U.S. patent application number 10/041917 was filed with the patent office on 2002-06-06 for method and apparatus for continuously testing a well.
Invention is credited to Langseth, Bjorn, Patel, Dinesh R., Spiers, Christopher W..
Application Number | 20020066563 10/041917 |
Document ID | / |
Family ID | 27384022 |
Filed Date | 2002-06-06 |
United States Patent
Application |
20020066563 |
Kind Code |
A1 |
Langseth, Bjorn ; et
al. |
June 6, 2002 |
Method and apparatus for continuously testing a well
Abstract
One embodiment of my invention comprises a tool string for
testing a wellbore formation that includes a production inlet, an
injection outlet, and a sampler apparatus. Fluid is taken from a
production zone, into the tool string through the production inlet,
out of the tool string through the injection outlet, and into the
injection zone. Within the interior of the tool string, the sampler
apparatus takes samples of the fluid flowing therethrough. In
another embodiment, a large volume of sample fluid is trapped
within the interior of the tool string, such as between two valves,
and is removed from the wellbore along with the tool string
subsequent to the test. In another embodiment, the tool string
includes at least one perforating gun to perforate one of the
production and injection zones. The tool string may also include
two perforating guns to perforate both the production and injection
zones. One of the two perforating guns may be an oriented
perforating gun so that upon activation the shape charges do not
disturb any of the cables, data lines, or transmission lines
associated with the tool string.
Inventors: |
Langseth, Bjorn; (Missouri
City, TX) ; Spiers, Christopher W.; (Sugar Land,
TX) ; Patel, Dinesh R.; (Sugar Land, TX) |
Correspondence
Address: |
PATENT COUNSEL
Schlumberger Reservoir Completions Center
14910 Airline Road
Rosharon
TX
77583-1590
US
|
Family ID: |
27384022 |
Appl. No.: |
10/041917 |
Filed: |
January 8, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10041917 |
Jan 8, 2002 |
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09552910 |
Apr 20, 2000 |
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09552910 |
Apr 20, 2000 |
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09514628 |
Feb 28, 2000 |
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09514628 |
Feb 28, 2000 |
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09512438 |
Feb 25, 2000 |
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60130589 |
Apr 22, 1999 |
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Current U.S.
Class: |
166/264 ;
166/250.01; 166/311; 166/373; 166/66.7 |
Current CPC
Class: |
E21B 49/081 20130101;
E21B 49/088 20130101; E21B 49/08 20130101 |
Class at
Publication: |
166/264 ;
166/250.01; 166/311; 166/373; 166/66.7 |
International
Class: |
E21B 049/08 |
Claims
I claim:
1. A method for testing a well having a production zone and an
injection zone, comprising: producing fluid from the production
zone into a tool string, the tool string including a compartment;
injecting the fluid from the tool string into the injection zone;
trapping a volume of dead fluid within the compartment; and
removing the volume of dead fluid from the compartment once the
tool string is retrieved to the surface.
2. The method of claim 1, further comprising: measuring the volume
of any gas trapped within the compartment.
3. The method of claim 1, further comprising: venting any gas
trapped within the compartment prior to the removal of the volume
of dead fluid from the compartment.
4. The method of claim 3, wherein the venting step comprises
attaching a vent valve to the tool string and allowing any gas
trapped within the compartment to vent through the vent valve.
5. The method of claim 4, further comprising: transferring the
volume of dead fluid from the compartment into at least one
container.
6. The method of claim 1, wherein the removing step comprises:
attaching a valve assembly to the tool string, the valve assembly
including a piston and a conduit, the conduit disposed through the
piston; and sliding the piston within the compartment towards the
dead fluid thereby forcing the fluid to pass into the conduit.
7. The method of claim 6, wherein the piston is slidably disposed
on the conduit.
8. The method of claim 1, wherein the removing step comprises:
attaching a valve assembly to the tool string, the valve assembly
including a piston and a passage; positioning the piston so that a
majority of the dead fluid is intermediate the piston and the
passage; and sliding the piston towards the passage thereby forcing
the dead fluid to pass into the passage.
9. The method of claim 1, wherein the removing step comprises:
attaching a valve assembly to the tool string, the valve assembly
including a conduit and a passage; and injecting a pressurized
fluid through the conduit and into the compartment wherein the
pressurized fluid forces the dead fluid out of the compartment
through the passage.
10. The method of claim 1, wherein the removing step comprises:
attaching a valve assembly to the tool string, the valve assembly
including a conduit and a passage; and injecting a pressurized
fluid through the passage and into the compartment wherein the
pressurized fluid forces the dead fluid out of the compartment
through the conduit.
11. A device for removing a dead fluid from a downhole tool string,
the tool string including a compartment, comprising: a valve
assembly including a piston, a conduit, and a passage; the conduit
in fluid communication with the dead fluid in the compartment; the
conduit disposed through the piston; the piston slidingly disposed
within the compartment; and the passage in fluid communication with
the compartment.
12. The device of claim 11, wherein the passage is in fluid
communication with the interior of the valve assembly.
13. The device of claim 11, wherein the passage provides fluid
communication between a pressure source and the compartment.
14. The device of claim 13, wherein pressurized fluid from the
pressure source causes the piston to slide within the compartment
towards the dead fluid forcing the dead fluid into the conduit.
15. The device of claim 14, wherein: the piston is slidably
disposed on the conduit; and the pressurized fluid causes the
piston to slide on the conduit within the compartment towards the
dead fluid forcing the dead fluid into the conduit.
16. The device of claim 11, wherein the conduit provides fluid
communication between the compartment and at least one
container.
17. The device of claim 11, wherein the conduit is in fluid
communication with a pressure source.
18. The device of claim 11, wherein the passage provides fluid
communication between at least one container and the
compartment.
19. The device of claim 11, wherein the piston includes at least
one selectively closable fluid communication port therethrough.
20. The device of claim 19, wherein the ports of the piston are
initially open and the piston is moved within the compartment so
that a majority of the dead fluid is intermediate the piston and
the passage.
21. The device of claim 20, wherein the ports of the piston are
closed when the piston reaches the location wherein a majority of
the dead fluid is intermediate the piston and the passage.
22. The device of claim 21, wherein: the conduit is in fluid
communication with a pressure source; and pressurized fluid from
the pressure source causes the piston to slide within the
compartment towards the passage forcing the dead fluid through the
passage.
23. The device of claim 11, wherein: the valve assembly further
comprises a stuffing box; and the conduit is sealingly disposed
through the stuffing box.
24. The device of claim 23, wherein the conduit is slidingly
disposed through the stuffing box.
25. A device for removing a dead fluid from a downhole tool string,
the tool string including a compartment, comprising: a valve
assembly including a conduit and a passage; the conduit in fluid
communication with the dead fluid in the compartment; the conduit
movably disposed within the compartment; and the passage in fluid
communication with the compartment.
26. The device of claim 25, wherein the passage provides fluid
communication between the compartment and a pressure source.
27. The device of claim 26, wherein pressurized fluid from the
pressure source forces the dead fluid into the conduit.
28. The device of claim 25, wherein the conduit provides fluid
communication between the compartment and a pressure source.
29. The device of claim 28, wherein pressurized fluid from the
pressure source forces the dead fluid into the passage.
30. The device of claim 25, wherein: the valve assembly further
comprises a stuffing box; and the conduit is sealingly disposed
through the stuffing box.
31. The device of claim 30, wherein the conduit is slidingly
disposed through the stuffing box.
32. A method for removing a fluid from a downhole tool string, the
tool string including a compartment, the method comprising:
attaching a valve assembly to the tool string, the valve assembly
including a piston and a conduit, the conduit disposed through the
piston; and sliding the piston within the compartment towards the
fluid thereby forcing the fluid to pass into the conduit.
33. The method of claim 32, wherein: the valve assembly further
includes a passage providing fluid communication between a pressure
source and the compartment; and wherein the sliding step comprises
injecting pressurized fluid through the passage which causes the
piston to slide within the compartment towards the fluid.
34. The method of claim 33, wherein: the piston is slidably
disposed on the conduit; and the pressurized fluid causes the
piston to slide on the conduit within the compartment towards the
fluid.
