Downhole casing-casing annulus sealant injection

Information

  • Patent Grant
  • 11549329
  • Patent Number
    11,549,329
  • Date Filed
    Tuesday, December 22, 2020
    3 years ago
  • Date Issued
    Tuesday, January 10, 2023
    a year ago
Abstract
A downhole sealant injection system includes a first casing configured to be positioned in a wellbore and a second casing configured to be positioned in the wellbore within the first casing. Cement at least partially fills an annulus between the interior of the first casing and the exterior of the second casing. A first sealant injection tool is configured to be attached to the exterior of the second casing, and is positioned at a downhole location and within an annulus between the interior of the first casing and the exterior of the second casing. The sealant injection tool includes a plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.
Description
TECHNICAL FIELD

This disclosure relates to wellbore drilling and completion.


BACKGROUND

In hydrocarbon production, a wellbore is drilled into a hydrocarbon-rich geological formation. After the wellbore is partially or completely drilled, a completion system is installed to secure the wellbore in preparation for production or injection. The completion system can include a series of casings or liners cemented in the wellbore to help control the well and maintain well integrity.


SUMMARY

An embodiment disclosed herein provides a downhole sealant injection system. The system includes a first casing configured to be positioned in a wellbore and a second casing configured to be positioned in the wellbore within the first casing. Cement at least partially fills an annulus between the interior of the first casing and the exterior of the second casing. A first sealant injection tool is configured to be attached to the exterior of the second casing, and is positioned at a downhole location and within an annulus between the interior of the first casing and the exterior of the second casing. The sealant injection tool includes a plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.


An aspect combinable with any of the other aspects can include the following features. At least a portion of the plurality of nozzles are defined in at least one of a plurality of centralizer arms.


An aspect combinable with any of the other aspects can include the following features. The centralizer arms are hollow, and an interior of the nozzles is fluidically connected to an interior of the centralizer arms.


An aspect combinable with any of the other aspects can include the following features. A second sealant injection tool is attached to the exterior of the second casing. The second sealant injection tool comprising a second plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.


An aspect combinable with any of the other aspects can include the following features. A first control line is configured to flow sealant from a surface control system to the first sealant injection tool.


An aspect combinable with any of the other aspects can include the following features. A second control line is configured to flow sealant from the surface control system to the second sealant injection tool.


An aspect combinable with any of the other aspects can include the following features. The nozzles comprise burst discs configured to flow sealant upon an exceedance of a burst pressure.


An aspect combinable with any of the other aspects can include the following features. The sealant comprises a resin.


Certain aspects of the subject matter described here can be implemented as a sealant injection tool. The tool includes clamps configured to be attached to the exterior of a casing. The casing is configured to be placed within a wellbore. A plurality of centralizer arms are attached to the clamps and extend radially outward from the straps and the casing. A plurality of nozzles are defined in the centralizer arms and are configured to inject sealant into a space exterior of the casing within the wellbore.


An aspect combinable with any of the other aspects can include the following features. The centralizer arms are hollow, and an interior of the nozzles is fluidically connected to an interior of the centralizer arms.


An aspect combinable with any of the other aspects can include the following features. The nozzles include burst discs configured to flow sealant upon an exceedance of a burst pressure.


An aspect combinable with any of the other aspects can include the following features. A first subset of the plurality of nozzles points outward away from the casing and a second subset of the plurality of nozzles points inward towards the casing.


An aspect combinable with any of the other aspects can include the following features. The sealant comprises a resin.


Certain aspects of the subject matter described here can be implemented as a method of sealing an annulus between a first casing and a second casing. The first casing is positioned within a wellbore. A first sealant injection tool is attached to the exterior of the second casing. The sealant injection tool includes a plurality of nozzles. The second casing and the sealant injection tool are lowered into the wellbore within the first casing. Cement is flowed into an annulus between the interior of the first casing and the exterior of the second casing. Sealant is injected from the nozzles. The sealant fills voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.


An aspect combinable with any of the other aspects can include the following features. A downhole end of a first control line is configured to be fluidically connected to the first sealant injection tool. An uphole end of the first control line is fluidically connected to a surface control system.


An aspect combinable with any of the other aspects can include the following features. Sealant is flowed from the surface control system through the first control line.


An aspect combinable with any of the other aspects can include the following features. A second sealant injection tool is attached to the exterior of the second casing. The second sealant injection tool includes a second plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.


An aspect combinable with any of the other aspects can include the following features. A downhole end of a second control line is configured to fluidically connect to the second sealant injection tool. An uphole end of the second control line is fluidically connected to a surface control system.


An aspect combinable with any of the other aspects can include the following features. The nozzles include burst discs. Pressure is applied to the first control line sufficient to burst the burst discs.


An aspect combinable with any of the other aspects can include the following features. The sealant includes a resin.


The details of one or more implementations of the subject matter of this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.





BRIEF DESCRIPTION OF DRAWINGS


FIG. 1 is a drawing of an exemplary well system in accordance with an embodiment of the present disclosure.



FIG. 2 is a drawing of an exemplary sealant injection tool in accordance with an embodiment of the present disclosure.



FIG. 3 is a drawing of a sealant injection system in accordance with an embodiment of the present disclosure.



FIG. 4 is a drawing of a dual sealant injection system comprising two injection tools, in accordance with an embodiment of the present disclosure.



FIG. 5 is a drawing of a sealant injection system flowing sealant in accordance with an embodiment of the present disclosure.



FIG. 6 is a process flow diagram of a method for sealing an annulus in accordance with an embodiment of the present disclosure.



FIGS. 7A-7D is a drawing of a control line extraction sequence in accordance with an embodiment of the present disclosure.



FIG. 8 is a drawing of a side outlet flange in accordance with an embodiment of the present disclosure.



FIG. 9 is a drawing of a control line extraction tool in accordance with an embodiment of the present disclosure.





DETAILED DESCRIPTION

This disclosure describes a system, tool, and method for sealing cracks, fractures, or other openings in a wellbore, for example, in a cemented annulus adjacent a casing of the wellbore. Many wellbores include a casing that lines at least a portion of a length of the wellbore, and cement that fills an annulus formed between the casing and another outer cylindrical wall, such as the wellbore wall or another casing. Cement is prone to cracking and wear over time due to a poor cement bond, thermal stress, or other factors. This can create an undesirable condition such as cracks, fissures, or microannuli which can provide a path for high-pressure fluids to migrate from deeper strata to lower-pressure strata or to the surface.


The system includes an injection tool positioned downhole and attached to the exterior of a casing, within the annulus formed between the inner casing and an outer casing. The tool is fluidically connected to one or more control lines which are operable to inject resin or other sealing fluid from the surface down to the tool.


