U.S. patent application number 14/937447 was filed with the patent office on 2016-03-03 for interacting hydraulic fracturing.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Bilu Verghis Cherian, Jayanth Krishnamurthy, Maraden Panjaitan.
Application Number | 20160061026 14/937447 |
Document ID | / |
Family ID | 49379040 |
Filed Date | 2016-03-03 |
United States Patent
Application |
20160061026 |
Kind Code |
A1 |
Cherian; Bilu Verghis ; et
al. |
March 3, 2016 |
INTERACTING HYDRAULIC FRACTURING
Abstract
A fracture extending away from a first subterranean well and
toward a second subterranean well may be initiated by pumping fluid
into the first subterranean well. The fracture may be propagated
further towards the second subterranean well by continuing to pump
fluid into the first subterranean well, while monitoring a pressure
in the second subterranean well. Proppant may be pumped into the
second subterranean well via the first subterranean well and the
fracture upon detection of a change in the monitored pressure in
the second subterranean well. The change in monitored pressure in
the second subterranean well may be sufficient to indicate that the
first and second wells are in fluid communication and interacting
via the fracture.
Inventors: |
Cherian; Bilu Verghis;
(Denver, CO) ; Panjaitan; Maraden; (Highlands
Ranch, CO) ; Krishnamurthy; Jayanth; (Denver,
CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
49379040 |
Appl. No.: |
14/937447 |
Filed: |
November 10, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13869482 |
Apr 24, 2013 |
9187992 |
|
|
14937447 |
|
|
|
|
61637585 |
Apr 24, 2012 |
|
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Current U.S.
Class: |
166/50 ;
166/52 |
Current CPC
Class: |
E21B 43/17 20130101;
E21B 43/267 20130101; E21B 47/06 20130101; E21B 43/26 20130101 |
International
Class: |
E21B 47/06 20060101
E21B047/06 |
Claims
1-10. (canceled)
11. A system, comprising: a first subterranean well; and a second
subterranean well having a pressure sensor responsive to fluid
pumped into the first subterranean well.
12. The system of claim 11 wherein the first subterranean well is a
cased well.
13. The system of claim 11 further comprising a downhole tool
positioned in the second subterranean well, wherein the downhole
tool comprises the pressure sensor.
14. The system of claim 11 wherein the pressure sensor is
permanently installed in the second subterranean well.
15. The system of claim 11 wherein at least one of the first and
second subterranean wells comprises at least one lateral
section.
16. A system, comprising: a first plurality of subterranean wells;
and a second plurality of subterranean wells each having a pressure
sensor responsive to fluid pumped into at least one of the first
plurality of subterranean wells.
17. The system of claim 16 wherein at least one of the first
plurality of subterranean wells is a cased well.
18. The system of claim 16 further comprising a plurality of
downhole tools each positioned in a corresponding one of the
plurality of second subterranean wells, wherein each of the
plurality of downhole tools comprises the pressure sensor within
the corresponding one of the plurality of second subterranean
wells.
19. The system of claim 16 wherein the pressure sensor of at least
one of the second plurality of subterranean wells is permanently
installed therein.
20. The system of claim 16 wherein at least one of the first and
second pluralities of subterranean wells comprises at least one
lateral section.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/637,585, entitled "INTERACTING HYDRAULIC
FRACTURING METHOD," filed Apr. 24, 2012, the entire disclosure of
which is hereby incorporated herein by reference.
BACKGROUND OF THE DISCLOSURE
[0002] Hydrocarbon fluids such as oil and natural gas are obtained
from a subterranean geologic formation by drilling a well that
penetrates the hydrocarbon-bearing formation. This provides a
partial flowpath for the hydrocarbon to reach the surface. The
hydrocarbon is "produced," or travels from the formation to the
wellbore (and ultimately to the surface), via a sufficiently
unimpeded flowpath from the formation to the wellbore.
