Note: Descriptions are shown in the official language in which they were submitted.
A8140817CA
APPARATUS AND METHOD FOR TESTING AN OIL AND/OR GAS WELL
WITH A MULTIPLE-STAGE COMPLETION
TECHNICAL FIELD
[0001] This disclosure generally relates to production of
hydrocarbons. In
particular, the disclosure relates to an apparatus and method for testing an
oil and/or gas
well that has been completed with single stages or multiple stages.
BACKGROUND
[0002] With advances in drilling technology it has become
increasingly common
to drill oil and/or gas wells that have sections that are deviated from a
vertical orientation.
In some wells one or more sections may be at least partially horizontal. A
well with such
a horizontal section may also be referred to as non-vertical well, a lateral
well, a deviated
well or a horizontal well. As a method to increase production from these
horizontal wells
the wellbores are first cased. The casing may then be perforated or otherwise
opened in
intervals at specific locations.
[0003] Various approaches are used for creating an opening or perforation
in the
casing. Such approaches include, but are not limited to: explosive
perforating, use of
screens and sliding sleeves, burst discs, and abrasive jetting each of which
can provide
fluid communication between the inside and outside of the casing.
100041 Next a portion or all of the horizontal wells can be subjected
to a
fracturing operation. The fracturing operation generates cracks within a
geologic
formation surrounding the horizontal well. The cracks provide a fluid pathway
for
facilitating fluid communication between the wellbore and an oil and/or gas
containing
reservoir within the geologic formation. Different fracturing methods are used
to
generate the cracks including, but not limited to pumping a high-pressure
fracturing
mixture of fluid and proppant into each stage of well and the local geological
formation
individually. Fracturing surface-pressures and flow rates are monitored to
determine the
breakdown pressures and effectiveness of the fracturing operation. However,
things can
go wrong while pumping the fracturing mixture. For example, sand within the
fracturing
mixture can plug off flow through one or more cracks; pumps can malfunction;
and
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characterization of the reservoir resistance can be inaccurate. These and
other known
issues can result in a less-than-ideal fracturing operation.
[0005] It also common that different portions of the same geologic
formation will
respond differently to the fracturing operation. This can result in different
production
rates between the stages of the horizontal well. The cracks tend to follow the
path of
least resistance in the geologic formation, which results in complex flow
paths for the
fluids to flow from the reservoir to the wellbore. The width of the fracture,
the tortuosity
of the fluid path and the amount of proppant in the fracture can all affect
the production
rate of fluids through a given crack.
[0006] Furthermore, one or more stages of the well may end up producing
water
from the geologic formation. For example, one stage may intersect with a water
layer
and produce more water than other stages of the horizontal well. Water has
lifting and
separating costs that impact the economics of the well's production. There are
known
methods that attempt to improve the well's economics by reducing the quantity
of
produced water using plugging gel fluids or mechanical shut-off devices. These
methods
require, however, that the well operator knows which stages of the well are
producing
the problematic water.
[0007] It has been estimated that only 25% of the fractured stages
in a horizontal
well provide significant oil and/or gas production. Very few direct
measurements of each
individual stage have been done because there are limited efficient manners to
measure
the characteristics of the fractured sections portions of the geologic
formation or the
nature of the fluids that are produced therefrom. Most measurements, such as a
draw-
down test, are performed on a well as a whole collective-unit by measuring a
pressure
response from the well based on rate changes provided at surface.
SUMMARY
[0008] Embodiments of the present disclosure relate to a testing
tool that includes
an uphole end and a downhole end, the uphole end is operatively connectible to
a coiled
tubing string; a downhole pump; an upper packer-assembly and a lower packer-
assembly; a sensor assembly comprising one or more sensors, the sensor
assembly ill
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fluid communication between the packer assemblies and the downhole pump; and a
flow-
through conduit for conducting fluids between the uphole end and the downhole
end.
[0009] In some embodiments of the present disclosure the testing
port may be in
fluid communication with the downhole pump independent of the configuration of
the
testing tool.
1000101 Some embodiments of the present disclosure may be used to
evaluate
fracturing effectiveness, estimate the stimulated reservoir volume (SRV), a
reservoir
ultimate recovery or other reservoir properties that can be measured by
pressure or rate
transient analysis techniques known to those skilled in the art.
[00011] Some embodiments of the present disclosure may also be used to test
individual stages of a horizontal section of a well for produced water, other
unwanted
fluids and to evaluate the effectiveness of water, steam, polymer or gas
flooding
procedures for enhanced oil-recovery processes.
[00012] Some embodiments of the present disclosure relate to testing
tools that
provide a fluid flow-through conduit through which fluids can pass from one
end of the
testing tool to the other. The implication of which is that testing tools of
the present
disclosure will not block fluid communication between a source of fluid and
any
hydraulically-actuated tools that are positioned within the well and downhole
of the
testing tool. Furthermore, the fluid conduit can be used to clear debris
within and below
the testing tool.
[00013] Some embodiments of the present disclosure relate to testing
tools that
can be connected directly to one end of a coiled tubing string. This
connection allows
fluids to be introduced into the testing tool from surface through the coiled
tubing string.
This connection also allows the testing tool to be physically moved within a
well by
moving the coiled tubing.
[00014] Some embodiments of the present disclosure also relate to
testing tools
that can be powered by a single conductor-cable. Without being bound by any
particular
theory, the single conductor-cable may make the setup, running in-and-out of
the well
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and operation of the testing tool simpler and more cost efficient than known
testing tools
that are powered by multiple conductor-cables. In other embodiments of the
present
disclosure the testing tools can be powered by multiple conductors that are
run into the
well with the coiled tubing string.