In some embodiments, the tool includes a plurality of nozzles with burst discs operable to inject resin or other sealing fluid into the annulus. Such sealant injection can be referred to as a “squeeze job.” The nozzles in some embodiments are positioned along centralizer arms attached to the tool and are circumferentially disposed about the tool to distribute the sealing fluid evenly within the annulus. The tool is configured to evenly distribute the sealing fluid in the annular space the annulus. The timing, composition, and amount of injected sealing fluid can be controlled from the surface. In this way, cracks, fissures, or microannuli in the cement are filled with the sealant material and undesirable pressure or fluid migration to the surface via the casing-casing annulus is eliminated or minimized.



FIG. 1 is a schematic partial cross-sectional side view of an example well system 100 that includes a substantially cylindrical wellbore 102 extending from a wellhead 104 at a surface 105 downward into the Earth into one or more subterranean zones of interest. The example well system 100 shows one subterranean zone 106; however, the example well system 100 can include more than one zone. The well system 100 includes a vertical well, with the wellbore 102 extending substantially vertically from the surface 105 to the subterranean zone 106. The concepts described here, however, are applicable to many different configurations of wells, including vertical, horizontal, slanted, or otherwise deviated wells.


The wellhead 104 defines an attachment point for other equipment of the well system 100 to attach to the well 102. For example, the wellhead 104 can include a Christmas tree structure including valves used to regulate flow into or out of the wellbore 102, or other structures incorporated in the wellhead 104.


After some or all of the wellbore 102 is drilled, a portion of the wellbore 102 extending from the wellhead 104 to the subterranean zone 106 can be lined with lengths of tubing, called casing or liner. The wellbore 102 can be drilled in stages, the casing can be installed between stages, and cementing operations can be performed to inject cement in stages between the casing and a cylindrical wall positioned radially outward from the casing. The cylindrical wall can be an inner wall of the wellbore 102 such that the cement is disposed between the casing and the wellbore wall, the cylindrical wall can be a second casing such that the cement is disposed between the two tubular casings, or the cylindrical wall can be a different substantially tubular or cylindrical surface radially outward of the casing. In the example well system 100 of FIG. 1, the system 100 includes a first, outer liner or casing 108, such as a surface casing, defined by lengths of tubing lining a first portion of the wellbore 102 extending from the surface 105 into the Earth. Outer casing 108 is shown as extending only partially down the wellbore 102 and into the subterranean zone 106; however, the outer casing 108 can extend further into the wellbore 102 or end further uphole in the wellbore 102 than what is shown schematically in FIG. 1.


A first annulus 109, radially outward of the outer casing 108 between the outer casing 108 and an inner wall of the wellbore 102, is shown as filled with cement. The example well system 100 also includes a second, inner liner or casing 110 positioned radially inward from the outer casing 108 and defined by lengths of tubing lining a second portion of the wellbore 102 that extends further downhole of the wellbore 102 than the first casing 108. The inner casing 110 is shown as extending only partially down the wellbore 102 and into the subterranean zone 106, with a remainder of the wellbore 102 shown as open-hole (for example, without a liner or casing); however, the inner casing 110 can extend further into the wellbore 102 or end further uphole in the wellbore 102 than what is shown schematically in FIG. 1.


A second annulus 112, radially outward of the inner casing 110 and between the outer casing 108 and the inner casing 110, is shown as filled with cement. The second annulus 112 can be filled partly or completely with cement. This second annulus 112 can be referred to as a casing-casing annulus, because it is an annulus between two tubular casings in a wellbore.


While FIG. 1 shows the example well system 100 as including two casings (outer casing 108 and inner casing 110), the well system 100 can include more casings, such as three, four, or more casings.


Cracks and fissures can develop in the annular cement due to a poor cement bond, thermal stress, or other factors. This can create an undesirable condition as such cracks and fissures can provide a path for high-pressure fluids to migrate from deeper strata to lower-pressure strata or to the surface. Sealing the annular channels that can provide a path for the migration of fluid through the casing-casing annulus 112. Sealant injection tool 150 is configured to inject resin or another sealant into casing-casing annulus 112 so as to fill such cracks, microannuli, or other voids within the cement filling casing-casing annulus 112. Sealant injection tool 150 is described in more detail in reference to FIG. 2. As described in more detail in FIGS. 3-5, sealant can be flowed from a surface control system to the sealant injection tool 150 via one or more control lines which extend from the surface control system down to the sealant injection tool 150. A suitable sealant can be resin such as WellLock resin or ThermaSet resin or other particle-free fluid with an adjustable thickening time and high bonding strength.



FIG. 2 shows an exemplary sealant injection tool 150 in accordance with an embodiment of the present disclosure. Referring to FIG. 2, tool 150 comprises upper clamp 202 and lower claim 204. Clamps 202 and 204 are circular in shape and are configured to be attachable to the exterior of a cylindrical casing (for example, inner casing 110 of FIG. 1). In the illustrated embodiment, clamps 202 and 204 have a hollow interior. Tool 150 can be comprised of stainless steel or another suitable material.


An inlet port 206 allows for a fluid such as resin to be injected into the hollow interior of upper clamp 202. Clamps 202 and 204 are connected by centralizer arms 208. Centralizer arms 208 likewise comprise a hollow interior, and the hollow interior of clamps 202 and 204 are fluidically connected to the hollow interiors of centralizer arms 208. In the illustrated embodiment, tool 150 comprises four centralizer arms 208, each separated by 90° circumferentially about clamps 202 and 204. Other embodiments can include a different number of centralizer arms 208, for example, six or eight arms. In one embodiment of the present disclosure, the number of arms can preferentially depend on the size of the casing. For example, four arms 90° apart from each other can be suitable for a 7″ production casing. In the case of large casing sizes like a 9⅝″ casing, the number of arms can be increased to six arms (60° apart) or eight arms (45° apart) to provide more radial coverage.


Each of centralizer arms 208 further comprise a plurality of outer nozzles 210 and a plurality of inner nozzles 212. In one embodiment, each centralizer arm 208 comprises a total of ten nozzles 210 and 212. In other embodiments, each centralizer arm 208 can comprise fewer or more nozzles. For example, approximately ten nozzles can be suitable for a 7″ casing, whereas a higher number such as fifteen nozzles can be suitable for a larger casing, such as a 9⅝″ casing, so as to better distribute the sealant in the annulus.


