Note: Descriptions are shown in the official language in which they were submitted.
CA 02829630 2013-10-11
Crossover Valve System and Method for Gas Production
Field of the Invention
[0001] The present invention is directed to a valve for use in production from
gas wells with
low flow pressures and inconsistent production line pressure.
Background
[0002] Gas wells, and in particular sour gas wells with varying quantities of
H2S are produced
throughout the Western Canada Sedimentary Basin. While reservoir pressures are
depleting,
the remaining gas volumes left in the reservoir are usually significant. The
challenge is to
produce the remaining reserves with low flow pressures and inconsistent
production line
pressures.
[0003] Sour gas wells are completed with a packer in place to isolate the sour
production
from the annular space between the well casing inside diameter and the outside
diameter of
the production tubing. The packer prevents sour gas from entering the annulus
and corroding
the casing string, which is the barrier between the wellbore and any adjacent
ground water or
aquifer. Additionally, the annulus above the packer is typically filled with
inhibited brine
solution to enhance corrosion protection and provide an additional barrier
preventing
migration of sour gas into the annulus.
[0004] All gas wells will produce a quantity of liquid which is unloaded
during gas
production. Liquid loading is a symptom of the well's inability to unload
liquids that are
naturally produced during the production life of the well and is the most
common cause of
production decline in a gas well. In addition to liquid loading, there are a
number of other
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reasons why wells will not produce at the maximum level. If a number of wells
are drilled
into the same reservoir and the gas is depleted at a faster that normal rate,
the competitive
drainage of the reservoir will reduce production. In a compartmentalized
reservoir, where
reservoir size is limited because of lack of connectivity between the
permeable parts of the
formation, there may be production issues. Also, production may be limited
because of
formation damage caused to the near well bore while drilling the well or on
subsequent work
over with a service rig or natural near well bore damage may also be caused by
liquid loading
or natural scaling effects of the produced well effluent.
[0005] When a well is initially drilled, it is typically in a virgin part of
the reservoir, and
therefore reservoir pressures and volumes are usually quite high. The surface
production lines
that will transport the gas and liquids are operated at pressures that allow
the well to flow to
surface. The difference between the surface lines pressure and the flowing
bottom hole
pressure of the well will dictate how much the well can flow. Other factors
also relate directly
to this such as gas density, friction effect, liquid density and depth of the
well. As the well
ages and flowing bottom hole pressure depletes, the well will experience
reduced flow
capability.
[0006] It is well known that liquid loading affects gas production when gas
velocity drops
below the level necessary to carry liquid droplets upwards. Critical gas
velocity is a function
of flowing pressure, fluid and gas density, droplet size, surface tension,
temperature and pipe
diameter.
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[0007] One method of increasing gas velocity is to change tubular size or
decrease surface
pressure; the effect on the wells ability to unload liquid is dramatic when
such solutions are
applied. However, these solutions will only last as long as the bottom
reservoir pressure can
produce against the new conditions.
[0008] Unfortunately for most sour gas wells, the option to change tubulars or
decrease
surface pressures are often uneconomic and the well is abandoned long before
its usable
reserves are depleted. The cost to change out tubulars is high in terms of
cost (rig, safety
equipment, pump trucks etc.) and the potential damage to the formation, which
may occur as
the well has to be killed using a fluid whose hydrostatic weight has to equal
or overcome the
shut in reservoir pressure. In many cases the depth of the well and the low
reservoir pressure
will not hold a full column of kill fluid and the fluid will fracture into the
formation face,
causing damage that cannot be repaired.
[0009] Surface pressure may be reduced by using a compressor to reduce the
flowing
wellhead pressure in the wellbore. The cost is directly related to the size of
compressor
required to have sufficient suction pressure that allows the well to unload
liquid with the
elevated velocity required to produce the gas to the gathering system lines.
Most compressors
for sour gas are required to have numerous safety shutdown systems, expensive
coolers to
reduce the heat of compressed gas and noise emission controls.
[0010] Artificial lift in these wells is difficult to implement. Most types of
downhole
mechanical or electrical pumps do not work well in a high gas environment due
to gas locking
and cavitation. The costs of the modifications or additional completion
components required
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to adapt the pumping systems to efficient operation in high gas ratio
environments can also be
prohibitively expensive.
