Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM, METHOD AND APPARATUS FOR LIFTING FORMATION FLUIDS
IN A WELLBORE
Field of the Invention
The present invention relates to the oil and gas industry. More particularly,
the
present invention relates to techniques for lifting formation fluids in a
wellbore.
Background of the Invention
During the production of oil and gas reservoirs, the pressure of the reservoir
decreases as reservoir fluids are produced. After some period of time, the
reservoir
pressure will be insufficient to force the reservoir fluids to flow to the
surface. A method
of artificial lift can then be used to continue the production of the
reservoir fluids.
The time duration from initial production to secondary or enhanced recovery of
formation fluids is governed by the size and initial pressure of the
reservoir. Actions
taken to achieve maximum hydrocarbon recovery include: lowering tubing head
pressure;
installing siphon strings to maintain critical velocity (the velocity at which
liquids will
travel up the wellbore in mist or droplet form); and running plunger lift
systems. After
all of these methods are exhausted, a large amount of reservoir fluids are
typically left in
place.. Because the reservoir fluids are no longer lifted to the surface, they
accumulate in
the well bore. At this time, the hydrostatic pressure of the fluids in the
well bore is equal
to the reservoir pressure and therefore reservoir fluid production ceases-.
Coiled tubing velocity strings are a popular method for completing gas
reservoirs,
including coal bed methane gas (CBM) reservoirs. For these reservoirs, it is
difficult to
artificially lift reservoir fluids to the surface for the following reasons:
^ Coiled tubing has a tendency to hang in the well in a spiral manner. This
excludes the possibility of lifting reservoir fluids by traditional methods
that use
beam lift equipment or progressive cavity pumps.
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Steel coiled tubing has a seam on the inside that is caused by the welding
process
used for manufacturing the tubing. Consequently, the inside of the tubing is
not
round. This limits the use of plunger lift methods for lifting reservoir
fluids in
coil tubing.
U.S. Patent 6,672,392 issued to Reitz Donald D. (Denver, CO) describes an
artificial lift method where a check valve is placed at the bottom of the
production tubing
and that gas is injected at a point above the check valve and below the liquid
level in the
production tubing. Unfortunately, this method does not address how the device
can be
attached to the coiled tubing for efficient installation and removal or how
the check valve
is deployed or retrieved under live gas well conditions.
U.S. Patent No. 5,522,418 to Johnson et al. describes a differential pressure
operated gas lift including a valve element movable in a tubular body to open
and close a
gas flow passage having flow restricting orifices upstream thereof. This gas
lift method
is achieved by installing gas lift valves to the exterior of the production
tubing. A packer
is needed near the bottom of the production tubing.
Canadian Patent No. 2,350,453 to Liknes describes a method for dewatering a
gas
well where a check valve is installed into a packer and the packer and check
valve
assembly are situated in the well bore above the perforated interval and below
the level of
the produced water. High pressure gas is introduced to the system and can be
injected
into either the annulus or the production tubing and that when high pressure
gas is
introduced to the system that the check valve situated in or near the packer
will become
closed and that the high pressure gaswill lift water out of the annulus or the
production
tubing. In such an instance as described above the well will need to be
temporality shut
in while the procedure takes place.'
What is needed therefore are systems, methods and/or apparatus for lifting
formation fluids in a well bore overcoming the limitations and disadvantages
of the prior
art.
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Summary of the Invention
In one aspect, the present invention is a system for lifting formation fluids
in a
well bore comprising a valve linking an intake and a collection area, wherein
when the
valve is open the fluids are able to flow from the intake to the collection
area, and
wherein when the valve is closed the fluids are able to be lifted through
velocity tubing
via injection means.
In one embodiment of the system of the present invention, the collection area
includes the micro annulus between the velocity tubing and production tubing,
and the
injecting means is a high pressure gas injected through the micro annulus or
the coiled
tubing to cause the valve to close and the fluid to be lifted through the
velocity tubing or
the micro annulus. The system comprises of pump out components allowing
implementation in a well while it is under pressure/producing.
In another aspect, the present invention is a method for lifting formation
fluids in
a well bore comprising deploying a valve near an intake, allowing the fluids
to flow from
.15 the intake through the valve to a collection area, and injecting gas to
the collection area at
pressure sufficient to close the valve and lift the fluids through velocity
tubing or micro
annulus. The application of high pressure gas forces the fluids through the
velocity
tubing to the surface for extraction.