35. A method for removing a fluid from a downhole tool string, the
tool string including a compartment, the method comprising:
attaching a valve assembly to the tool string, the valve assembly
including a piston and a passage; positioning the piston so that a
majority of the fluid is intermediate the piston and the passage;
and sliding the piston towards the passage thereby forcing the
fluid to pass into the passage.
36. The method of claim 35, wherein the piston includes at least
one selectively closable fluid communication port therethrough.
37. The method of claim 36, wherein prior to the sliding step the
ports of the piston are initially open and the piston is moved
within the compartment so that a majority of the fluid is
intermediate the piston and the passage.
38. The method of claim 37, wherein the ports of the piston are
closed when the piston reaches the location wherein a majority of
the fluid is intermediate the piston and the passage.
39. The method of claim 38, wherein: the valve assembly further
includes a conduit providing fluid communication between a pressure
source and the compartment; and wherein the sliding step comprises
injecting pressurized fluid through the conduit which causes the
piston to slide within the compartment towards the passage.
40. The method of claim 35, wherein: the valve assembly further
includes a conduit providing fluid communication between a pressure
source and the compartment; and wherein the sliding step comprises
injecting pressurized fluid through the conduit which causes the
piston to slide within the compartment towards the passage.
41. A method for removing a fluid from a downhole tool string, the
tool string including a compartment, the method comprising:
attaching a valve assembly to the tool string, the valve assembly
including a conduit and a passage; and injecting a pressurized
fluid through the conduit wherein the pressurized fluid forces the
dead fluid out of the compartment through the passage.
42. A method for removing a fluid from a downhole tool string, the
tool string including a compartment, the method comprising:
attaching a valve assembly to the tool string; the valve assembly
including a conduit and a passage; and injecting a pressurized
fluid through the passage wherein the pressurized fluid forces the
dead fluid out of the compartment through the conduit.
43. A tool string for testing a well having a production zone and
an injection zone, comprising: a production inlet that provides
communication between the production zone and the interior of the
tool string; an injection outlet that provides communication
between the injection zone and the interior of the tool string; and
at least one fluid identifier for monitoring the oil content of
fluid from the production zone.
44. A method of testing a well having a production zone and an
injection zone, comprising: deploying a tool string into the well;
producing fluid from the production zone into the tool string;
injecting the fluid into the injection zone; and monitoring the oil
content of the fluid.
45. A tool string for testing a well having a production zone and
an injection zone, comprising: a production inlet that provides
communication between the production zone and the interior of the
tool string; an injection outlet that provides communication
between the injection zone and the interior of the tool string; and
at least one solids detector for detecting flowing solids.
46. A method of testing a well having a production zone and an
injection zone, comprising: deploying a tool string into the well;
producing fluid from the production zone into the tool string;
injecting the fluid into the injection zone; and detecting solids
contained in the fluid.
47. A tool string for testing a well having a production zone and
an injection zone, comprising: a production inlet that provides
communication between the production zone and the interior of the
tool string; an injection outlet that provides communication
between the injection zone and the interior of the tool string; and
at least one fluid density meter for monitoring the density of
fluid from the production zone.
48. A method of testing a well having a production zone and an
injection zone, comprising: deploying a tool string into the well;
producing fluid from the production zone into the tool string;
injecting the fluid into the injection zone; and monitoring the
density of the fluid.
Description
[0001] This application is a continuation-in-part of U.S.
Non-Provisional Application Serial No. 09/514,628 filed by Langseth
on Feb. 28, 2000 and entitled "Method and Apparatus for
Continuously Testing a Well", which application is a
continuation-in-part of U.S. Non-Provisional Application Serial No.
09/512,438 filed by Langseth, Spiers, Patel, and Vella on Feb. 25,
2000 and entitled "Method and Apparatus for Testing a Well", which
application claims priority under 35 U.S.C. .sctn. 119(e) to U.S.
Provisional Application Serial No. 60/130,589, entitled "Method and
Apparatus for Testing a Well," filed Apr. 22, 1999.
BACKGROUND
[0002] This invention relates to methods and apparatus for testing
wells.
[0003] After a wellbore has been drilled, testing (e.g., drillstem
testing or production testing) may be performed to determine the
nature and characteristics of one or more zones of a formation
before the well is completed. Characteristics that are tested for
include the permeability of a formation, volume, pressure, skin,
and temperature of a reservoir in the formation, fluid content of
the reservoir, and other characteristics. To obtain the desired
data, fluid samples may be taken as well as measurements made with
downhole sensors and other instruments.
[0004] One type of testing that may be performed is a conventional
drillstem test. A drillstem test is a test taken through the
drillstem by means of special testing equipment attached to the
drillstem. The special equipment, which may include pressure and
temperature sensors and fluid identifiers, determines if fluid
components in commercial quantities have been encountered in the
wellbore. The fluid components are normally then produced to the
surface and are either flared or transported to storage containers.
Producing the fluid components to the surface at the testing stage,
and particularly flaring the fluid components at the surface,
creates a potential environmental hazard and is quickly becoming a
discouraged practice.
[0005] Another type of testing that may be performed is a
closed-chamber drillstem test. In a closed-chamber test, the well
is closed in at the surface when producing from the formation under
test. Instruments may be positioned downhole and at the surface to
make measurements. One advantage offered by closed-chamber testing
is that hydrocarbons and other well fluids are not produced to the
surface during the test. This alleviates some of the environmental
concerns associated with having to burn off or otherwise dispose of
hydrocarbons that are produced to the surface. However,
conventional closed-chamber testing is limited in its accuracy and
completeness due to limited flow of fluids from the formation under
test. The amount of fluids that can be produced from the zone under
test may be limited by the volume of the closed chamber.
[0006] A further issue associated with testing a well is
communication of test results to the surface. Some type of
mechanism is typically preferred to communicate real-time test data
to well surface equipment. One possible communications mechanism is
to run an electrical cable down the wellbore to the sensors. An
alternative to real-time data gathering is to utilize downhole
recorders that record the downhole sensor data and are subsequently
retrieved to the surface after the test.
[0007] In addition, when testing is conducted in a cased wellbore,
the casing must be perforated in order to flow the hydrocarbons
into the wellbore. Perforating methods used to perforate the
appropriate zones include wireline and tubing conveyed perforating.
If tubing conveyed, the perforating guns are run downhole attached
to the testing instruments. If wireline conveyed, the perforating
guns are run first, and the testing instruments are deployed
downhole once the guns are removed from the wellbore. The
perforating jobs tend to be more intricate if more than one zone
needs to be perforated within the wellbore.
[0008] A need thus exists for an improved method and apparatus for
testing wells.
SUMMARY
[0009] One embodiment of my invention comprises a tool string for
testing a wellbore formation that includes a production inlet, an
injection outlet, and a sampler apparatus. Fluid is taken from a
production zone, into the tool string through the production inlet,
out of the tool string through the injection outlet, and into the
injection zone. Within the interior of the tool string, the sampler
apparatus takes samples of the fluid flowing therethrough. In
another embodiment, a large volume of sample fluid is trapped
within the interior of the tool string, such as between two valves,
and is removed from the wellbore along with the tool string
subsequent to the test. In another embodiment, the tool string
includes at least one perforating gun to perforate one of the
production and injection zones. The tool string may also include
two perforating guns to perforate both the production and injection
zones. One of the two perforating guns may be an oriented
perforating gun so that upon activation the shape charges do not
disturb any of the cables, data lines, or transmission lines
associated with the tool string.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 illustrates one embodiment of the tool string
disposed in a wellbore.
[0011] FIG. 2 illustrated another embodiment of the tool string
disposed in a wellbore.
[0012] FIG. 3 illustrates an embodiment of the tool string,
including a multi-port packer as the upper sealing element and a
packer stinger assembly as the lower sealing element.
[0013] FIG. 4 illustrates one embodiment for operating the valves
located below the upper sealing element.
[0014] FIG. 5 illustrates another embodiment for operating the
valves located below the upper sealing element.
[0015] FIG. 6 illustrates another embodiment for operating the
valves located below the upper sealing element.
[0016] FIG. 7 illustrates one embodiment of the tool string,
including a perforating gun to perforate the lower zone.