[0011] Therefore, there is a need in the art for an innovative and economical
solution to
produce gas from these aging reservoirs.
Summary of The Invention
[0012] In one aspect, the invention comprises a valve as part of an
operational system that
uses reservoir energy and injected sweet gas to activate a plunger up and down
the well bore
and acts as interface between the produced liquid and produced gas, there by
unloading all
liquid to surface. The plunger may be cycled numerous times throughout the day
and is the
frequency of cycling is only dependent on how much gas is available for each
cycle.
[0013] Therefore, in one aspect, the invention comprises a method of producing
a vertical,
deviated or horizontal gas well having an annular space defined by a well
casing and a
concentrically disposed production tubing, said well having an upper annulus
and a lower
producing zone open to the production tubing, wherein the upper annulus is
isolated from the
lower producing zone by a packer, comprising the steps of:
(a) opening a communication path through the tubing into the upper annulus,
and if
necessary, removing any inhibited fluid in the upper annulus;
(b) landing at least one crossover valve within the production tubing above
the packer
and exposed to the upper annulus; and
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(c) periodically injecting gas into the annular space to open the crossover
valve and
enter the production tubing, wherein the injected gas lifts liquids in the
production tubing
to the surface.
In one embodiment, the at least one crossover valve is deployed on a
continuous or jointed
tubing string or by wireline, within the production tubing.
100141 In another aspect, the invention may comprise a crossover valve
assembly for insertion
into production tubing, comprising:
(a) a pilot section comprising an outer housing and an inner production
tube
disposed concentrically within the housing, defining an annular space
therebetween, a
pilot valve assembly within the annular space and comprising a valve seat and
a pilot
piston moveable between a closed position and an open position, a pilot
chamber
exposed through a pilot opening in the outer housing, a spring for biasing the
pilot
piston towards the closed position;
(b) a power section comprising an outer housing and an inner production
tube
disposed concentrically within the housing, defining an annular space
therebetween, a
power valve assembly disposed within the annular space and comprising a valve
seat,
a valve mandrel and an activation piston, wherein the valve mandrel and an
activation
piston are moveable between a closed position and an open position, wherein
the
power section defines an activation chamber;
(c) an activation fluid passage between the pilot chamber and the
activation
chamber which is closed when the pilot piston is in its closed position and
open when
the pilot piston is in its open position, and wherein fluid pressure in the
fluid passage
moves the activation piston and valve mandrel to their open position;
(d) a crossover fluid passage through the power section outer
housing and the power
section inner production tube which is closed when the activation piston and
the valve
mandrel are in their closed position; and
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(e) an equalization fluid passage between the activation chamber and through
the
power section outer housing, which equalization passage is more restrictive
than the
activation fluid passage.
[0015] In another aspect, the invention may comprise a crossover valve
assembly for insertion
into production tubing, or integral with production tubing, comprising:
(a) an outer housing;
(b) an inner production tube;
(c) a pilot section responsive to external pressure to open an activation
passage
above a pre-determined pressure;
(d) a power section responsive to pressure in the activation passage to
open an
injection opening; and
(e) a crossover valve responsive to pressure in the injection
opening to open a
crossover port, allowing fluid communication from outside the outer housing to
within
the inner production tube.
In one embodiment, the pre-determined pressure is set by means of a coil
spring, or a gas
spring, or both a coil and gas spring, acting within the pilot section. The
power section may
comprise an equalization pathway open to outside the outer housing, which
equalization
pathway is more restrictive to gas flow than the activation passage.
[0016] In another aspect, the invention may comprise a system for producing a
vertical,
deviated or horizontal gas well having an annular space defined by a well
casing and a
concentrically disposed production tubing, said well having an upper annulus
and a lower
producing zone open to the production tubing, wherein the upper annulus is
isolated from the
lower producing zone by a packer, comprising:
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(a) a communication path through the tubing into the upper annulus;
(b) at least one crossover valve within the production tubing above the packer
and
exposed to the upper annulus through the communication path; and
(c) a surface gas injector and a gas supply for injecting gas into the annular
space to
open the crossover valve and enter the production tubing.
