Note: Descriptions are shown in the official language in which they were submitted.
CA 02573189 2007-01-05
ARTIFICIAL LIFT SYSTEM
BACKGROUND
[0001] Subterranean wells have been drilled primarily to produce one or more
of
the following desired products for example fluids such as water, hydrocarbon
liquids and hydrocarbon gas. There are other uses for wells but these are by
far the
most common. These desired fluids can exist in the geologic layers to depths
in
excess of 5,000m below the surface and are found in geological traps called
reservoirs where they may accumulate in sufficient quantities to make their
recovery
economically viable. Finding the location of the desirable reservoirs and
drilling the
wells present their own unique challenges. Once drilled, the welibore of the
well
must be configured to transport safely and efficiently the desired fluid from
the
reservoir to surface.
[0002] Whether or not the desired fluid can reach surface without aid is a
function of numerous variables, including: potential energy of the fluid in
the
reservoir, reservoir driver mechanisms, reservoir rock characteristics, near
wellbore
rock characteristics, physical properties of the desired fluid and associated
fluids,
depth of the reservoir, wellbore configuration, operating conditions of the
surface
facilities receiving fluids and the stage of the reservoirs depletion. Many
wells in
the early stages of their producing life are capable of producing fluids with
little
more than a conduit to connect the reservoir with the surface facilities, as
energy
from the reservoir and changing fluid characteristics can lift desired fluids
to
surface.
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[0003] Typically fluids in a liquid phase cause the most problems when
attempting to move the fluids vertically up the wellbore. Fluids in the liquid
phase
are much denser than fluids in a gaseous phase and therefore require greater
energy to lift vertically. These fluids in the liquid phase can enter the
wellbore in the
liquid state as free liquids or they can enter the wellbore in the gas phase
and later
condense into liquid in the wellbore due to changing physical conditions. The
liquids that enter the wellbore may be desirable fluids, such as hydrocarbon
liquids
or useable water, or they may be liquids associated with the desired fluids,
for
example, water produced with oil or gas. Often the liquids associated with the
desired fluids must be produced in order to recover the desired fluid.
Regardless of
the desirability of the liquid, energy is required to transport the liquid
vertically
from the reservoir to surface. Optimizing the energy required through improved
wellbore dynamics or with the aid of artificial lift has been an area of
intense study
and literature for those dealing with subsurface wells.
[0004] To improve the economics of a well, it is desirable to increase the
production rate and maximize the recovery of the desired fluid from the well.
Transportation of fluids from reservoir to surface, that is well bore
dynamics, is one
of the variables of the well that can be controlled and has a major impact on
the
economics of a well. One can improve the well bore dynamics by two methods -
1)
designing a wellbore configuration that optimizes and improves the flow
characteristics of the fluid in the well bore conduit or 2) aiding in lifting
the fluid to
surface with artificial lift. Artificial lift can significantly improve
production early in
the life of many wells and is the only options for wells if they are to
continue
producing in the later stages of depletion. Regardless of whether the well can
lift
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the desired fluids to surface on its own or requires artificial lift, the well
bore
dynamics should be reviewed continually as the variables change over the life
of the
well and the economics for the well need to be maximized.
[0005] The methods of improving flow characteristics include: proper tubing
selection, plunger systems, addition of surface tension reducers, reduced
surface
pressures, downhole chokes and production intermitters. These methods do not
add energy to the fluids in the well bore, and therefore are not considered
artificial
lift systems; however, they do optimize the use of the energy that the
reservoir and
fluids provide. These methods optimize the well bore dynamics and/or add
energy
to the fluid transportation process at the surface. Depending on the
application,
each of the different methods above has numerous models and configurations
each
having their own unique advantages and disadvantages.
[0006] There are numerous systems of artificial lift available and operating
throughout the world. The more common systems are reciprocating rod string and
plunger pumps, rotating rod strings and progressive cavity pumps, electric
submersible multi-stage centrifugal pump, jet pumps, hydraulic pumps and gas
lift
systems. Again, depending on the intended application, each of the different
systems has numerous models each having their own unique advantages and
disadvantages. To fit in the category of artificial lift, additional energy
not from the
producing formation and fluids is input into the well bore to help lift fluids
in the
liquid phase to surface. The artificial lift systems listed above have been
developed
for water and hydrocarbon liquids as they require the greatest assistance when
being transported to surface and provide the greatest economic incentive. They
also
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have applications in lifting liquids that are associated with the gas in
natural gas
wells.
[0007] With the depletion of the world gas reserves there is a need to develop
an
artificial lift system that is better suited to removing liquids associated
with natural
gas production from the wellbore. These liquids, if not removed from the
wellbore,
will significantly limit the natural gas production rates as wells as the
ultimate
recovery of the natural gas reserves.
[0008] Other artificial lift systems have been designed and used based on
injection of high-pressure gas. Gas lift is a common form of artificial lift
and relies
on injection of enough gas to reach the critical rate for removing liquids
from the
wellbore (Turner et al in 1969: Turner, R. G., Hubbard, M. G., and Dukler, A.
E.,
1969, "Analysis and Prediction of Minimum Flow Rate for the Continuous Removal
of Liquids from Gas Wells," J. Pet. Technol., 21(1 1), pp. 1475-1482. )
[0009] US patent no. 5,211,242 by Malcolm W Coleman and J Byron Sandel
outlines the complete removal of fluids from the well on each cycle, which
requires
large gas volume and therefore large associated equipment with pumping, for
example large tubing, a large compressor, large power source valves, etc.
[0010] There is a need for pumps that can be installed and serviced without
the
use of a service rig using wireline or coiled tubing equipment and techniques,
to
allow for easy installation and servicing. There is a need for pumps that fit
with
existing technologies, services and equipment, and may fit with existing
wellbore
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configurations with only minor modifications.
SUMMARY
[0011] In an embodiment there is an artificial lift system, comprising a gas
compressor, a gas pump seated downhole in a well and a power conduit. The
power
conduit extends along the well and provides a fluid connection between the gas
pump and the gas compressor.
[0012] In an embodiment there is an artificial lift system comprising a
downhole
pump, a power conduit connected to the gas pump and a downhole release
mechanism between the power conduit and the downhole pump.