[0003] Hydraulic fracturing is a tool for improving well
productivity by placing or extending channels from the wellbore to
the formation. This operation comprises hydraulically injecting a
fracturing fluid into a wellbore penetrating a subterranean
formation, thus forcing the fracturing fluid against the formation
strata by pressure. The formation strata or rock is thus forced to
crack and fracture. Proppant may then be placed in the fracture to
prevent the fracture from closing.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] The present disclosure is best understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0005] FIG. 1 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0006] FIG. 2 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0007] FIG. 3 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0008] FIG. 4 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
[0009] FIG. 5 is a flow-chart diagram of at least a portion of a
method according to one or more aspects of the present
disclosure.
[0010] FIG. 6 is a schematic view of at least a portion of
apparatus according to one or more aspects of the present
disclosure.
DETAILED DESCRIPTION
[0011] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, merely examples and are
not intended to be limiting. In addition, the present disclosure
may repeat reference numerals and/or letters in the various
examples. This repetition is for the purpose of simplicity and
clarity and does not in itself dictate a relationship between the
various embodiments and/or configurations discussed. Moreover, one
or more inventive and/or other aspects of the present disclosure
may lie in less than all features of a single disclosed
implementation and/or embodiment. Thus, the claims following the
Detailed Description are hereby expressly incorporated into this
Detailed Description, with each claim standing on its own as a
separate implementation and/or embodiment of this disclosure.
[0012] FIG. 1 is a schematic view of at least a portion of a
wellsite 100 according to one or more aspects of the present
disclosure. For example, at least a portion of the wellsite 100 is
operable to perform the treatment of multiple zones of interest
using one or more aspects of interacting hydraulic fracturing
within the scope of the present disclosure.
[0013] The wellsite 100 comprises a wellbore 110 that intersects
one or more subterranean formations and establishes multiple zones
of interest 120. At least a portion of the wellbore 110 may be
cased and thus comprise a casing string 130, although one or more
aspects of the present disclosure may be similarly applicable
and/or readily adaptable for use with uncased or "open" wellbores.
The casing string 130 may be cemented in the wellbore 110, such as
by pumping cement into the annulus between the casing string 130
and the sidewalls of the wellbore 110. However, the casing string
130 may not be cemented, such as where the casing string 130 lines
a lateral or other section of the wellbore 110. Thus, it is
appreciated that the casing string 130 may be a liner, broadly
considered herein as any form of casing, including that which may
not extend to the surface 115, such as a specific interval length
along a vertical, horizontal, and/or deviated wellbore.
[0014] A conveyance string 140 comprising and/or otherwise coupled
to a bottom-hole assembly (BHA) 150 may extend downhole from the
surface 115 of the wellsite 100 into the wellbore 110. The
conveyance string 140 may be or comprise coiled tubing. However,
one or more aspects of the present disclosure may be similarly
applicable and/or readily adaptable for use with another type of
string, such as a drillstring and/or other jointed tubing string,
wired drill pipe, wireline, slickline, and/or others.
[0015] The wellsite 100 is depicted in FIG. 1 as being in a state
in which fluid connectivity between the wellbore 110 and the zones
120 has been established, as depicted by perforations 160 that
penetrate the casing string 130 and extend into the surrounding
formation(s) F. Perforation of the zones 120 may be performed by
jetting subs, for example, as well as other conventional
perforation means, such as tubing or wireline-conveyed
shaped-charge perforating guns, sliding sleeves, and/or TAP valves,
among other possible examples.
[0016] For implementations utilizing jetting for perforation, the
wellsite 100 may comprise a cutting fluid source 170 at the surface
115, such as may be utilized for cutting formation strata, control
valves, and/or other subterranean and/or downhole features. The
cutting fluid source 170 may, for example, supply an abrasive
slurry and/or other cutting fluid to a passageway of the conveyance
string 110, such that the cutting fluid may be radially directed by
a jetting sub 154 to penetrate the casing string 130 and/or a
surrounding formation. The jetting sub 154 may be part of or
otherwise carried by the BHA 150.
[0017] The wellsite 100 may further comprise a treatment fluid
source 175 at the surface 115 that may be utilized to introduce
treatment fluid into the wellbore 110. The treatment fluid source
175 may comprise a treatment fluid reservoir, a pump, control
valves, and/or other components, and may be in selective
communication with an annulus defined between the conveyance string
140 and the sidewalls of the wellbore 110 and/or the casing string
130.