The present iinvention comprises the following general advantages:
^ No packer is required to form a seal between the production tubing and the
seal
assembly mandrel, and the space created by both tubes is sufficient in
diameter to
inject a high-pressure gas.
^ In most cases of shallow gas production, the gas can be produced out of the
casing. In sucli .circumstances, the present invention can displace water from
the
well bore while the well is flowing.
^ Although additional tubing is required, the present invention is quite
inexpensive
when compared with the costs installing a packer.
^ The present invention can be located at a point below the perforated
interval.
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The present invention can be deployed into a well that is under pressure.
Brief Description of the Drawings
A detailed description of the preferred embodiments is provided herein below
by
way of example only and with reference to the following drawings, in which:
Figure 1a illustrates a system in accordance with an embodiment of the present
invention;
Figure lb illustrates a system in accordance with an embodiment of the present
invention where the invention may be deployed into a live well;
Figure 2a illustrates a wellbore including the direction of flow of fluids in
accordance with an embodiment of the present invention;
Figure 2b depicts tools that can be attached to the coiled tubing and explains
how
the tools can be deployed and retrieved from a live gas well; and
Figure 2c depicts tools that can be attached to the coiled tubing and explains
how
the tools carn be deployed and retrieved from a live gas well.
In the drawings, one embodiment of the invention is illustrated by way of
example. It is to be expressly understood that the description and drawings
are only for
the purpose of illustration and as an aid to understanding, and are not
intended as a
definition of the limits of the invention.
Detailed Descrintion of the Invention
Figure 1 a illustrates the present invention in accordance with an embodiment.
Fluid, meaning water, oil, gas, sediment or any combination thereof, enters
the intake 110
at the seal assembly mandrel 108 (or "no-go" mandrel), and opens the check
valve
consisting of the ball 142 and seat 141 (upper and lower) housed in the open
cage 105.
The open cage 105 allows the well fluid to enter the micro annulus 103 through
holes,
ports or slots 106 when the ball 142 is in the open position (disposed upward
from the
lower seat 141).
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The micro annulus 103 is formed by the space between production tubing 101 and
velocity tubing 102. The micro annulus 103, according to this embodiment,
serves as a
collection area for fluids and serves a conduit for the injected gas,
described below. It
should be understood that the production tubing 101 could be flared or
enlarged in the
area around the mandrel 108 and valve assembly such that the gap between the
production tubing 101 and the velocity tubing 102 is greater, creating a
larger volume for
the collection area.
Production tubing 101 is typically large diameter tubing that, e.g., can be
coiled
tubing or conventional jointed tubing, and is positioned between the wellhead
(not
shown) and the seating nipple 109. Such tubing is typically spooled.into the
well by
means of a coiled tubing surface rig in a manner that is known.
Generally speaking, it is preferable that the tubing dimensions for the
present
invention allows for a'/a" clearance between the production tubing and the
velocity
tubing. Therefore, 2.00 inch production tubing would accept a velocity tubing
of 1.250
or smaller, 1.750-production tubing would accept 1.00-inch velocity tube or
smaller and
1.500 production tubing would accept a 0.750 velocity tube or smaller, for
example.
If the ball 142 is open, fluid will then enter the micro annulus 103 by
flowing
through the slots 106 in the open cage 105 and the interior of the velocity
tubing 102.
Although the valves are depicted as ball and seat valves, it should be
understood that.
other types of valves are suitable, such as a flapper valve.
The seating nipple 109 generally provides a means for the'seal assembly
mandrel
108 to stop at a predetermined depth, and also provides an internal surface
suitable for
sealing. The seal assembly mandrel 108 generally provides a means for
targeting the
seating nipple 109 and forms a seal when inserted on to the seating nipple
109, and also
allows for the attachment of additional components within the well bore. The
mandrel
108 preferably includes one or more seals 155 to ensure that pressure does not
leak out of
the end of the production tubing 101 when pressuring out the production tubing
101.
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When a predetermined amount of water has been trapped between the production
tubing 101. and the velocity tubing 102, high-pressure gas is introduced to
the micro
annulus 103. This high-pressure gas is provided in a manner described below.
High pressure gas will then force the ball 142 to meet the lower seat '141,
and
fluid will then be forced into the interior of the, velocity tubing 102. The
velocity tubing
102 (e.g., a small diameter coiled tubing or conventional jointed tubing) is
tubing that has
a diameter such that a given volume of liquid will travel at a higher rate of
speed than the
liquid normally would in a tubing of gTeater diameter (i.e. the production
tubing 101).