[0013] In an embodiment there is a method of installing a downhole pump in a
well, the method comprising the steps of connecting a downhole pump to coil
tubing and lowering the downhole pump into the well.
[0014] In an embodiment there is a method of removing an artificial lift
system
from a wellbore, comprising the steps of disconnecting a power conduit from a
downhole pump, pulling the power conduit from the wellbore and pulling the
downhole pump from the wellbore.
BRIEF DESCRIPTION OF THE FIGURES
[0015] Embodiments will now be described with reference to the figures, in
which like reference characters denote like elements, by way of example, and
in
which:
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FIG. 1 is a section view of a wellbore showing the producing formation;
FIG. 2 is a section view of an embodiment of downhole components of a
wellbore showing the production formation;
FIG. 3 is a side view showing an embodiment of the installation of a gas
pump in a wellbore;
FIG. 4 is a side view showing an embodiment of the surface components
of a gas pump;
FIG. 5 is a section view of an embodiment of a downhole release
mechanism;
FIG. 6 is a section view of an embodiment of a downhole valve body; and
FIG. 7A, FIG. 7B, FIG. 7C and FIG. 7D are sectional views of the
embodiment of a downhole valve body of FIG. 6 along the lines A, B, C, and D,
respectively.
DETAILED DESCRIPTION
[0016] In the claims, the word "comprising" is used in its inclusive sense and
does not exclude other elements being present. The indefinite article "a"
before a
claim feature does not exclude more than one of the feature being present.
[0017] Figure 1 is an embodiment of a wellbore showing a reservoir 15, a
drilled
hole from surface to the producing formation, a liquid conduit 23, including
casing
and tubing string 9 that safely transport the producing fluids from the
reservoir
to surface. Also included in the drawing is the equipment associated with the
pump:
a downhole pump 12, small diameter continuous tubing string 8, a compressor
unit
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2 and a logic controller 4. The small diameter continuous tubing string 8 is
also
called a power conduit, a power fluid conduit or small diameter continuous
tubing.
[0018] In an embodiment, an artificial lift system uses high pressure dry gas
1 A
as the power fluid to pump liquids from the bottom of gas wells, therefore
allowing
gas to flow unrestricted to surface, for example, the gas may flow to the
surface
unrestricted by liquid build up in the wellbore. In doing so the production
rate of
the gas can be increased and additional reserves recovered.
[0019] Figure 1 shows an embodiment of the device, in which a downhole pump
12 is driven by high pressure gas from the surface. High pressure dry gas 1 A
is
injected down a dedicated small diameter continuous tubing 8 into a pump
pressure chamber 18 at the bottom of the well expelling any liquid present in
the
pump pressure chamber 18 through an exit check valve 19 and out of a liquid
discharge port 24 at the top of the downhole pump 12. After the liquid in the
pump
pressure chamber 18 has been expelled, the pressure in the pump pressure
chamber 18 is bled off. When depressurized, liquid from the bottom of the
wellbore
17 is allowed to enter the pump pressure chamber 18 through the check valve 21
on an inlet screen 22 at the bottom of the downhole pump 12. To achieve
maximum efficiency the pump pressure chamber 18 is allowed sufficient time to
completely fill with liquid and to completely expel that liquid before the
cycle
repeats itself.
[0020] In order to recover the desired fluids from a reservoir 15, casing 10
and
tubing string 9 are run in the well for the safe and efficient transportation
of a
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desired fluid from the reservoir to the surface facilities 7 using acceptable
oilfield
designs. Initially, the reservoir fluids often have sufficient energy in the
form of
pressure to transport the desired fluids and associated fluids from the
reservoir 15
to the bottom of the wellbore 17, and then from the bottom of the wellbore 17
to
the surface facilities 7 without the aid of artificial lift equipment.
However, once a
well has reached a stage of depletion where there is insufficient energy
available to
transport the fluids vertically to surface the economics may justify the
addition of
artificial lift. Artificial lift aids in the vertical transportation of the
fluids in the liquid
phase from the bottom of the wellbore 17 to the surface facilities 7.
Typically the
fluids in the liquid and gas phases are allowed to separate in the bottom of
the
wellbore 17. Due to density differences, since liquids are of much higher
densities,
the fluids in the liquid phase drop to the bottom of the wellbore 17 where
they can
be pumped to surface facilities 7 up the small diameter continuous tubing 8 by
the
artificial lift equipment. The fluids in the gas phase require much less
energy to be
transported vertically up the wellbore when the liquids are not interfering
with this
transportation. The fluids in the gas phase are allowed to flow up a tubing
annulus
29 unrestricted by the fluid in the liquid phase.
[0021] For description purposes an embodiment of a downhole pump in a
wellbore has been broken into three main components: surface equipment, a
wellbore conduit and a downhole pump.
[0022] A compressor unit 2 comprises a gas dryer, a high pressure compressor
coupled with a drive unit, an accumulator (not shown), a logic controller 4, a
surface
fill valve 3 and a surface bleed valve 5. This equipment provides a power
fluid, for
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example a high pressure dry gas 1 A, necessary to operate the downhole pump
12.
The compressor unit 2 takes natural gas from the well or other desired source
1
and removes any contaminants including water. After cleaning the gas it is
compressed to the desired operating pressure for the downhole pump 12 and
stored in the accumulator until required to operate the pump. The operating
pressure is the sum of the hydrostatic pressure of the liquid column between
surface and the downhole pump 12, the pressure of the surface equipment the
liquid is being discharged into, and the desired preset pump activation
pressure
that insures efficient operation of the pump. The accumulator is connected to
the
small diameter continuous tubing 8, through a surface fill valve 3. Downstream
of
the surface fill valve 3 there is a surface bleed valve 5. These valves are
controlled
by the logic controller 4 which open and closes the valves for the different
stages of
the pumping cycle.
[0023] A power fluid conduit 8 comprising small diameter continuous tubing
runs from the compressor unit 2 to the downhole pump 12. The power fluid
conduit
8 delivers the power fluid 1 A from the compressor unit 2 to the downhole pump
12
during the pressurization stage and from the downhole pump 12 to the surface
facilities 7 during the depressurization stage.