[0017] FIG. 8 illustrates another embodiment of the tool string,
including a perforating gun to perforate the lower zone.
[0018] FIG. 9 illustrates an embodiment of the tool string,
including two perforating guns, one for perforating the upper zone
and the second for perforating the lower zone.
[0019] FIG. 10 illustrates an embodiment of the tool string,
including an oriented perforating gun for perforating the upper
zone and a perforating gun for perforating the lower zone.
[0020] FIG. 11 illustrates a first embodiment of the dedicated
surface equipment used to vent off the gas trapped in and to drain
the dead-oil volume.
[0021] FIG. 12 illustrates an embodiment of the tool string as
disclosed in the Parent Application.
[0022] FIG. 13 illustrates another embodiment of the tool string as
disclosed in the Parent Application.
[0023] FIG. 14 illustrates another embodiment of the tool string as
disclosed in the Parent Application.
[0024] FIG. 15 illustrates another embodiment of the tool string as
disclosed in the Parent Application.
[0025] FIG. 16 illustrates another embodiment of the tool string as
disclosed in the Parent Application.
[0026] FIG. 17 illustrates another embodiment of the tool string as
disclosed in the Parent Application.
[0027] FIG. 18 illustrates a second embodiment of the dedicated
surface equipment used to vent off the gas trapped in and to drain
the dead-oil volume.
[0028] FIG. 19 illustrates a third embodiment of the dedicated
surface equipment used to vent off the gas trapped in and to drain
the dead-oil volume.
[0029] FIG. 20 illustrates a fourth embodiment of the dedicated
surface equipment used to vent off the gas trapped in and to drain
the dead-oil volume.
[0030] FIG. 21 illustrates a fifth embodiment of the dedicated
surface equipment used to vent off the gas trapped in and to drain
the dead-oil volume.
[0031] FIG. 22 illustrates a cross-section of the flow bypass
housing.
[0032] FIG. 23 illustrates a longitudinal section of the flow
bypass housing.
DETAILED DESCRIPTION
[0033] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those skilled in the art that the present
invention may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0034] As used here, the terms "up" and "down"; "upper" and
"lower"; "upwardly" and "downwardly"; "below" and "above"; and
other like terms indicating relative positions above or below a
given point or element are used in this description to more clearly
describe some embodiments of the invention. However, when applied
to equipment and methods for use in wells that are deviated or
horizontal, such terms may refer to a "left to right" or "right to
left", or other relationship as appropriate. Further, the relative
positions of the referenced components may be reversed.
[0035] One embodiment of the tool string 10 of this invention is
illustrated in FIG. 1. Tool string 10 is positioned in a wellbore
12 that may be lined with a casing 14. The wellbore 12 may include
a production zone 16 and an injection zone 18 and may be a part of
a subsea well or a land well. Tool string 10 is designed to perform
an extensive flow test collecting data and oil samples without
producing formation fluids to the surface. Tool string 10 is
capable of conducting long flow periods and build up periods to
evaluate reservoir limits or boundaries. In one embodiment, tool
string 10 provides real time surface readout of all the data
collected during the flow and shut-in phases. In the preferred
embodiment, tool string 10 has a modular design wherein different
components may be added to or removed from the tool string 10 at
the discretion of the operator.
[0036] Tool string 10 may be conveyed by tubing, wireline, or
coiled tubing, depending on the requirements of the operator and/or
the depth of operation. In the preferred embodiment, the casing 14
adjacent production zone 16 is perforated with production zone
perforations 17, and the casing 14 adjacent injection zone 18 is
perforated with injection zone perforations 19.
[0037] In the embodiment of FIG. 1, tool string 10 includes a
production inlet 20, an injection outlet 22, a pump 24, and a flow
valve 26. Generally, pump 24 when activated causes production zone
fluid to flow from the production zone 16 through the production
zone perforations 17, into the tool string 10 through the
production inlet 20, through the tool string 10 interior, out of
the tool string 10 through the injection outlet 22, and into the
injection zone 18 through the injection zone perforations 19. Flow
valve 26 controls the flow of fluid through the interior of tool
string 10.
[0038] Tool string 10 may be used to induce flow from a lower
production zone 16 to a higher injection zone 18 as shown in FIG. 1
or from a higher production zone 16 to a lower injection zone 16 as
shown in FIG. 2. For purposes of brevity, the higher of the
production zone 16 and the injection zone 18 will hereinafter be
referred to as the upper zone 92, and the lower of the production
zone 16 and the injection zone 18 will hereinafter be referred to
as the lower zone 94. Thus, for example, in FIG. 1, the injection
zone 18 is the upper zone 92, and the production zone 18 is the
lower zone 94. On the other hand, in FIG. 2, the production zone 18
is the upper zone 92, and the injection zone 18 is the lower zone
94.
[0039] Tool string 10 preferably includes an upper sealing element
28 and a lower sealing element 30, which each may comprise packers.
Upper sealing element 28 is positioned above the upper zone 92,
isolating the upper zone 92 from the remainder of the annulus 15
uphole of the upper sealing element 28. Lower sealing element 30 is
positioned between the upper zone 92 and the lower zone 94,
isolating the upper zone 92 from the lower zone 94. As is
well-known in the art, upper sealing element 28 and lower sealing
element 30 are adapted to move into sealing engagement with the
wellbore 12 or casing 14 upon their actuation.
[0040] In one embodiment as best shown in FIG. 3, upper sealing
element 28 comprises a multi-port packer 56 that allows access to
power and data cables and transmission lines 58 below the upper
sealing element 28. As is known in the art, multi-port packers 56
include secondary ports 60 through their body in addition to the
main bore 62. The secondary ports 60 are used to pass cables or
transmission lines 58 therethrough, which cables and lines 58 are
operatively connected to the tools and sensors below the upper
sealing element 28, as will be described herein.
[0041] In one embodiment, lower sealing element 30 comprises a
packer stinger assembly 64. Packer stinger assembly 64 includes a
stinger portion 66 and a packer body portion 68. Packer body
portion 68 includes the sealing elements 70 that seal with the
wellbore 12 or casing 14 as well as packer body portion bore 72.
Stinger portion 66 is connected to the remainder of tool string 10
and is sized and constructed to be inserted into the packer body
portion bore 72. A packer stinger assembly seal 74, disposed either
on stinger portion 66 or packer body portion 68, enables the
sealing engagement of the stinger portion 66 within the packer body
portion 68.
[0042] Packer stinger assembly 64 is beneficial because the lower
sealing element 30 can be exposed to debris and sand from the
formation located above it. The debris and sand could fill up the
annular region between the lower sealing element 30 and the casing
14 or wellbore 12, which could prevent the subsequent retrieval of
the lower sealing element 30. If the packer stinger assembly 64 is
used, the stinger portion 66 can be easily retrieved by disengaging
it from the packer body portion 68, and the packer body portion 68
can be subsequently removed with a specialized fishing tool. In
addition, packer stinger assembly 64 is beneficial because the
engagement between the stinger portion 66 and the packer body
portion 68 compensates for any tubing movement between the upper
sealing element 28 and the lower sealing element 30.
[0043] Production inlet 20 provides fluid communication between the
annulus 15 region adjacent the production zone 16 and the interior
of the tool string 10. In the embodiment shown in FIG. 1,
production inlet 20 is located below the lower sealing element 30
and provides fluid communication between the annulus 15 region
below the lower sealing element 30 and the interior of the tool
string 10. In the embodiment shown in FIG. 2, production inlet 20
is located intermediate the upper sealing element 28 and the lower
sealing element 30 and provides fluid communication between the
interior of the tool string 10 and the annulus 15 region that is
intermediate the upper sealing element 28 and the lower sealing
element 30.
[0044] In the preferred embodiment, production inlet 20 comprises a
section of production slotted tubing 36 on tool string 10.
Production inlet 20 may also comprise ported tubing (not shown in
the Figures). In the preferred embodiment production inlet 20
includes a filter mechanism, gravel pack, or other sand control
means, which prohibits flow of particles that are greater than a
pre-determined size. The filter mechanism may comprise a filter
screen on the production inlet 20 or the construction of the slots
of the production slotted tubing 36 or the ports of the ported
tubing being the certain predetermined size.