The supply of high-pressure gas is continued at a rate and pressure to produce
the fluid to
the surface wellhead.
Those who are skilled in the art will recognize that frictional losses in the
micro
annulus or the coiled tubing will add significantly to the pressure and flow
rate of the
introduced gas to achieve artificial lift in this fashion. There are numerous
materials used
in the manufacture of coiled tubing that affect frictional losses. The above
example is
used to provide a basic understanding of the operating principles of this
method of
artificial lift only.
The amount of pressure required to displace fluid is related to the volume of
fluid
present in the micro annulus 103. The pressure requirements to displace, for
example,
one barrel of water from a well bore may be achieved by applying a large
amount of
pressure with fewer cycles per day or a lesser amount of pressure over many
cycles per
day. The pressure (pounds per square inch) and rate of flow (cubic feet per
minute) to
produce water to surface is calculated by known data from. the well according
to methods
that are known.
For example, if a gas well produces one barrel of water per day then every
hour it
can be assumed that it produces 1/24 of a barrel, or approximately 405 cubic
inches. It is
apparent then at this time that a predetermined amount of water is related to
the pressure
available to displace the water into the velocity tube. To displace 405 cubic
inches of
fresh water into a 0.750 inch velocity tube would require approximately 33 PSI
more
pressure than the pressure at the valve assembly.
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The present invention can also include the known method of injecting a
surfactant
(e.g., soap) to a point below the collection area in order to lighten and help
displace well
bore fluid. For example, soap sticks can be placed in the micro annulus 103.
The rate of flow is dependent on the diameter of the velocity tubing 102 and
is
also related to the time required to complete one cycle. However, it is a
general rule of
thumb that gas traveling at rate greater than 10 feet per second will
transform water to a
mist or droplet form, thus suggesting that a minimum rate need to be supplied
for a given
diameter of velocity tubing. Gas traveling though a one-inch velocity tubing
at a rate of
2.5 CFM will travel at approximately 11.65 feet per second. At a rate of 20
CFM then
the rate of travel will be approximately 93 feet per second. It becomes
apparent that high
CFM flow will shorten the cycle time.
In the example above it would take a pressure greater than 33 PSI to displace
405
cubic inches of water into a 0.750 velocity tube and at a rate of 2 CFM the
gas water
mixture would travel at over 10 feet per second, repeating this cycle 24 times
a day or
once an hour a barrel of water would be produced to surface.
It is preferable to apply pressure to the top of the fluids in the micro
annulus 103
and force them into the velocity tubing 102 since the cross-sectional area in
the micro
annulus 103 is greater than the cross-sectional area in the velocity tubing
102 and thus
requires a lesser amount of gas to mist fluid in the micro annulus 103 to lift
the fluid to
the surface wellhead.
Further, most water and oil fluids also contain sediment, and by forcing
pressure
on top of the fluid column, thus forcing fluid and sediment back through the
open cage,
the sediments will wash through the bottom hole assembly and be produced to
the surface
wellhead. This is advantageous because it helps to maintain a clear flow path.
Figure lb illustrates the system of the present invention with blow out
components so that the system can be implemented in a live well scenario.
Located in
the seating nipple 109, a spring 151 applies pressure to a push rod 150. The
push rod 150
is in contact with the ball 142 and forces the ball against the seat 142. The
spring 151 is
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held in place in the mandrel 108 by a blow out plug 152, and the blow out plug
152 is
held in place in the mandrel 108 by a shear pin 153.
When the blow out components is in place the valve assembly may be run into a
well while it is under pressure or producing. Once the valve assembly is
landed into the
seating nipple 109, the wellhead can then be assembled. Once the wellhead
assembly has
been completed, pressure is applied to both the micro annulus 103 and the
velocity tube
102 resulting in the shear pin 153 to shear and the blow out plug 152, spring
151 and
push rod 150 to fall to the bottom of the well bore. The apparatus may
comprise a
retainer means to "catch" these components subsequent to blow out.
Figure 2a is a general well bore diagram and illustrates the direction of flow
of
fluids and the general location of apparatus components in the well bore,
according to an
embodiment of the present invention. Figure 2a does not show in detail
wellhead
equipment but it should be understood that the wellhead equipment is
commonplace for
such a system to be installed, e.g., wellhead equipment manufactured by SELECT
ENERGY SYSTEMSTM or PROGRESSIVE TECHNOLOGYTM.
The valve assembly 228 (comprising the open cage 105,. seal assembly mandrel
108, ball 142 and seats 141, for example) is preferably located in the well
bore below the
perforated interval 206. The compressor 202 located near the . surface is in
communication with flow line gas 203 coming out of the well bore.