Outer nozzles 210 extend radially outward from centralizer arms 208, and inner nozzles 212 extend radially inward from centralizer arms 208. Nozzles 210 and 212 are hollow and are fluidically connected to the hollow interior of their respective centralizer arms 208. The ends of nozzles 210 and 212 comprise burst discs configured to rupture when the interior pressure exceeds a predetermined amount. In one embodiment of the present disclosure, a burst pressure of the nozzles is chosen based on the collapse pressure of the host casing and the burst pressure of the outer casing. For typical 13⅜″×9⅝″ casing-casing annulus, a suitable burst pressure of the nozzles can be approximately 4500 psi.


In the illustrated embodiment, centralizer arms 208 have an arcuate shape such that they extend radially outward in an arc from clamps 202 and 204. In other embodiments, centralizer arms can have a different shape, such as trapezoidal. In addition to the injection function, centralizer arms 208 act as bowsprings to keep the casing or liner in the center of the wellbore to help ensure efficient placement of the cement sheath around the casing string. In still other embodiments, tool 150 does not comprise centralizer arms but can instead comprise nozzles extending from another portion or portions of tool 150, for example from one or both of clamps 202 or 204.


In the illustrated embodiment, each of the centralizer arms 208 further comprise a protector assembly 214 located at the radially outmost central portions of the arms 208. Protector assembly 214 comprises side protector plates 216, upper protector plates 218, and lower protector plates 220. Protector plates 216, 218, and 220 are comprised of high-grade stainless steel, titanium alloy, or another suitable material and are configured such that, when tool 150 is positioned within a casing or other tubular, protector plates 216, 218, and/or 220 contact the interior surface of the casing and protect outer nozzles 210 and the other portions of centralizer arms 208 from impact and/or friction caused by contact between the interior surface of the casing and the centralizer arms 208.


Tool 150 is configured such that a fluid (for example, resin) can be injected into inlet port 206 and will fill the hollow interiors of upper clamps 202, centralizer arms 208, and lower clamp 204. In one embodiment, the burst discs at the end of nozzles 210 and 212 are configured to rupture when the interior pressure exceeds a predetermined amount. When the discs are ruptured, the resin or other injected fluid exits the nozzles 210 and 212.


The distribution of centralizer arms 208 evenly from each other about the circumference of the casing (90° apart in the illustrated embodiment) and the distribution of the plurality of outer nozzles 210 facing outwards and the plurality of inner nozzles 212 facing inwards, distribute the resin evenly as it fills the space around centralizer arms 208.



FIG. 3 shows an exemplary sealant injection system 300 in accordance with an embodiment of the present disclosure. Referring to FIG. 3, and as also described in reference to FIG. 1, outer casing 108 is cemented into wellbore 102, with cement filling the annulus 109 between the exterior of outer casing 108 and the inner surface of wellbore 102. Inner casing 110 is cemented within outer casing 108, such that cement fills casing-casing annulus 112 between the exterior of inner casing 110 and the interior of outer casing 108.


Sealant injection tool 150, as described in reference to FIG. 2, is attached to the exterior of inner casing 110. A control line 302 is connected at its downhole end to the tool 150 at inlet port 206 (shown in FIG. 2). Control line 302 can be comprised of tungsten or another suitable material. In one embodiment of the disclosure, control line 302 has a minimum of 10,000 psi pressure rating. One or more intermediate clamps 304 keep control line 302 strapped closely to inner casing 110 uphole of tool 150. Control line 302 extends uphole to wellhead 104, exits wellhead 104 through side outlet flange 306, and connects to injection control system 350. Side outlet flange 306 is described in more detail in reference to FIG. 8.


Control system 350 is configured to controllably flow resin or other sealant downhole through control line 302. As shown in reference to FIG. 4, in some embodiments, control system 350 can be configured to controllably flow resin or another sealant downhole though more than one control line. In one embodiment, control system 350 comprises a high pressure/low injectivity pump with pressure sensors. Once it is decided to perform a squeeze job/sealant injection, the pump is connected to the control line 302 and sealant resin is pumped. At a pre-determined pressure, the nozzles 210 and 212 of the centralizers 208 burst and the sealant will start flowing in to the fractures, microannuli, and/or cracks within the cement within casing-casing annulus 112.



FIG. 4 shows an exemplary dual sealant injection system 400 in accordance with an embodiment of the present disclosure, comprising both a first and a second sealant injection tool.


Like the system 300 of FIG. 3, system 400 comprises a first sealant tool 150 attached to an inner casing 110 within the casing-casing annulus 112 between inner casing 110 and outer casing 108. Cement fills the outer annulus 109 and the casing-casing annulus 112, respectively. Control line 302 connects first sealant injection tool to control system 350.


In contrast to system 300 of FIG. 3, system 400 includes a second sealant injection tool 150B attached to the inner casing 110 uphole of first sealant injection tool 150. Sealant injection tool 150B can be configured with centralizer arms, nozzles, and the other features of sealant injection tool 150 as described in reference to FIG. 2. Second control line 402 extends uphole from sealant injection tool 150B to wellhead 104, exits the well through side outlet flange 306, and, as required, connects to injection control system 350.


One or more intermediate clamps 304 keep control lines 302 and 402 strapped closely to inner casing 110 uphole of tools 150 and 150B. Control lines 302 and 402 extend uphole to wellhead 104 and exit the wellhead through side outlet flange 306. Control system 350 is configured to flow sealant downhole through control lines 302 and 402. Control system 350 can be configured to pump sealant down control lines 302 and 402 at a controllable pressure, either simultaneously or at different times (for example, sequentially). At a pre-determined pressure, the nozzles 210 and 212 of the centralizers 208 burst and the sealant will start flowing in to the fractures, microannuli, and/or cracks within the cement within casing-casing annulus 112.



FIG. 5 is a drawing of a sealant injection system flowing resin or another sealant in accordance with an embodiment of the present disclosure. The system shown in FIG. 5 is the dual-injection tool embodiment shown in reference to FIG. 4; however, the flow of sealant as described in reference to FIG. 5 is applicable to other embodiments as well; for example, a single-tool system as shown in FIG. 3 or a system with a different number of injection tools attached to the casing.


As shown in FIG. 5, as sealant 510 and 512 is flowed through control lines 302 and 402 and exits the nozzles from tools 150 and 150B, respectively. Centralizer arms 208 are distributed evenly from each other about the circumference of the inner casing 110 (90° apart in the illustrated embodiment), and a plurality of outer nozzles 210 face outwards and the plurality of inner nozzles 212 face inwards, thus distributing the sealant 510 and 512 evenly as it fills any small voids or microannuli in the cement that fills casing-casing annulus 112. In one embodiment, sealant can be pumped at a pressure that is 80%-90% of the burst and collapse pressure of casing 110 and casing 108, respectively.


