Note: Descriptions are shown in the official language in which they were submitted.
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METHOD OF USING AN ADJUSTABLE DOWNHOLE FORMATION TESTING TOOL
HAVING PROPERTY DEPENDENT PACKER EXTENSION
TECHNICAL FIELD
The present invention relates to well testing tools and method of use. More
particularly, the invention relates to testing tools having a plurality of
packer elements and at
least a testing port on the tool body.
BACKGROUND OF THE INVENTION
Advanced formation testing tools have been used for example to capture quid
samples from subsurface earth formations. The fluid samples could be gas,
liquid hydrocarbons
or formation water. Formation testing tools are typically equipped with a
device, such as a
straddle or dual packer. Straddle or dual packers comprise two inflatable
sleeves around the
formation testing tool, which makes contact with the earth formation in
drilled wells when
inflated and seal an interval of the wellbore. The testing tool usually
comprises a port and a flow
line communicating with the sealed interval, in which fluid is flown between
the packer interval
and in the testing tool.
Examples of such tools are schematically depicted in FIGURES 1A to ID. FIGURE
IA shows an elevational view of a typical drill-string conveyed testing tool
IOa. Testing tool
I Oa is conveyed by drill string 13a into wellbore 11 penetrating a
subterranean formation 12.
Drill string 13a has a central passageway. that usually allows for mud
circulation from the
surface, then through downhole tool l Oa,.through the drilling bit 20 and back
to the surface, as
known in the art. Testing tool I Oa may be integral to one of more drill
collar(s) constituting the
bottom hole assembly or "BHA". Testing tool I Oa is conveyed among (or may
itself be) one or
more measurement-while-drilling or logging while drilling tool(s) known to
those skilled in the
art. In some cases, the bottom hole assembly is adapted to convey a casing or
a liner during
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CA 02594042 2007-07-18
drilling. Optionally, drill string 13a allows for two-way mud pulse telemetry
between testing
tool 10a and the surface. A mud pulse telemetry system typically comprises
surface pressure
sensors and actuators (such as variable rate pumps) and downhole pressure
sensors and actuators
(such as a siren) for sending acoustic signals between the downhole tool and
the surface. These
signals are usually encoded, for example compressed, and decoded by surface
and downhole
controllers. Alternatively any kind of telemetry known in the art may be used
instead of mud
pulse telemetry, such as electro-magnetic telemetry or wired drill pipe
telemetry. Tool 10a may
be equipped with one or more packer(s) 26a, that are preferably deflated and
maintained below
the outer surface of tool 10a during drilling operations. When testing is
desired, a command may
be sent from the surface to the tool 10a via the telemetry system. Straddle
packer 26a can be
inflated and extended toward the wall of wellbore 11, achieving thereby a
fluid connection
between the formation 12 and the testing tool IOa across wellbore 11. As an
example, tool 1Oa
may be capable of drawing fluid from formation 12 into the testing tool I Oa,
as shown by arrows
30a. Usually one or more sensor(s) located in tool 10a, such as pressure
sensor, monitors a
characteristic of the fluid. The signal of such sensor may be stored in
downhole memory,
processed or compressed by a downhole processor and/or send uphole via
telemetry. Note that
in some cases, part of tool 10a may be retrievable if the bottom hole assembly
becomes stuck in
the wellbore, for example by lowering a wireline cable and a fishing head.
FIGURE 1B shows an elevational view of a typical drill-stem conveyed testing
tool
l Ob. Testing tool 1 Ob is conveyed by tubing or drill pipe string 13b into
wellbore 11 penetrating
a subterranean formation 12. Tubing string 13b may have a central passageway
that usually
allows for fluid circulation (wellbore fluids or mud, treatment fluids, or
formation fluids for
example). The passageway may extend through downhole tool l Ob, as known in
the art. Tubing
or drill string 13b may also allow for tool rotation from the surface. Testing
tool l 0b may be
integral to one of more tubular(s) screwed together. Testing tool 10b is
conveyed among (or
may be itself) one or more well testing tool(s) known to those skilled in the
art, such as
perforating gun. The testing tool 10b may be lowered in an open hole as shown,
or in a cased
wellbore. In some cases, tubing string 13b allows for two-way acoustic
telemetry between
testing tool l Ob and the surface, or any kind of telemetry known in the art
may be used instead,
including conductive tubing or wired drill pipe. Tool 10b may be equipped with
one or more
packer(s) 26b that is usually retracted (deflated) during tripping of testing
tool 10b. When
testing is desired, tool l Ob may be set into testing configuration, for
example by manipulating
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flow in tubing string 13b. Extendable packer 26b can be extended (inflated)
toward the wall of
wellbore 11, achieving thereby a fluid connection between an interval of
formation 12 and the
testing tool I Ob across wellbore 11. As an example, tool l Ob may be capable
of drawing fluid
from formation 12 into the testing tool l Ob, as shown by arrows 30b. Usually
one or more
sensor(s) located in tool l Ob, such as pressure or flow rate sensor,
monitor(s) a characteristic of
the fluid. The signal of such sensor may be stored in downhole memory,
processed or
compressed by a downhole processor and/or send uphole via telemetry. Note that
in some cases
part of tool 10b may be a wireline run-in tool, lowered for example into the
tubing string 13b
when a test is desired.
FIGURE 1 C shows an elevational view of a typical wireline conveyed testing
tool
10c. Testing tool 10c is conveyed by wireline cable 13c into wellbore 11
penetrating a
subterranean formation 12. Testing tool 10c may be an integral tool or may be
build in a
modular fashion, as known to those skilled in the art. Testing tool l Oc is
conveyed among (or
may be itself) one or more logging tool(s) known to those skilled in the art.
Preferably the
wireline cable 13c allows signal and power communication between the surface
and testing tool
l Oc. Testing tool l Oc may be equipped with straddle packers 26c, that are
preferably recessed
below the outer surface of tool l Oc during tripping operations. When testing
is desired, straddle
packer 26c can be extended (inflated) toward the wall of wellbore 11
achieving, thereby, a fluid
connection between an interval of formation 12 and the testing tool l Ob
across wellbore 11. As
an example, tool 10c may be capable of drawing fluid from formation 12 into
the testing tool
10c, as shown by arrows 30c. Examples of such tools can be found US patent
4,860,581 and US
patent 4,936,139, both assigned to the assignee of the present invention.