[00015] Some embodiments of the present disclosure relate to testing tools
that
employ an electrically-powered, mechanically-driven downhole pump. Without
being
bound by any particular theory, a mechanically-driven downhole pump may
provide
precise control over the volume of test fluids that are drawn into the sensor
assembly for
testing. Precise control over the volume of test fluids that are being tested
may provide
more accurate information regarding the properties of the test fluids, the
extent and
quality of the fracturing operation and the geological formation from which
the test fluids
are produced.
[00016] Some embodiments of the present disclosure relate to testing
tools that
can be used to test the breakdown strength of rock or other geological
formations, which
may be informative for assessing cap rock integrity in oil sand steam flood
projects. In
these embodiments, the pumping direction of the downhole pump can be reversed
from
when the testing tool is used to test the produced fluids, fracturing
operation extent and
quality and the geological formation.
[00017] Some embodiments of the present disclosure relate to a method
for testing
a multistage well-completion. The method comprises some or all of the
following steps:
connecting a testing tool to one end of coiled tubing; running the coiled
tubing and the
testing tool into a well; positioning the testing tool substantially adjacent
a desired
perforated section of the well; setting a first packer element of the testing
tool on one
side of the desired perforated section of the well and a second packer element
of the
testing tool on an opposite side of the desired perforated section;
establishing fluid
communication between a sensor assembly of the testing tool and the desired
perforated
section; pumping fluid through a downhole pump of the testing tool at a first
output
parameter; capturing fluid-property data and/or pressure data from the test
fluids as they
are drawn towards the downhole pump; and unsetting the packer elements.
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BRIEF DESCRIPTION OF THE DRAWINGS
[00018] These and other features of the present disclosure will
become more
apparent in the following detailed description in which reference is made to
the appended
drawings.
[00019] FIG. 1 is a schematic diagram of one embodiment of a testing
tool
according to the present disclosure, the testing tool is positioned within a
horizontal oil
and/or gas well and it is fluidly and mechanically connected to topside
surface
equipment;
[00020] FIG. 2 is a longitudinal, mid-line cross-sectional view of
the testing tool
of FIG. 1, wherein FIG. 2A shows the testing tool in a first configuration and
FIG. 2B
shows the testing tool in a second configuration;
[00021] FIG. 3 is a longitudinal, mid-line cross-sectional view of
the testing tool
of FIG. 1 with a closer view towards a downhole end of the testing tool,
wherein FIG.
3A shows the testing tool in the first configuration and FIG. 3B shows the
testing tool in
the second configuration;
1000221 FIG. 4 is a longitudinal, mid-line cross-sectional view of the
testing tool
of FIG. 1 with a closer view of a fluid control valve towards an uphole end of
the testing
tool that shows the flow of fluids therethrough;
[00023] FIG. 5 is a longitudinal, mid-line cross-sectional view of
the testing tool
of FIG. 1 disconnected from the topside surface equipment;
[00024] FIG. 6 is a longitudinal, mid-line cross-sectional view of another
embodiment of a testing tool according to the present disclosure;
[00025] FIG. 7 is a longitudinal, mid-line cross-sectional view that
shows the flow
of fluids through a portion of the testing tool shown in FIG. 6;
[00026] FIG. 8 is a longitudinal, mid-line cross-sectional view of an
electric
release for use with the testing tools of the present disclosure; and
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1000271 FIG. 9 is a schematic diagram of a method for using the
testing tools of
the present disclosure, wherein FIG. 9A is a first method and FIG. 9B shows
some further
optional steps of the method shown in FIG. 9A.
DETAILED DESCRIPTION
[00028] The present disclosure relates to an apparatus and method of
testing an oil
and/or gas well that has been completed with one or multiple stages.
Definitions:
[00029] Unless defined otherwise, all technical and scientific terms
used herein
have the same meaning as commonly understood by one of ordinary skill in the
art to
which this disclosure belongs.
[00030] As used herein, the term "about" refers to an approximately
+/-10%
variation from a given value. It is to be understood that such a variation is
always
included in any given value provided herein, whether or not it is specifically
referred to.
[00031] Embodiments of the present disclosure will now be described
by reference
to FIG. 1 through FIG. 8, which show representations of testing tools and
testing methods
according to the present disclosure.
1000321 Some embodiments of the present disclosure relate to an
apparatus,
referred to herein as a testing tool 100 that can be positioned within an oil
and/or gas well
204 that has at least one horizontal section 206. The horizontal section 206
can be
partially, substantially or entirely horizontal. The well 204 defines an
uphole end 206A
and a downhole end 206B (as shown in FIG. 1). The well 204 extends from the
surface
200 into a geologic formation 250 below. Oil and/or gas are contained within a
reservoir
252 of the geologic formation 250. The horizontal section 206 may be
substantially
parallel to the surface 200, or not. The horizontal section 206 may be open
hole or lined
with liner, casing or other type of well pipe that is known in the art, all of
which are
referred to herein as liner 208. The remainder of the well 204 may be cased,
lined or
open hole.
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[00033] As shown in FIG. 1, the horizontal section 206 has a
longitudinal axis that
is indicated by line X. As will be described further below, the testing tool
100 can be
moved along the longitudinal axis X of the horizontal section 206 in order to
performed
testing operations at different locations of the horizontal section 206. Said
another way,
the testing tool 100 may be moved towards either the uphole end 206A or the
downhole
end 206B of the well 204 so as to perform testing operations on different
stages of the
well 204. This movement along the longitudinal axis X of the horizontal
section may
also be referred to as moving uphole or moving downhole.