According to this particular embodiment, a flow line check valve 204 is
located at
a point downstream of the inlet to the compressor 202. The flow line check
valve 204 is
in place to ensure that the produced water-gas mixture is not re-injected into
the casing
201.
It is preferable, in most methods of lifting well bore fluids, to have the
pump
situated below the perforated interval 206. Situating a pump below the
perforated
interval and into the fluid itself has the effect of a gas separator. Gas has
the tendency to
flow towards a lower pressure point, in this case the flow line at surface.
The water,
however, is more affected by gravitational forces and will collect at the
bottom of the
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well bore. By placing the intake 110 of the valve assembly 228 at a point
below the
perforated, interval 206 and into the water, a natural gas separation effect
takes place.
The compressor 202 is operable to provide high pressure gas when required to
the
system of the present invention by redirecting a portion of the produced gas
from the
flow line gas 203 and injecting it down the micro annulus 103. By circulating
the gas-
water mixture up through the velocity tubing 102, the gas-water mixture may.
be
separated at the surface or simply placed back on the flow line for further
processing
downstream of the well.
The compressor 202 creates pressure and flow rate. In general terms, to create
pressure does not require a great amount of horsepower if the pressure can be
built over a
long time period. However, to supply pressure and a high rate of flow requires
more
horsepower.
Since the velocity tube has a smaller cross sectional area than the micro
annulus it
requires less flow rate or less compressor power (horsepower). For example, in
a
situation where the production tubing diameter is 1.75 inches with a cross
sectional area
of 2.40 square inches and the velocity tube diameter is 1.00 inch with a cross
sectional
area of 0.785 inches the resulting cross sectional area of the micro-annulus
is 1.62 square
inches. At a given flow rate gas will travel faster in a tube of smaller
diameter.
Therefore, it should be understood that a further advantage of the present
invention is the
cost efficacy (i.e. reduction in compressor power) in terms of supplying high
pressure gas
to the valve assembly at a lower flow rate.
In summary, when the well is flowing under normal operating conditions,
formation pressure (i.e. bottom hole pressure) will force formation fluids to
open the
bottom valve and allow formation fluids into the open cage 105 and into the
micro
annulus 103. The following sequence of events then occur:
1. High-pressure gas enters the micro annulus 103 and applies force to the top
of the
fluid column and forces the ball 142 to seal against the lower seat 141 into a
closed position.
2. Fluids in the micro annulus 103 are.forced into the velocity tubing 102.
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4. High-pressure gas then enters the velocity tubing 102. The high-pressure
gas in
the velocity tubing 102 accelerates the fluids to a velocity that transforms
the
fluids into mist or droplet form.
5. High-pressure gas is supplied for a sufficient period of time toallow the
production of fluids (in the form of mist or droplets) to the surface
wellhead.
6. The supply of high-pressure gas is discontinued.
7. Pressure is relieved from both the micro annulus 103 and the velocity
tubing 102.
8. This completes one cycle. The cycle repeats as necessary.
Figure 2b shows a method of attaching a tool 100 to a length of coiled tubing
by
using what is commonly referred to as a roll on connector landing nipple 1.
Connected to
the roll on connector landing nipple 1 is a plug catcher 3. The plug catcher 3
is
perforated or slotted at the upper end of the tool 100 which allows for the
passage of
liquids to enter or exit the coiled tubing when a plug 2 located in the an
intake has been
pumped off. At the lower end of the plug catcher 3 is an area that is not
slotted or
perforated 4. Once the plug 2 has been pumped off it will be caught and remain
in this
area.
Below the plug catcher 3 is a connector 5 that connects the plug catcher 3 to
ari
open cage 6. The cage 6 is slotted or perforated to allow passage of liquids
into the
production tubing or the coiled tubing. The cage 6 additionally houses the
check valve
ball and seat 7 when liquids enter the cage 6 the ball will float off the seat
but will not
travel any further than the connector 5.
It is common practice to attach a landing nipple 1 at or near the end of
production
tubing. The production tubing may be conventional jointed tubing or coiled
production
tubing. Landing nipples are common and are available from a wide source of
manufactures and distributors of oilfield products. Landing nipples are
designed to stop
tools that are deployed in the production tubing and provide an area for
sealing.
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Referring to Figure 2b is a rriandrel9 that will stop when it locates the
designated
landing nipple 1 and will become sealed in the nipple 1. Seals 8 are attached
to the
mandrel 9 and contact the inside area of the landing nipple 1 to provide a
positive seal.