In some circumstances, sealant 510 and 512 can be simultaneously injected from tools 150 and 150B. That is, sealant is flowed through both control lines 301 and 402 at the same time. In other circumstances, sealant can be injected first through one of tools 150 and 150B, and then sealant flowed at a later time through the other tool. For example, upon first detection or concern regarding any potential cracks or voids in the casing-casing annulus (as can be evident by pressure readings at the surface in the casing-casing annulus 112), sealant can be flowed through a first tool. If such sealant injection is successful, a second injection through the second tool can be unnecessary and/or can be delayed until subsequent detection or concern regarding additional or remaining cracks or voids. Such detection can be via pressure readings at the surface indicating higher pressures in casing-casing annulus 112. In one embodiment, side-outlet flange 306 comprises a pressure gauge configured to detect such casing-casing annulus pressure.



FIG. 6 is a process flow diagram of a method 600 for sealing an annulus in accordance with an embodiment of the present disclosure. The method is described with reference to the components described in reference to FIGS. 1-5.


The method begins at block 602 with the positioning of a first, outer casing 108 within a wellbore 102. At block 604, the outer casing is cemented in the well using standard casing cementing methods.


The method continues at block 606 with the attachment at the surface of sealant injection tool(s) 150 to a second, inner casing 110 using clamps 202 and 204. In some embodiments, only one tool 150 is attached to casing 110. In another embodiment, a first tool 150 and a second tool 150B are attached to inner casing 110. In one embodiment, where flange 306 comprises a standard 2 1/16″ flange, such a flange can accommodate a maximum of two control lines, and thus a maximum of two sealant injection tools can be utilized in a system with such a standard flange size. In other embodiments, utilizing different flange configurations or sizes, more than two sealant injection tools 150 can be attached to inner casing 110. Clamps 202 and 204 fit around the circumference of the inner casing and control lines 302 and 402 extend from the tools 150 and 150B.


At block 608, the inner casing 110 is lowered into the wellbore, within the outer casing 108. Control lines 302 extend from tool 150 to the surface as the tool is lowered downhole. A casing-casing annulus 112 is formed by the annular space between the outer casing 108 and the inner casing 110.


At block 610, the upper ends of the control lines 302 and 402 are extracted from the wellhead and attached or passed through side-control flange 306 and, when sealant injection is required, connected to surface control system 350. Further details regarding the control line extraction procedure are described in reference to FIGS. 7A-7D, FIG. 8, and FIG. 9. At block 612, the inner casing 110 is cemented in the wellbore using standard cementing methods.


As the cement cures or ages, small microannuli or other voids can form in the cement. At block 614, sealant is injected from the first sealant injection tool 150, filling voids within the cement in the annulus between the first and second casing.


In the embodiment wherein two injection tools 150 and 150B are attached to inner casing 110, at step 616, sealant is injected from the second sealant injection tool 150B, filling remaining or additional voids within the cement in the annulus between the first and second casing.



FIGS. 7A-7D is a drawing of a control line extraction sequence in accordance with an embodiment of the present disclosure.


As shown in FIG. 7A, control lines 302 and 402 extend uphole from the downhole-positioned sealant injection tools (not shown) and extend into wellhead 104. A control line extraction tool 704 is inserted into wellhead 104 via a side outlet 702. Control line extraction tool 704 is described in more detail in reference to FIG. 9.


As shown in FIG. 7B, control line extraction tool 704 grabs control lines 302 and 402 and pulls control lines 302 and 402 out of wellhead 104 through the side outlet 702. Control lines 302 and 304 are cut to the required length.


As shown in FIG. 7C, control lines 302 and 402 are inserted through side outlet flange 306. At FIG. 7D, side outlet flange 306 is secured to the side outlet, thus sealing wellhead 104 but allowing fluid flow into the wellbore via control lines 302 and 402 when required. Control lines 302 and 402 can remain closed with ½″ NPT connections during normal well operations. When a squeeze job/sealant injection is required, control lines 302 and 402 can be connected to surface control system 350 (not shown).


Control lines 302 and 402 can in some embodiments comprise continuous lines from downhole tool to surface control system 350. In other embodiments, control lines 302 and 402 can comprise different segments of lines fluidically attached to each other. For example, one segment of control lines 302 and 402 can connect downhole tools 150 to side outlet flange 306, and another segment of control lines 302 and 402 can connect from side outlet flange 306 to control system 350, providing continuous fluidic connection from downhole tool to surface control system.



FIG. 8 is a drawing of a side outlet flange 306 in accordance with an embodiment of the present disclosure.


Side outlet flange 306 comprises a main body 802 and ports 804 and 806. In one embodiment of the present disclosure, ports 804 and 806 comprise ½ inch NPT (National Pipe Tapered) connections. The side outlet flange 306 and ports 804 and 806 can have a pressure rating that is the same as control lines 302 and 402. In one embodiment of the present disclosure, side outlet flange 306 and ports 804 and 806 have a pressure rating of 10,000 psi.



FIG. 9 is a drawing of a control line extraction tool 704 in accordance with an embodiment of the present disclosure.


Control line extraction tool 704 can be inserted into a side outlet of the wellhead (for example side outlet 702 in FIG. 7A) to allow the user to locate and grab control lines (for example, control lines 302 and 304 of FIG. 7A).


Referring to FIG. 9, control line extraction tool 704 comprises grab arms 902 attached to arm 904. Arm 904 is configured to move up, down, sideways, or forwards or backwards, in response to commands from joystick controller 906. Joystick controller 906 also allows the user to close or open grab arms 902.


Sensor unit 908 can comprise cameras and/or lights so that the user can observe the vicinity of grab arms 902 using observation screen 910. Using the information regarding control line and grab arm location exhibited on observation screen 901, the user can locate and grab the control lines. As shown in FIGS. 7A-7E, after the control lines have been grabbed by grab arms 902, control line extraction tool 704 is pulled from the outlet, pulling out control lines so that they can then be attached to a surface control system (for example, control system 350 of FIG. 3).