[0018] The wellsite 100 may further comprise a surface treatment
monitoring system 180 at the surface 115, which may be in
communication with a downhole treatment monitoring system 156
and/or other means for monitoring one or more parameters of the
wellbore 110, such as in connection with the communication of one
or more fluids downhole. The downhole treatment monitoring system
156 may be part of or carried by the BHA 150. The surface treatment
monitoring system 180 and/or the downhole treatment monitoring
system 156 may be individually or collectively utilized to, for
example, regulate the delivery of fluids downhole based on one or
more monitored parameters. For example, the surface treatment
monitoring system 180 and/or the downhole treatment monitoring
system 156 may be individually or collectively utilized to monitor
a pressure within the wellbore 110, including in the multi-well
implementations described below.
[0019] While the implementation depicted in FIG. 1 comprises a
single wellbore 110, aspects of the present disclosure may relate
to implementations in or comprising two or more wellbores, one or
more of which may comprise a multi-lateral well. FIG. 2 is a
schematic view of one such implementation 200, which comprises a
first wellbore 210 and a second wellbore 220. One or both of the
first and second wellbores 210 and 220 may be substantially similar
to or otherwise share one or more common aspects with the wellbore
110 shown in FIG. 1.
[0020] While either or both of the wellbores 210 and 220 may be or
comprise a multi-lateral well, only the second wellbore 220 is
depicted as such in FIG. 2, although merely for ease of
understanding, as a person having ordinary skill in the art will
readily recognize that aspects of the present disclosure may be
applicable to implementations in which either, neither, or both of
the wellbores 210 and 220 are multi-lateral, vertical, horizontal,
and/or deviated wells. In implementations in which the first and/or
second wellbore 220 is or comprises a multi-lateral well, such
wellbore(s) may comprise multiple lateral sections 225.
Cross-hatching is also excluded from FIG. 2 for the purposes of
clarity and simplicity, although a person having ordinary skill in
the art will readily recognize the schematic view of FIG. 2 as
being a subterranean cross-sectional view of the first and second
wellbores 210 and 220.
[0021] Additionally, the first wellbore 210 is depicted in FIG. 2
as being cased (and thus comprising a casing string 215), whereas
the second wellbore 220 is depicted as being uncased. However,
aspects of the present disclosure are applicable or readily
adaptable to implementations in which either, neither, or both of
the first and second wellbores 210 and 220 are cased. One or both
of the first and second wellbores 210 and 220 may also comprise
conventional completion equipment (not shown), such as plugs,
perforations, sliding sleeves, and/or packers, among other
completion apparatus within the scope of the present
disclosure.
[0022] The first wellbore 210 may be hydraulically fractured using,
for example, one or more fracturing techniques described above. The
first wellbore 210 may additionally or alternatively be
hydraulically fractured utilizing other techniques, such as those
disclosed in U.S. Pat. No. 6,776,235 and/or U.S. Pat. No.
7,581,590, which are both hereby incorporated by reference in their
entireties for all intents and purposes. As a result of the
hydraulic fracturing, fractures 240 may initiate from the first
wellbore 210 and propagate toward the second wellbore 220, such
that the first and second wellbores 210 and 220 may ultimately be
hydraulically coupled and, thus, interacting.
[0023] The second wellbore 220 may comprise one or more pressure
sensors 230, such as is depicted in FIG. 2 in each of the lateral
sections 225. The pressure sensors 230 are depicted as being
imbedded into the sidewalls of the lateral sections 225 of the
second wellbore. However, in other implementations within the scope
of the present disclosure, the pressure sensors 230 may be
otherwise positioned within the wellbore 220, whether temporarily
or permanently. For example, a downhole tool comprising pressure
sensors may be operable to be conveyed within the second wellbore
220 and measure pressure of the second wellbore 220 and/or the
formation F via one or more probes extendable from or otherwise
coupled to the downhole tool. An example of such a downhole tool is
described below with respect to FIG. 6, although others are also
within the scope of the present disclosure. The pressure sensors
230 may also or alternatively be part of or otherwise carried by a
downhole treatment monitoring system and/or other feature of a BHA,
such as of the BHA 150 shown in FIG. 1.