[00034] The liner 208 can be perforated to provide the potential for
fluid
communication between inside of the liner 208 and the reservoir 252. The liner
208 can
be perforated by various mechanisms including, but not limited to: explosive
perforating,
sliding sleeves, burst discs, and abrasive jetting, which are collectively
referred to herein
as mechanisms for perforating the liner 208. The liner 208 may then comprise
various
perforated sections 210 that are spaced apart from each other along the
horizontal section
206. In some instances, but not all, a fracturing operation may be performed
to generate
fractures 210A in the geologic formation 250. The fractures 210A may also be
referred
to as cracks or openings. The fractures 210A may provide one or more fluid
pathways
between the reservoir 252 and the well 204 so as to facilitate fluid
communication
between the reservoir 252 and the well 204. Typically, testing tool 100 is
positioned in
the horizontal section 206 so that the perforated sections 210 are adjacent to
the fractures
210A. For the purposes of this disclosure, it is understood that fractures
210A may not
be required for the various embodiments of the present disclosure to operate.
Furthermore, one or more perforated sections 210 may form a stage with each
horizontal
section 206 and the horizontal section 206 is divided up into multiple stages
of perforated
sections 210.
100035] As shown in FIG. 2, the testing tool 100 can change or move
between at
least two configurations. In a first configuration (see FIG. 2A), the testing
tool 100 can
move along the longitudinal axis X within the horizontal section 206. In a
second
configuration (see FIG. 2B) the testing tool 100 engages the liner 208 with
sealing
mechanisms, as described further below.
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[00036] The testing tool 100 may be mechanically and fluidly coupled
to topside
surface equipment 202 by a string of coiled tubing 102. Examples of surface
equipment
202 include but are not limited to one or more coiled tubing trucks, an
electric generator,
one or more pumps such as a reciprocating piston-pumps that can generate as
high a
pressure as is required to perform fracturing operations while still providing
accurate
volumetric control. The pumps may be used to pump water or a mixture of water
and
glycol from a holding tank (not shown). In one embodiment, the testing tool
100 may be
operatively coupled to a coiled tubing truck, or other surface equipment 202,
at the
surface 200. In this embodiment, an uphole end 100A of the testing tool 100 is
operatively coupled to a downhole end of a string of coiled tubing 102 so that
fluids that
are conducted through the coiled tubing 102 are fluidly communicated into the
testing
tool 102 and so that movement of the coiled tubing 102 can translate into
movement of
the testing tool 100. For example, the coiled tubing 102 is operatively
coupled to the
testing tool 100 by a cable-head assembly 104. The coiled tubing 102 may be
used to
provide fluids from the surface 200 to the testing tool 100 and downhole of
the testing
tool 100. The coiled tubing 102 may be used to convey one or more electrical
conductors
400 from the surface 200 to the testing tool 100. The coiled tubing 102 may
also be used
to move the testing tool 100 through the well 204 and along the longitudinal
axis X of
the horizontal section 206.
[00037] The testing tool 100 may comprise one or more connected mandrels or
tubulars with each mandrel or tubular connected to each other by threading or
other
known means and providing a hollow bore therethrough. In some instances, the
testing
tool 100 may comprise one or more mandrels that are at least partially nested
within
another mandrel.
[00038] In some embodiments of the present disclosure, the testing tool 100
can
have some or all of the following features in the following order from the
uphole end
100A towards the downhole end 100B: the cable-head assembly 104, a pump
assembly
106, an optional sensor telemetry assembly 113, an upper packer-assembly 110,
a sensor
assembly 112, a lower packer-assembly 116 and a bottom connector-assembly 118.
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[00039] The cable-head assembly 104 may comprise a holdback valve 138
that
controls the flow of fluids through therethrough. FIG. 4 depicts one
embodiment of a
holdback valve 138 that comprises a biasing-member regulated stem valve 107.
When
the potential energy in the hydraulic pressure of fluids flowing through the
coiled tubing
102 is less than the biasing force of the biasing member 109, the stem valve
107 remains
seated in a valve seat 115. In this position, the holdback valve 138 is closed
and no fluids
will flow past the holdback valve 138. The biasing force is adjustable at the
surface and
can be set to allow fluids to pass when a predetermined pressure of the fluids
in the coiled
tubing 102 is achieved. The holdback valve 138 can be set to open when the
predetermined pressure is slightly above a calculated true vertical depth
hydrostatic
downhole pressure to keep the coiled tubing 102 full of fluid at all times.
This may save
time that would otherwise be required to refill the coiled tubing 102.
However, when the
pressure of the fluids in the coiled tubing 102 are sufficiently high, the
biasing force of
the biasing member 109 can be overcome and the valve stem 107 will dislodge
from the
valve seat 115. In this position, the holdback valve 138 is open and fluids
may flow from
the coiled tubing 102 through to the portions of the testing tool 100 that are
downhole
from the holdback valve 138. The fluid flows through the testing tool 100 and
can .
circulate in the well 204 downhole from the testing tool 100 if the testing
tool 100 is in
the first configuration. In some embodiments of the present disclosure the
fluids may
flow through the testing tool 100 by one or more flow-through conduits 132. In
some
embodiments of the present disclosure the fluid flows through the testing tool
100 for
driving a hydraulic pump, as described further below, if the tool is in the
second
configuration. As will be appreciated by those skilled in the art other types
of holdback
valves 138 that respond to changes in the hydrostatic pressure of fluids
within the coiled
tubing 102 may also be useful. As will be discussed further below, some
embodiments
of the present disclosure relate to a testing tool 300 that does not include a
hold-back
valve 138 and so fluids may flow through the testing tool 300 independent of
the pressure
of the fluid in the coiled tubing 102.