Claims
  • 1. A downhole sealant injection system, comprising a first casing configured to be positioned in a wellbore;a second casing configured to be positioned in the wellbore and to be cemented within the first casing such that cement at least partially fills an annulus between the interior of the first casing and the exterior of the second casing;a first sealant injection tool configured to be attached to the exterior of the second casing, the first sealant injection tool configured to be positioned at a downhole location and within the annulus between the interior of the first casing and the exterior of the second casing, wherein the sealant injection tool comprises a plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing after the second casing has been cemented within the first casing.
  • 2. The downhole sealant injection system of claim 1, wherein at least a portion of the plurality of nozzles are defined in at least one of a plurality of centralizer arms.
  • 3. The downhole sealant injection system of claim 2, wherein the centralizer arms are hollow, and wherein an interior of the nozzles is fluidically connected to an interior of the centralizer arms.
  • 4. The downhole sealant injection system of claim 1, further comprising a second sealant injection tool attached to the exterior of the second casing, the second sealant injection tool comprising a second plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.
  • 5. The downhole sealant injection system of claim 1, further comprising a first control line configured to flow sealant from a surface control system to the first sealant injection tool.
  • 6. The downhole sealant injection system of claim 5, further comprising a second control line configured to flow sealant from the surface control system to the second sealant injection tool.
  • 7. The downhole sealant injection system of claim 1, wherein the nozzles comprise burst discs configured to flow sealant upon an exceedance of a burst pressure.
  • 8. The downhole sealant injection system of claim 1, wherein the sealant comprises a resin.
  • 9. A sealant injection tool, comprising: clamps configured to be attached to the exterior of a casing, the casing configured to be placed within a wellbore;a plurality of centralizer arms attached to the clamps and extending radially outward from the casing;a plurality of nozzles defined in the centralizer arms, the plurality of nozzles configured to inject sealant into a space exterior of the casing within the wellbore.
  • 10. The sealant injection tool of claim 9, wherein the centralizer arms are hollow, and wherein an interior of the nozzles is fluidically connected to an interior of the centralizer arms.
  • 11. The sealant injection tool of claim 9, wherein the nozzles comprise burst discs configured to flow sealant upon an exceedance of a burst pressure.
  • 12. The sealant injection tool of claim 9, wherein a first subset of the plurality of nozzles points outward away from the casing and a second subset of the plurality of nozzles points inward towards the casing.
  • 13. The sealant injection tool of claim 9, wherein the sealant comprises a resin.
  • 14. A method of sealing an annulus between a first casing and a second casing, the first casing positioned within a wellbore, the method comprising: attaching a first sealant injection tool to the exterior of the second casing, the sealant injection tool comprising a plurality of nozzles;lowering the second casing and the sealant injection tool into the wellbore within the first casing;cementing the second casing within the first casing by flowing cement into the [an] annulus between the interior of the first casing and the exterior of the second casing; andinjecting, after the second casing has been cemented within the first casing, sealant from the nozzles, the sealant filling voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.
  • 15. The method of claim 14, wherein a downhole end of a first control line is configured to be fluidically connected to the first sealant injection tool, and further comprising fluidically connecting an uphole end of the first control line to a surface control system.
  • 16. The method of claim 15, further comprising flowing sealant from the surface control system through the first control line.
  • 17. The method of claim 14, further comprising attaching a second sealant injection tool to the exterior of the second casing, the second sealant injection tool comprising a second plurality of nozzles configured to inject sealant into voids within the cement in the annulus between the interior of the first casing and the exterior of the second casing.
  • 18. The method of claim 17, wherein a downhole end of a second control line is configured to fluidically connect to the second sealant injection tool, and further comprising fluidically connecting an uphole end of the second control line to a surface control system.
  • 19. The method of claim 14, wherein the nozzles comprise burst discs, and further comprising applying pressure to the first control line sufficient to burst the burst discs.
  • 20. The method of claim 14, wherein the sealant comprises a resin.
US Referenced Citations (317)
Number Name Date Kind
880404 Sanford Feb 1908 A
1033655 Baker Jul 1912 A
1258273 Titus et al. Mar 1918 A
1392650 Mcmillian Oct 1921 A
1491066 Patrick Apr 1924 A
1580352 Ercole Apr 1926 A
1591264 Baash Jul 1926 A
1621947 Moore Mar 1927 A
1638494 Lewis et al. Aug 1927 A