Note in some cases that wireline tools (and wireline cable) may be
alternatively
conveyed on a tubing string, or by a downhole tractor (not shown). Note also
that the wireline
tool may also be used in run-in tools inside a drill string, such as the drill
string shown in
FIGURE 1A. In these cases, the wireline tool 10c usually sticks out of bit 20
and may perform
measurements, for example when the bottom hole assembly is pulled out of
wellbore 11.
FIGURE 1 D shows an elevational view of another typical wireline conveyed
testing
tool 10d. Testing tool 10d is conveyed by wireline cable 13d into wellbore 11
penetrating a
subterranean formation 12. This time wellbore 11 is cased with a casing 40.
Testing tool 10d
may be equipped with one or more extendable (inflatable) packer(s) 26d, that
are preferably
recessed (deflated) below the outer surface of tool l Od during tripping
operations. Tool IOd is
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capable of perforating the casing 40, usually below at least one packer (see
perforation 41), for
example, the tool could include one or more perforating gun(s). In FIGURE 1D,
the testing tool
10d is shown drawing fluid from formation 12 into the testing tool 10d (see
arrows 30d).
Usually one or more sensor(s) is located in tool l Od, such as a pressure
sensor, monitors a
characteristic of the fluid. The signal of such sensor is usually send uphole
via telemetry. Note
that in some cases, tools designed to test a formation behind a casing may
also be used in open
hole. Note also that cased formations may be evaluated by downhole tool
conveyed by other
means than wireline cables.
Typical tools are not restricted to two packers. Downhole systems having more
than
two packers have been disclosed for example in patents US 4,353,249, US
4,392,376, US
6,301,959 or US 6,065,544.
In some situations, a problem occurs when fluid is drawn into the tool through
openings along the tool body. Formation fluids, wellbore fluids and other
debris from the
wellbore may occupy the volume between the upper sealed packer and the lower
sealed packer.
This causes various fluids to enter the same openings (or similar openings)
located in the sealed
volume. Moreover, when the density of the wellbore fluid is larger than the
density of the
formation fluid, it is very difficult to remove all of the wellbore fluid
since there will be a
residual of wellbore fluid that resides between the lowest opening and the
lowest packer, even
after a long pumping time. Thus, these wellbore fluids can contaminate the
formation fluid
entering the tool.
Downhole systems facilitating the adjustment of the flow pattern between the
formation and the interior of the tool have been disclosed for example in
patent application US
2005/0155760. These systems may be used to reduce the contamination of the
formation fluid
by mud filtrate surrounding the wellbore. Note that methods applicable for
reducing the
contamination by mud filtrate surrounding the wellbore are not always
applicable for reducing
the contamination by fluids and other debris from the wellbore.
Despite the advances in formation testing, there is a need for improved
testing
methods utilizing a tool having a plurality of packers spaced apart along the
axis of the tool, and
at least a port on the tool body located between two packer elements. Such
methods are
preferably capable of reducing the contamination of the formation fluid by
fluid or debris in the
wellbore. These methods may comprise adjusting in situ the length of a sealed
interval between
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two packer elements. Alternatively, these methods may comprise adjusting the
location of the
port within a packer interval.
SUMMARY OF THE INVENTION
Methods and systems for testing a subterranean formation penetrated by a
wellbore
are provided. A testing tool has a tool body, a plurality of packer elements
spaced apart from
one another along the longitudinal axis of the tool body, and at least a
testing port on the tool
body located between two packer elements. The testing tool is positioned into
the wellbore and
packers are extended into sealing engagement with the wellbore wall, sealing
thereby an interval
of the wellbore. Fluid is flown between the sealed interval and the testing
tool through the
testing port.
In at least one aspect, the invention relates to a method that comprises the
steps of
selecting in situ the length of an interval of the wellbore to be sealed, and
extending at least two
packer elements. The length of the interval of the wellbore that is sealed by
extending the packer
elements is substantially equal to the selected length.
In yet another aspect, the invention relates to a method that comprises the
step of
adjusting a port on a testing tool.
The foregoing has outlined rather broadly the features and technical
advantages of
the present invention in order that the detailed description of the invention
that follows may be
better understood. Additional features and advantages of the invention will be
described
hereinafter which form the subject of the claims of the invention. It should
be appreciated by
those skilled in the art that the conception and specific embodiment disclosed
may be readily
utilized as a basis for modifying or designing other structures for carrying
out the same purposes
of the present invention. It should also be realized by those skilled in the
art that such equivalent
constructions do not depart from the spirit and scope of the invention as set
forth in the appended
claims. The novel features which are believed to be characteristic of the
invention, both as to its
organization and method of operation, together with further objects and
advantages will be better
understood from the following description when considered in connection with
the
accompanying figures. It is to be expressly understood, however, that each of
the figures is
provided for the purpose of illustration and description only and is not
intended as a definition of
the limits of the present invention.
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According to an aspect of the invention, there is provided a method
for testing a subterranean formation penetrated by a wellbore, comprising:
positioning a testing tool in the wellbore, the testing tool comprising a tool
body, a
sensor, a plurality of packer elements spaced apart from one another along the
longitudinal axis of the tool body, and a port on the tool body located
between two
of the plurality of packer elements; extending at least two packer elements
into
sealing engagement with the wellbore wall; sealing a first interval of the
wellbore;
flowing fluid between the first sealed interval and the testing tool through
the port;
monitoring a property of the fluid from the first sealed interval with the
sensor;
extending a third packer element into sealing engagement with the wellbore
wall,
wherein extending the third packer element into sealing engagement with the
wellbore wall is triggered by a measured valve of the monitored property; and
sealing a second interval of the wellbore.
5a
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BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present invention, reference is now
made
to the following descriptions taken in conjunction with the accompanying
drawings, in which:
FIGURES IA-11) are elevation views showing typical examples of downhole
testing
tools, where the testing tool is drill string conveyed in FIGURE IA, tubing
string conveyed in
FIGURE 1B, and wireline conveyed in FIGURES 1C and 1D;
FIGURE 2 is a schematic showing one embodiment of a testing tool capable of
sealing wellbore intervals of various lengths;
FIGURE 3 is a schematic illustrating the selective length adjustment of a
sealed
wellbore interval with a tool having a plurality of spaced apart packer
elements;
FIGURE 4 is a schematic illustrating the selective adjustment the length of a
sealed
wellbore interval with a tool having a slidable packer element;
FIGURES 5A-5B are cross sectional views showing embodiments of a snorkel
assembly adapted to a testing tool;
FIGURES 6A-6B show a flow chart describing the steps involved in one
embodiment of a method for testing a subterranean formation;
FIGURES 7A-7D are schematics illustrating a method for testing a subterranean
formation;
FIGURES 8A-8D are schematics illustrating another a method for testing a
subterranean formation; and
FIGURES 9A-9B are schematics illustrating yet another method for testing a
subterranean formation.