[00040] The cable-head assembly 104 may also include feedthroughs 105
to allow
the electrical conductor 400 to pass therethrough. The electrical conductor
400 provides
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power to at least to the sensor assembly 112, the optional sensor telemetry
assembly 113,
and optionally to the downhole pump 108 if the pump requires electrical power.
[00041] In some embodiments of the present disclosure, the coiled
tubing 102 may
be separated from the testing tool 100 at or about the cable-head assembly
104. The
coiled tubing 102 may be releasably connected to the cable-head assembly 104
by one
or more shear elements that will shear and allow the coiled tubing 102 to
release from
the testing tool 100 when an uphole force of a predetermined amplitude is
exerted on the
coiled tubing 102. In these embodiments, one or more feedthroughs 105 for the
electrical
conductor 400 may also disconnect when the coiled tubing 102 is disconnected
from the
testing tool 100. As shown in FIG. 5.
[00042] In some embodiments of the present disclosure, the pump
assembly 106
is mounted on a side of a sleeve that allows fluid to pass through it. The
pump assembly
106 comprises a downhole pump 108. The downhole pump 108 can be installed and
removed at surface by a technician. There can be a port 103 on the side of the
pump
assembly 106 that allows fluid to flow from the flow-through conduit 132 and
into a
power section of the downhole pump 108 to hydraulically power the downhole
pump
108 (FIG. 3A). A hydraulic line runs from an upper packer-assembly 110 to an
inlet of
the downhole pump 108. The electrical conductor 400 passes through
feedthroughs of
the pump assembly 106 to provide electrical power to the downhole pump 108.
[00043] In some embodiments of the present disclosure the downhole pump 108
may be a hydraulically driven pump which is powered by the surface-driven flow
of fluid
through the one or more flow-through conduits 132 of the coiled tubing 102
when the
holdback valve 138 is open. In some embodiments of the present disclosure,
when the
downhole pump 108 is operating, small quantities of test fluid are drawn from
the
reservoir 252 into an annular space 124 in the vicinity of the sensor assembly
112.
Continued operation of the downhole pump 108 moves test fluid from the portion
of the
annular space 124 between the upper packer-assembly 110 and the lower packer-
assembly 116, past the sensor assembly 112 and into the annular space 124
uphole of the
upper packer-assembly 110.
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[00044] In some embodiments of the present disclosure, the downhole
pump 108
may be an electrical submersible pump that operates to drive fluids from the
downhole
end 206A of the horizontal section 206 towards the uphole end 206B.
Optionally, the
downhole pump 108 may drive fluids within the coiled tubing 102 or within the
annular
space 124 between the coiled tubing 102 and an outer surface of the well 204
to the
surface 200.
[00045] The packer elements 120 and 122 may operate by use one of
various
commonly used packer activation methods. These methods include compression
activation, tension activation, hydraulic activation, or inflatable activation
of the packers.
For example, the upper packer-assembly 110 may comprise a drag block that
expands a
set of slips when the testing tool 100 is moved uphole. One example of a drag
block is
referred to as an auto ¨ J mechanism. A specific movement pattern of the
coiled tubing
102 and the testing tool 100 causes the slips to dig into the liner 208 and
then squeezes
an upper packer-element 120 and a lower packer-element 122 causing the packer
elements 120, 122 to expand and provide a hydraulic seal against an inner
surface of the
liner 208. The upper packer-assembly 110 may also provide a feedthrough (not
shown)
for the electrical lines 400 to power the sensor assembly 112, and optionally
the sensor
telemetry assembly 113. The upper packer-assembly 110 provides a test-fluid
conduit
130 between the sensor assembly 112 and the pump assembly 108 (FIG. 3A and
FIG.
3B). The upper packer-assembly 110 also has a sliding-sleeve assembly 111
which shifts
positions when the testing tool 100 is moved uphole or downhole. Shifting of
the sliding
sleeve 111 may change the fluid path of the testing tool 100 from the first
configuration
to the second configuration. For example, in the first configuration, fluid
may move from
the coiled tubing 102 through the one or more flow-through conduits 132 and a
downhole
port 136 and then through the downhole end 100B of the testing tool 100.
[00046] After the specific packer setting movement, the testing tool
100 moves to
the second configuration and the sliding-sleeve assembly 111 covers the
downhole port
136 (FIG. 2B). In the second configuration, the test-fluid conduit 130 is
fluidly
connected to the annular space 124 between an outer surface of the testing
tool 100 and
the liner 208 by aligning the test port 126 with one end of the test-fluid
conduit 130. In
the second configuration the sliding assembly 111 aligns, or allows the
alignment of, the
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test-fluid conduit 130 with a testing port 126. This creates a fluid flow path
from the
perforated section 210, into the annular space 124 through the testing port
126, along the
test-fluid conduit 130 to the downhole pump 108. The fluids that are being
tested by the
sensor assembly 112 are referred to herein as the test fluids. As test fluids
pass into the
annular space 124 between the packer assemblies 110, 116, the sensor assembly
112 may
perform one or more testing operations. If the sliding-sleeve assembly 111 is
shifted to
the first configuration the flow of test fluids to the downhole pump 108 is
cut off and a
flow restricted path is opened between a hydraulic line from the sensor
assembly 112 and
the annular space 124. This restricted path allows a slower flow of test
fluids for a
gradual equalization of pressure imbalances which may restrict subsequent
movement or
operation of the testing tool 100. For example a draw-down test may cause a
partial
vacuum which can hinder or prevent repositioning of the testing tool 100.
[00047] In some embodiments of the present disclosure the sensor
assembly 112
is positioned between the upper packer-element 120 and the lower packer-
element 122.