In one embodiment, the system may further comprise a plunger for reciprocating
within the
production tubing. The system may further comprise a surface controller for
controlling the
gas injector, wherein the controller is responsive to a signal indicative of
one or more of the
following: the position of the plunger, pressure in the annulus, pressure or
gas flow in the
production tubing.
Brief Description of The Drawings
[0017] In the drawings, like elements are assigned like reference numerals.
The drawings are
not necessarily to scale, with the emphasis instead placed upon the principles
of the present
invention. Additionally, each of the embodiments depicted are but one of a
number of
possible arrangements utilizing the fundamental concepts of the present
invention. The
drawings are briefly described as follows:
[0018] Figure 1 is a schematic representation of a wellbore with an upper
annulus and lower
producing zone, sectioned vertically along its length and depicting the
crossover valve thru
tubing completion.
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[0019] Figure 2 is a schematic representation of the crossover valve device
sectioned along its
length to reveal all of the working components.
[0020] Figure 3 is a detailed view of area A shown in Figure 2, showing the
power section
valve assembly.
[0021] Figure 4 is a detailed view of area B of Figure 2, showing the pilot
section valve
assembly.
[0022] Figure 5 is a tranverse cross-sectional view along line C-C in Figure
2.
[0023] Figure 6 is a cross sectional of the crossover valve of Figure 2, shown
with the pilot
valve assembly in its open position.
[0024] Figure 7 is a cross sectional of the power section of the crossover
valve of Figure 2,
shown with the power valve assembly in its open position.
[0025] Figure 8 is a cross sectional of the power section of the crossover
valve of Figure 2,
shown with the RCV valve in its open position.
Detailed Description Of Preferred Embodiments
[0026] When describing the present invention, all terms not defined herein
have their
common art-recognized meanings. To the extent that the following description
is of a specific
embodiment or a particular use of the invention, it is intended to be
illustrative only, and not
limiting of the claimed invention.
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[0027] The apparatus of the present invention is designed to facilitate
production of gas wells
with low flow pressures and/or inconsistent production line pressure, and sour
gas wells in
particular. The term "fluid" is used herein as comprising both liquids and
gases.
[0028] As shown in Figure 1, a producing gas well comprises a casing string
(1) and a
production tubing string (2). A packer (3) provides a seal between the tubing
outside
diameter and the casing inside diameter, The packer prevents cross-flow of
produced liquids
and gas above the packer and protects the casing from corrosion usually
associated with H2S,
as the casing is the only barrier between the wellbore and the surrounding
natural formation.
100291 Many sour gas well sites are equipped with high pressure, sweet fuel
gas for
instrumentation operation. This source gas may also be an excellent medium for
annular
circulation gas.
[0030] In one aspect, the invention comprises a method of producing natural
gas from an
isolated zone, such as a sour gas zone, by thing injected sweet gas to lift
liquids in the
production tubing to the surface. In general terms, in another aspect, the
apparatus of the
present invention comprises a crossover valve device, which opens in response
to pressure in
the casing annulus, to permit fluid flow from the annulus into the tubing
string.
[0031] The valve (10) comprises a number of tubular elements (11) assembled
together to
define an internal production flow path and an outer housing (12). In one
embodiment, the
valve comprises a pilot section (13) and a power section (14), connected by a
pup joint (16)
defining a fluid passage (17). In one embodiment, the valve (10) is adapted to
be run on
wireline, or on continuous or jointed tubing string. In one embodiment, the
valve may be an
integral component of a tubing string.
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[0032] The pilot section comprises a concentric sliding pilot piston (18), a
pilot valve seat
(20) and an annular pressure opening (22) in the outer housing (11). In its
closed position, as
shown in Figures 2 and 4, the downhole end of the pilot piston (18) is seated
against valve
seat (20), closing off the pup joint fluid passage (17). The pilot piston (18)
is appropriately
sealed with seals which slide against the inner surface of the housing (11)
and the outer
surface of the inner tubing.