[0024] Figure 2 shows an embodiment of the device in which a downhole pump
12 comprises a number of parts required for operation and serviceability of
the
pump. At the top of the downhole pump 12 is a connector head 30 which
connects,
releases and seals the power fluid conduit 8 to the downhole pump 12. Below
the
connector head 30 is a pump seating assembly 31 which comprises: an internal
fish
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neck 78 (Fig. 5) for setting and retrieving the pump, the liquid discharge
port 24, a
NoGo ring 88 (Fig. 5) to hold the pump in position, an external seal pack 90
(Fig. 5)
to isolate the liquid conduit 23 from the bottom of the wellbore 17, a
connection
between the connector head 30 and the pump pressure chamber 18 for the power
fluid and a primary equalizing port 72 (Fig. 5) for pulling of the pump. Below
the
pump seating assembly 31 is a pump pressure chamber connector 32 with the
connection between the pump pressure chamber 18 and the power fluid conduit 8
directly or via the downhole fill valve 100 (Fig. 6) and downhole bleed valve
28 and
the connections from the liquid exit tube 26 to the liquid discharge port 24
on the
pump seating assembly 31. The downhole fill valve 100 (Fig. 6) and downhole
bleed
valve 28 work together and as an assembly is also called a three way valve 28,
100.
Below the pump pressure chamber connector 32 is the pump pressure chamber 18
which acts as a receptacle for liquids on the intake stage and a pressure
chamber
on the discharge stage of the pumping cycle and the liquid exit tube 26 is
inside the
pump pressure chamber 18 connecting an exit check valve 19 on the bottom of
the
liquid exit tube 26 to the liquid discharge port 24 on the pump pressure
chamber
connector 32. On the bottom of the downhole pump 12 is an inlet check valve 21
and an inlet screen 22.
[0025] In an embodiment, a downhole pump 12 is run in a wellbore hole on
small diameter continuous tubing 8 using a conventional wireline unit having a
drawworks or specially built coiled tubing unit. The downhole pump 12 has a
NoGo
ring 88 (Fig. 5) and an external seal pack 90 (Fig. 5) that seat in a profile
13 at the
bottom of the well that is part of the existing tubing string 9. Landing the
downhole
pump 12 in the profile 13 holds the downhole pump 12 in place and also seals
the
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small diameter continuous tubing 8 inside a liquid conduit 23 above the
profile 13
separate from the bottom of the wellbore 17. Once in place, the small diameter
continuous tubing 8 acts as the conduit to deliver high pressure dry gas 1 A
to the
pump pressure chamber 18 and acts as a conduit to bleed off the pump pressure
chamber 18 once liquids have been expelled from the pump pressure chamber 18.
The annular area between the small diameter continuous tubing 8 and the
existing
tubing string 9 act as the liquid conduit 23 to deliver the liquid expelled
from the
liquid discharge port 24 to surface facilities 7. The downhole pump 12 has two
check valves, one at a inlet check valve 21 where liquid from the bottom of
the
wellbore 17 enters the pump pressure chamber 18 and one at an exit check valve
19 where liquids are expelled from the pump pressure chamber 18 into the
liquid
exit tube 26 and then into the liquid conduit 23.
[0026] In an embodiment, there are three stages in a pumping cycle; the first
stage starts with the pump pressure chamber 18 depressurized to a pressure
below
the pressure external to the intake check valve 21.
[0027] In the first stage of the pump cycle time is allowed for fluids
external to
the pump pressure chamber 18, for example at the bottom of the wellbore 17, to
flow into the pump pressure chamber 18 through the inlet check valve 21.
[0028] In the second stage of the pump cycle time is allowed for the
compressor
unit 2 and accumulator to supply high pressure dry gas 1 A at a sufficient
pressure
down the power fluid conduit 8 to the pump pressure chamber 18 to expel the
liquid from the pump pressure chamber 18 through the exit check valve 19 into
the
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liquid exit tube 26 and then out the liquid discharge port 24 into the liquid
conduit
23.
[0029] In the third stage of the pump cycle time is allowed for the
depressurizing of the pump pressure chamber 18 which can be done in multiple
ways. Two exemplary embodiments for methods of depressurizing the pump
pressure chamber are as follows:
[0030] In an embodiment of one method the gas pressure 1 B is bled back to
surface facilities 7 through the power fluid conduit 8 and surface bleed valve
5. This
approach of bleeding off pump pressure chamber 18 and power fluid conduit 8
reduces efficiency and pump capacity but is mechanically simple and therefore
is
often applicable in shallower wells.
[0031] In an embodiment of a second method a pressure activated downhole fill
valve 100 (Fig. 6) and downhole bleed valve 28 are installed. This second
method
allows for a more efficient pump operation by only bleeding off a small amount
of
the gas pressure 1 B from the power fluid conduit 8. When the power fluid
conduit 8
is pressured up above the set point of the three way valve set point the power
fluid
conduit 8 and the pump pressure chamber 18 are in communication and the pump
pressure chamber 18 is isolated from the downhole bleed port 27 allowing pump
pressure chamber 18 to be pressurized. When the power fluid conduit 8 is bled
off
to below the set point of the three way valve 28 & 100 (Fig. 6) the power
fluid
conduit 8 is isolated from the pump pressure chamber 18, at the same time the
pump pressure chamber 18 and the downhole bleed port 27 are in communication
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allowing the pump pressure chamber 18 to be depressurized.
[0032] The third stage is the final stage in the pump cycle. All the stages
may be
controlled by a logic controller 4 using time and/or pressure and are adjusted
based on the application requirements.
[0033] Now installation and removal of an embodiment of an artificial lift
system
will be described.
[0034] In an embodiment, to ensure a cost effective installation and positive
working results one must first review and analyze the working conditions of
the
well. This includes gathering information on the configuration of the
wellbore, such
as casing size, tubing size and depth, type and location of profiles in tubing
string,
type and location of packer that may isolate a tubing annulus, depth of
perforations
and restriction and/or objects that may interfere with the running of the pump
in
the well. Fluid characteristics should also be determined - gas density, water
density and hydrocarbon liquid density along with their expected production
rates.
Pressures and temperatures at the pump intake and surface outlet must also be
determined through measurement or estimated. Once gathered, this information
can be used to calculate the desired configuration of the equipment and
operating
parameters.
[0035] In an embodiment, an artificial lift system is designed to work with
existing wellbore equipment and configurations but if the existing wellbore
configuration is less than optimum for pumping liquids it may need to be
modified.