The sensor assembly 112 may comprise one or more sensors including but not
limited to
a telemetry package, a gamma-ray detector, a casing-collar locator, a
temperature probe,
a fluid-capacitance sensor, a fluid-conductivity sensor, an optical sensor, a
pressure
probe, an optical spectroscopy sensor, a sensor to measure ultrasonic speed
within the
tested fluid, a magnetic resonance imaging sensor package, a radioactive
density
measurement sensor, a fluid-resistivity sensor, a sensor for measuring
dielectric
properties of the tested fluid, a tuning-fork vibration resonance sensor for
measuring the
density and viscosity of the tested fluid or combinations thereof. The sensors
allow the
testing tool 100 to perform one or more testing operations that capture fluid-
property data
and/or pressure data which the sensor assembly 112 can record and/or
communicate to
the surface 200 by the telemetry package and known mechanisms or methods. In
one
embodiment of the present disclosure, the sensor assembly 112 comprises at
least one of
all of these sensors. In some embodiments of the present disclosure, the fluid-
capacitance
sensor and/or the conductivity sensor may be used to identify the fluid types
within the
test fluid (e.g. water, oil or gas). Further, the conductivity sensor may be
used to
determine the source of any detected water, for example, if the detected water
is reservoir
water, fracking water or wellbore water. Because flow of the tested fluid may
be a
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mixture of bubbles of oil, water or gas. This conductivity sensor may also
count the
length and duration of the bubbles. The optical sensor can be used to
determine if the
test fluid is a liquid or a gas and to count the number and size of any
bubbles present in
the test fluid. The casing-collar locator and gamma-ray detector may be used
to get the
testing tool 100 at a desired position along the well 204. The pressure and
temperature
sensors may be used for drawdown and buildup analysis.
[00048] In some embodiments of the present disclosure the sensor
assembly 112
allows side loading of the desired sensors for ease of access. The sensors
will be
electrically connected at one end, for example the uphole end 206A. The
sensors can be
installed and removed at the surface 200 by a technician to provide a testing
package of
desired sensors and to maintain and replace sensors as required. The sensor
assembly
112 allows fluid flow therethrough via the test-fluid conduit 130 so that the
sensors can
access the test fluids but to avoid wetting sensitive electronics of the
sensor assembly
112.
[00049] The lower packer-assembly 116 is similar to the upper packer-
assembly
110. The lower packer-assembly 116 does not have a sliding-sleeve assembly or
any
electrical conductors or hydraulic lines, as the upper packer-assembly 110
does. The
lower packer-assembly 116 operates in the same manner for setting and
releasing the
lower packer-element 122.
[00050] The bottom connector-assembly assembly 118 is connected to the
downhole end of the testing tool 100. The bottom connector-assembly assembly
118 is
configured to be coupled to various standard coiled tubing tools such as but
not limited
to jetting nozzles for cleaning or a drill bit.
=
[00051] FIG. 6 shows another embodiment of a testing tool 300
positioned within
a liner 208 that forms part of the horizontal section 206. The testing tool
300 can be
operatively coupled to the coiled tubing 102 as described herein above
regarding the
testing tool 100. The testing tool 300 performs similar functions and testing
operations
as described herein above regarding the testing tool 100.
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[00052] The testing tool 300 can include an electric release 302, a
telemetry and
control electronic section 313, an electrically powered downhole-motor 306, a
downhole
pump 308, an optional collar locator 310, a sensor assembly 312, an
equalization sub
304, an upper packer-element 320, a lower packer-element 322, a testing port
326, a
flow-through conduit 332 and a flow-control valve 338. Optionally, the testing
tool 300
can also include a bottom connector-assembly as described herein above. The
electric
downhole-motor 306 can receive power from surface by an electric power
conductor 400
that extends from the surface 200 through the coiled tubing 102. The conductor
400 can
be a single conductor or multiple conductors. The upper packer-element 320 and
the
lower packer-element 322 can be actuated between a set and an unset position
in a similar
manner as described above, or by a hydraulic mechanism. For example, the
hydraulic
packer set described in U.S. Patent No. 9,187,989, the entire disclosure of
which is
incorporated herein by reference, may be a suitable type of packer set for use
with either
of the testing tools 100, 300.
[00053] At least one difference between the testing tool 100 and the
testing tool
300 is that the sensor assembly 312 is positioned in fluid communication with
a position
between the two packer assemblies 110, 116 and the downhole pump 308, without
being
restricted to a position in between the two packer assemblies 110, 116 (FIG.
7). For
example, the sensor assembly 312 may be in fluid communication with the
position
between the two packer assemblies 110, 116 via the testing port 326 and the
sensor
assembly 312 may be in fluid communication with the downhole pump 308 by a
test-
fluid conduit 362. In some embodiments of the testing tool 300 the testing
port 326 is
not closed by a sliding sleeve, rather the testing port 326 is open. The
testing port 326 is
positioned between the two packer elements 320, 322 and the testing port 326
is in fluid
communication with the test-fluid conduit 362 that extends from the testing
port 326 to
the downhole pump 308. The test-fluid conduit 362 passes through the sensor
assembly
312 and the one or more sensors therein can perform testing operations on the
test fluid
within the test-fluid conduit 362. The sensor assembly 312 can include the
same
compliment of sensors as described herein above in reference to the sensor
assembly 112.
The flow of the test fluid is shown by a series of arrows. FIG.7 also show the
flow of
fluids from the coiled tubing 102 through the flow-through conduit 332 by
further arrows.