1789993 Switzer Jan 1931 A
1896236 Howard Feb 1933 A
1896482 Crowell Feb 1933 A
1897297 Brown Feb 1933 A
1949498 Frederick et al. Mar 1934 A
2047774 Greene Jul 1936 A
2121002 Baker Jun 1938 A
2121051 Ragan et al. Jun 1938 A
2187487 Burt Jan 1940 A
2189697 Baker Feb 1940 A
2222233 Mize Nov 1940 A
2286075 Evans Jun 1942 A
2304793 Bodine Dec 1942 A
2316402 Canon Apr 1943 A
2327092 Botkin Aug 1943 A
2377249 Lawrence May 1945 A
2411260 Glover et al. Nov 1946 A
2481637 Yancey Sep 1949 A
2546978 Collins et al. Apr 1951 A
2638988 Williams May 1953 A
2663370 Robert et al. Dec 1953 A
2672199 McKenna Mar 1954 A
2701019 Steed Feb 1955 A
2707998 Baker et al. May 1955 A
2708973 Twining May 1955 A
2728599 Moore Dec 1955 A
2734581 Bonner Feb 1956 A
2745693 Mcgill May 1956 A
2751010 Trahan Jun 1956 A
2762438 Naylor Sep 1956 A
2778428 Baker et al. Jan 1957 A
2806532 Baker et al. Sep 1957 A
2881838 Morse et al. Apr 1959 A
2887162 Le Bus et al. May 1959 A
2912053 Bruekelman Nov 1959 A
2912273 Chadderdon et al. Nov 1959 A
2915127 Abendroth Dec 1959 A
2947362 Smith Aug 1960 A
2965175 Ransom Dec 1960 A
2965177 Le Bus et al. Dec 1960 A
2965183 Le Bus et al. Dec 1960 A
3005506 Le Bus et al. Oct 1961 A
3023810 Anderson Mar 1962 A
3116799 Lemons Jan 1964 A
3147536 Lamphere Sep 1964 A
3225828 Wisenbaker et al. Dec 1965 A
3255821 Curlet Jun 1966 A
3308886 Evans Mar 1967 A
3352593 Webb Nov 1967 A
3369603 Trantham Feb 1968 A
3376934 William Apr 1968 A
3380528 Durwood Apr 1968 A
3381748 Peters et al. May 1968 A
3382925 Jennings May 1968 A
3437136 Young Apr 1969 A
3667721 Vujasinovic Jun 1972 A
3747674 Murray Jul 1973 A
3752230 Bernat et al. Aug 1973 A
3897038 Le Rouax Jul 1975 A
3915426 Le Rouax Oct 1975 A
4030354 Scott Jun 1977 A
4039798 Lyhall et al. Aug 1977 A
4042019 Henning Aug 1977 A
4059155 Greer Nov 1977 A
4099699 Allen Jul 1978 A
4158388 Owen Jun 1979 A
4190112 Davis Feb 1980 A
4227573 Pearce et al. Oct 1980 A
4254983 Harris Mar 1981 A
4276931 Murray Jul 1981 A
4296822 Ormsby Oct 1981 A
4349071 Fish Sep 1982 A
4391326 Greenlee Jul 1983 A
4407367 Kydd Oct 1983 A
4412130 Winters Oct 1983 A
4413642 Smith et al. Nov 1983 A
4422948 Corley et al. Dec 1983 A
4467996 Baugh Aug 1984 A
4515212 Krugh May 1985 A
4538684 Sheffield Sep 1985 A
4562888 Collet Jan 1986 A
4603578 Stolz Aug 1986 A
4616721 Furse Oct 1986 A
4696502 Desai Sep 1987 A
4834184 Streich et al. May 1989 A
4836289 Young Jun 1989 A
4869321 Hamilton Sep 1989 A
4877085 Pullig, Jr. Oct 1989 A
4898245 Braddick Feb 1990 A
4928762 Mamke May 1990 A
4953617 Ross et al. Sep 1990 A
4997225 Denis Mar 1991 A
5012863 Springer May 1991 A
5054833 Bishop et al. Oct 1991 A
5060737 Mohn Oct 1991 A
5117909 Wilton Jun 1992 A
5129956 Christopher et al. Jul 1992 A
5176208 Lalande et al. Jan 1993 A
5178219 Streich et al. Jan 1993 A
5197547 Morgan Mar 1993 A
5203646 Landsberger et al. Apr 1993 A
5295541 Ng et al. Mar 1994 A
5330000 Givens et al. Jul 1994 A
5358048 Brooks Oct 1994 A
5392715 Pelrine Feb 1995 A
5456312 Lynde et al. Oct 1995 A
5507346 Gano et al. Apr 1996 A
5580114 Palmer Dec 1996 A
5584342 Swinford Dec 1996 A
5605366 Beeman Feb 1997 A
5639135 Beeman Jun 1997 A
5667015 Harestad et al. Sep 1997 A
5673754 Taylor Oct 1997 A
5678635 Dunlap et al. Oct 1997 A
5685982 Foster Nov 1997 A
5806596 Hardy et al. Sep 1998 A
5833001 Song et al. Nov 1998 A
5842518 Soybel et al. Dec 1998 A
5881816 Wright Mar 1999 A
5924489 Hatcher Jul 1999 A
5944101 Hearn Aug 1999 A
6070665 Singleton et al. Jun 2000 A
6112809 Angle Sep 2000 A
6130615 Poteet Oct 2000 A
6138764 Scarsdale et al. Oct 2000 A
6155428 Bailey et al. Dec 2000 A
6247542 Kruspe et al. Jun 2001 B1
6276452 Davis et al. Aug 2001 B1
6371204 Singh et al. Apr 2002 B1
6378627 Tubel et al. Apr 2002 B1
6478086 Hansen Nov 2002 B1
6491108 Slup et al. Dec 2002 B1
6510947 Schulte et al. Jan 2003 B1
6595289 Tumlin et al. Jul 2003 B2
6637511 Linaker Oct 2003 B2
6679330 Compton et al. Jan 2004 B1
6688386 Comelssen Feb 2004 B2
6698712 Milberger et al. Mar 2004 B2
6729392 DeBerry et al. May 2004 B2
6768106 Gzara et al. Jul 2004 B2
6772839 Bond Aug 2004 B1
6808023 Smith et al. Oct 2004 B2
6811032 Schulte et al. Nov 2004 B2
6880639 Rhodes et al. Apr 2005 B2
6899178 Tubel May 2005 B2
6913084 Boyd Jul 2005 B2
7049272 Sinclair et al. May 2006 B2
7051810 Halliburton May 2006 B2
7096950 Howlett et al. Aug 2006 B2
7117956 Grattan et al. Oct 2006 B2
7150328 Marketz et al. Dec 2006 B2
7188674 McGavem, III et al. Mar 2007 B2
7188675 Reynolds Mar 2007 B2
7218235 Rainey May 2007 B1
7231975 Lavaure et al. Jun 2007 B2
7249633 Ravensbergen et al. Jul 2007 B2
7275591 Allen et al. Oct 2007 B2
7284611 Reddy et al. Oct 2007 B2
7303010 de Guzman et al. Dec 2007 B2
7398832 Brisco Jul 2008 B2
7405182 Verrett Jul 2008 B2
7418860 Austerlitz et al. Sep 2008 B2
7424909 Roberts et al. Sep 2008 B2
7488705 Reddy et al. Feb 2009 B2
7497260 Telfer Mar 2009 B2
7591305 Brookey et al. Sep 2009 B2
7600572 Slup et al. Oct 2009 B2
7617876 Patel et al. Nov 2009 B2
7621324 Atencio Nov 2009 B2
7712527 Roddy May 2010 B2
7735564 Guerrero Jun 2010 B2
7762323 Frazier Jul 2010 B2
7802621 Richards et al. Sep 2010 B2
7934552 La Rovere May 2011 B2
7965175 Yamano Jun 2011 B2
8002049 Keese et al. Aug 2011 B2
8056621 Ring et al. Nov 2011 B2
8069916 Giroux et al. Dec 2011 B2
8201693 Jan Jun 2012 B2
8210251 Lynde et al. Jul 2012 B2
8376051 McGrath et al. Feb 2013 B2
8453724 Zhou Jun 2013 B2
8496055 Mootoo et al. Jul 2013 B2
8579024 Mailand et al. Nov 2013 B2
8596463 Burkhard Dec 2013 B2
8726983 Khan May 2014 B2