[0024] As cutting and/or other fracturing fluid (hereafter
collectively referred to simply as fracturing fluid) is pumped into
the first wellbore 210 from equipment at the surface 205 (such as
the surface equipment shown in FIG. 1), a pressure pulse and/or
other pressure change may be observed in the second wellbore 220,
as detected by the pressure sensors 230. Such detection may
indicate that one or more fractures 240 originating from the first
wellbore 210 have expanded in length until they ultimately arrived
at the second wellbore 220. For example, the detection may comprise
comparing the pressure sensed in the second wellbore 220, or the
change thereof, to a predetermined level. Once the detected
pressure or pressure change exceeds the predetermined level, the
first and second wellbores 210 and 220 may be considered to be in
hydraulic communication and interacting.
[0025] Thereafter, the fracturing fluid being pumped into the first
wellbore 210 may be circulated to the surface 205 via the second
wellbore 220 (which may also be known as "return"). This return
confirms that the first and second wellbores 210 and 220 are indeed
in hydraulic communication and interacting.
[0026] Thereafter, the rate at which fracturing fluid is pumped
into the first wellbore 210 may be gradually increased to, for
example, compensate for the return from the second wellbore 220.
Proppant may also be pumped into the first wellbore 210 to, for
example, support the now interacting fracture system and returns
taken from the one or more formations F intersected by the lateral
sections 225 and/or other portions of the second wellbore 220.
[0027] The interaction of the fractures 240 with the second
wellbore 220 may also cause a drop in the applicable pressure of
the first wellbore 210. In such instances, the pressure at which
fracturing fluid is pumped into the first wellbore 210 may be
increased to compensate for this pressure change.
[0028] Similar implementations within the scope of the present
disclosure may utilize the interacting hydraulic fracturing
described above to connect any number of vertical, horizontal,
deviated, and/or multi-lateral wells, whether the interacting
fractures of such connection extend laterally, vertically, and/or
otherwise. Moreover, when multiple formations F are potential
targets and separate lateral wells or well sections have been
utilized to complete the wells, one or more scaffolding or
laddering techniques may be utilized according to one or more
aspects of the present disclosure. One or more aspects of such
scaffolding techniques may ensure and/or improve connectivity and
interaction between the first and second wellbores 210 and 220,
which may aid in increasing recovery.
[0029] FIG. 3 is a schematic view of one such implementation 300,
which comprises the first and second wellbores 210 and 220 shown in
FIG. 2, wherein the first wellbore 210 is utilized as a fracturing
well and the second wellbore 220 is utilized as a target well. The
implementation 300 shown in FIG. 3 also comprises an additional
fracturing well 310 and an additional target well 320, which may be
substantially similar or identical to the fracturing well 210 and
the target well 220, respectively.
[0030] The two target wells 220 and 320 are hydraulically linked to
the two fracturing wells 210 and 310 by fractures 240 according to
aspects of the present disclosure. The target wells 220 and 320 may
be positioned to intersect or engage multiple formations F, of
which four are depicted in FIG. 3. As described above, when
pressure sensors 230 provided in the target wells 220 and 320
indicate a change in pressure, proppant may be pumped into one or
both fracturing wells 210 and 310, and returns may then be taken
from one or both target wells 220 and 320.
[0031] FIG. 4 schematically depicts another example implementation
400. The implementation 400 depicted in FIG. 4 is substantially
similar or identical to the implementation 300 shown in FIG. 3.
However, in the implementation 400 shown in FIG. 4, the two target
wells 220 and 320 and the two fracturing wells 210 and 310 are in
hydraulic communication due to ten different fracturing stages
440-449. Each stage of fracturing 440-449 may be substantially
similar to and/or comprise one or more fractures hydraulically
coupling neighboring ones of the wells 210, 220, 310, and 320. As
with the implementation 300 depicted in FIG. 3, the implementation
400 shown in FIG. 4 may be referred to as scaffolding or
laddering.
[0032] FIG. 5 is a flow-chart diagram of at least a portion of a
method 500 of interacting hydraulic fracturing according to one or
more aspects of the present disclosure. The method 500 is described
below with reference to FIG. 4. However, the method 500 and/or
variants within the scope of the present disclosure may be
performed to achieve the implementations shown in any of FIGS. 1-4,
as well as other implementations within the scope of the present
disclosure.