DETAILED DESCRIPTION
Certain examples are shown in the above identified figures and described in
detail
below. In describing these examples, like or identical reference numbers are
used to identify
common or similar elements. The figures are not necessarily to scale and
certain features and
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certain views of the figures may be shown exaggerated in scale or in schematic
for clarity and/or
conciseness.
FIGURE 2 shows one embodiment of a testing tool capable of sealing wellbore
intervals of various lengths. The testing tool 10 is conveyed within wellbore
11 created in
formation 12 via conveyance mean 13. The testing tool 10 can be conveyed
downhole using a
wireline cable after the well has been drilled and the drill string removed
from the wellbore.
Alternatively, the testing tool can be conveyed downhole on the drill string
used to drill the
wellbore. Any conveyance means known in the art can be used to convey the tool
10.
Optionally, the conveyance means allows for two way communication between tool
10 and the
surface, typically a surface monitor (not shown), via a telemetry system as
known by those
skilled in the art. When used with some conveyance means, tool 10 may
accommodate for mud
circulation through the tool (not shown), as well known by those skilled in
the art. As shown in
FIGURE 2, the testing tool 10 is build in a modular fashion, with
telemetry/electronics module
154, packer module 100, downhole fluid analysis module 151, pump module 152,
and carrier
module 153. Telemetry/electronics module 154 may comprise a controller 140,
for controlling
the tool operation, either from instructions programmed in the tool and
executed by processor
140a and stored in memory 140b, or from instruction received from the surface
and decoded by
telemetry system 140c. Controller 140 is preferably connected to valves, such
as valves 110,
111, 112, 113, 114, 115 and 116 via one or more bus 190 running through the
modules of tool 10
for selectively enabling the valves. Controller 140 may also control a pump
130, collect data
from sensors (such as optical analyzer 131), store data in memory 140b or send
data to surface
using telemetry system 140c. The fluid analysis module 151 may include an
optical analyzer
131, but other sensors such as resistivity cells, pressure gauges, temperature
gauges, may also be
included in fluid analysis module 151 or in any other locations in tool 10.
Pump module 152
may comprise the pump 130, which may be a bidirectional pump, or an equivalent
device, that
may be used to circulate fluid along the tool modules via one or more flow
line 180. Carrier
module 153 can have a plurality of cavities, such as cavities 150-1, 150-2, to
150-n to either store
samples of fluid collected downhole, or transport materials from the surface,
as required for the
operation of tool 10. Packer elements 102, 103, 104 and 105 are shown
uninflated and spaced
along the longitudinal axis of packer module 100. Although not shown, the
packers extend
circumferentially around tool 100 so that when they are inflated they will
each form a seal
between the tool and a wellbore wall 15.
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Also shown on FIGURE 2 are particle breaking devices 160, 161, or 162. These
particle breaking devices could be focused ultrasonic transducers or laser
diodes. Particle
breaking devices are preferably used to pulverize sand, or other particles
passing into the flow
lines, into smaller size particle, for example, for avoiding plugging of
component of the testing
tool. These devices may use different energy/frequency levels to target
various grain sizes. For
example, particle breaking device 162 may be used to break produced sand
during a sampling
operation. In some cases, the readings of downhole sensor 131 will be less
affected by
pulverized particles than larger size particles. In another example, particle
breaking device 163
may be used to break particles in suspension in the drilling mud during an
injection (fracturing)
operation. In some cases, pump 130 will be able to handle pulverized particles
more efficiently
and will not plug, leak or erode as fast as with larger size particles in the
mud. Particle breaking
devices may be used for other applications, such as transferring heat to the
flow line fluid.
While testing tool 10, as shown in FIGURE 2, is build in a modular fashion,
those
skilled in the art will appreciate that all the components of tool 10 may be
packaged in a single
housing. Also, the arrangement of the modules in FIGURE 2 may be modified. For
example,
fluid analysis module 151 shown above pump module 152 may alternatively be
located between
pump module 130 and carrier module 153. In some situation, tool 10 can have
additional (or
fewer) operational capabilities beyond what is discussed herein. The tool can
be used for a
variety of testing, sampling and/or injection operations using the selectively
enabled packer
elements as discussed herein.
FIGURE 3 shows in more details an embodiment of packer module 200 similar to
module 100 of FIGURE 2, where two of the four packer elements have been
inflated. Packer
module or tool portion 200 may comprise one or more flow line 280, similar to
flow line 180 in
FIGURE 2. Flowline 280 is selectively connected to one or more port(s) in the
tool, such as
ports 252, 253a, 253b and 254 via associated valves 242, 243a, 243b and 244
respectively,
allowing fluid to flow from or into flow line 280. Each interval between
packer elements 262,
263, 264 and 265 has preferably at least one port. Although shown on the same
side of the tool,
ports may be located anywhere around the tool. Packer module or tool portion
200 may also
comprise packer inflation devices 212, 213, 214 and 215 for selectively
inflate or deflate packers
262, 263, 264, and 265 respectively. Other means to extend packers into
sealing engagement
with the wellbore wall may also be used without departing from the invention.
Inflation devices
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212, 213, 214 and 215 may consist of one or more pump(s), controlled by a
controller (not
shown) via bus 290, similar to bus 190 of FIGURE 2.
Note that testing tool 10 may not be modular. In this eventuality FIGURE 3
would
represent a portion of testing tool 10. Note also that the concepts discussed
herein are not limited
to four packer elements. Any number of packer elements may be deployed on a
tool and
selectively inflated depending on desired results and the operations to be
performed. Also note
that the packer elements need not be all of the same type or spaced
equidistant from each other.