8770276 Nish et al. Jul 2014 B1
8899338 Elsayed et al. Dec 2014 B2
8936097 Heijnen Jan 2015 B2
8991489 Redlinger et al. Mar 2015 B2
9079222 Burnett et al. Jul 2015 B2
9109433 DiFoggio et al. Aug 2015 B2
9133671 Kellner Sep 2015 B2
9163469 Broussard et al. Oct 2015 B2
9181782 Berube et al. Nov 2015 B2
9212532 Leuchtenberg et al. Dec 2015 B2
9234394 Wheater et al. Jan 2016 B2
9359861 Burgos Jun 2016 B2
9410066 Ghassemzadeh Aug 2016 B2
9416617 Wiese et al. Aug 2016 B2
9551200 Read et al. Jan 2017 B2
9574417 Laird et al. Feb 2017 B2
9657213 Murphy et al. May 2017 B2
9976407 Ash et al. May 2018 B2
10018011 Van Dongen Jul 2018 B2
10087752 Bedonet Oct 2018 B2
10198929 Snyder Feb 2019 B2
10266698 Cano et al. Apr 2019 B2
10280706 Sharp, III May 2019 B1
10301898 Orban May 2019 B2
10301989 Imada May 2019 B2
10584546 Ford Mar 2020 B1
10626698 Al-Mousa Apr 2020 B2
10655456 Espe May 2020 B2
10837254 Al-Mousa et al. Nov 2020 B2
11274515 Grimsbo Mar 2022 B2
20020053428 Maples May 2002 A1
20030047312 Bell Mar 2003 A1
20030098064 Kohli et al. May 2003 A1
20030132224 Spencer Jul 2003 A1
20030155155 Dewey et al. Aug 2003 A1
20040040707 Dusterhoft et al. Mar 2004 A1
20040065446 Tran et al. Apr 2004 A1
20040074819 Burnett Apr 2004 A1
20040095248 Mandel May 2004 A1
20050056427 Clemens et al. Mar 2005 A1
20050167097 Sommers et al. Aug 2005 A1
20050263282 Jeffrey et al. Dec 2005 A1
20060082462 Crook Apr 2006 A1
20060105896 Smith et al. May 2006 A1
20070137528 Le Roy-Ddelage et al. Jun 2007 A1
20070181304 Rankin et al. Aug 2007 A1
20070204999 Cowie et al. Sep 2007 A1
20070256867 DeGeare et al. Nov 2007 A1
20080087439 Dallas Apr 2008 A1
20080236841 Howlett et al. Oct 2008 A1
20080251253 Lumbye Oct 2008 A1
20080314591 Hales et al. Dec 2008 A1
20090194290 Parks et al. Aug 2009 A1
20090250220 Stamoulis Oct 2009 A1
20100258289 Lynde et al. Oct 2010 A1
20100263856 Lynde et al. Oct 2010 A1
20100270018 Howlett Oct 2010 A1
20110036570 La Rovere et al. Feb 2011 A1
20110056681 Khan Mar 2011 A1
20110067869 Bour et al. Mar 2011 A1
20110168411 Braddick Jul 2011 A1
20110203794 Moffitt et al. Aug 2011 A1
20110259609 Hessels et al. Oct 2011 A1
20110273291 Adams Nov 2011 A1
20110278021 Travis et al. Nov 2011 A1
20120012335 White et al. Jan 2012 A1
20120067447 Ryan et al. Mar 2012 A1
20120118571 Zhou May 2012 A1
20120170406 DiFoggio et al. Jul 2012 A1
20120285684 Crow et al. Nov 2012 A1
20130134704 Klimack May 2013 A1
20130213654 Dewey et al. Aug 2013 A1
20130240207 Frazier Sep 2013 A1
20130269097 Alammari Oct 2013 A1
20130296199 Ghassemzadeh Nov 2013 A1
20140138091 Fuhst May 2014 A1
20140158350 Castillo et al. Jun 2014 A1
20140231068 Isaksen Aug 2014 A1
20140251616 O'Rourke et al. Sep 2014 A1
20140311756 Dicke Oct 2014 A1
20150013994 Bailey et al. Jan 2015 A1
20150021028 Boekholtz Jan 2015 A1
20150096738 Atencio Apr 2015 A1
20150198009 Bexte Jul 2015 A1
20160076327 Glaser et al. Mar 2016 A1
20160084034 Roane et al. Mar 2016 A1
20160130914 Steele May 2016 A1
20160160106 Jamison et al. Jun 2016 A1
20160177637 Fleckenstein Jun 2016 A1
20160237810 Beaman et al. Aug 2016 A1
20160281458 Greenlee Sep 2016 A1
20160305215 Harris et al. Oct 2016 A1
20160340994 Ferguson et al. Nov 2016 A1
20170009554 Surjaatmadja Jan 2017 A1
20170044864 Sabins et al. Feb 2017 A1
20170058628 Wijk et al. Mar 2017 A1
20170067313 Connell et al. Mar 2017 A1
20170089166 Sullivan Mar 2017 A1
20180010418 VanLue Jan 2018 A1
20180030809 Harestad et al. Feb 2018 A1
20180187498 Soto et al. Jul 2018 A1
20180209565 Lingnau Jul 2018 A1
20180216438 Sewell Aug 2018 A1
20180245427 Jimenez et al. Aug 2018 A1
20180252069 Abdollah et al. Sep 2018 A1
20180363407 Kunz Dec 2018 A1
20190024473 Arefi Jan 2019 A1
20190049017 McAdam et al. Feb 2019 A1
20190087548 Bennett et al. Mar 2019 A1
20190186232 Ingram Jun 2019 A1
20190203551 Davis et al. Jul 2019 A1
20190284894 Schmidt et al. Sep 2019 A1
20190284898 Fagna et al. Sep 2019 A1
20190316424 Robichaux et al. Oct 2019 A1
20190338615 Landry Nov 2019 A1
20200032604 Al-Ramadhan Jan 2020 A1
20200040707 Watts et al. Feb 2020 A1
20200056446 Al-Mousa et al. Feb 2020 A1
20200325746 Lerbrekk Oct 2020 A1
20210285306 Al Mulhem Sep 2021 A1
20210388693 Machocki Dec 2021 A1
20220098949 Grimsbo Mar 2022 A1
Foreign Referenced Citations (48)
Number Date Country
636642 May 1993 AU
2007249417 Nov 2007 AU
2441138 Mar 2004 CA
2734032 Jun 2016 CA
203292820 Nov 2013 CN
103785923 Jun 2016 CN
104712320 Dec 2016 CN
107060679 Aug 2017 CN
107191152 Sep 2017 CN
107227939 Oct 2017 CN
110998059 Apr 2020 CN
2545245 Apr 2017 DK
2236742 Aug 2017 DK
0622522 Nov 1994 EP
2964874 Jan 2016 EP
2545245 Apr 2017 EP
958734 May 1964 GB
2356415 May 2001 GB
2392183 Feb 2004 GB
2414586 Nov 2005 GB
2425138 Oct 2006 GB
2453279 Jan 2009 GB
2492663 Jan 2014 GB
2548768 Sep 2017 GB
5503 Apr 1981 OA
WO 1989012728 Dec 1989 WO
WO 1996039570 Dec 1996 WO
WO 2002090711 Nov 2002 WO
WO 2008106639 Sep 2008 WO
WO 2010132807 Nov 2010 WO
WO 2012164023 Dec 2012 WO
WO 2013109248 Jul 2013 WO
WO 2015112022 Jul 2015 WO
WO 2016011085 Jan 2016 WO
WO 2016040310 Mar 2016 WO
WO-2016123166 Aug 2016 WO
WO 2016140807 Sep 2016 WO
WO 2017043977 Mar 2017 WO
WO-2017173540 Oct 2017 WO
WO 2018017104 Jan 2018 WO
WO-2018034672 Feb 2018 WO
WO 2018164680 Sep 2018 WO
WO 2019027830 Feb 2019 WO
WO 2019132877 Jul 2019 WO
WO 2019231679 Dec 2019 WO
WO-2021107937 Jun 2021 WO
WO-2021145902 Jul 2021 WO
WO-2022025942 Feb 2022 WO
Non-Patent Literature Citations (33)
Entry