[0033] Thus, referring to FIGS. 4 and 5, collectively, the method
500 comprises a repeated loop for each fracturing stage 440-449.
Each iteration of the loop comprises deploying (505) a conveyance
string to the current zone of interest in one or more fracturing
wells 210/310, initiating fracturing (510) from one or more
fracturing wells 210/310 in the current zone, propagating (515) the
resulting one or more fractures, and continuing to pump fracturing
fluid into the one or more fracturing wells 210/310 until a
pressure or pressure change in one or more target wells 220/320
exceeds a predetermined threshold (520). Proppant may then be
pumped (525) from the one or more fracturing wells 210/310 to the
one or more target wells 220/320 via the one or more fractures
created during that iteration of the loop. Thus, the different
fracturing stages 440-449 may each be established one at a time. If
a determination is made (530) that other zones or fracturing stages
have yet to be established, then the loop is repeated.
[0034] Variations of the method 500 within the scope of the present
disclosure also include those in which multiple or all of the
fracturing stages 440-449 are established substantially
simultaneously, as well as those in which one or more portions of
the loop are performed substantially simultaneously or serially for
each fracturing stage 440-449 before other portions of the loop are
performed. For example, the fracture initiation (510) may be
performed for each zone or fracturing stage 440-449 in a single
trip, such as by utilizing a perforating gun deployed on wireline.
The fracture initiation (510) may entail the use of pre-perforated
casing, shifting a sleeve to expose openings between the wellbore
and the casing, cutting a slot or slots in the casing, laser
perforating, chemical dissolution, and/or any other method for
providing an opening in the casing string and initiating the
fracturing.
[0035] FIG. 6 is a schematic view of an example wellsite system
according to one or more aspects of the present disclosure. The
wellsite may have one or more aspects in common with the wellsite
100 shown in FIG. 1 and/or the implementation shown in one or more
of FIGS. 2-4, and comprises a wireline tool 600 configured for
conveyance within a wellbore 602 penetrating a subterranean
formation 630.
[0036] The wireline tool 600 may be suspended in the wellbore 602
from a lower end of a wireline and/or other multi-conductor cable
604 that may be spooled on a winch (not shown) at the surface 605.
At the surface 605, the cable 604 may be communicatively coupled to
an electronics and processing system 606. The electronics and
processing system 606 may include a controller having an interface
configured to receive commands from a surface operator. In some
cases, the electronics and processing system 606 may further
comprise a processor configured to implement one or more aspects of
the methods described herein.
[0037] The wireline tool 600 may comprise a telemetry module 610
and a test module 614. Although the telemetry module 610 is shown
as being implemented separate from the test module 614, the
telemetry module 610 may be implemented in the test module 614. The
wireline tool 600 may also comprise additional components at
various locations, such as one or more modules 608 above the
telemetry module 610 and/or one or more modules 626/628 below the
test module 614, which may have varying functionality within the
scope of the present disclosure.
[0038] The test module 614 may comprise a static or selectively
extendable probe assembly 616 and a selectively extendable
anchoring member 618 that are respectively arranged on opposing
sides of the wireline tool 600. The probe assembly 616 may comprise
one or more pressure sensors 622 operable to detect pressure and/or
pressure changes within the wellbore 602. The one or more pressure
sensors 622 may be located adjacent a port of the probe assembly
616, among other possible locations within the downhole tool 600.
For example, the test module 614 may comprise a sensing unit 620
which may also comprise one or more pressure sensors and/or other
types of sensors.
[0039] The probe assembly 616 may also be configured to selectively
seal off or isolate one or more selected portions of the sidewall
of the wellbore 602. For example, the probe assembly 616 may
comprise a sealing pad that may be urged against the sidewall of
the wellbore 602 in a sealing manner to prevent movement of fluid
into or out of the formation 630 other than through the probe
assembly 616. The probe assembly 616 may be configured to fluidly
couple a pump 621 and/or other components of the test module 614 to
the adjacent formation 630. Accordingly, the test module 614 may
also be utilized to obtain pressure and/or fluid samples from the
formation 630.