Each of the packers 262, 263, 264 and 265 can be inflated so that the packers
radially
expand and contact wellbore wall 15 of formation 12. By expanding at least two
of the packers
sufficiently to contact the wellbore wall, the interval of the wellbore
between the two inflated
packers can be sealed off from the rest of the wellbore. Thus, as shown in
FIGURE 2, packers
263 and 265 have been selectively inflated to form a sealed interval 221
between packers 263
and 265. The sealed interval allows, for example, formation fluid to be drawn
into the tool for
testing. The selective enabling of each packer can be, for example, by
expanding the packer
under the control of inflation devices 212, 213, 214 and 215 by hydraulic
lines extending into the
packer element. Note that while each packer is shown with an individual
inflation device, a
device common to each packer can be used. Also, the force for enabling the
packers can come
from the surface or from another tool, if desired.
Other packers may be selectively extended to seal wellbore intervals of
various
lengths. An interval length may be selected downhole, for example by analyzing
measurements
performed by sensors of tool 10 or from another tool in the tool string. A
measurement that may
be used in some cases could be a wellbore resistivity image. By way of
example, the longest
testing interval may be selected. Sampling a long interval of wellbore wall in
this way could
result in a lower drawdown pressure. The user (or some logic implemented
downhole) would
then enable packers 262 and 265, for example by activating inflation devices
212 and 215
through bus 290. Packers 263 and 264 would not be enabled and would remain
retracted
(deflated). By extending packers 262 and 265, the wellbore interval between
top packer 262 and
bottom packer 265 would be sealed. Testing would follow. For example, this may
include
injecting or drawing fluid from any of the ports 252, 253a, 253b or 254 by
opening any of the
associated valves 242, 243a, 243b or 244 respectively. Alternatively, a short
testing interval may
be selected. Sampling a short interval of wellbore wall in this way could
result in a more
9
CA 02594042 2007-07-18
homogenous fluid. For example, it may be desirable to only test an interval
having a length
almost equal to the distance between packers 263 and 264. This can be done by
extending
packers 263 and 264 toward the wellbore wall and sealing the corresponding
interval. Note that
by having non-equal spacings between three or more packers, the user can
choose among a
variety of interval length to be sealed and test the formation.
In some testing applications, monitoring the flow of fluids in the formation
(injected
from the tool or drawn into the tool) may be desirable. In some situations, it
can be
advantageous to have sensors, such has sensors 201, close to the wellbore wall
15. In one
embodiment, sensors 201a, 201b, 201c and 201d maybe located directly on the
packers. These
sensors can measure various formation or fluid properties while the tool is in
the wellbore. For
simplification, FIGURE 3 illustrates sensors 201a-201d only on packers 263 and
265. However,
the sensors may also be located on any or all of the packers. In addition to
locating the sensors
on the packers, other sensors 202, such as sensors 202a 202b, and 202c, may be
located on or
within the tool at any location. Some of these sensors 201, 202 may measure
fluid properties
(such as pressure, optical densities) while others may measure formation
properties (such as
resistivity, sigma, carbon-oxygen ratio, sonic travel time). Data gathered by
sensors 201 a-d and
202a-c (and other sensors) may be communicated via bus 290 to a controller
(not shown) similar
to the controller 140 of FIGURE 2. The data sent to the controller may further
by processed
downhole by a processor, similar to the processor 140a of FIGURE 2. The
controller may
further adjust operations of the tool 10, for example modify the pumping rate
of pump 130 or
modifying the length of the sealed interval, based on the processed data. Data
gathered by
sensors 201, 202 may also be stored downhole into a memory, similar to the
memory 140b of
FIGURE 2, or sent uphole for analysis by an operator via a telemetry system,
similar to the
telemetry system 140c of FIGURE 2.
Perforation may be desirable for some testing applications. Thus, the
formation may
further be perforated at a point within the sealed off interval of the
wellbore, for example, for
altering the fluid flow from the formation to the sealed interval of the
wellbore between the two
inflated packers. Any kind of perforation device may be mounted between two
inflatable
packers, such as perforation guns 230 and 231. For example, a bullet fired
from a perforating
gun 230 may be used to perforate formation 12 as shown in FIGURE 3 to create a
perforation
222. The bullet may hold a sensor capable of sending data to tool 10, for
example using an
electromagnetic wave communication.
CA 02594042 2007-07-18
FIGURE 4 shows another embodiment of a testing tool capable of selecting in
situ
the length of an interval to be sealed. Thus, FIGURE 4 illustrates the
selective length adjustment
of a sealed wellbore interval by sliding a packer element along the length of
the tool to vary the
distance between two packer elements. Referring to FIGURE 4, packer module 300
similar to
packer module 100 of FIGURE 2 is shown. Packer module 300 is shown with three
packer
elements 360, 361 and 362 but any number of packers could be employed. These
three packer
modules are operatively coupled with three inflation devices 310, 311 and 312
respectively for
selectively extending (inflating) and recessing (deflating) the three packer
elements. The
inflation devices 310, 311 and 312 may be communicatively coupled to a
downhole controller
via a bus 390, similar to bus 190. In the embodiment of FIGURE 4, the middle
packer 361 is
shown to be slidably movable along the longitudinal axis of the tool 10.
Packer element 361 is
coupled to piston actuator 302 which may be utilized to slide packer 361 up or
down the length
of the tool body. For example, actuator 302 could be used to move packer 361
to position 361'.
The fluid for inflating/deflating the packer could be delivered by inflation
device 311 to packer
361, for example, via hydraulic line located in ram 303 (not shown).
In operation, testing tool 10 of FIGURE 4 would be lowered into formation 12
traversed by wellbore 11. The length of an interval of wellbore 11 to be
sealed can be
determined in situ. For example, a Nuclear Magnetic Resonance measurement can
be used to
estimate the viscosity of the formation fluid surrounding tool 10, and the
length of the interval to
be sealed for a sampling operation may be adjusted therefrom. The piston
actuator 302 may then
be activated for sliding packer element 361 along the tool body for adjusting
the distance
between packer element 360 and packer element 361. For example, once the
length is selected
(packer element 361 is moved to position 361' on FIGURE 4), packer elements
360 and 361 may
be extended (inflated) toward the wellbore wall 15 by inflation devices 310
and 311, sealing
thereby an interval of the wellbore which length is substantially equal to the
selected length.
Testing may then begin. For example, fluid may be drawn into the tool through
port 351. The
testing step may involve manipulating valves, such as valve 341. Fluid may be
flown into
flowline 380 (similar to flowline 180 in FIGURE 2). When testing is finished,
packers are
usually deflated below the outer surface of the testing tool.