[0045] Injection outlet 22 provides fluid communication between the
annulus 15 region adjacent the injection zone 18 and the interior
of the tool string 10. In the embodiment shown in FIG. 1, injection
outlet 22 is located intermediate the upper sealing element 28 and
the lower sealing element 30 and provides fluid communication
between the interior of the tool string 10 and the annulus 15
region intermediate the upper sealing element 28 and the lower
sealing element 30. In the embodiment shown in FIG. 2, injection
outlet 22 is located below the lower sealing element 30 and
provides fluid communication between the interior of the tool
string 10 and the annulus 15 region that is below the lower sealing
element 30. In either embodiment, injection outlet 22 is preferably
located on the pressure end 43 of pump 24.
[0046] In the preferred embodiment, injection outlet 22 comprises a
section of ported tubing 38 on tool string 10. Injection outlet 22
may also comprise slotted tubing (not shown in the Figures). In one
embodiment injection outlet 22 includes a filter mechanism, gravel
pack, or other sand control means, which prohibits flow of
particles that are greater than a pre-determined size. The filter
mechanism may also comprise a filter screen on the injection outlet
22 or the construction of the slots of the injection slotted tubing
or the ports of the ported tubing being the certain pre-determined
size.
[0047] Pump 24 preferably comprises a submersible pump that is
operatively connected to an electric motor 42. Pump 24 may,
however, also comprise other types of pumps. A power cable 90
extends through upper sealing element 28, such as through one of
the secondary ports 60 of multi-port packer 56, and is operatively
connected to motor 42.
[0048] In the embodiment illustrated in FIG. 1 in which the
injection zone 18 is the upper zone 92, the pump 24 is preferably
positioned higher up on the tool string 10 so that motor 42 is
proximate and preferably below the injection zone 18. The flow of
fluid around motor 42 serves to cool the motor 42 during operation.
Also preferably and in the embodiment of FIG. 1, pump 24 is located
so that flow valve 26 is on the suction end 41 of pump 24 and flow
valve 26 is downhole of pump 24.
[0049] In the embodiment illustrated in FIG. 2 in which the
production zone 16 is the upper zone 92, pump 24 is preferably
positioned lower in the tool string 10 so that pump 24 is downhole
of sampling valve 52, which will be described herein, and the
suction end 41 of pump 24 is proximate sampling valve 52.
Preferably, motor 42 is disposed intermediate pump 24 and sampling
valve 52. In this embodiment, pump 24 may also require a shroud 45
around motor 42 to communicate the suction side 41 of pump 24 to
the remainder of the tool string 10 uphole of motor 42.
[0050] Flow valve 26 is located within tool string 10 intermediate
the production inlet 20 and the injection outlet 22. In the
preferred embodiment, flow valve 26 comprises a ball valve that
defines a full bore through tool string 10 in the open position and
prohibits flow through tool string 10 in the closed position. Flow
valve 26 may also comprise other types of valves such as flapper
valves or disc valves.
[0051] Tool string 10 may also comprise a barrier valve mechanism
44 located uphole of the injection outlet 22 in the embodiment of
FIG. 1 and uphole of the production inlet 20 in the embodiment of
FIG. 2. In the closed position, barrier' valve mechanism 44
prohibits flow to the surface during the operation of tool string
10. In one embodiment, barrier valve mechanism 44 comprises a ball
valve that defines a full bore through tools string 10 in the open
position and prohibits flow through tool string 10 in the closed
position. Barrier valve mechanism 44 may also comprise two ball
valves in series, such as the Schlumberger IRIS Safety Valve, one
valve being a cable cutting valve and the second valve being a
sealing valve. In another embodiment, barrier valve mechanism 44
comprises a ball valve, which selectively prohibits flow through
the tool string 10, and a circulation valve, which selectively
enables flow from the interior of the tool string 10 to the annulus
15, such as the Schlumberger IRIS Dual Valve. Barrier valve
mechanism 44 is preferably operated from the surface by means known
in the art, such as pressure pulse telemetry or control lines.
[0052] Preferably, tool string 10 also comprises a sampling valve
52 located downhole of the flow valve 26 and above the production
inlet 20 in the embodiment of FIG. 1 or above the injection outlet
in the embodiment of FIG. 2. Preferably, sampling valve 52
comprises a ball valve that defines a full bore through tool string
10 in the open position and prohibits flow through tool string 10
in the closed position.
[0053] In one embodiment, tool string 10 also comprises a
circulating valve 100 located below sampling valve 52 and above
lower sealing element 30. Circulating valve 100 may comprise a
sleeve valve, provides fluid communication between the interior of
the tool string 10 and the annulus 15 when in the open position,
and prohibits fluid communication between the interior of the tool
string 10 and the annulus 15 when in the closed position. In one
embodiment, sampling valve 52 and circulating valve 100 comprise a
Schlumberger IRIS Dual Valve that includes one ball valve and one
sleeve valve.
[0054] Tool string 10 may also include at least one pressure and
temperature unit 46, each unit 46 including at least one and
preferably a plurality of pressure and temperature sensors for
recording and monitoring the pressure and temperature of the fluid
flowing through the interior of tool string 10. Preferably,
pressure and temperature units 46 are located intermediate the
production inlet 20 and the injection outlet 22. Preferably, tool
string 10 includes at least two pressure and temperature units 46,
one unit 46 proximate the production zone 16 and the other unit 46
proximate the injection zone 18. It is also noted that the units 46
may be constructed to take measurements of fluid either in the
interior of the tool string 10 or in the annulus 15. It is noted
that the data taken by the pressure and temperature units 46 has a
number of uses, including to modify the flow rate of the fluid
within tool string 10 so that its fluid pressure does not drop
below the bubble point.
[0055] Tool string 10 may also include a flow meter 48 for
recording and monitoring the flow rate of the fluid flowing through
the interior of tool string 10. Flow meter 48 is located
intermediate the production inlet 20 and the injection outlet
22.
[0056] Tool string 10 may also include a fluid identifier 50,
preferably including an optical fluid analyzer, for recording and
monitoring the oil content in the fluid flowing through the
interior of tool string 10. Fluid identifier 50 is preferably able
to take at least two measurements: visible and near-infrared
absorption for fluid composition and change in index of refraction
for gas composition. Fluid identifier 50 is located intermediate
the production inlet 20 and the injection outlet 22.
[0057] Tool string 10 may also include a solid detector (not shown)
for detecting solids, such as sand, flowing from the production
zone 16 or a fluid density meter (not shown) for monitoring the
density of the fluid from the production zone 16. Solid detector
and fluid density meter may be located intermediate the production
inlet 20 and the injection outlet 22. Other sensors or meters that
may be included are H.sub.2S detectors, CO.sub.2 detectors, and
water cut meters.
[0058] In the preferred embodiment, tool string 10 also includes a
sampler apparatus 54 that contains at least one PVT sample chamber.
Sampler apparatus 54 is preferably part of the tool string 10, as
opposed to being run on slick line or wireline independent of the
tool string 10. Sampler apparatus 54 preferably includes a
plurality of PVT sampler chambers. The plurality of sampler
chambers may be triggered all at once or at separate times. Sampler
apparatus 54 is located intermediate the production inlet 20 and
the injection outlet 22. Sampler apparatus 54 may also include an
activation verification mechanism (not shown) which automatically
signals at the surface when the sampler apparatus has successfully
obtained a sample of fluid. Activation verification mechanism may
comprise a pressure sensor within each sampler chamber or a switch
triggered upon the stroke of the sampler chamber mechanism.
[0059] A data line 104 is preferably run from the surface of the
wellbore 12 to the tool string 10. Data line 104 is preferably in
communication with the pressure and temperature units 46, the flow
meter 48, the fluid identifier 50, the solid detector, the fluid
density meter, and the other meters/sensors. It is noted that data
line 104 must pass through the upper sealing element 28 and
preferably does so by way of one of the secondary ports 60 of the
multi-port packer 56. Data line 104 transmits the readings of the
pressure and temperature units 46, the flow meter 48, the fluid
identifier 50, the solid detector, the fluid density meter, and the
other meters/sensors to the surface, preferably continuously but at
the least in time intervals. Moreover, in one embodiment, data line
104 and the instruments, 46, 48, and 50 (and the other
meters/sensors), are constructed so that signals may be sent from
the surface to the instruments, 46, 48, and 50 (and the other
meters/sensors), which signals can modify characteristics of the
instruments such as data tolerances or the time intervals at which
readings are taken. As an example, data line 104 may comprise a
fiber optic line.
