Note: Descriptions are shown in the official language in which they were submitted.
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Pressure protection system
Production wells are used to produce fluid from reservoirs in the geological
subsurface.
In particular, fluids in the form of oil and gas are produced through wells,
as is routinely
the case in the oil and gas industry. The production fluid is typically
received in the well
from the subsurface reservoir due to the natural pressure conditions, and then
flows
out of the well inside a dedicated production tubing disposed in the well. The
flow of
gas and liquids in a production well takes place as a result of pressure in
the reservoir.
The naturally occurring pressure may be sufficient to lift the fluids to the
surface. In
addition to the natural flow of fluids, an artificial pressure may be added to
increase the
flow, or create a flow if the naturally occurring pressure is not sufficient
to lift the fluids
to the surface. The artificial pressure is also referred to as artificial
lift. An electric
submersible pump (ESP) is a downhole pump which can be used to create
artificial lift.
A system of multiple EPS lifted wells may be used, wherein the wells are
connected to
a common manifold. The production fluid from the well is then transported
along
pipelines to a downstream facility, for example a floating production platform
(in the
case of an offshore well) where the fluid may be processed further. Additional
booster
pumps may be provided in the production system at the surface, for example on
the
seabed, to help pump the production fluid from the well along the pipeline to
the
downstream facility at a suitable rate.
The invention provides a method and system as defined in the accompanying
claims.
Some embodiments of the invention will now be described by way of example only
and
with reference to the accompanying drawing, in which:
Fig.1 illustrates schematically a system;
Fig.2 illustrates a method.
A method is provided wherein a combination of water and gas is injected into
the well.
The method described herein may be used as an artificial lift method for heavy
oil
reservoirs where gas-lift cannot be applied due to high viscosity of the
reservoir oil.
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The method described herein provides for a method of injecting a combination
of water
and gas into a well. This method may be used to create artificial lift.
The water and gas may be injected simultaneously into the well.
The water and gas may be injected into the well through holes in the
production tubing,
optionally as deep as possible such that injection takes place close to a
lower
completion section. The holes in the production tubing may be provided with
valves to
control the inflow of water and gas.
The water and gas may be transported down in the annular space between the
tubing
and the smallest casing. Alternatively, the water and gas may be transported
down in a
single shared tubing which is provided inside or outside the production
tubing.
Alternatively, the water and gas may be transported down in separate tubing
inside or
outside the production tubing, wherein a first tube is provided for the water
and a
second tubing for the gas. With separate tubing, water can be provided at any
position
upstream the gas injection. Water can also be provided by extending the well
or a well
branch into an aquifer.
An advantage of adding or injecting water to the produced reservoir fluid is
to generate
a flow regime inside the production tubing with a low apparent viscosity, when
compared to reservoir fluid without water, to reduce the frictional pressure
loss. An
advantage of adding or injecting gas to the produced reservoir fluid is to
generate a
fluid mixture in the tubing with low apparent density, when compared to
reservoir fluid
without gas.
Consequently, by adding, injecting and/or mixing water and gas down hole in
the well
with the produced reservoir fluid, the fluid mixture in the tubing will have
both low
viscosity and low density, thereby combining the advantages of water and gas.
The amount of water and gas injected into the production tubing down hole can
be
regulated continuously to maximize the production of reservoir fluid. The
amount of
water and gas injected into the well may be varied depending on the
composition of the
produced fluid, such as water cut and gas liquid ratio of the produced
reservoir fluid.
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Addition of water with continuous flow conditions can be one solution to
secure low
apparent viscosity of the fluid in the production tubing.
Injection of both water and gas simultaneously reduces pressure losses both
due to
friction and gravity. Without adding further pressure, the well pressure
itself may be
sufficient to transport the production fluids to the surface in combination
with the
reduction of pressure losses after injection of water and gas.
The added water to reduce friction pressure loss may also be used in
connection with
transportation of heavy oil outside the well, such as in pipeline
transportation of oil.
A possible problem with providing artificial lift is an increase of pressure
at the well
beyond a threshold at which the surrounding formation fractures or other
undesired
effects take place. The downhole well equipment may also fail beyond a
threshold
pressure.
Existing technology to protect the well/downhole well equipment and rock
formation at
the intermediate casing shoe depth against overpressure are the use of a first
barrier
provided by a steel casing, and the use of a second barrier provided by a
pressure
relief device at the wellhead which limits the maximum pressure of the annular
space
between the tubing and the smallest casing, hereafter called annulus. The
pressure is
thus limited to avoid fracturing the formation at the level of the shoe in the
well. A
casing shoe may be used as a term for the bottom of the casing string,
including the
cement provided around it.