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As an example, a possible wellbore configuration is as follows: production
depth of
the well not greater than 3000m, clean 60 mm tubing string or larger, one
profile
located at bottom of the perforations or lower, no tailpipe below the profile
or a 6
mm hole 33 in tailpipe immediately below profile, 5 m of clean cased hole
below
bottom of perforations, no packer in hole that would restrict flow up the
tubing
annulus. Such a wellbore configuration is very similar to that of the common
oilwell
rod pump installation; where the liquids are pumped up the tubing string and
the
gas flows up the tubing annulus. However in this design, instead of a rod
string
being run inside the existing tubing string, the rods are replaced by the
small
diameter continuous tubing 8 that delivers high pressure gas 1 A to drive the
pump
which is a pump pressure chamber 18 rather then a plunger style pump. Existing
wellheads may be utilized by installing a production blowout preventer (BOP)
40
(Fig. 3) into the top of the existing flow tee. The production BOP 40 (Fig. 3)
provides
the primary seal around the small diameter continuous tubing 8. Above the
production BOP 40 (Fig. 3) is a device to suspend the small diameter
continuous
tubing 8 in the well and above this device there is a pack-off 45A (Fig. 4) to
provide
a secondary seal around the small diameter continuous tubing 8. The existing
master valves will need to be locked open to prevent damage to the small
diameter
continuous tubing 8. In an emergency the master valves could be shut, cutting
the
small diameter continuous tubing 8 to shut-in the well.
[0036] In an embodiment, once a wellbore has been configured for pumping
conditions and pumping equipment has been selected, the artificial lift system
can
be constructed for the application and surface tested. The downhole pump 12 is
run
in the hole on the small diameter continuous tubing 8 using the drawworks of
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conventional wireline or coiled tubing methods and equipment. A variety of
equipment may be used as a lift unit to run and pull the pump, such as an
electric
line unit, a braided line unit, a slickline unit, a wireline unit and a
logging unit. The
pump can be run down the existing tubing string 9 under pressure conditions or
with the existing tubing string 9 in a killed state. To run in under pressure
one can
use conventional wireline or coiled tubing BOPs, lubricator, grease injector
and
pack-off equipment following wireline or coiled tubing procedures. The
downhole
pump 12 and small diameter continuous tubing 8 are run in the hole to the
depth
where the pump seating assembly 31 is landed in the profile 13. First the
external
seal pack 90 (Fig. 5) on the external diameter of the pump seating assembly 31
are
landed in the sealing section of the desired profile 13 (Fig. 1) and the
production
BOP 40 (Fig. 3) and service BOP 44 (Fig. 3) on top of the wellhead are closed
around
the small diameter continuous tubing 8. Then the liquid conduit 23 may then be
filled with water and the tubing, external seal pack 90 (Fig. 5) and
production BOP
40 and service BOP 44 (Fig. 3) may be pressure tested. After proving the
integrity of
the components the small diameter continuous tubing 8 is hung off at surface
and
the pack-off 45A (Fig 4) is installed. The small diameter continuous tubing 8
is then
detached or cut off and a valve 45B (Fig 4) is installed on the end of the
small
diameter continuous tubing, disconnecting it from the unit which ran it into
the
well. Cutting the small diameter continuous tubing off and installing the
valve 45B,
makes it possible to connect the small diameter continuous tubing 8 to the
compressor unit 2.
[0037] In an embodiment, once the downhole pump 12 and power fluid conduit
8 are installed the power fluid conduit 8 can be connected to a compressor
unit 2.
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Cycle times and pressure settings calculated in the pump configuration program
are
input into the logic controller 4. To start the pump, the power fluid conduit
8 and
the pump pressure chamber 18 are pressurized to the desired operating
pressure.
During the pressurization stage the pressure in the power fluid conduit 8 will
activate the three way valve 28 & 100 (Fig. 6) in the top of the downhole pump
12 at
the set pressure of the three way valve 28 & 100 (Fig. 6), closing the
downhole
bleed port 27 and opening the pump pressure chamber 18 to the power fluid
conduit 8. Once the required operating pressure has been reached in the pump
pressure chamber 18, liquid in the pump pressure chamber 18 is expelled
through
the exit check valve 19 into the liquid exit tube 26, out the downhole pumps
liquid
discharge port 24 and into the liquid conduit 23. No backfiow will be allowed
due to
the exit check valve 19. Once the appropriate time has passed to expel liquid
from
the pump pressure chamber 18, the timer will close the surface fill valve 3
and open
the surface bleed valve 5. At this point the bleed down cycle will begin.
During the
bleed down cycle, gas is bled from the power fluid conduit 8 at surface
through the
surface bleed valve 5 to the flowline. To monitor the pump operation, a
surface
liquid conduit valve 38C should remain closed until the desired increase in
pressure
is observed. A number of pump cycles may be required to see the desired
pressure
response. Depending on the downhole pump 12 configuration, downhole three way
valve installed or no downhole three way valve installed, the timing on the
bleed
down stage of the pump cycle will need to be configured appropriately.
[0038] For the downhole three way valve configuration: the pressure on the
power fluid conduit 8 is reduced, until it is below the pressure set point to
actuate
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the downhole three way valve. The three way valve closes the pressure chamber
depressurization port 1 10 (Fig. 6) which connects with the pump pressure
chamber
18 and opens the downhole bleed port 27 allowing the pump pressure chamber 18
to bleed off to the area external to the pump below the downhole pump sealing
profile 13. Once sufficient time has passed to allow the pump pressure chamber
18
to fully depressurize additional time is allowed for the pump pressure chamber
18
to fill completely with liquid. Once filled completely with liquid the next
pump
pressurization stage begins. To control the rate at which liquid is pumped
from the
well, the times allowed for stage 3 & 2 can be adjusted. The times for these
stages
must remains above the calculated minimum times required to depressurize and
fill
the pump pressure chamber 18.
[0039] For the no downhole three way valve configuration: the pressure on the
power fluid conduit 8 is reduced until it is below the bottomhole flowing
pressure of
the well. Here typical pipeline flowing pressure may be used. Once sufficient
time
has passed to allow the pump pressure chamber 18 to fully depressurize
additional
time is allowed for pump pressure chamber 18 to fill completely with liquid.