[0060] In one embodiment, tool string 10 also includes a
communication component 106 preferably located above the upper
sealing element 28. Alternatively, communication component 106 may
be located anywhere on the tool string 10. Data line 104, in this
embodiment, extends from the communication component 106 to each
instrument, 46, 48, and 50 (and the other meters/sensors). A
transmission line 108 extends from the communication component 106
to the surface. All signals from the surface pass through the
transmission line 108 and are interpreted by the communication
component 106, which then operates the relevant instrument, 46, 48,
and 50 (and the other meters/sensors), appropriately by sending a
signal through data line 104. All signals from the instruments, 46,
48, and 50 (and the other meters/sensors), pass through data line
104 and are interpreted by the communication component 106, which
then relays the information to the surface through the transmission
line 108. As an example, transmission line 108 may comprise a fiber
optic line.
[0061] In another embodiment, instead of including data line 104,
tool string 10 includes at least one recorder (not shown) for
recording the data taken by the pressure and temperature units 46,
the flow meter 48, the fluid identifier 50, the solid detector, the
fluid density meter, and the other meters/sensors. In this
embodiment, the data is recorded while the tool string 10 is
downhole and is then retrieved once the tool string 10 is removed
from the wellbore 12. Tool string 10 may include a separate
recorder for each of the relevant instruments.
[0062] The flow valve 26, sampling valve 52, and circulating valve
100 are, as illustrated in the Figures, located below upper sealing
element 28. There are several ways in which the flow valve 26,
sampling valve 52, and circulating valve 100 can be operated from
above the upper sealing element 28.
[0063] In one embodiment (not shown in the Figures), at least one
passageway provides communication from above the upper sealing
element 28 to the valves, 26, 52, and/or 100. In the preferred
embodiment, the passageway comprises a hydraulic line that is
passed through the upper sealing element 28 (such as through a
secondary port 60 of the multi-port packer 56) and is operatively
connected to the valves, 26, 52, and 100. In one embodiment, the
hydraulic line extends to the surface and pressure therein operates
the valve. In another embodiment, the hydraulic line is open to the
annulus 15 above the upper sealing element 28. In this embodiment,
hydraulic pressure in the line applied to the annulus 15 above the
upper sealing element 28 acts to operate the flow valve 26,
sampling valve 52, and circulating valve 100. Each valve may have
its own independent hydraulic line. In another embodiment, one
hydraulic line is connected to the valves.
[0064] In another embodiment as shown in FIG. 4, tool string 10
includes a local telemetry bus 76 and an interface module 78. Local
telemetry bus 76, which may correspond to data line 104, extends
through upper sealing element 28 and communicates with interface
module 78. Interface module 78 is operatively connected to a valve,
26, 52, or 100. Local telemetry bus 76 is capable of handling data
transfer and tool operation commands. A command signal from the
surface sent through the local telemetry bus 76 is received by the
interface module 78. Interface module 78 interprets the command
signal and responds by operating the valve, 26, 52, or 100, in the
appropriate manner. Additionally, tool status may be sent through
local telemetry bus 76 from the downhole environment to the
surface. In one embodiment, each valve, 26, 52, or 100, has its own
independent local telemetry bus. In another embodiment, all of the
valves, 26, 52, and 100, operate through one local telemetry bus.
In a further embodiment, each valve, 26, 52, or 100, has its own
interface module. In another embodiment, all of the valves, 26, 52,
and 100, operate through one interface module.
[0065] In another embodiment as shown in FIG. 5, tool string 10
includes a direct control line 80, which may correspond to data
line 104, that extends through upper sealing element 28 and is in
direct communication with solenoids that operate the valves, 26,
52, and 100. Electric pulses sent through the direct control line
80 are used to operate the solenoid valves. In one embodiment, each
valve, 26, 52, or 100, has its own independent direct control line.
In another embodiment all of the valves, 26, 52, and 100, are
operated by one direct control line.
[0066] In another embodiment as shown in FIG. 6, tool string 10
includes an acoustic or electromagnetic telemetry system 82 and an
interface module 84. Acoustic telemetry system 82 is preferably
located above upper sealing element 28 and includes a signal line
86 and an acoustic system module 88. Acoustic system module 88 may
correspond to communication component 106, and signal line 86 may
correspond to transmission line 108. Signals are sent from the
surface through signal line 86 and are received by the acoustic
system module 88. Acoustic system module 88 then acoustically
transmits command signatures downhole, past the upper sealing
element 28, to the acoustic interface module 84. Acoustic interface
module 84 interprets the acoustic command signatures and responds
by operating the valve, 26, 52, or 100, in the appropriate
corresponding manner. In one embodiment, each valve, 26, 52, or
100, has its own independent acoustic interface module. In another
embodiment, all of the valves, 26, 52, and 100, are operated by one
acoustic interface module.
[0067] The sampler apparatus 54 is, as illustrated in the Figures,
also located below upper sealing element 28. The sampler apparatus
54 may be operated from above the upper sealing element 28
utilizing the same techniques discussed with respect to the valves,
26, 52, and 100. That is, the sampler apparatus 54 may be operated
by use of a hydraulic line exposed to the annulus above the upper
sealing element 28, a local telemetry bus and an interface module,
a direct control line and solenoids, or an acoustic telemetry
system and an acoustic interface module.
[0068] Schlumberger's IRIS Dual Valve and IRIS Safety Valve have
been identified herein as potential candidates for some of the
valves of tool string 10. One of the benefits of using the IRIS
Dual and Safety Valves is that they may be activated electrically,
by applied pressure, or by pressure pulse telemetry. Thus, with no
or few modifications, the IRIS Dual and Safety Valves may be
operated by most if not all of the techniques discussed above (a
hydraulic line exposed to the annulus above the upper sealing
element 28, a local telemetry bus and an interface module, a direct
control line and solenoids, or an acoustic telemetry system and an
acoustic interface module). In the preferred embodiment, each of
the valves, 26, 52, and 100, as well as the sampler apparatus 54
are constructed so that they may be similarly operated by most if
not all of the same techniques.
[0069] If the wellbore 12 is cased, then the casing 14 must be
perforated prior to testing. There are a variety of perforating
methods available to perforate the casing 14 adjacent the
production zone 16 and the injection zone 18.
[0070] In one embodiment, the upper zone 92 is perforated by a
wireline conveyed perforating gun run in the wellbore 12 prior to
running the tool string 10 downhole. Similarly, in one embodiment,
the lower zone 94 is perforated by a wireline conveyed perforating
gun run in the wellbore 12 prior to running the-tool string 10
downhole.
[0071] In the embodiment in which the upper zone 92 is perforated
by a wireline conveyed perforating gun, the lower zone 94 can be
perforated by a tubing conveyed perforating gun attached to the
tool string 10. In one embodiment as shown in FIG. 7, perforating
gun 96 is attached to the lower end of tool string 10. Upper zone
92 is already perforated. Tool string 10, with perforating gun 96
thereon, is lowered into the wellbore 12. In the embodiment shown
in FIG. 7, the tool string 10 is shown being deployed with the use
of a packer stinger assembly 64 in which the stinger portion 66 is
being stung into the already set packer body portion 68. It is
understood, however, that a packer, such as Schlumberger's High
Performance Packer, may also be used, in which case the lower
sealing element 30 would be deployed on the tool string 10 together
with the upper sealing element 28. Once properly positioned,
perforating gun 96 is activated by means known in the art, such as
by pressure pulse signals or applied pressure, thereby perforating
the lower zone 94. In another embodiment as shown in FIG. 8,
perforating gun 96 is attached to the packer body portion 68 of the
packer stinger assembly 64. Upper zone 96 is already perforated.