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[00054] The downhole pump 308 defines a shaft chamber 361 in which a
pump
shaft 358 and a piston 360 are housed. The shaft chamber 361 can be filled
with a typical
pump chamber fluid, such as a lubricating oil, or the like. The pump shaft 358
is
operatively coupled to the electric downhole-motor 306 to provide accurate
control over
actuating movements of the pump shaft 358 and the piston 360 connected
thereto. The
downhole pump 308 can be separated from the sensor assembly 312 by a check-
valve
sub 364. A pump chamber 363 is defined between a face of the piston 360 and
the check-
valve sub 364. The check-valve sub 364 defines an end of the test-fluid
conduit 362 that
is opposite to the testing port 326. As such, when the piston 360 moves away
from the
check-valve sub 364, the volume of the pump chamber 363 increases causing test
fluids
to flow through the test-fluid conduit 362, through the sensor assembly 312
and into the
pump chamber 363. The check-valve sub 364 may include a first one-way check
valve
368 that prevents the backflow of test fluids back into the sensor assembly
312. Test
fluids within the pump chamber 363 can be expelled into the annular space 124
by an
output conduit 370, which can include a second one-way valve 372 to prevent
the ingress
of fluids from the annular space 124 into the pump chamber 363. In some
embodiments
of the present disclosure the downhole pump 308 can be a double-acting pump
that can
expel and draw fluids into the downhole pump as the piston 360 moves in both
directions.
In some embodiments of the present disclosure the check-valve sub 364 can
define an
extension 366 of the flow-through conduit 332.
[00055] In some embodiments of the present disclosure relate to a
pressure sensing
package that can be used with the testing tools 100, 300 for detecting the
pressure within
different regions of the annular space 124. The pressure sensing package can
comprise
a first pressure-sensor that is positioned between the two packer elements
220, 222, a
second pressure-sensor that is positioned uphole of the upper packer-element
220 for
measuring the pressure within the annular space 124 and a third pressure-
sensor that is
positioned downhole of the lower packer-element 222. The pressure information
from
these three pressure sensors, or only two of them, can be used to detect if
there is any
fluid leakage between the stages uphole or downhole of the stage that is being
tested.
These types of fluid leaks may occur in an open-hole wellbore with a leaking
open-hole
packer, when there is a suboptimal cement job, combinations thereof or for
other reasons.
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These types of fluid leaks can cause inefficient fracturing operations and
inefficient
production of produced fluids from the reservoir 252 into the well 204.
1000561 FIG. 8 shows one embodiment of the electric release 302. The
electric
release 302 allows the user to separate the testing tool 300 into an upper
section 300A
from a lower section 30013 for example if the testing tool 300 becomes stuck
downhole.
The upper section 300A is releasably connectible to the lower section 300B.
The upper
section 300A may include one or more of the telemetry and control electronics
section
313, the electric downhole-motor 306 or the sensor assembly 312. The lower
section
300B can include the packer elements 320, 322 the flow-control valve 338 and
the bottom
connector-assembly 118. The upper section 300A can be pulled uphole by the
coiled
tubing 102 and the lower section 300B can be recovered by a fishing operation.
[00057] The electric release 302 includes at least one electrical
feedthrough 105
for the conductor 400, after which the conductor 400 is referred to as the
second
conductor 342, which can diverge into an upper conductor 344 that provides
electrical
power to a release motor 350 and a lower conductor 346 that provides
electrical power
to the remainder of the testing tool 300. The electric release 302 can also
include one or
more power controls, such as one or more diodes, electronic circuits,
electronic
components or combinations thereof that can control the flow of power to a
release motor
350. The release motor 350 can be operatively coupled to a release gear 352
that is
operatively coupled to a release sleeve 354. The release motor 350, the
release gear 352
and the release sleeve 354 are also part of the upper section 300A. When the
upper
section 300A is releasably connected to the lower section 300B, the release
sleeve 354 is
positioned to retain one or more collapsible fingers 356 of the upper section
300A in
corresponding finger-retaining grooves 357 of the lower section 300B.
[00058] The release motor 350 can be powered by electric power that is of
an
opposite polarity to the electric power that powers the remainder of the
testing tool 300.
For example the release motor 350 can be powered by negative voltage whereas
the
remainder of the testing tool 300 can be powered by positive voltage, or vice
versa. The
power controls and the use of electric power of a different polarity call
allow the release
motor 350 to be powered separately from the remainder of the testing tool 300.
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1000591 When powered, the release motor 350 actuates the release gear
352, for
example the release gear 352 may be a worm gear that rotates and linearly
moves the
release sleeve 354 towards or away from the release motor 350. Alternatively,
the release
gear 352 may simply pull or push the release sleeve 354. When the release
sleeve 354
moves a predetermined distance relative to the release motor 350 that causes
the one or
more collapsible fingers 356 to be released from the corresponding finger-
retaining
grooves 357 that are defined on the inner surface of the lower section 300B.
When the
one or more collapsible fingers 356 are released, the upper section 300A can
be separated
from the lower section 300B. When separated from the upper section 300A,
fishing
profiles 348 on an uphole end of the lower section 300B are exposed facilitate
recovery
by a fishing operation.