Once
filled completely with liquid, the next pump pressurization stage begins. To
control
the rate at which liquid is pump from the well, the times allowed for stage 3
& 2 can
be adjusted. The times for these stages must remains above the calculated
minimum times required to depressurize and fill the pump pressure chamber 18
with liquid.
[0040] To pull the artificial lift system one must release or cut the power
fluid
conduit 8 immediately above the internal fish neck 78 (Fig. 5) and pull the
small
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diameter continuous tubing 8 out of the well. The small diameter continuous
tubing
8 is not normally strong enough to pull the downhole pump 12 out of the well.
Prior
to pulling the downhole pump 12 the pressure above the downhole pump 12 must
be equalized with the pressure below the downhole pump 12. This is done by
removing some of the liquid from the liquid conduit 23. This can occur
automatically if the primary equalization port 72 is not plugged, allowing
liquids
above pump to drain back into the bottom of the wellbore 17 once the
connecting
head is released 62. If it is undesirable to allow liquids to drain back into
the
bottom of the wellbore 17 the primary equalization port 72 may be plugged and
the
use of conventional swab equipment and techniques to remove the liquid from
the
liquid conduit may be employed. Swabbing the tubing minimizes the fluid that
drains back into formation once the equalizing plug of the downhole pump has
been broken off. As a backup if primary equalization port 72 becomes plugged
or
swabbing is unable to be performed the liquid may be drained through the
backup
equalizing port 74 by running in the hole with slickline tools, break off the
equalizing plug inside the internal fish neck 78 (Fig. 5) on the downhole pump
12
allowing the liquids above the downhole pump to drain back into the well below
the
sealing profile at the bottom of the wellbore 17. After equalizing the
pressure above
and below the downhole pump 12, run in with wireline equipment with sufficient
line size and tool configuration to unseat the gas pump and pull the gas pump
to
surface and latch on to the internal fish neck 78 (Fig. 5) and pull downhole
pump 12
to surface.
[0041] Once the downhole pump 12 has been pulled from well, the downhole
pump 12 can be repaired and reinstalled or other activities conducted on well
as
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desired using normal oilfield procedures.
[0042] In an embodiment shown in Figure 3, an artificial lift system makes use
of conventional electric line and slickline methods and equipment, making
installing
and removal of the artificial lift system effective, quick and safe. A
conventional
electric line or slickline unit 34 is placed approximately 50 ft from an
existing
wellhead 38 and a crane unit 36 is placed next to the wellhead 38. Other
orientations of the slickline unit 34 and crane unit 36 will also work. Other
suitable
equipment for running and pulling an artificial lift system may alternatively
be used.
The conventional slickline unit 34 installs small diameter coiled tubing 8 on
cable or
wire draw workings. The small diameter coiled tubing 8 replaces the
conventional
cable or wire. In an embodiment the wellhead 38 comprises a top master valve
38A,
a flow tee 38B and a wing valve 38C.
[0043] To install, sections of lubricator 46 are laid out on ground stands and
which when connected together are of sufficient length to enclose a complete
artificial lift system 60 assembly. In the embodiment shown in Figure 3, the
artificial
lift system 60 is hanging in the lubricator sections 46 prior to running in
hole. In an
embodiment, the sections of lubricator 46 are used to contain pressure while
running and pulling the artificial lift system 60 from the well. The sections
of
lubricator 46 could be, for example, a lubricator section of Bowen type such
as PN
14339. A service BOP 44 is connected to the bottom of the lubricator sections.
The
service BOP 44 is installed for running and pulling the artificial lift system
60. The
service BOP 44 could be, for example, a service BOP of Bowen type such as PN
57678. The bottom of the artificial lift system 60 is inserted into the top of
the
19
CA 02573189 2007-01-05
lubricator sections 46.
[0044] Some of the power conduit 8 is spooled out from the slickline unit 34
and the power conduit is threaded through a top block assembly 50 combined
with
a pack-off 48. A make up connection is used between the power conduit 8 and
the
downhole release mechanism 76, an embodiment of which is shown in Figure 5.
[0045] Next, the top block assembly 50 combined with pack-off 48 is installed
to the top of lubricator sections 46. The top block assembly 50 redirects the
path of
the small diameter coiled tubing 8 and supports the weight of the small
diameter
coiled tubing 8 as well as the weight of an artificial lift system assembly,
comprising
the artificial lift system 60, attached to the end of the small diameter
coiled tubing
8. The top block assembly 50 could be, for example, a top block of Bowen type,
such as PN 44677. The downhole release mechanism 76 is connected to the
artificial lift system assembly that was inserted in the top of the lubricator
sections
46. After the downhole release mechanism 76 is connected to the artificial
lift
system assembly, the artificial lift system 60 is pushed completely into the
lubricator sections 46 and the top block assembly 50 is connected to the top
of the
lubricator sections 46. A cap (not shown) is inserted on the bottom of the
service
BOP 44 to ensure the artificial lift system assembly does not fall out the
bottom
when it is raised.
[0046] Next, the wellhead is prepared for being connected to the lubricator
sections 46. A pressure reading is taken. The top master valve 38A and the
wing
valve 38C are both closed. The pressure trapped between these two valves is
bled
CA 02573189 2007-01-05
to 0 psig using the flow tee 38B bleed valve. The cap (not shown) is removed
from
the flow tee 38B and a production BOP 40 is installed into the internal
connection of
the flow tee 38B. In an embodiment, the production BOP 40 comprises a modified
sucker rod BOP with rams modified to seal on the small diameter coiled tubing
8.
An adaptor nipple 42 is installed into the top of the production BOP 40. The
adapter
nipple 42 connects the production BOP 40 to the service BOP 44.
[0047] Next the lubricator sections 46 is prepared for being connected to the
wellhead. A top block support cable 56 is installed between the top block
assembly
50 and a crane hoisting cable hook 92. A pack-off 48 with the power conduit 8
threaded through is attached to the lubricator sections 46. The top block
support
cable 56 supports the weight of and stabilizes the movement of the power
conduit
8, the artificial lift system 60, the top block assembly 50, the pack-off 48
and the
lubricator section 46. The top of lubricator section 46 is lifted until
lubricator
sections 46 are hanging vertical. The power conduit 8 may need to be spooled
out
at the same time so that it does not get damaged as the lubricator sections 46
are
lifted. A bottom block 52 and a tie down cable 54 are installed. The power
conduit 8
is threaded through the bottom block 52. The bottom of the lubricator sections
46
is positioned directly over the wellhead. The bottom block 52 redirects the
path of
the small diameter coiled tubing 8 and supports the weight of the small
diameter
coiled tubing 8 as well as the weight of the pump assembly attached to the end
of
the small diameter coiled tubing 8. The bottom block 52 assembly could be, for
example, a bottom block of Bowen type, such as PN 14414. The lubricator
sections
46 when assembled together comprise a lubricator assembly.