Packer body portion 68 and perforating gun 96 are first run into
the wellbore 12 and the sealing elements 70 are set. Next, the
remainder of the tool string 10 is run in the wellbore 12 and the
stinger portion 66 is inserted into the packer body portion 68.
Once tool string 10 is properly positioned and set, perforating gun
96 is then activated thereby perforating lower zone 94.
[0072] In another embodiment (not shown), perforating gun 96 is
attached to an anchor located below the lower sealing elements 30
so that perforating gun 96 is adjacent lower zone 94. Once the tool
string 10 is in position and set, perforating gun 95 is activated
thereby perforating lower zone 94. In the embodiments in which the
perforating gun 96 is attached to the packer body portion 68 or the
anchor, the upper zone 96 may also be perforated with guns attached
to the tool string 10.
[0073] In the embodiment shown in FIG. 9, both the upper zone 92
and the lower zone 94 are perforated using tubing conveyed
perforating guns. In this embodiment, two perforating guns 96 are
positioned preferably at the lower end of tool string 10. As the
tool string 10 is run downhole, one of the perforating guns 96 is
used to perforate the upper zone 92. Thereafter, the tool string 10
is continued to be run downhole. Once properly positioned, the
second perforating gun 96 is activated thereby perforating the
lower zone 94. In the preferred embodiment, the higher of the two
perforating guns 96 is used to perforate the lower zone 94.
[0074] In the embodiment shown in FIG. 10, the upper zone 92 and
lower zone 94 are also perforated using tubing conveyed perforating
guns. In this embodiment, however, one perforating gun 96 is
positioned at the lower end of tool string 10 and a second oriented
perforating gun 98 is positioned in the tool string 10 so that is
adjacent the upper zone 92 once the tool string 10 is in place.
Oriented perforating gun 98 is constructed and positioned on tool
string 10 so that it does not perforate in the direction of power
cable 90, data line 104, or transmission line 108, when fired. Once
tool string 10 is properly positioned in wellbore 12 and the upper
sealing element 28 and lower sealing element 30 are set, the
oriented perforating gun 98 is activated thereby perforating upper
zone 92, and the perforating gun 96 is activated thereby
perforating lower zone 94.
[0075] Preferably, all perforating guns 96 and oriented perforating
gun 98 used are low debris guns. When activated, the low debris
guns minimize the amount of perforating debris in the wellbore 12
and in the perforations, 17 and 19.
[0076] In operation, the tool string 10 is run downhole with the
barrier valve mechanism 44 in the closed position, the flow valve
26 in the closed position, the sampling valve 52 in the open
position, and the circulating valve 100 in the closed position. It
is assumed that the upper zone 92 and the lower zone 94 have
already been perforated using one of the techniques described
herein, that the tool string 10 is properly positioned in the
wellbore 10, and that the upper sealing element 28 and the lower
sealing element 30 have been set. It is also assumed that wellbore
12 is already filled with an appropriate kill fluid.
[0077] First, a signal is sent from the surface through the data
line 104 or transmission line 108 (or hydraulic line not shown) to
open the flow valve 26. The pump 24 is also activated by turning
the power on through power cable 90. Pump 24 generates a flow of
fluid from the production zone 16, through the production zone
perforations 17, through the production inlet 20, through the
interior of tool string 10, through the injection outlet 22,
through the injection zone perforations 19, and into the injection
zone 18. As the fluid flows through the interior of tool string 10,
the pressure and temperature units 46 record and monitor the
pressure and temperature of the fluid, the flow meter 48 records
and monitors the flow rate of the fluid, and the fluid identifier
50 records and monitors the oil content of the fluid. The data
taken by these instruments, 46, 48, and 50 (and the solid detector
and fluid density meter), is preferably available at the surface by
way of data line 104 or transmission line 108. In the alternative
embodiment, downhole recorders record the data.
[0078] After a sufficient amount of time, the appropriate signal is
transmitted through data line 104 or transmission line 108 (or
hydraulic line not shown) from the surface to close the flow valve
26. Immediately thereafter, the pump 24 is stopped by turning the
power off through power cable 90. Closing the fluid path through
tool string 10 results in a pressure build up of the fluid in the
production zone 16 occurring on the production zone 16 side of the
flow valve 26. The build up is recorded and monitored by at least
one of the pressure and temperature units 46, which data is
available at the surface by way of data line 104 or transmission
line 108 (or is being recorded by a downhole recorder).
[0079] Once the build up is completed, the appropriate signal is
transmitted from the surface through data line 104 or transmission
line 108 (or hydraulic line not shown) to once again open the flow
valve 26. The pump 24 is then once again activated by turning the
power on through power cable 90, which action re-establishes the
flow of fluid from production zone 16 to injection zone 18. The
characteristics of the fluid are once again recorded and monitored
by the relevant tool string 10 instruments and surface equipment,
and the reservoir limits or boundaries are thereby evaluated.
Additional build up and flow periods may be performed.
[0080] During at least the flow periods, the fluid identifier 50
monitors the oil content of the fluid flowing through tool string
10, such readings being preferably available at the surface through
data line 104 or transmission line 108. Once the operator
determines by way of the fluid identifier readings that the fluid
flowing through the interior of the tool string 10 has the
appropriate oil content, the flow of the fluid through tool string
10 should be lowered, such as by running pump 24 at a lower rate,
as is well-known in the art. During the lower flow period, the
sampler apparatus 54 is triggered by the appropriate signal through
data line 104 or transmission line 108 (or hydraulic line not
shown) and samples of the fluid are taken by the sample chambers.
It is noted that the readings taken by the fluid identifier 50
which are preferably available at the surface through data line 104
or transmission line 108 may be used to ensure that the sampler
apparatus 54 is triggered at the appropriate time.
[0081] Subsequent to triggering the sampler apparatus 54, a signal
is sent through the data line 104 or transmission line 108 (or
hydraulic line not shown) which closes the sampling valve 52 and
the flow valve 26, trapping a substantial volume of dead fluid
therebetween. A signal is also sent by way of power cable 90 to
stop the pump 24. This type of sampling will be hereinafter
referred to as "dead-oil sampling". The area between sampling valve
52 and flow valve 26 comprises a compartment 500 wherein the
compartment 500 is at least partially defined by the valves, 52 and
26. The volume of dead-oil or dead fluid within compartment 500
comprises several barrels of fluid, a much larger amount than
typically held by the sample chambers of sampler apparatus 54. This
volume of dead-oil is then brought back to the surface together
with the remainder of the tool string 10. An alternative to the
dead-oil sampling technique is to reverse circulate a volume of
fluid to the surface while the tool string 10 remains downhole.
[0082] The dead-oil sampling technique may also be performed by use
of other tool string architectures (not shown) and designs of
compartment 500. For instance, instead of comprising the area
between two valves, compartment 500 may be at least partially
defined by a large compartment chamber or conduit selectively
closed by one valve or a large compartment chamber or conduit that
is selectively in fluid communication with the interior of the tool
string. All of these designs are within the scope of this
invention.
[0083] It is noted that the amount of dead oil sampled depends on
the distance between the two valves, 52 and 26, or the size of the
relevant compartment chamber or conduit. Since tool string 10 is
modular, the distance between the two valves, 52 and 26, may be
modified at the discretion of the operator by adding tubing string
or other components therebetween. The size of the compartment
chamber or conduit may also be modified by the operator. Thus,
since the operator has control over the distance between the two
valves, 52 and 26, and over the size of the compartment chamber or
conduit, the operator may also control the amount of dead oil
sampled using this technique.
[0084] In the embodiment including the dead-oil sampling technique,
dedicated surface equipment 102 is preferred in order to vent off
any trapped gas and safely transfer the dead-oil volume to
containers. In addition, in one embodiment, prior to or during
venting of the gas, the volume of the gas trapped within the
compartment 500 is measured by use of a gas volume measuring
device, such as a gauge.
[0085] FIG. 11 illustrates one embodiment of the dedicated surface
equipment 102. As the tool string 10 is brought back to the
surface, the modules of the tool string 10 are disassembled. When
the flow valve 26 is at surface, the operator should attach a vent
valve (not shown) above the flow valve 26 and should open the flow
valve 26. By opening the flow valve 26, the gas trapped below the
flow valve 26 passes through the flow valve 26 and out of the
assembly through the vent valve. Once the trapped gas is vented,
the vent valve and the flow valve 26 may be removed from the
assembly, leaving the dead-oil volume 110 disposed in now partially
open compartment 500.