In a traditional application with only one phase in the annulus (i.e. only
water, gas or
oil) the effect of the static head is relatively easy to account for. Static
head refers to
the pressure exerted due to the gravitational force of the fluid column in the
annulus.
For a gas column used in traditional gas lift, the static head is relatively
low and a high
topside pressure is permissible. For a water column, the static head is high
and
permissible topside pressure is thus limited. However, the static head also
aids
injection of water and the topside pressure need not be too high.
In the method disclosed herein, both water and gas is provided in the annulus.
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The static head of pure water need to be assumed (-1 bar/10m) as a worst case,
i.e. a
threshold which should not be exceeded, when defining the set point so the
permissible
pressure at the wellhead is quite limited in order to protect the formation
In normal operation there is a significant amount of gas in the fluid column
reducing the
density and thus static head. In order to get the lift working, a significant
pressure
needs to be applied topside, easily exceeding the permissible pressure.
Herein disclosed is a pressure regulating system or a pressure sensing system,
comprising one or more tubulars extending downhole. The tubulars may be filled
with
gas. A positive pressure may be provided in the one or more tubulars. A
pressure
regulating valve may be provided within the one or more tubulars.
The one or several small bore tubulars may be extended down to the level of
the shoe.
The tubes may be strapped to the outside of the production tubing as is
sometimes
done for chemical injection lines. A small positive flow of gas is set from
the topside
with a flow restriction located between the pressure source and the tubes
controlling
the flow. A precise control of the flow rate is less relevant for this
application.
The tubular is now acting as a pressure sensing tube at the level of the shoe
with only
the relatively small static head of the gas column to be accounted for. The
tube may be
connected to a pressure relief device, such as a pilot operated relief valve,
to ensure
that this opens at a correct pressure measured at the level of the shoe after
adjusting
for the static head of gas. The connection is to be made downstream of the
flow
restriction from the gas source. The gas source would have a pressure high
enough to
force open the relief device. If the tubular clogs for any reason or the
annulus outlet
valve opening is blocked or restricted, the pressure from the gas source will
ensure that
the pressure relief device takes the desired action. If the pressure relief
device opens it
will relieve the pressure sources that feed and pressurize the annulus. Other
pressure
relief devices, including instrumented systems may also be used for pressure
protection.
A plurality of separate small gas tubes may be provided inside the annulus and
these
may be used for measuring and/or controlling the actual downhole pressure
inside the
annulus and for pressure protection of the well.
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This method and system can be used on a well where water and gas is injected
simultaneously into the well through the annular space between the tubing and
the
smallest casing, referred to as the simultaneous injection of gas and water
used as
5 artificial lift (SWAG-L) method.
By using a dedicated gas filled sensing line one avoids the complication of
having to
account for a heavy fluid (water) when defining the set pressure topside.
Instead, the
actual pressure at the level where the system needs to be protected is
measured. The
operational envelope for topside pressure is not dependent on conservative
assumptions and ensures efficient lift.
Figure 1 illustrates a simultaneous water and gas lifted well including a
pressure
protection system. The system includes a gas supply (1) and a water supply (2)
which
are used to provide a flow of water and gas in the annulus A (3). The gas
supply is
also connected to small bore injection lines (4) to provide the pressure
protection
system as described above. A flow measuring element (5) is provided and a flow
restriction (6). A pressure safety valve (7) is also connected to the combined
water and
gas tubular as well as to the small bore injection lines. In the example
illustrated in the
Figure, the small bore injection lines extend from the surface though the
Christmas tree
into annulus A, past the sea floor to the intermediate casing shoe (8), where
the
intermediate casing ends. The injection point where the combined water and gas
are
injected into the well is provided below the point where the small bore
injection lines
end. A small positive gas pressure is maintained within the small bore
injection lines.
Figure 2 shows a method comprising: (Si) providing a gas supply to the annulus
through one or more tubulars extending from the surface into the annulus.
Although the invention has been described in terms of preferred embodiments as
set
forth above, it should be understood that these embodiments are illustrative
only and
that the claims are not limited to those embodiments. Those skilled in the art
will be
able to make modifications and alternatives in view of the disclosure which
are
contemplated as falling within the scope of the appended claims. Each feature
disclosed or illustrated in the present specification may be incorporated in
the
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invention, whether alone or in any appropriate combination with any other
feature
disclosed or illustrated herein.