The embodiment shown in FIGURE 4 can be combined with the embodiment shown
in FIGURE 2 or FIGURE 3, such that packers 102, 103, 104 and 105 (FIGURE 2)
may all be
slidably moved along the tool such that it is possible to vary the vertical
distance between any
11
CA 02594042 2007-07-18
two packers. As an example, it may be desirable to test a region of an earth
formation larger
than that covered by the area between packers 102 and 103 but not as large as
the areas covered
by packers 102 and 104. In this case, packer 102 could be moved upward in the
vertical
direction along the tool to expand the top area, or packer 103 may be moved
downward in the
vertical direction along the tool to expand the area downward. The ability to
selectively move
packers in the vertical direction along the tool provides an infinite number
of testing regions
within the well.
Note that some packers may be slidable and some may not, as shown in FIGURE 4
by non slidable packer 360 and 362, and slidable packer 361. Note also that
slidable and non
slidable packers may be arranged in various combinations. Although the
operation of testing
tool 10 of FIGURE 4 has been described using packer element 360 and 361 to
seal an interval
with a length selected downhole, packer 361 and 362 may be used instead, and
fluid may
alternatively be flown through port 352 (and open valve 342) on tool 10.
FIGURES 5A-5B show embodiments of a snorkel assembly 401 (FIGURE 5A) and
401' (FIGURE 5B) adapted to a testing tool 10. The snorkel assembly may be
used to advantage
for bringing a port of the sampling tool to a more effective relative position
with respect to the
packer elements. FIGURE 5A-5B show a packer module 400 adapted on a testing
tool 10
lowered in a wellbore 11 penetrating a formation 12. Note that the testing
tool is shown
partially, and may be similar to the testing tool of FIGURE 2. The testing
tool 10 may include
centralizer bow springs 480 and 481 as known in the art. The packer module 400
comprises
packer elements 462 and 463 for sealing an interval of the wellbore 11 by
extending (inflating)
the packer elements into sealing engagement with the wellbore wall 15, for
example with
inflation devices 412 and 413 respectively. The packer module 400 may further
comprise a port
450 on the tool body and an associated valve 451. The port allows for fluid
communication
between a flow line 490 in the downhole tool, similar to flow line 180 in
FIGURE 2, and a
sealed interval of the wellbore. In the examples of FIGURES 5A-5B two
different snorkel
assemblies 401 and 401' respectively, are adapted on the testing tool 10. The
snorkel assembly
401 or 401' may comprise a filter 423, an adapter 422, a snorkel 421 (FIGURE
5A) or 421'
(FIGURE 5B), and a ring 420. Note that the snorkel assembly may comprise
additional parts,
such as sensors, for providing other functionalities. Note also that the
snorkel assembly may
comprise fewer parts. For example the filter 423, the ring 420, may be
optional.
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CA 02594042 2007-07-18
The snorkel assembly is preferably adaptable on the testing tool 10. For
example,
while the packer module 400 is disconnected from the testing tool 10, and the
packer element
462 is not mounted on the packer module, the adapter 422 may slide around the
packer module
body and rest on the mounted packer 463. When the adapter 422 is in place, the
port 450 of the
tool is fluidly connected to annular groove 431 of the adapter 422. Then the
snorkel 421 or 421'
is slid on top of the adapter 422. Snorkel 421 (421') comprises one or more
fluid
communication(s) 440 (440') between a snorkel port 430 (430') and annular
groove 431 via one
or more passageway 441. In the example of FIGURES 5A-5B, fluid
communication(s) 440
comprise a plurality of flow lines, for example eight, distributed around the
circumference of the
snorkel. A screen filter 423 may then slide around the snorkel and may be held
in place with
screws 470 or other fasteners. The filter 423 preferably covers the snorkel
port 430 (430'). A
ring 420 may finally be slid on the tool mandrel and locked in place before
the packer element
462 is mounted. The packer module 400 is further included into testing tool
10. The testing tool
may be lowered into a wellbore to perform a test on a subterranean formation.
Different snorkel designs may have different snorkel port configurations. The
snorkel design that is adapted on tool 10 is preferably chosen such that the
snorkel port
configuration is adjusted for a particular testing operation. In the example
of FIGURE 5A, the
snorkel port 430 is shown higher than the snorkel port 430' of FIGURE 5B. Also
the snorkel
port shape may be adjusted from one snorkel design to another. Thus, if a
snorkel port
configuration such as shown by 430 is desirable for testing, an operator may
adapt the snorkel
421 to the testing tool 10, adjusting thereby the initial configuration of the
port on the testing tool
450 to the desired configuration of the snorkel port 430. In other cases, a
different snorkel port
configuration, such as shown by 430', may be desirable for testing. Here
again, an operator may
adapt a different snorkel to the testing tool 10, adjusting thereby the
initial configuration of the
port on the testing tool 450 to the different configuration of the snorkel
port 430'.
Screen filters with various characteristics can be assembled in the snorkel
assembly.
In some cases, the screen filter may comprise two or more screens. In some
cases, the screens
may be separated by a small gap. Also the screens can be reinforced, for
example by vertical
strips. The screen filter characteristics are preferably adjusted for the
testing operation the tool is
intended to perform.
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Note that a snorkel assembly can be adapted to any kind of testing tool, such
as the
testing tool of FIGURES 2,3 or 4. Note also that the snorkel in the snorkel
assembly could be
made telescopic and may be adjusted downhole using an actuator.
FIGURES 6A-6B describe one embodiment of a method 500 for testing a
subterranean formation. The method 500 preferably utilizes a testing tool
having a tool body, a
plurality of packer elements spaced apart from one another along the
longitudinal axis of the tool
body, and at least a testing port on the tool body located between two packer,
as is the described
herein. However, the method 500 may be used with any testing tool having
selectively-activated
packer elements and capable of formation testing.
In optional step 505, a snorkel assembly is placed on the testing tool. The
snorkel
assembly is capable of adjusting a port on a testing tool. The snorkel
assembly may also be
capable of adjusting the characteristic of a filter screen. The snorkel may
further be capable of
reducing the volume trapped in the sealed interval. For example, the testing
tool may be
intended to sample formation fluid in an unconsolidated formation, and the
formation fluid is
expected to have a lower density than the borehole fluid. The testing tool may
also be intended
for a large diameter wellbore. Such sampling situation is illustrated in
FIGURE 9A-9B for
explanatory purposes. Note that in step 505 of method 500, the testing tool is
not yet lowered
into the borehole, and FIGURE 9A-9B are used therebelow to explain how the
testing tool is
expected to perform in the sampling situation discussed above, based on a
prior knowledge of the
sampling conditions, and how the adjustment of step 505 may be performed.