[0040] The sensors 622 and/or other sensors of the downhole tool
600 may also or alternatively be configured to determine other
parameters of the wellbore 602, the formation 630, and/or fluids
therein. For example, the sensors of the downhole tool 600 may be
configured to measure or detect one or more of electric
resistivity, dielectric constant, magnetic resonance relaxation
time, nuclear radiation, and/or combinations thereof, although
other types of sensors are also within the scope of the present
disclosure.
[0041] The telemetry module 610 may comprise a downhole control
system 612 communicatively coupled to the electronics and
processing system 606. The electronics and processing system 606
and/or the downhole control system 612 may be configured to control
the probe assembly 616 and/or the detection of pressure and/or
pressure changes within the formation 630. The electronics and
processing system 606 and/or the downhole control system 612 may be
further configured to analyze and/or process data obtained from
various sensors, store measurements or processed data, and/or
communicate measurements or processed data to surface or another
component for subsequent analysis.
[0042] In view of all of the above and FIGS. 1-6, a person having
ordinary skill in the art should readily recognize that the present
disclosure introduces a method comprising: initiating a fracture
extending away from a first subterranean well and toward a second
subterranean well by pumping fluid into the first subterranean
well; propagating the fracture further towards the second
subterranean well by continuing to pump fluid into the first
subterranean well, while monitoring a pressure in the second
subterranean well; and pumping proppant into the second
subterranean well via the first subterranean well and the fracture
upon detection of a change in the monitored pressure in the second
subterranean well.
[0043] Monitoring the pressure in the second subterranean well may
comprise operating a downhole tool positioned within the second
subterranean well, wherein the downhole tool may comprise a
pressure sensor.
[0044] The detection of the change in the monitored pressure in the
second subterranean well may comprise the detection of an increase
in the monitored pressure.
[0045] The detection of the change in the monitored pressure in the
second subterranean well may comprise the detection of a decrease
in the monitored pressure. The method may further comprise
increasing a pressure at which the fluid is pumped into the first
subterranean well to compensate for the decrease in the monitored
pressure.
[0046] The method may further comprise collecting the fluid from
the second subterranean well. Such method may further comprise
increasing a pressure at which the fluid is pumped into the first
subterranean well to compensate for the fluid collected from the
second subterranean well.
[0047] At least one of the first and second subterranean wells may
comprise at least one lateral section.
[0048] One of the first and second subterranean wells may comprise
a plurality of subterranean wells.
[0049] The first subterranean well may comprise two first
subterranean wells, and the second subterranean well may comprise
two first subterranean wells.
[0050] The present disclosure also introduces a system comprising:
a first subterranean well; and a second subterranean well having a
pressure sensor responsive to fluid pumped into the first
subterranean well.
[0051] The first subterranean well may be a cased well.
[0052] The system may further comprise a downhole tool positioned
in the second subterranean well. The downhole tool may comprise the
pressure sensor.
[0053] The pressure sensor may be permanently installed in the
second subterranean well.
[0054] At least one of the first and second subterranean wells may
comprise at least one lateral section.
[0055] The present disclosure also introduces a system comprising:
a first plurality of subterranean wells; and a second plurality of
subterranean wells each having a pressure sensor responsive to
fluid pumped into at least one of the first plurality of
subterranean wells.
[0056] At least one of the first plurality of subterranean wells
may be a cased well.
[0057] The system may further comprise a plurality of downhole
tools each positioned in a corresponding one of the plurality of
second subterranean wells. Each of the plurality of downhole tools
may comprise the pressure sensor within the corresponding one of
the plurality of second subterranean wells.
[0058] The pressure sensor of at least one of the second plurality
of subterranean wells may be permanently installed therein.
[0059] At least one of the first and second pluralities of
subterranean wells may comprise at least one lateral section.
[0060] The foregoing outlines features of several embodiments so
that those skilled in the art may better understand the aspects of
the present disclosure. Those skilled in the art should appreciate
that they may readily use the present disclosure as a basis for
designing or modifying other processes and structures for carrying
out the same purposes and/or achieving the same advantages of the
embodiments introduced herein. Those skilled in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
[0061] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn.1.72(b) to allow the reader to quickly
ascertain the nature of the technical disclosure. It is submitted
with the understanding that it will not be used to interpret or
limit the scope or meaning of the claims.
* * * * *