21
CA 02573189 2007-01-05
[0048] The power conduit 8 is spooled so that slack in the power conduit 8 is
removed and the artificial lift system is no longer resting on the cap (not
shown) on
the bottom of the service BOP 44. The cap (not shown) is removed from bottom
of
service BOP 44. In an embodiment, the artificial lift system 60 is lowered out
the
bottom of the lubricator assembly 46 to a measurement datum and a depth
counter
is adjusted appropriately. The artificial lift system 60 is raised into the
lubricator
assembly 46 and lubricator assembly 46 is lowered onto the top of the wellhead
and the connection is made. The lubricator assembly 46 is then pressure tested
to
the appropriate pressure.
[0049] At this point, the artificial lift system 60 is ready to run in the
hole. The
top master valve 38A is opened. The artificial lift system 60 is run down to a
desired
depth. The artificial lift system landing assembly is landed in a desired
profile 13
(Fig. 1) in the well. Thus, the artificial lift system 60 and the power
conduit 8 are
now in place. A pressure test can be carried out to ensure that no leaks are
present
in the power conduit 8 or the liquid conduit 23 (Fig. 1).
[0050] In an embodiment, handles on the top master valve 38A and bottom
master valves are locked and warning signs are installed to warn against the
operation of the valves. The production BOP 40 is closed and the pressure is
bled
from the lubricator assembly 46 to 0 psig.
[0051] The adaptor nipple 42 is disconnected from the bottom of the lubricator
assembly and the lubricator assembly 46 is raised. Approximately 200 feet of
power
conduit 8 is pulled down through the lubricator assembly 46 and the power
conduit
22
CA 02573189 2007-01-05
8 is cut off at the bottom of lubricator assembly 46. Other lengths of power
conduit
8 may be pulled down through the lubricator assembly 46.
[0052] In an embodiment of the installation shown in Figure 4, a production
BOP
40 is connected to the top of the wellhead which comprises a top master valve
38A,
a flow tee 38B and a wing valve 38C. A production pack-off 45A is connected to
the
top of the production BOP 40. A length of surplus power conduit 45C, for
example,
approximately 200 feet long, is coiled and a valve 45B lies on the end of the
surplus
power conduit 45B.
[0053] The surplus power conduit 45C must remain attached and will be
required for the pulling operation. The adaptor nipple 42 (Fig. 3) is removed
from
the production BOP 40 and a production pack-off 45A is installed on top of the
production BOP 40. The 200 feet of surplus power conduit 45C protruding from
top
of the production pack-off 45A is coiled and a valve 45B is installed on the
end of
the surplus power conduit 45C.
[0054] After installation of the artificial lift system, the slickline unit 34
(Fig. 3),
the crane unit 36 (Fig. 3) and associated equipment are rigged out. Surface
equipment associated with the artificial lift system 60 (Fig. 3) is installed
and pump
operation is started.
[0055] An embodiment of a downhole release sub 62 is shown in Figure 5. The
downhole release sub 62 comprises a downhole release mechanism 76 and a
downhole pump connector 86 being releasably attached to the downhole release
23
CA 02573189 2007-01-05
mechanism 76. The downhole release mechanism 76 is an embodiment of the
connector head 30 shown in Fig. 1. The downhole pump connector 86 is an
embodiment of the pump seating assembly 31 shown in Fig. 1. A power conduit 8
is attached at one end to the downhole release mechanism 76. A power fluid
extension prong 68 is attached to the base of the downhole release mechanism
76.
A connection fitting 64 attaches the power conduit 8 to the downhole release
mechanism 76. The downhole pump connector 86 is releasably attached to the
downhole release mechanism 76 by breakable fastenings, such as release shear
pins 66. A chamber 96 lies between the downhole release mechanism 76 and the
downhole pump connector 86. The chamber 96 is pressure sealed with pressure
seals 70 which lie below the release shear pins 66. A pressure release
mechanism,
such as release equalizing stem 94, lies between the downhole pump connector
86
and the downhole release mechanism 76 and provides a fluid connection between
the exterior of the downhole release mechanism 76 and the chamber 96.
[0056] An external fish neck lies at the top of the downhole release mechanism
76 where the power conduit 8 connects to the downhole release mechanism 76. A
fish neck, for example internal fish neck 78, is attached to the top of the
downhole
pump connector 86. Below the chamber 96 is a liquid discharge port 24 at the
end
of liquid exit tube 26. Below the liquid discharge port 24 is a NoGo ring 88.
At some
point below the NoGo ring 88 is an external seal pack 90. A primary equalizing
port
72 lies on the exterior of the downhole pump connector 86. Pressure seals 71
seal
the power fluid extension prong 68 from the primary equalizing port. A backup
equalizing port 74, as shown in Figure 5, may also be present if additional
equalizing ports are necessary. A connection interface, such as threading 84,
lies on
24
CA 02573189 2007-01-05
the base of the downhole pump connector 86.
[0057] The downhole release mechanism 76 is designed to release the power
conduit 8 from the downhole pump after an application of external pressure on
both the power conduit 8 and the downhole release mechanism 76 that is
sufficient
to break breakable fastenings, such as release shear pins 66. Pressure is
applied to
the area exterior to the power conduit 8 defined by the liquid conduit 23. The
release shear pins 66 are to be sized so as not to release under normal
operating
condition yet shear below safe operating limits of the liquid conduit 23 (Fig.
1) and
the wellhead. The pressure seals 70 maintain fluid pressure between the
chamber
96 and a liquid conduit (Fig. 1) exterior to the downhole release mechanism
76.