Referring to FIGURE 9A, a portion of testing tool similar to testing tool 10
of
FIGURE 2 is shown in a wellbore 11 traversing a formation 12 during a sampling
operation.
Packer elements 862 and 863 are shown in an extended position, and engaged
with the wellbore
wall 15 for sealing a wellbore interval therebetween. In the example of FIGURE
9A, the testing
tool 10 has drained fluid from the wellbore into flowline 890 (similar to flow
line 180 of
FIGURE 2) through tool port 850 and open valve 851. The fluid drained from the
wellbore has
been partially replaced by formation fluid 842, and sand or debris 840
produced from the
formation. Note that some wellbore fluid may still be present in the sealed
interval, as shown by
wellbore fluid 841. The illustration of FIGURE 9A assumes that debris,
wellbore fluid and
formation fluid have segregated in the order as shown, because of the density
contrast between
these materials. However segregation may occur in a different order. During
the sampling
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operation shown in FIGURE 9A, sand or debris may enter tool port 850 and plug,
clog or erode
various components in the testing tool 10, such as pumps, or valves. Also,
debris may cause
noise at a fluid property sensor. Finally, the volume of the sealed interval
may be large, because
the testing tool is run in a wellbore of large diameter. Because of this large
volume, the sampling
operation may require a long time before formation fluid enters in the testing
tool and is
available for capture in a cavity. This long sampling time may increase the
probability of the
testing tool to become stuck in the wellbore.
Turning now to FIGURE 9B, a snorkel assembly 800 is shown in a wellbore 11
traversing a formation 12 during a sampling operation similar to the sampling
operation shown in
FIGURE 9A. In FIGURE 9B the location of the tool port 850 has been adjusted
for this
particular operation by adapting a snorkel assembly to the testing tool prior
to lowering it into the
borehole. Fluid is now drawn from the wellbore at the snorkel port 830.
Snorkel port 830 is
located above the debris that have segregated on top of the lower packer
element 863, reducing
thereby the probability of components of the tool 10 being plugged by debris
entering the testing
tool 10. Note also that the snorkel port is located close to the upper packer
element 862,
reducing thereby the volume and the time needed to draw into the tool
formation fluid that has
segregated above the wellbore fluid. In the example of FIGURE 9B, the snorkel
assembly also
comprises a filter screen 823, whose characteristics such as the area, the
screen mesh size, the
number of screen layers or the screen collapse resistance may have been
adjusted to the sampling
operation. For example, the screen filter 823 may be chosen to be a double
layer filter, or may
be reinforced by vertical stripes between the layers to insure a high collapse
resistance. The
snorkel port 830 may further extend around the entire circumference of the
tool, increasing
thereby the area of the intake adjacent to the filter screen, which may be
advantageous for
avoiding plugging of the filter screen. In the example of FIGURE 9B, the
outside diameter of
the snorkel module has been selected so that the trapped volume of fluid
between packer element
862 and 863 is reduced with respect to FIGURE 9A. Specifically, the outside
diameter is
selected just below the wellbore diameter. Reducing the trapped volume of
fluid may decrease
the volume of fluid needed to be pumped before formation fluid enters the tool
and decreases the
time needed to capture a formation fluid sample. Note that the volume may also
be reduced by
using rings, such as ring 820.
Turning back to FIGURES 6A-6B, the testing tool is lowered in the wellbore in
step
510. As mentioned before, the testing tool may be conveyed on a drill sting, a
tubing string, a
CA 02594042 2007-07-18
wireline cable or any other means known by those skilled in the art. Lowering
the downhole tool
may comprise drilling or reaming the wellbore. The wellbore may be open to the
formation or
may be cased. If the wellbore is cased, the testing tool preferably comprises
perforation devices,
such as drilling shafts or perforating guns, for example located between two
packer elements.
The testing tool may be lowered in the wellbore with other tools, such as
formation evaluation
tools known by those skilled in the art. The conveyance means preferably
comprises a telemetry
system capable of sending information collected by a downhole tool to the
surface, and receiving
commands from the surface for controlling operation of the testing tool. A
downhole controller
executing instructions stored in a downhole memory in the testing tool may
also control
operations of the testing tool.
Step 515 in FIGURES 6A-6B determines the length of the wellbore interval to be
tested. This can be achieved downhole, for example using a processor and data
collected by
sensors. This can alternatively be achieved under control of a user operating
from the surface,
for example, using a camera or other sensing tools, not shown, which are part
of the downhole
tool string. This can be alternatively achieved by any other methods and/or
sensors mentioned
therein. Other methods and/or sensors may also be used without departing from
this invention.
The method 500 may comprise the optional step 520, that determines whether
cleaning is desired
within the testing interval. Cleaning may comprise delivering materials
conveyed from the
surface in one of the cavity of testing tool 10, such as cavity 150-1 of
FIGURE 2, into the
wellbore, for example for dissolving locally the mudcake on the wellbore wall
15. This material
could be water, steam, acid solution, solvent or any combination thereof. If
cleaning is desired,
optional step 525 determines the length of a cleaning interval to be sealed,
usually comprising
the testing interval so that the cleaning material can be fully removed from
the testing interval as
further discussed below. The cleaning interval length may be selected by
enabling the extension
of two packer elements from the plurality of the packer elements carried by
the testing tool in
step 530. Note that the adjustment of the testing interval length may
alternatively be achieved by
sliding packer elements along the axis of the tool prior to extending the
packer element toward
the wellbore wall, as previously discussed with respect to FIGURE 4.
As a way of example, FIGURES 7A-7D show a portion of a testing tool similar to
testing 10 of FIGURE 2, lowered in a wellbore 11 traversing a formation 12.
The testing tool 10
comprises packer elements 602, 603, 604 and 605, and ports 652, 653, and 654.
In the example
of FIGURES 7A-7D, the extension of packer elements 602, 603, 604 or 605 can be
selectively
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enabled, for example using the apparatus described in more details with
respect to FIGURE 3.