[0033] The pilot piston (18) is biased towards its closed position by a coil
spring (26), or a
gas spring (28), or a combination of a coil spring and a gas spring. As shown
in Figure 2, a
pilot pressure chamber (28) is filled with an inert gas such as nitrogen
through a valve (24),
and resists upward movement of the pilot piston. The casing pressure required
to open the
pilot valve must overcome the closing pressure, which is the sum of the gas
pressure in
chamber (28) and the pressure exerted by the coil spring. When the annular
pressure drops
below the closing pressure, the pilot valve will close.
[0034] When the pressure applied through the pressure opening (22) overcomes
the closing
pressure, the pilot piston (18) is urged upwards as fluid fills the pilot
chamber (23) until the
casing pressure equals the closing pressure exerted by the coil spring and the
gas spring.
[0035] This fluid in the pilot chamber (23) then travels downwards through the
pup joint fluid
passage (17) and enters the power section (14), activating the power piston
(30) which is also
a sealed concentric sliding piston. In one embodiment, the power piston is
biased in a closed
position by a coil spring (31).
[0036] The power piston (30) pushes against a mandrel (32) having a valve face
(34) which is
seated against an injection gas inlet (36) through the outer housing. The
injection gas inlet
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may be provided in a circumferential groove (38) around the outer housing
which has an
angled conical section. The valve face (34) has a matching conical section
which sealingly
engages the gas inlet when closed.
[0037] As injected gas (G) in the casing annular space enters the power
section (14) through
gas inlet (36), it proceeds through the valve between the lower tubular (11A)
and the outer
housing (12) until it reaches the cross-over valve or RCV valve (50), where it
unseats the
RCV valve (50), and through crossover port (52) and enters the internal flow
path of the valve
(10). The RCV valve (50) is biased upwards by a coil spring (51), the force of
which is
overcome by the injected sweet gas pressure. The RCV valve is shown seated
(closed) in
Figure 7 and unseated (open) in Figure 8.
[0038] When the annular pressure outside the valve drops below the closing
pressure of the
pilot section, the pilot piston (18) will be urged towards its closed
position, and eventually
seating against the valve seat (20), and initiating the valve closure
sequence. If the annular
pressure continues to drop, the fluid in the pilot chamber (23) and in the pup
joint fluid
passage (17) is allowed to slowly equalize to the annular pressure through a
restrictive bypass
(42) which exists between the lower tubular (11A) and the outer housing (12)
around the
power piston (30). The closing pressure exerted by the power section coil
spring (31) is then
sufficient to return the power piston (30) to its closed position, as the
pressure equalizes.
When the power piston returns the closed position, the valve face (34) closes
the injection gas
inlet (36). The RCV valve (50) will then close and the valve (10) again
isolates the annular
space from the production tubing.
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[0039] The restrictive bypass (42) is always open, but provides sufficient
resistance to gas
flow to allow gas pressure from the pilot section to open the power piston,
while allowing
equalization within a reasonably short period of time, in one embodiment, in
the order of a
few minutes.
[0040] The valve (10) will open at annular pressures above the closing
pressure, and will
close when the annular pressure drops below the closing pressure. In one
embodiment, the
closing pressure of the pilot section of the valve is adjusted by adjusting
the strength of the
coil spring and the gas spring, if both are used. The selected closing
pressure may be
determined by considering the well depth, annulus volume available and
gas/liquid ratios. In
one embodiment, the low pressure closure will be set significantly higher than
the minimum
tubing pressure, thereby ensuring no sour gas in the production tubing can
escape into the
annulus through the valve (10). For example, the low pressure closure may be
set at 500 kPa
over the minimum tubing pressure. This is important in the absence of the
inhibited annulus
fluid to prevent sour gas migration into the annulus. In addition, the valve
may be equipped
with two isolation mechanisms (or barriers) between the tubing ID where sour
gas resides and
the annulus which is required to remain sweet.
[0041] In one embodiment, the gas spring can be charged to a very high
pressure before use
in the field, and can then be adjusted to a desired pressure for the
particular downhole
conditions it will encounter before installation downhole. The coil spring
provides a fixed
closing pressure, while the gas spring may provides a variable customizable
closing pressure.