Power fluid is pumped down the power conduit 8 through the power fluid
extension
plug 68 into the pump pressure chamber 18 (Fig. 1) below the downhole release
mechanism 76. Production fluid that is returning to surface from the pump
pressure
chamber 18 (Fig. 1) passes through the liquid exit tube 26 and through the
liquid
discharge port 24 into the liquid conduit 23 (Fig. 1). The pump pressure
chamber
18 (Fig. 1) may be connected, for example by threads 84, to the base of the
downhole pump connector 86. In an embodiment the downhole pump connector 86
may sit on the profile NoGo ring 88 in a seat in the profile 13 (Fig. 1) of
the
wellbore.
[0058] Once sheared, the downhole release mechanism 76 can be pulled apart
from the internal fish neck 78 on the artificial lift system which in turn
opens a
primary equalizing port 72 connecting the liquid conduit 23 (Fig. 1) and the
bottom
of the wellbore 17 (Fig. 1). Pressure seals 71 maintain fluid pressure around
the
CA 02573189 2007-01-05
primary equalizing port 72. In an embodiment, the backup equalizing port 74
may
also be used to equalize the pressure between the liquid conduit 23 (Fig. 1)
and the
bottom of the wellbore 17 (Fig. 1). When the power fluid extension prong 68 is
removed from the wellbore the primary equalizing port 72 supplies a direct
connection between the bottom of the wellbore 17 (Fig. 1) and the chamber 96.
After the removal of the downhole release mechanism 76, the chamber 96 lies
within the liquid conduit 23 (Fig. 1). Alternatively, the primary equalizing
port 72
may be plugged if draining of fluid back into the bottom of wellbore 17 (Fig.
1) is
undesirable. The release equalizing stem 94 equalizes the pressure in a
chamber 96
lying between the downhole release mechanism 76 and the internal fish neck 78
with the pressure lying exterior to the chamber 96. Other methods of releasing
the
residual pressure in the artificial lift system and the downhole release
mechanism
76 may also be used provided that pressures in the wellbore are sufficiently
equalized to allow the downhole release mechanism 76 to be pulled from the
wellbore. The power conduit 8 and the downhole release mechanism 76 can be
pulled from the wellbore once released. The external seal pack 90 sits below
the
NoGo ring 88 and the wellbore profile 13 (Fig. 1).
[0059] An embodiment of a downhole valve body 98 is shown in Figure 6. A
downhole valve body 98 is designed to provide power fluid to the pump chamber
by
a pressure actuated gas lift valve 100. The downhole valve body 98 is an
embodiment of the pump pressure chamber connector 32 shown in Fig. 2. In use,
the downhole valve body 98 is attached by an external thread connection 1 16
to a
downhole pump 1 2 (Fig. 1 ) and attached by threading 1 18 to the downhole
pump
connector 86 (Fig. 5). The downhole pump comprises a pump pressure chamber 18
26
CA 02573189 2007-01-05
(Fig. 1) and could be, for example, the downhole pump shown in the embodiment
of Figure 2. Power fluid is supplied to the pump pressure chamber 18 (Fig. 1)
when
sufficient pressure to open a gas lift valve 100 is applied. The gas lift
valve 100 is
pressure activated to facilitate supplying power fluid to the pump pressure
chamber. From the gas lift valve 100 the pressure fluid flows through a fluid
conduit 120 into a pressure regulating check valve 104 and through a power
fluid
outlet 106 to the pump pressure chamber 18 (Fig. 1). Between the gas lift
valve 100
and the pressure regulating check valve 104 is a passage to the actuator of
the
pump chamber pressure release valve 28 from the fluid conduit 120. The power
fluid being supplied to the pump pressure chamber 18 (Fig. 1) closes the pump
chamber release valve and therefore the connection between the pump pressure
chamber 18 and the downhole bleed port 27. Once the pump pressure chamber 18
(Fig. 1) is pressurized to full operating pressure the liquid in the pump
pressure
chamber 18 (Fig. 1) is expelled into a liquid inlet 108 through a liquid
conduit 122
and out a valve body liquid port 102. The liquid inlet 108 includes a liquid
exit tube
26 and an exit check valve 19 (Fig. 1). On a separate port adjacent to the
liquid inlet
108 and the power fluid regulating check valve connection 104 is a pump
chamber
pressure depressurization port 110. Once this part of the cycle is complete
the
pressure that activates the gas lift valve 100 is reduced and the gas lift
valve 100
closes. With the gas lift valve 100 closed the pump chamber pressure release
valve
28 opens to make a connection between the pump pressure chamber 18 (Fig. 1)
and the downhole bleed port 27 allowing the pressure in the pump pressure
chamber to be bled off. The pump pressure chamber 18 (Fig. 1) is attached by
external thread connection 116 to the downhole valve body 98. After bleeding,
liquid from the well bore can enter the pump pressure chamber 18 (Fig. 1) for
the
27
CA 02573189 2007-01-05
next pumping cycle.
[0060] Figures 7A, 7B, 7C and 7D show cross section views of the embodiment
of Figure 6 along the lines A, B, C and D, respectively. Figure 7A shows a
joint in the
fluid conduit 120 that allows the fluid conduit 120 below the joint to lie
more to the
radial exterior of the downhole valve body below the line A than the fluid
conduit
does above the line A. In other embodiments such a joint may not be necessary.
[0061] Figure 7B shows a cross section of the embodiment of Figure 6 along the
line B. The cross section indicates a horizontal connecting passage 128 to be
used
in an embodiment where liquid conduit 122 could not be drilled straight
through
the downhole valve body 98 (Fig. 6). A threaded plug 124 separates the liquid
conduit 122 from the exterior of the downhole valve body 98 (Fig. 6). In other
embodiments horizontal connecting passage 128 may not be necessary.
[0062] Figure 7C shows a cross section of the embodiment of Figure 6 along the
line C. The cross section indicates a horizontal connecting passage 130 to be
used
in an embodiment where fluid conduit 120 could not be drilled straight through
the
downhole valve body 98 (Fig. 6). A threaded plug 126 separates the fluid
conduit
120 from the exterior of the downhole valve body (Fig. 6). In other
embodiments
horizontal connecting passage 130 may not be necessary.
[0063] Figure 7D shows a cross section of the embodiment of Figure 6 along the
line D. The cross section shows the pump chamber downhole bleed valve 28, the
fluid conduit 120 and then liquid conduit 122.