As a way of example, the length of the wellbore interval to be sealed
determined in step 515 may
be represented by interval 610 on FIGURES 7A-7D. As a way of example, the
length of the
wellbore interval to be sealed determined in step 525, may be represented by
interval 611 on
FIGURES 7B-7D.
Turning back to FIGURES 6A-6B, packer elements of the testing tool are
extended
toward the wellbore wall in step 535 if cleaning is desired. A first interval,
the cleaning interval,
is sealed from the rest of the wellbore in step 540. Note that in some cases
it may be
advantageous to bypass one of the sealing packer element with a flow line (not
shown) in the
testing tool that establishes a fluid communication between the sealed
interval in step 540 and
another part of the system, for example the wellbore outside the sealed
cleaning interval.
Optional cleaning or treatment is performed in step 545.
In the example of FIGURES 7B and 7C, the interval length may be selected by
enabling the extension of two selected packer elements from a plurality of
packer elements
carried by the testing tool. Packers 602 and 604 are first enabled and then
extended (inflated) in
step 535 of the method shown in FIGURES 6A-6B. By extending toward the
wellbore wall,
packers 602 and 604 seal the cleaning interval 611 which length is roughly
equivalent to the
determined length in step 525 of the method 500 shown in FIGURES 6A-6B. A
cleaning fluid
660 may then be injected through port 652 or 653 into the wellbore in step 545
of the method
shown in FIGURES 6A-6B. Preferably the cleaning fluid 660 will occupy a large
portion of the
cleaning interval, as indicated by cleaning fluid 660 in FIGURE 7B. Sensors,
similar to sensors
202a-c or 201 a-d shown in FIGURE 3, or other sensors, may optionally monitor
the cleaning
process, and the cleaning process may be controlled based on the sensor
signals. Step 545 may
further comprise draining the cleaning fluid 660, for example in port 653 as
shown in FIGURE
7C. This cleaning fluid may be dumped into the wellbore outside the sealed
interval, for
example at port 163 of FIGURE 2, or stored in a cavity in the testing tool,
such as cavity 150-2
of FIGURE 2. Usually, draining through port 653 will not efficiently remove
the cleaning fluid
660 located between the lower packer element of the sealed interval 604 and
the draining port
653. Note that in the example of FIGURE 7C, it is assumed that the density of
the cleaning fluid
and/or cleaning debris is larger than the density of the formation fluid. It
is further assumed that
the testing tool 10 is operated such that formation fluid is drawn from the
surrounding formation
as cleaning fluid is drained outside the cleaning interval, as shown by
formation fluid 661. Thus,
17
CA 02594042 2007-07-18
formation fluid and cleaning fluid may segregate by gravity as shown in FIGURE
7C. In the
case the formation fluid density is higher than the cleaning fluid and/or
cleaning debris density,
the sequence of formation fluid, cleaning fluid, and/or cleaning debris may be
different. Note
also that this invention is not limited to the presence of two segregated
fluids in the sealed
interval.
Turning back to FIGURES 6A-6B, the testing interval length may be selected by
enabling the extension of two packer elements from the plurality of the packer
elements carried
by the testing tool in step 550. Note that the adjustment of the testing
interval length may
alternatively be achieved by sliding packer elements along the axis of the
tool prior to extending
the packer element toward the wellbore wall, as previously discussed with
respect to FIGURE 4.
Packer elements of the testing tool are extended toward the wellbore wall in
step 555. Note that
if a first cleaning interval has already been sealed, it may be advantageous
in some cases to
maintain the first interval sealed while sealing a second interval, the
testing interval. Thus, it
may be advantageous to bypass one of the sealing packer element with a flow
line (not shown) in
the testing tool that establishes a fluid communication between the cleaning
interval and another
part of the system, for example the wellbore outside the sealed cleaning
interval. This would
allow for the fluid displaced by the extension of a third packer element in
the sealed interval to
be vented out of the sealed interval. A testing interval is sealed from the
rest of the wellbore in
step 560. Testing of the formation is performed in step 565, for example
injection, sampling, or
local interference test (also known as interval pressure transient test or
IPTT) is preferably
performed in a manner known in the art.
Continuing with the example of FIGURE 7D, the testing interval 610 is selected
by
enabling the extension (inflation) of packer element 603 between already
extended packer
elements 602 and 603 (step 550 of the method in FIGURES 6A-6B). Note, that in
this scenario
packer element 602 would be enabled for both sealing the testing volume and
the cleaning
volume. The testing interval 610 is sealed once the packer element 603 reaches
the wellbore
wall. Thus, the testing interval 610 is now isolated from the residual
cleaning material and/or
debris 660 above the lower packer 604. The residual cleaning material and/or
debris 660 is
retained below expanded packer 603 and is trapped, so as not to contaminate
the fluid contained
in the testing interval 610. However, if desired, packer 604 can be retracted
(deflated) thereby
allowing the residual cleaning material to disburse downhole if desired.
Testing may then begin.
Formation fluid may be drawn from interval 610 into the port 652. Note that
cleaning fluid 660
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CA 02594042 2007-07-18
was drained during the cleaning period through port 653 and formation fluid
661 is now drawn
through port 652 during the testing period. This may be achieved by
associating port 652 and
653 with valves (not shown), similar to valves 242 and 243 associated
respectively to ports 252
and 253 in FIGURE 3.
Turning back to FIGURES 6A-6B, one or more additional interval may be sealed
if
needed, including the option of selecting of the length of these additional
intervals, as shown by
step 570. Also, additional testing may be performed as shown by step 575. At
any time, the
operator or internal logic may decide to abort the cycle and terminate the
test. All the packer
elements are preferably retracted (deflated) in step 580 and the testing tool
is free to move in the
wellbore. Other methods than method 500 may also benefit from sealed interval
of adjustable
length. These methods include, but are not limited to, injecting materials
into the formation, or
formation testing to determine for example pressure and mobility of
hydrocarbons in a reservoir.
As mentioned above, a local interference test (also known as interval pressure
transient test or
IPTT) may benefit from sealed interval of adjustable length. The pressure in
sealed intervals of
variable length may be pulsed. The pressure pulse may be detected at a probe
located above or
below the sealed interval (similar to probe 16c in FIGURE 1 C), that is in
pressure
communication with the formation.