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[0042] Therefore, in one embodiment, the crossover valve comprises three
actuating
components, the pilot section, the power section and the RCV valve, which
interact by gas
pressure and not physical linkage.
[0043] In operation, and with reference to Figure 1, a bottom hole check valve
(8A) is placed
into the bottom of production tubing string, which functions to prevent gas
injected from
surface entry into the formation when the well is completed, but does allow
gas flow from the
formation into the tubing string,
[0044] The cross-over valve (10) assembly can be run using wire line
techniques or coiled or
jointed tubing techniques that are well known in the industry and need not be
further
described here. If an existing sliding sleeve is part of the production
string, it may be opened.
Alternatively, the tubing may be perforated above the packer (3). The valve is
landed above
the isolation packer (3), level with an open sliding sleeve or with tubing
perforations. The
valve is located in between two thru-tubing pack-offs (4, 5) which isolate the
production
tubing above and below the valve. Any gas from the annulus can only enter the
production
tubing through the valve (10). Suitable anchor and packer configurations are
described in co-
owned U.S. Patent No. 7,347,273 B2, the entire contents of which are
incorporated herein by
reference (where permitted).
[0045] Any inhibited fluid in the annulus may be removed using conventional
means, such as
by circulation of nitrogen gas.
[0046] Once the dovvnhole equipment has been installed and any inhibited fluid
has been
removed, a sweet gas compressor (102) can compress low volume gas from the
instrument
supply line (104) and inject it down the casing tubing annulus. Once the
annular pressure
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exceeds the closing pressure of the crossover valve (10), the injected sweet
gas (G) will pass
through the valve (10) into the production tubing, overcome the flowing bottom
hole pressure,
and cause the bottom check valve (8A) to close. Thus, all the sweet annular
gas (G) will
move upwards in the production tubing. This will increase the gas velocity to
above the
critical rate and drive any liquid column in the production tubing to the
surface.
[0047] Once the liquid column is produced, the pressure in the annulus may be
reduced,
closing the valve while maintaining a positive pressure differential against
the tubing. With
the liquid hydrostatic column removed from the well bore, the well can now
produce to full
potential through the bottom check valve (8A). The production cycle is
repeated when the
annular gas column has reached the required pressure to open the crossover
valve (10) again.
[0048] A plunger assembly (not shown) may be introduced into the tubing string
to allow the
well to be operated at lower gas velocities. The plunger acts as an interface
between the liquid
column and the injected gas. Because the plunger is a dynamic seal with close
tolerance
between the plunger body and the tubing wall (as opposed to perfect seal), it
still requires
velocity to move the liquid up hole, however the cross sectional area of the
plunger coupled
with the gas velocity trying to pass the outside creates a differential
pressure from below
which drives the plunger and the liquid column to surface.
[0049] In one embodiment, the system may comprise electronic monitoring and
pressure
recording to determine when the system operates, such as, for example, by
using a PLC
(Programmable Logic Controller) with various analog and digital inputs and
outputs, which
can read and record signals from external sensors such as pressure
transducers. These
transducers constantly sample the well pressures and will signal the PLC
control box to open
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casing valves to flow or shut in. The PLC may also have a proximity switch
which detects the
plunger arrival at surface and records times and flows. With these electronic
instruments and
control the well can be left with no human intervention once the flow cycles
are set into the
controller. These set pressures and times can be adjusted to suit the changing
well conditions.
[0050] Alternate means exist of completing this production workflow including,
but not
limited to a locking and sealing mandrel assembly (as is well known in the
art) to engage and
seal in an existing selective profile nipple integral to the production tubing
string. This would
replace the tubing packer (5) depicted in Figure 1. This completion is
possible if a selective
profile nipple exists and is easily accessible in the wellbore relative to the
location of the
communication ports through the production tubing wall. In another
alternative, the tool
string may be landed across an open sliding sleeve providing communication
through the wall
of the tubing from the annulus. All of the elements of the tool string may be
designed to pass
through the largest standard selective profile nipple size in order to easily
facilitate landing
said tool string across an existing sliding sleeve (equipped with profile
nipple) or below an
existing profile nipple in the event that complex wellbore geometry is
encountered.