28
CA 02573189 2007-01-05
[0064] In an embodiment, once it has been determine that the artificial lift
system 60 needs to be pulled, a pressure unit (not shown) is brought in to
shear the
downhole release mechanism 76 of the artificial lift system. The wing valve
38C is
closed, the pressure unit is connected to the liquid conduit 23 via the wing
valve
38C and the connections are pressure tested.
[0065] The pressure from the power conduit 8 is bled to 0 psig. The wing valve
38C is opened and the liquid conduit 23 is pressured up to the desired
pressure to
shear the breakable fastenings 66 of the downhole release mechanism 76. The
power conduit 8 is pressured up to ensure release has been effective. Then the
wing
valve 38C is closed and the pressure unit is rigged out.
[0066] In an embodiment, if the pressure unit fails to break the breakable
fastenings of the downhole release mechanism 76 the external fish neck 80 may
be
latched on to using wireline tools and the release mechanism sheared and
pulled
from the wellbore. Prior to the wireline tools latching on to the external
fish neck 80
the power fluid conduit 8 must first be cut immediately above the external
fish neck
80 and pulled from the wellbore. Wireline can be attached to the downhole
release
mechanism 76 at the external fish neck 80, and hammer tools can break the
breakable fastenings of the downhole release mechanism 76. Then the downhole
release mechanism 76 may be pulled from the well.
[0067] In an embodiment, the artificial lift system 60 may be left for a
period of
time, for example 24 hours, to allow the liquid in the liquid conduit 23 to
drain
29
CA 02573189 2007-01-05
back into the bottom of the wellbore 17 equalizing pressure above and below
the
artificial lift system 60. However, there is also the potential to swab liquid
from the
well in the case that draining fluid back is determined to be an undesirable
activity.
Other methods of equalizing pressure above and below the artificial lift
system 60
may also be used.
[0068] Gas well pump removal equipment, such as a slickline unit 34 and a
crane unit 36 are rigged in to pull the power conduit 8 and the artificial
lift system
60 from the wellbore. In an embodiment the slickline unit 34 may rigged in
approximately 50 ft from wellhead 38 and crane unit 36 next to wellhead. Other
placements of the slickline unit 34 and crane unit 36 are possible.
[0069] Sections of lubricator 46 are laid out on ground stands. The sections
of
lubricator 46 are connected together with sufficient length to enclose the
complete
artificial lift system assembly. The service BOP 44 is installed to bottom of
the
lubricator sections 46.
[0070] Pressure is bled off the power conduit 8, the surplus power conduit 8
is
uncoiled and the valve (not shown) connected to the surface end of power
conduit 8
is removed. The production pack-off is removed from the top of production BOP
40
and the adaptor nipple 42 is installed in the top of the production BOP 40.
[0071] The end of the surplus power conduit 8 is thread through the bottom of
service BOP 44 to the top of the lubricator sections 46. The end of the
surplus
power conduit 8 is thread through the lubricator pack-off 48 combined with the
top
CA 02573189 2007-01-05
block assembly 50. The pack-off/top bock assembly 50 is connected to the top
of
the lubricator sections 46. The top block support cable 56 is installed
between the
top block assembly 50 and the crane hoisting cable hook 92.
[0072] The top of the lubricator assembly 46 is lifted until the lubricator
assembly 46 is hanging vertically above the well head. The surplus power
conduit is
pulled through the lubricator assembly 46 so that the surplus power conduit
can be
connected to the slickline unit 34. The bottom block 52 and the tie down cable
54
are installed. The power conduit 8 is threaded through the bottom block 52.
[0073] The end of the power conduit 8 is connected to the slickline unit 34.
The
slack from the power conduit 8 is pulled onto the slickline unit's draw works
and
the lubricator assembly 46 is lowered onto the wellhead connection and the
connection is made. The lubricator assembly 46 is pressure tested to
appropriate
pressure.
[0074] The production BOP 40 is opened and the power conduit and the
downhole release mechanism 76 are pulled from well.
[0075] Once the power conduit and the downhole release mechanism 76 are
pulled from the well, the top master valve 38A is closed and the lubricator
assembly
46 is laid down. The equipment is then reconfigured to run in a conventional
slickline configuration which replaces the power conduit 8 with conventional
slickline (not shown) and pulling string (not shown). In an embodiment the
pulling
string (not shown) comprises a rope socket, sinker bars, mechanical jars,
hydraulic
31
CA 02573189 2007-01-05
jars and a pulling tool.
[0076] Then, the equipment is rigged in and run in hole. While running in the
hole, the liquid level should be determined to ensure the pressure above and
below
the artificial lift system 60 have equalized. A secondary equalizing
mechanism, such
as the backup equalizing port 74, may be activated at this time, if necessary.
A
pulling tool (not shown) is latched onto the internal fish neck 78 and the
artificial
lift system 60 is pulled from the hole.
[0077] The artificial lift system 60 is pulled into the lubricator assembly
46. The
top master valve 38A is closed. The pressure in the lubricator assembly 46 is
bled
to 0 psig. The service BOP 44 is disconnected from the adaptor nipple 42 and a
cap
is installed on the bottom of the service BOP 44. The lubricator assembly 46
is laid
down with artificial lift system 60 inside. The adaptor nipple 42 and
production BOP
40 are removed from the top of the wellhead. The original wellhead cap (not
shown)
is re-installed.
[0078] The artificial lift system 60 is removed by pulling out the bottom of
the
lubricator assembly 46 and the artificial lift system 60 is disconnected from
the
pulling tool.
[0079] After the artificial lift system 60 is successfully removed, the
slickline
equipment, slickline unit 34 and crane unit 36 may be rigged out.
[0080] In an embodiment the artificial lift system may be developed to be
32
CA 02573189 2007-01-05
operable with existing technology, services and components. In an embodiment
artificial lift system may be designed to fit within existing wellbore
configurations
with only minor modification. In an embodiment the artificial lift system may
be
designed to not gas lock. In an embodiment the artificial lift system may
allow for
easy installation and servicing. In an embodiment the artificial lift sytem
may be
designed to reduce energy consumption. In an embodiment the artificial lift
system
may be designed for simplicity and trouble free operation. In an embodiment
the
artificial lift system may be designed as a cost effective pumping
alternative.
[00811 Immaterial modifications may be made to the embodiments described
here without departing from what is covered by the claims.
33