1000601 In some embodiments of the present disclosure, the testing
tool 300 can
include the flow-control valve 338. The flow-control valve 338 can be useful
when the
packer elements 320, 322 are hydraulically actuated. The flow-control valve
338 can be
set to actuate at a predetermined flow rate or pressure so that when fluids
that are
conducted through the testing tool 300, via the flow-through conduit 332,
achieve the
predetermined flow rate or pressure the flow-control valve 338 will actuate
and direct
that fluid towards pistons (not shown) that actuate the packer elements 320,
322 into the
set position. In some examples the predetermined flow rate may be between
about 150
and 250 litres per minute. Once the packer elements 320, 322 are set, the
fluid pressure
within the coiled tubing 102 can be held at a sufficient level so as to keep
the packer
elements 320, 322 sealingly engaged with the inner surface of the liner 208 or
the open
hole wellbore, as the case may be. When the fluid flow rates or pressures are
below the
predetermined value, the flow-control valve 338 will allow fluids to pass
downhole of
the testing tool 300. In other embodiments of the present disclosure, the
packer elements
320, 322 themselves may be inflatable. For example, the packer elements 320,
322 can
contain an internal plenum that can be put into and out of fluid communication
with the
flow-through conduit 132 by actuation of the flow-control valve 338. For
example, if
the fluids delivered through the coiled tubing 102 are above the predetermined
rate or
pressure, the flow-control valve 338 can direct the fluids to inflate the
packer elements
320, 322 directly. When the fluids delivered through the coiled tubing 102
decrease
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below the predetermined rate or pressure, the flow-control valve 338 can
actuate again
and release the fluids from the packer elements 320, 322 while permitting
fluids to pass
through the flow-control valve 338.
[00061] Some embodiments of the present disclosure the testing tool
300 includes
the equalization sub 313. The purpose of the equalization sub 304 is to
release a negative
pressure that can generate between the two packer elements 320, 322. This
negative
pressure can be created during testing operations and it can hinder or prevent
the packer
elements 320, 322 from returning to the unset position. As such, the
equalization sub
304 can be operatively connected to the coiled tubing 102 so that an uphole
movement
of the coiled tubing 102 can shift a sleeve (not shown) to provide fluid
communication
between the annular space 124 and the space between the two packer elements
320, 322.
[00062] In some embodiments of the present disclosure, the testing
tools 100, 300
may have an outer diameter of between about 2 inches to about 6 inches or
between about
3 inches to about 5 inches or about 3 and 3/8 inches (one inch equals about
2.54 cm). In
some embodiments of the present disclosure, the testing tools 100, 300 may be
run into
the well 204 with coiled tubing 102 of any outer diameter, for example coiled
tubing 102
with an outer diameter of about 1.5 inches. In some embodiments of the present
disclosure, the testing tools 100, 300 may have a temperature tolerance of
about 932 F
(about 500 C) or about 752 F (about 400 C) or about 617 F (about 325 C).
In some
embodiments of the present disclosure, the testing tools 100, 300 may have an
upper
pressure tolerance of about 20,000 pounds per square inch (psi, 1 psi equals
about 6.89
kPa) or about 12,000 psi or about 10,000 psi.
[00063] In operation, the testing tools 100, 300 may be used to
perform testing
operations of a perforated horizontal section 206 of a well 204 according to
embodiments
of the present disclosure. In one embodiment of the present disclosure, a
method 500 for
deploying and using the testing tools 100, 300 comprises some or all of the
following
steps: assembling 502 the testing tool 100, 300 and operatively coupling the
testing tool
100, 300 to the coiled tubing 102; running 504 the coiled tubing 102 and the
testing tool
100, 300 into the well 204; positioning 506 the testing tool 100, 300
substantially
adjacent a desired perforated section 210 of the well 204 where testing
operations will
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be conducted; setting 508 the packer elements 120, 122, 320, 322 establishing
fluid
communication between the sensor assembly 112 and the desired perforated
section 210;
pumping 510 test fluid by operating the downhole pump 108, 308 at a first
output
parameter and capturing fluid property and/or pressure data from the test
fluids as they
are drawn into the sensor assembly 112, 312; capturing 512 fluid-property data
from the
test fluids; stopping 514 the downhole pump 108 and capturing further fluid-
property
data from the test fluids; and unsetting 516 the packer elements 120, 122. The
method
500 may include a step of positioning 518 the testing tools 100, 300 to
another desired
location for further testing of test fluids within the well 204 and repeating
520 the
previous steps of the method 500. The method 500 may further include a step of
disconnecting 522 the coiled tubing 102 from the testing tool 100, 300 by
overcoming
shear connections at the uphole end of the testing tool 100, 300 or by
reversing the
polarity of the electrical power that powers the testing tool 100, 300 in
order to utilize
the electric release 302.
[00064] During the assembling step 502 the desired sensors are assembled at
the
surface 200 within the sensor assembly 112, 312 and the testing tool 100, 300
is
operatively connected to the coiled tubing 102. The sensors of the sensor
assembly 112,
312 are tested, calibrated and otherwise prepared to travel down into the well
204 and
the environment therein. The coiled tubing 102 and the testing tool 100, 300
are then
run 504 down into the well 204.
[00065] During the positioning steps 506, 518 the testing tool 100,
300 is
positioned at a desired location adjacent a desired stage of the horizontal
section 206
adjacent a perforated section 210, which are optionally adjacent fractures in
the geologic
formation 250. As a further option, the position of the testing apparatus 100
relative to
the first stage may be corrected based upon a short pass with the collar
locator 310. If
required, the position of the testing tool 100 may be adjusted accordingly by
moving the
coiled tubing 102 either further uphole or further downhole.
[00066] During the setting step 508 the packer elements 120, 122,
320, 322 are set
in the desired position within the well 204 and a step of establishing fluid
communication
between the sensor assembly 112, 312 and the test fluids is achieved. In some
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embodiments of the present disclosure the packer elements 120, 122 are set by
moving
the packer assemblies 110, 116 past the perforated section 210, then pulling
the coiled
tubing 102 uphole to set the packer elements 120, 122. As will be appreciated
by one
skilled in the art, an opposite downhole movement or other movements of the
coiled
tubing 102 call also be used to set the packer elements 120, 122.