FIGURES 8A-8D show another illustration of a method for testing a subterranean
formation according to one aspect of this invention. FIGURES 8A-8D show a
portion of a
testing tool similar to testing tool 10 of FIGURE 2, lowered in a wellbore 11
traversing a
formation 12, as taught by step 510 of method 500. Testing tool 10 comprises
packer elements
702, 703, 704 and 705, and ports 752, 753, 754 and 755. In the example of
FIGURES 8A-8D,
packer elements 703 is slidable, for example using the apparatus described in
more details with
respect to FIGURE 4.
As a way of example, the length of the wellbore interval to be sealed
determined in
step 515 of method 500 may be represented by interval 770 on FIGURES 8A-8D. As
taught by
step 550 of method 500, the testing interval length may then be selected by
sliding packer
element 703 as indicated by arrow 730 on FIGURE 8A. The movement of packer
element may
be controlled by a downhole controller (not shown), either automatically
according to
instructions executed by the downhole controller, or under the supervision of
a surface operator
sending a command to the testing tool. The command sent to the testing tool
could comprise a
19
CA 02594042 2007-07-18
value of the testing interval length determined by the operator, for example
in view of
information recorded by downhole sensors (not shown) and sent uphole by a
telemetry system
(not shown).
FIGURE 8B illustrate a first testing operation. In the example of FIGURE 8B,
packer elements 702 and 703 have been extended into sealing engagement with
the wellbore wall
15 (step 555 of method 500) and the testing interval 770 is isolated (step 560
of method 500).
The testing operation (step 565 of method 500) may comprise the optional step
of perforating the
formation as shown by tunnel 722 in formation 12. Perforation may be achieved
by perforating
guns, such as perforating gun 231 of FIGURE 3, or by any other method known by
those skilled
in the art. Note that the perforation of the formation 12 about the testing
interval 770 may be
performed before or after inflation of the packer elements 702 and 703. The
testing operation
shown in the example of FIGURE 8B comprises injecting material through the
port 752, for
example steam, hot water, acid or solvent, into the testing interval 770 and
the formation 12.
Injection of steam, hot water or solvent may be desirable for example to lower
viscosity of heavy
hydrocarbon in formation 12 prior to sampling. Injection may also be desirable
for testing the
compatibility of the injected fluid with the formation or reservoir fluid. The
injected material
may be conveyed downhole in a cavity (not shown), similar to cavity 150-1 in
FIGURE 2, or
may also be conveyed from the surface into the conveyance mean 13b, as
explained above with
respect to FIGURE 113. The testing operation preferably allows for the
injected material to
diffuse in the formation 12, as indicated by arrows 731. During this soaking
period, various
sensors (not shown) may measure formation of fluid properties, such as fluid
temperature, fluid
pressure, or formation resistivity profile along the radial, axial or
azimuthal direction of the
wellbore.
FIGURES 8C and 8D illustrate an optional testing operation following the
injection
described in FIGURE 8B. The length of a second testing interval can be
selected, for example
from the set of the distance between packer element 703 and 704, the distance
between packer
703 and 705 or the distance between packer 704 and 705. In the example of
FIGURE 8C, a
second testing interval 771 between packer elements 705 and 703 is sealed, as
taught by step 570
of method 500. Alternatively, packer element 704 may have been enabled instead
of packer
element 705, sealing thereby a second testing interval with a shorter length.
The testing tool may
start drawing fluid from interval 771 through port 753, as taught in step 575
of method 500.
Fluid leaving the interval 771 may be replaced by sand 763, produced by an
unconsolidated
CA 02594042 2011-12-08
79350-243
formation, and formation fluid 762, as indicated by arrows 732. Note that in
the example of
FIGURE 8C, it is assumed that the density of the formation fluid 762, for
example heavy oil, is
larger than the density of the wellbore fluid 761, for example water. Note
also that formation
fluid 762 may be contaminated by injection materials or other materials.
FIGURE 8D shows the continuation of the sampling process started in FIGURE 8C.
In FIGURE 8D, an alternate fluid communication with the testing tool is
established through port
754 by selectively opening a valve (not shown) associated with port 754, for
example a valve
similar to valve 243b of FIGURE 3, and by closing. a valve (not shown)
associated with port 753,
for example a valve similar to valve 243a of FIGURE 3. This operation may be
initiated by a
surface operator, for example in view of fluid properties measured by the
testing tool, for
example by a sensor similar to sensor 131 of FIGURE 2, and send uphole via
telemetry. This
operation may alternatively be initiated by a downhole controller. Thus,
formation fluid 762
may enter the testing tool through port 754, as indicated by arrows 733. In
the example of
FIGURE 8D, packer element 704 has not been inflated, increasing thereby the
risk of particles,
such as sand or other debris, to enter the testing tool via port 754. In some
cases, there may still
be particles in suspension in formation fluid 754. It may be advantageous to
pulverize these
particles with particle breaking devices, such as particles breaking devices
160, 161 or 162 on
FIGURE 2. Formation fluid may then be analyzed by one or more sensor in the
testing tool
and/or captured in a cavity in the testing tool and brought to the surface for
further analysis, as
known by those skilled in the art.
In the example of FIGURE 8C, the second testing interval 771 is located below
the
first interval, for example to take advantage of gravity during a sampling
operation of a heavy
hydrocarbon in formation 12. It will be appreciated by those skilled in the
art that a second
testing interval may have alternatively be chosen above the first interval,
for example by
extending initially packer elements 704 and 705 for sealing the first testing
interval.
Alternatively, the second testing interval may comprise the first testing
interval, for example by
extending packer element 704 and retracting packer element 703.
Although the present invention and its advantages have been described in
detail, it
should be understood that various changes, substitutions and alterations can
be made herein
without departing from the scope of the invention as defined by the appended
claims.
Moreover, the scope of the present application is not intended to be limited
to the particular
21
CA 02594042 2007-07-18
embodiments of the process, machine, manufacture, composition of matter,
means, methods and
steps described in the specification. As one of ordinary skill in the art will
readily appreciate
from the disclosure of the present invention, processes, machines,
manufacture, compositions of
matter, means, methods, or steps, presently existing or later to be developed
that perform
substantially the same function or achieve substantially the same result as
the corresponding
embodiments described herein may be utilized according to the present
invention. Accordingly,
the appended claims are intended to include within their scope such processes,
machines,
manufacture, compositions of matter, means, methods, or steps.
22