[0086] Next, a valve assembly 112 is attached to the assembly. The
valve assembly 112 includes a stuffing box 114, a piston 116, and a
conduit 118. Conduit 118 is sealingly disposed through stuffing box
114 and piston 116. In addition, conduit 118 may slide within
stuffing box 114, and piston 116 may slide within the interior of
the remaining tool string 10. Valve assembly 112 also includes a
passage 120 in fluid communication with a pressure source 122.
Passage 120 is preferably located so that it is also in fluid
communication with the interior of the valve assembly 112
intermediate the stuffing box 114 and the piston 116.
[0087] The operator should first activate the pressure source 122,
which may be nitrogen gas, so that the pressurized fluid flows
through passage 120 and into the valve assembly 112. The
pressurized fluid acts against the piston 116, making it slide
toward the dead fluid or downwardly within the compartment 500. As
the piston 116 slides, it compresses the dead-oil volume 110
disposed within compartment 500. As the dead-oil volume 110 is
compressed, the dead-oil volume 110 is forced into and through
conduit 118. Conduit 118 transmits the dead-oil volume 110 to
appropriate containers 124. It is noted that a reel 126 may be used
in order to retrieve or extend conduit 118.
[0088] When the piston 116 is adjacent the sampling valve 52, the
pressurized fluid is bled off. The conduit 118 is then retrieved
and is unlatched from the piston 116 and stuffing box 114. Conduit
118 may include a check valve (not shown) to prevent any fluid from
flowing out of its open end. The remainder of the tool string 10,
including valve assembly 112, is then disassembled.
[0089] In another embodiment of the dedicated surface equipment 102
(as shown in FIG. 18), after the trapped gas is vented and the vent
valve and flow valve 26 are removed from the assembly, the conduit
118 and piston 116 are moved into and within compartment 500 so
that a majority of the dead fluid is intermediate the piston 116
and the passage 120. Preferably, the piston 116 is moved so that
its lower end is adjacent the lower end of compartment 500. In this
embodiment, piston 116 includes fluid communication ports 117
therethrough that can be selectively closed. The piston 116 and
conduit 118 are moved towards the lower end of compartment 500 with
the ports 117 of the piston 116 in the open position. Once the
piston 116 and conduit 118 are next to the lower end of compartment
500, the fluid communication ports 117 of the piston 116 are
closed. In this embodiment, pressure source 122 is connected to the
conduit 118 so that pressurized fluid is injected through conduit
118. Also in this embodiment, the containers 124 are in fluid
communication with the passage 120. When pressurized fluid is
injected through conduit 118, the pressure flowing out of the open
end of the conduit 118 makes the piston 116 (now with closed fluid
communication ports 117) move upwards. As the piston 116 moves
upwards, the dead oil volume is forced towards and through the
passage 120, which is in fluid communication with the containers
124. The dead oil volume is thus passed through the passage 120
into the containers 124. Lastly, the pressurized fluid is
vented/removed, and the valve assembly 112 is disassembled.
[0090] In another embodiment of the dedicated surface equipment 102
(as shown in FIG. 19), after the trapped gas is vented and the vent
valve and flow valve 26 are removed from the assembly, the conduit
118 is moved into and within compartment 500 so that a majority of
the fluid is intermediate the open end of the conduit 118 and the
passage 120. Preferably, the conduit 118 is moved within
compartment 500 so that its open end is adjacent the lower end of
compartment 500. This embodiment is very similar to that of FIG.
18. However, in contrast to the embodiment shown in FIG. 18, this
embodiment does not include a piston 116. Instead, it includes only
conduit 118 movably disposed within compartment 500. Once the
conduit 118 is properly positioned, the pressure source 122 is
activated so that pressurized fluid is injected through conduit
118. In this embodiment, the pressurized fluid contained in
pressure source 122 and injected through conduit 118 is preferably
a pressurized fluid that is denser than the dead fluid found in
compartment 500 (so that the pressurized fluid does not tend to
rise through the dead fluid). Thus, as this pressurized fluid is
injected through conduit 118, the increasing volume of pressurized
fluid forces the dead fluid towards and through the passage 120,
which is in fluid communication with the containers 124. The
pressurized fluid is then vented/removed, and the valve assembly
112 is disassembled.
[0091] Another embodiment of the dedicated surface equipment 102
(as shown in FIG. 20) is similar to the embodiment of FIG. 11, such
that the conduit 118 is connected to the container 124 and the
passage 120 is connected to the pressure source 122. The embodiment
of FIG. 20, however, does not include a piston 116. The conduit 118
is moved into and within compartment 500 so that a majority of the
fluid is intermediate the open end of the conduit 118 and the
passage 120. Preferably, the conduit 118 is moved so that its open
end is adjacent the lower end of compartment 500. Once the conduit
118 is properly positioned, the pressure source 122 is activated so
that pressurized fluid is injected through passage 120. As this
pressurized fluid is injected through the passage 120, it
compresses the dead fluid and forces it into and through the
conduit 118, which is in fluid communication with containers 124.
The pressurized fluid is then vented/removed, and the valve
assembly 112 is disassembled.
[0092] In another embodiment as shown in FIG. 21, the dedicated
surface equipment 102 includes the conduit 118 and the piston 116,
with the conduit 118 connected to the container 124 and the passage
120 connected to the pressure source 122. In this embodiment,
however, piston 116 is slidingly disposed on conduit 118, with
conduit 118 located within compartment 500 so that a majority of
the fluid is intermediate the open end of the conduit 118 and the
piston 116. Piston 116 may include at least one seal 119 to
slidingly seal against the compartment 500. Preferably, the conduit
118 is moved within compartment 500 so that its open end is
adjacent the lower end of the compartment 500. Once the conduit 118
is properly positioned, the pressure source 122 is activated so
that pressurized fluid is injected through passage 120. As this
pressurized fluid is injected through the passage 120, it forces
the piston 116 so slide on conduit 118 towards the dead fluid
thereby compressing the dead fluid. The compression of the dead
fluid, in turn, causes the dead fluid to flow into and through the
conduit 118, which is in fluid communication with containers 124.
It is noted that during the sliding movement of piston 116, conduit
118 preferably moves only a small amount, if at all. The
pressurized fluid is then vented/removed, and the valve assembly
112 is disassembled.
[0093] As previously disclosed, the wellbore 12, prior to the
insertion of tool string 10, is filled with kill fluid. Before
removing tool string 10 from the wellbore 12 but after the
completion of the test, the operator may choose to condition the
wellbore fluids and to remove the formation fluids that remain in
the wellbore 12 by injecting them back into one of the zones, 92
and 94. First, the barrier valve mechanism 44 is opened and kill
fluid is forced therethrough. In the embodiment of FIG. 1, the kill
fluid flows through the ports 128 and into the injection zone 18
through the injection zone perforations 19. Ports 128, in one
embodiment, may also be a part of a sleeve valve or other type of
valve. Note that flow valve 26 is closed at this point prohibiting
kill fluid from flowing downwardly through the interior of tool
string 10 where the dead-oil volume is contained. It is also noted
that kill fluid would likely already be present intermediate the
injection zone 18 and the lower sealing element 30. In the
embodiment of FIG. 2, the kill fluid flows through the production
inlet 20 and into the production zone 16 through the production
zone perforations 17. Note that flow valve 26 is closed at this
point prohibiting kill fluid from flowing downwardly through the
interior of tool string 10. It is also noted that kill fluid would
likely already be present intermediate the production zone 16 and
the lower sealing element 30.
[0094] The next step in the operation is to release the upper
sealing element 28 and observe the wellbore 12 to ensure its
stability. If the wellbore 12 remains stable, then the lower
sealing element 30 may be released and the wellbore 12 should once
again be observed. If the wellbore 12 remains stable, then the tool
string 10 can then be safely removed from the wellbore 12. It is
noted that before or after unsetting the upper and lower sealing
elements, 28 and 30, mud can be circulated through the circulation
valve of the barrier valve mechanism 44 (in the relevant
embodiment) or through an additional circulation valve located
above the barrier valve mechanism 44.