Once the tool 100 has been set into the landing nipple 1 in the production
tubing
well bore gas and liquids can not enter the coiled tubing as the intake 2 to
the coiled
tubing is plugged. At this point the coiled tubing is hung in the well head by
use of a
coiled tubing hanger. The hanger provides a method to secure the coiled tubing
from
further downward movement and seals the coiled tubing from the production
tubing.
Well head hangers are available from manufactures and suppliers of coiled
tubing
and are common place. Once the hanger is set then the well is considered to be
under
pressure control, at this point the coiled tubing is cut and the well head
assembly
completed. To remove the plug 2 from the intake (Figure 2a) from the end of
the coiled
tubing, pressure is applied to the coiled tubing and forces the plug to become
unseated
from its running position, the plug then rests in the plug catcher at area 4.
Figure 2c represents an alternate method of deploying the device 200 under
live
well conditions also. The connector in this example is known as a dimple
connector 11.
Around the circumference of the dimple connector 11 is a series of threaded
holes 17.
The connector 11 is pushed onto the end of the coiled tubing and a seal is
established
between the connector 11 and the coiled tubing by the use of set screws 19
that are
threaded into the dimple connector 11 and provide sufficient friction to hold
the tool
firmly to the coiled tubing.
Attached below the dimple connector is an open cage 12. The cage 12 is slotted
or perforated to allow the passage of liquids into the production tubing/
coiled tubing and
provides a method to capture the ball and seat valve. With in the open cage is
12 a stop
pin 16 that limits the travel of the ball.
Below the open cage 12 is attached a mandrel 13 that is designed to locate and
seal inside the landing nipple as discussed earlier.
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The pump out plug 14 is forced inside the mandrel 13 and is sealed inside the
mandrel by use of a seals 20. A shear pin or pins 18 may also be used to
ensure that the
plug 14 does not come loose as it is conveyed into the production tubing. The
plug 14 is
of sufficient length to keep the ball from resting on the seat until its seal
20 has passed the
end of the mandrel 13.
The assembly would be affixed to the end of the coiled tubing and stop when
the
designated landing nipple is located. At this point the coiled tubing is set
in and sealed in
the well head by use of a coiled tubing hanger.
Once the coiled tubing has been hung and sealed in the well head hanger the
coiled tubing is cut of at the well head and the well head is assembled. Once
the well
head has been assembled the pump off plug is ejected from its running
position. Ejecting
the plug requires that pressure is applied to the coiled tubing if the tool is
of the type
explained in Figure 1. Sufficient pressure is reached, when sufficient force
over comes
the frictional force that holds the plug in place.
If the tool is a type that is explained in Figure 2c, then pressure is applied
to either
the production tubing or the coiled tubing until the pressure exerts a force
greater than the
frictional force of the frictional fit of the pump out plug.
Both tools described above and illustrated in Figures 2b and 2c can be
retrieved
from the well bore under live well conditions. To retrieve the tool 100
described in
Figure 2b from the well bore under live well conditions would require that a
sealing plug
or dart would be dropped through the coiled tubing.
Once the sealing plug/dart has been dropped it would land in the roll on
connector/landing nipple and become locked in the connector/nipple. Once in
place the
pressure from the coiled tubing would be bled off and the coiled tubing is
retrieved from
the well bore. Such procedure to retrieve coiled tubing fr om the well bore
while the well
bore is under pressure is a routine operation and drop darts are commercially
available
from manufacturers of products of coiled tubing accessories.
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To retrieve the tool described as Figure 2c from the well bore under live well
conditions would require that a sealing plug would be installed at the top of
the coiled
tubing. A tool and method for installing such a plug and it is often referred
to a surface
isolation plug or SIP. The use and procedure for retrieving coiled tubing from
the well
bore under pressure by using a SIP is common place and is routinely used when
the
coiled tubing has no landing nipple at its end or that the landing nipple at
the end of the
coiled tubing is damaged and cannot form a seal between the drop dart and the
landing
nipple. The use of a SIP is commonly referred to as top killing the well.
It is will be apparent to those skilled in the art that the means of
compression and
how it is 'connected to the wellhead be many, and that various surface
auxiliary
equipment such as separators, automation equipment, pressure sensors, etc.,
could be
used in conjunction with the system. It will be appreciated by those skilled
in the art that
other variations of the preferred embodiment may also be practised without
departing
from the scope of the invention.