Alternatively, the setting
step 508 can include increasing the flow rate of the fluids delivered through
the coiled
tubing 102 into the testing tool 100, 300 are above the predetermined level so
as to actuate
the flow-control valve 338, which redirects the delivered fluids to
hydraulically actuate =
the packer elements 320, 322 as described herein above. In a further
alternative, the
packer elements 320, 322 themselves may be inflatable and in fluid
communication with
the flow-through conduit 132 that is regulated by the flow-control valve 338.
For
example, if the fluids delivered through the coiled tubing 102 are above the
predetermined level, the flow-control valve 338 can direct the fluids to
inflate the packer
elements 320, 322 directly.
[00067] In the desired position, the portion of the annular space 124 that
is
between the two packer elements 120, 122 is positioned adjacent the perforated
section
210 within the selected stage. In the desired position, the testing port 126,
326 is also
positioned adjacent the perforated section 210.
[00068] During the step of setting 508 the packer elements 120, 122,
the sliding-
sleeve assembly 111 is also moved to transition the testing tool 100 from the
first
configuration to the second configuration. In the second configuration, any
test fluids
that are flowing from the reservoir 252 into the annular space 124 are fluidly
communicated to the sensor assembly and can be tested by the sensor assembly
112 to
test static pressure and temperature of the fluids within the annular space
124 and those
test results can be captured 512.
[00069] Alternatively, the sensor assembly 312 can be in fluid
communication
with the test fluids from the annular space 124 between the set packer
elements 320, 322
to capture 512 test results without requiring movement of any sliding sleeve.
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[00070] The method 500 may include a step of opening the holdback
valve 138 by
engaging a topside pump, as part of the surface equipment 202, to pump fluids
down the
coiled tubing 102 with sufficient hydrostatic pressure to overcome the
holdback valve
138, which in turn allows fluids to flow into the portions of the testing tool
100 that are
downhole from the holdback valve 138. The volumes and pressures introduced by
the
topside equipment may be recorded. Alternatively, if the testing tool 100, 300
is used
without the holdback valve 138, this step of opening the holdback valve 138 is
not
required.
[00071] During the step of pumping 510 fluid with the downhole pump
108, 308,
when the holdback valve 138 is in the open position or is not present, the
downhole pump
108, 308 will engage and pump in unison. As test fluids are drawn through the
annular
space 124 they flow past the sensor assembly 112, 312 which captures the test
results
including but not limited to test fluid: pressures, fluid capacitance,
temperatures and other
fluid-property data of the test fluids, as determined by the package of
sensors that are
included in the sensor assembly 112, 312. The downhole pump 108, 308 can be
operated
at a first-output parameter so that the amount of test fluid pumped is kept to
a low level
and the test fluids are kept below the bubble point. Then the downhole pump
108, 308
is stopped 514 and the test fluids will continue to flow into the annular
space 124. After
the passage of time the pressure within the annular space 124 will
substantially
equilibrate with the pressure of the reservoir 252. This equilibrium pressure
and the
timing and the pressure profile to achieve this equilibrium may be captured as
pressure
data as a measure of the reservoir pressure, permeability, the stimulated
reservoir volume
(SRV) or other reservoir properties that can be captured from pressure
transient analysis
and/or rate transient analysis.
[00072] Capturing 512 the test results can include either recording the
test results
on some form of electronic memory upon the testing tool 100, 300 or
communicating the
test results back to the surface 200. Once all test results are captured 512,
the packer
elements 120, 122, 320, 322 can be unset 516 by moving the coiled tubing 102
or
decreasing the flow rate or hydrostatic pressure of the fluids passing through
the flow-
control valve 338. This will cause the testing tool 100 to move from the
second
configuration back to the first configuration. The coiled tubing 102 may be
moved at
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surface to position 518 the testing tool 100 adjacent another a new desired
location
adjacent or proximal to a new perforated section 210 for repeating 520 the
testing
procedures on another stage of the horizontal section 206. The method 500 can
be
repeated until testing operations are performed on all desired stages of the
well 204. As
described above, the coiled tubing 102 may need to be moved in order to
actuate the
equalization sub 304 in order to relieve any negative pressure between the
packer
elements 320, 322 and the annular space 124.
[00073] In some embodiments of the present disclosure the method can
include a
step of circulating debris out of the testing tool 100, 300 by a surface pump
that can pump
a high pressure bolus of fluid down the coiled tubing 102 which will flow past
the
holdback valve 138, if present, and circulate the fluids out the downhole end
100B of the
testing tool 100, 300. This bolus may be useful for circulating debris out of
the downhole
end of the testing tool 100, 300, for cleaning up the well 204, delivering
fluids to any
further tools that are downhole of the testing tool 100, 300 or for
introducing friction
reducing fluids downhole of the testing tool 100, 300.
[00074] If the testing tool 100 becomes lodged or locked within the
well 204, in
some embodiments of the present disclosure the disconnecting step 522 can be
performed
by pulling the coiled tubing 102 uphole with a sufficient force to overcome
the shear
features in the cable-head assembly 104. This will releasing the testing tool
100 from
the coiled tubing 102 (FIG. 5). Alternatively, if the upper section of the
testing tool 100,
300 can be disconnected 522 from the lower section by using the electric
release 302.
The release motor 350 can then be powered up with a voltage that is of an
opposite
polarity as the voltage that is used to power the remainder of the testing
tool 100, 330 so
as to disengage the collapsible fingers 356 from the finger-retaining grooves
357. After
which the coiled tubing 102 can be pulled uphole along with the upper section
of the
testing tool 100, 300. A fishing operation can then be performed to retrieve
the lower
section of the testing tool 100, 300.
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