manual solution when numerous wells are
draining a single reservoir and adjustments to the gas lift settings on
one well inevitably affect the others to create a cause-and-effect
network too complex and often too subtle to be calculated by hand.
The
solution to the complex problem of setting an optimum gas lift cycle is
coming not so much from research on gas lift but as a beneficiary of
development of other technologies, particularly on the heels of recent
strides made in the difficult science of measuring multiphase flow. At
present, measuring exactly what is flowing from any given well, that is
the actual fluid makeup in percentages of gas, oil, and water, could
only be determined through a production test. And since this requires
manually turning flow to a separator, operators are loath to do it on
anything but an intermittent basis, commonly once-a-week or less.
Naturally, with such a long time between tests and the fact that such a
test shows only a moment in time that may not be very representative of
the well's longer term flow makeup, it is impossible to "tweak" gas
injection on any kind of timely or reliable basis.
But with the introduction of multiphase flow metering in real time and
SCADA telemetry, gas lift efficiencies can be monitored continuously and
without production interruptions. The addition of computers that can
read and analyze the data instantly and then make the necessary changes
that consider optimizing the field as a whole promises to bring
heretofore unseen efficiencies to what has always been considered an
inexact science.
One key to the multiphase meter's role in gas lift optimization is its
ability to measure the flow makeup with extreme frequency. In the case
of a meter developed by Schlumberger and Framo, a reading is taken every
22 milliseconds.
"The high frequency measure gets rid of the effects of any type flow,"
said Schlumberger's Jeremy Walker. "Other ways to do that involve very
large pieces of equipment. Gas lift causes instability and taking high
frequency measurements you can measure the effects of changes you make
(to the gas lift cycle) in real time."
Using multiphase flow metering, reported Walker, one large multi-well
field was able to maximize its fluid production and minimize gas
injection within five days.
Likewise, when a field is facilities-constrained, that is when the wells
are capable of producing more than the field processing and gathering
system can handle, the multiphase meter can be invaluable in optimizing
production by assuring available facilities are used to accommodate the
most productive wells in terms of revenue rather than waste gas on less
productive ones. Without multiphase meter data, the guess work involved
in such a decision can be wildly inaccurate because it is not merely a
question of fluid volume wells are delivering, but at what cost in terms
of gas injected and how efficiently that gas is being used.
Since the meter is sufficiently compact to allow each well to be
equipped with one, an entire field can be tied together. When reservoir
models and production data are added to the mix, the loop can be closed
and injection as well as production rates set with an eye toward long
field life, accelerated production or some combination in thereof.
Another problems long vexing secondary recovery experts trying to set
the gas lift cycle to optimum is presumption of constant gas supply.
While it has long been understood that all gas supplies fluctuate
causing gas to be wasted or production reduced, operators have long been
resigned to the problem as nearly impossible to correct. But oil
service giant Halliburton now claims to have developed an answer to gas
supply interruptions through what it calls the Intelligent Flow
Controller (IQV-332 for short).
According to company literature, the electronics-based system monitors
gas supply variables and controls the injection choke to maintain a
constant injection rate and can be applied to as many as four wells at a
time. It works through six user-defined injection set points per well.
The set points are based on each well's production curves and are stored
in the IQV's memory. In the event of lift gas shortage, the IQV
automatically supplies gas to the most productive wells first.
Using a somewhat different approach to improving efficiencies,
Weatherford has chosen to create hybrid lift systems that combine gas
lift with some of their mechanical secondary recovery tools such as
progressive cavity pumps, electric submersible pumps, reciprocating
pumps, and plungers.
Essentially all these systems seek to reduce the cost and therefore the
size of the lift equipment on the surface while at the same time
improving the efficacy of both the gas and mechanical lift systems. In
each instance, gas is injected above the pump (or plunger) in order to
reduce the fluid head and allow the mechanical component to more easily
lift the fluid to the surface.
The company claims this method can reduce the liquid head, essentially
the downward force resisting the ESPs and PCPs, by up to 40%. As might
be expected, the systems are particularly useful in heavy crude
situations that cause great strain on pumps and are often of too high a
viscosity for gas to effectively lighten or propel.
Weatherford also advocates use of gas lift with the plunger, one of the
older artificial lift systems that works by converting well gas trapped
beneath it into pressure that carries it and a load of fluid above it to
the surface. Essentially a piston-shaped mandrel whose outside diameter
is near that of the tubing wall's inside diameter the plunger system
has long suffered from a phenomenon known as "fall back". "Fall back"
occurs when fluid clings to the walls of the tubing when being gas
lifted and as the name would imply, falls back to the bottom of the
well. Production loss from "fall back", particularly in deep or
heavy-oil wells, can be considerably and the hybrid system can therefore
significantly increase production and extend well economic life.
Gas lift is no newcomer to the oil industry. But in its long history its
effectiveness has been defined by human limitations. By combining the
older lift technology with new ones like data acquisition including
accurate realtime flow measurements, simulation, and automation, as well
as old ones like downhole pumps, greater efficiency and stability are
now possible. As a consequence, the technology appears ready to live up
to a whole new potential.
Source:
http://www.oilandgasonline.com