[0095] FIGS. 12-17 comprise several illustrations taken from this
application's Parent Application, which was filed on Feb. 25, 2000,
is entitled "Method and Apparatus for Testing a Well", includes
Bjorn Langseth, Christopher W. Spiers, Mark Vella, and Dinesh R.
Patel as inventors, and is assigned to the Assignee hereto (such
application referred to as "Parent Application"). The Parent
Application claims priority from U.S. Provisional Application No.
60/130,589 filed on Apr. 22, 1999.
[0096] A variety of devices and methods described herein may also
be utilized and accomplished using the invention disclosed in the
Parent Application. The specification of the Parent Application is
hereby incorporated by reference.
[0097] Briefly, the invention disclosed in the Parent Application
includes a tool string 220 disposed in a wellbore 210, which may
include a production zone 214 and an injection zone 212. Tool
string 220 may include an enlarged tubing 236 having an increased
diameter which forms part of a relatively large volume chamber 237
into which well fluids may flow during closed-chamber testing. Tool
string 220 may also include an isolation device 300.
[0098] Tool string 220 may include upper and lower sealing
elements, 234 and 239, to seal tool string 220 to the wellbore 210
in order to isolate the production and storage zones, 214 and 212,
as well as the upper wellbore section above the upper packer 234.
Tool string 220 may also include one or more perforating guns 222
attached to the lower end of the tool string 220 to create
perforations in the production zone 214 and/or the injection zone
212. Tools string 220 may include one perforating gun (not shown)
located higher up on tool string 220 to perforate the higher of the
zones, 212 and 214, and a perforating gun 222 located lower down on
tool string 220 to perforate the lower of the zones, 212 and 214.
The higher up of the perforating guns may comprise an oriented
perforating gun so as to not disturb any cables or lines passing
from above it. The other perforating methods mentioned in this
application may also be utilized in the Parent Application. In
addition, tool string 220 includes a production inlet 224 that may
comprise a slotted pipe sized to prevent larger debris from being
produced into the tool string 220. Alternatively, production inlet
224 may comprise a prepacked screen used to filter our the debris.
Tool string 220 also includes an injection outlet 225.
[0099] Tool string 220 may also include a sampler apparatus 268
having sampler chambers to collect fluid samples from the
production zone 214. In addition, tool string 220 may include at
least one pressure and temperature unit 266, each unit 266
including at least one and preferably a plurality of pressure and
temperature sensors, for recording and monitoring the pressure and
temperature of the fluid flowing through the interior of tool
string 220
[0100] Tool string 220 may also include a flow valve 227 to control
the flow through the interior of tool string 220. Flow valve 227 is
preferably a ball valve 228 that is preferably a component of a
Schlumberger IRIS Dual Valve. In some embodiments (FIGS. 14, 15,
16, and 17), tool string 220 also includes a second flow valve 299,
preferably a ball valve 298, that controls the flow through the
interior of tool string 220. The dead-oil sampling technique
described herein may be utilized with the invention disclosed in
the Parent Application by trapping the volume of fluid between the
ball valves 228 and 298 (or any other relevant valves), the ball
valves 228 and 229 at least partially defining compartment 500. As
in this invention, the dead-oil sampling technique can be used with
the invention disclosed in the Parent Application after the flow
and build up periods are completed. In the invention disclosed in
the Parent Application, the dead-oil sampling technique may also be
performed by use of other tool string architectures and compartment
500 designs, such as a large compartment chamber or conduit (ie.,
enlarged tubing 36 or large volume chamber 37) selectively closed
by one valve or a large compartment chamber or conduit that is
selectively in fluid communication with the interior of the tool
string.
[0101] Moreover, as specified in the specification of the Parent
Applications, a variety of other valves, sensors (including flow
meters, fluid identifiers, fluid density meters, solids detectors,
H.sub.2S detectors, CO.sub.2 detectors, and water cut meters), and
recorders may be included in tool string 220. In addition, some of
these valves, sensors, and recorders are included in tool string
220 below upper sealing element 234. Like in the invention
disclosed herein, the valves, sensors, and equipment located below
upper sealing means 234, including sampler apparatus 268, pressure
and temperature unit 266, flow valve 227, and flow valve 299, may
be operated by use of a hydraulic line exposed to the annulus above
the upper sealing element 234, a local telemetry bus and an
interface module, a direct control line and solenoids, or an
acoustic telemetry system and an acoustic interface module.
Moreover, a data line similar to data line 104 of the invention
described herein, may be used to transmit the readings of the
downhole equipment to the surface. To accommodate such functions,
upper sealing element 234 preferably comprises a multi-port packer
(not shown) including secondary ports. In one embodiment, lower
sealing element 239 comprises a packer stinger assembly.
[0102] The embodiments of this application as well as the
embodiments of the Parent Application have been described as
enabling the production of fluid from a first or production zone to
a second or injection zone. However, the tool strings 10 or 220 may
also be used to produce and inject fluids from and into the same
formation. The tool string 10 of this application can achieve this
as long as the perforations 19 of upper zone 92 and the
perforations 17 of lower zone 94 provide communication to the same
formation. Similarly, the tool string 220 of the Parent Application
can achieve this if the production and injection zones are part of
the same formation. In addition, the tool string 220 of the Parent
Application can achieve this by including only the production zone
214 (not an additional injection zone), flowing from the production
zone 214 into the chamber 237, and injecting the fluid from the
chamber 237 back into the production zone 214.
[0103] Moreover, the tool string 10 of this application and the
tool string 220 of the Parent Application may be used to produce
fluid from a multilateral or other bore (instead of a production
zone) and/or to inject fluid into a multilateral or other bore
(instead of a production zone). Such a use enables the testing of
the fluid flowing through the relevant multilaterals or other
bores.
[0104] In addition, the tool string 10 of this application and the
tool string 220 of the Parent Application can be easily adapted to
support two or more production zones and or two or more injection
zones. Such adaptation may include the incorporation of a
production inlet for each production zone, an injection outlet for
each injection zone, and/or valves to control the flow to and from
the zones.
[0105] The tool string 10 of this application and the tool string
220 of the Parent Application can also be used to test both the
production zone and the injection zone. The tool string 220 can be
adapted to include the relevant sensors/gauges/meters adjacent the
injection zone and the production zone so that both zones are
monitored, particularly when chamber 237 is full of fluid from the
production zone. Likewise, the tool string 10 can be adapted to
include the relevant sensors/gauges/meters adjacent the injection
zone and the production zone so that both zones are monitored,
particularly during the build up periods of the test cycle.
[0106] FIGS. 22 and 23 illustrate a bypass flow housing 300 that
may be utilized with tool string 10 or 220 in order to accommodate
equipment 302. Equipment 302 may comprise a variety of downhole
equipment including electronic equipment, such as fluid identifiers
or other sensors or meters. Bypass flow housing 300 includes an
eccentric main bore 304 as well as a plurality of bypass channels
306 disposed between the main bore 304 and the outer surface 308 of
the housing 300. Each channel 306 has two ends 310, each end 310
communicating with the main bore 304. Equipment 302 is disposed
intermediate the channel ends 310.
[0107] In use, housing 300 is integrated into the tool string 10 or
220. Fluid flow passing through tool string 10 or 220 enters
housing 300 through main bore 304, passes through channels 306 by
way of ends 310, and exits housing 300 through main bore 304. Thus,
the fluid flow bypasses equipment 302. The shape and relative
placement of the channels 306 in relation to the main bore 304
allows the wall thickness of the channels 306 to remain
substantially thick enough to enable and withstand the high
pressure flow rate through tool string 10 or 220. Thus, bypassing
equipment 302 is achieved without sacrificing flow rate. It is
noted that depending on the identity of the equipment 302,
equipment 302 may allow the passage of fluid therethrough by way of
port(s) 312.
[0108] While the invention has been disclosed with respect to a
limited number of embodiments, those skilled in the art will
appreciate numerous modifications and variations therefrom. It is
intended that the appended claims cover all such modifications and
variations as fall within the true spirit and scope of the
invention.
* * * * *