Al-Ansari et al., “Thermal Activated Resin to Avoid Pressure Build-Up in Casing-Casing Annulus (CCA),” SA-175425-MS, Society of Petroleum Engineers (SPE), presented at the SPE Offshore Europe Conference and Exhibition, Sep. 8-11, 2015, 11 pages.
Al-Ibrahim et al., “Automated Cyclostratigraphic Analysis in Carbonate Mudrocks Using Borehole Images,” Article #41425, posted presented at the 2014 AAPG Annual Convention and Exhibition, Search and Discovery, Apr. 6-9, 2014, 4 pages.
Bautista et al., “Probability-based Dynamic TimeWarping for Gesture Recognition on RGB-D data,” WDIA 2012: Advances in Depth Image Analysis and Application, 126-135, International Workshop on Depth Image Analysis and Applications, 2012, 11 pages.
Boriah et al., “Similarity Measures for Categorical Data: A Comparative Evaluation,” presented at the SIAM International Conference on Data Mining, SDM 2008, Apr. 24-26, 2008, 12 pages.
Bruton et al., “Whipstock Options for Sidetracking,” Oilfield Review, Spring 2014, 26:1, 10 pages.
Edwards et al., “Assessing Uncertainty in Stratigraphic Correlation: A Stochastic Method Based on Dynamic Time Warping,” RM13, Second EAGE Integrated Reservoir Modelling Conference, Nov. 16-19, 2014, 2 pages.
Edwards, “Constructionde modèles stratigraphiques à partir de données éparses,” Stratigraphie, Université de Lorraine, 2017, 133 pages, English abstract.
Fischer, “The Lofer Cyclothems of the Alpine Triassic,” published in Merriam, Symposium on Cyclic Sedimentation: Kansas Geological Survey (KGS), Bulletin, 1964, 169: 107-149, 50 pages.
Hernandez-Vela et al., “Probability-based Dynamic Time Warping and Bag-of-Visual-and-Depth-Words for human Gesture Recognition in RGB-D,” Pattern Recognition Letters, 2014, 50: 112-121, 10 pages.
Herrera and Bann, “Guided seismic-to-well tying based on dynamic time warping,” SEG Las Vegas 2012 Annual Meeting, Nov. 2012, 6 pages.
Keogh and Ratanamahatana, “Exact indexing of dynamic time warping,” Knowledge and Information Systems, Springer-Verlag London Ltd., 2004, 29 pages.
Lallier et al., “3D Stochastic Stratigraphic Well Correlation of Carbonate Ramp Systems,” IPTC 14046, International Petroleum Technology Conference (IPTC), presented at the International Petroleum Technology Conference, Dec. 7-9, 2009, 5 pages.
Lallier et al., “Management of ambiguities in magnetostratigraphic correlation,” Earth and Planetary Science Letters, 2013, 371-372: 26-36, 11 pages.
Lallier et al., “Uncertainty assessment in the stratigraphic well correlation of a carbonate ramp: Method and application of the Beausset Basin, SE France,” C. R. Geoscience, 2016, 348: 499-509, 11 pages.
Lineman et al., “Well to Well Log Correlation Using Knowledge-Based Systems and Dynamic Depth Warping,” SPWLA Twenty-Eighth Annual Logging Symposium, Jun. 29-Jul. 2, 1987, 25 pages.
Nakanishi and Nakagawa, “Speaker-Independent Word Recognition by Less Cost and Stochastic Dynamic Time Warping Method,” ISCA Archive, European Conference on Speech Technology, Sep. 1987, 4 pages.
Pels et al., “Automated biostratigraphic correlation of palynological records on the basis of shapes of pollen curves and evaluation of next-best solutions,” Paleogeography, Paleoclimatology, Paleoecology, 1996, 124: 17-37, 21 pages.
Pollack et al., “Automatic Well Log Correlation,” AAPG Annual Convention and Exhibition, Apr. 3, 2017, 1 page, Abstract Only.
Rudman and Lankston, “Stratigraphic Correlation of Well Logs by Computer Techniques,” The American Association of Petroleum Geologists, Mar. 1973, 53:3 (557-588), 12 pages.
Sakoe and Chiba, “Dynamic Programming Algorithm Optimization for Spoken Word Recognition,” IEEE Transactions on Acoustics, Speech and Signal Processing, ASSP-26:1, Feb. 1978, 7 pages.
Salvador and Chan, “FastDTW: Toward Accurate Dynamic Time Warping in Linear Time and Space,” presented at the KDD Workshop on Mining Temporal and Sequential Data, Intelligent Data Analysis, Jan. 2004, 11:5 (70-80), 11 pages.
Say hi, “peakdet: Peak detection using MATLAB,” Jul. 2012, 4 pages.
Scribd.com [online], “Milling Practices and Procedures,” retrieved from URL <https://www.scribd.com/document/358420338/Milling-Rev-2-Secured>, 80 pages.
Silva and Koegh, “Prefix and Suffix Invariant Dynamic Time Warping,” IEEE Computer Society, presented at the IEEE 16th International Conference on Data Mining, 2016, 6 pages.
Smith and Waterman, “New Stratigraphic Correlation Techniques,” Journal of Geology, 1980, 88: 451-457, 8 pages.
Startzman and Kuo, “A Rule-Based System for Well Log Correlation,” SPE Formative Evaluation, Society of Petroleum Engineers (SPE), Sep. 1987, 9 pages.
TAM International Inflatable and Swellable Packers, “TAM Scab Liner brochure,” Tam International, available on or before Nov. 15, 2016, 4 pages.
Tomasi et al., “Correlation optimized warping and dynamic time warping as preprocessing methods for chromatographic data,” Journal of Chemometrics, 2004, 18: 231-241, 11 pages.
Uchida et al., “Non-Markovian Dynamic Time Warping,” presented at the 21st International Conference on Pattern Recognition (ICPR), Nov. 11-15, 2012, 4 pages.
Waterman and Raymond, “The Match Game: New Stratigraphic Correlation Algorithms,” Mathematical Geology, 1987, 19:2, 19 pages.
Weatherford, “Micro-Seal Isolation System-Bow (MSIS-B),” Weatherford Swellable Well Construction Products, Brochure, 2009-2011, 2 pages.
Zoraster et al., “Curve Alignment for Well-to-Well Log Correlation,” SPE 90471, Society of Petroleum Engineers (SPE), presented at the SPE Annual Technical Conference and Exhibition, Sep. 26-29, 2004, 6 pages.
PCT International Search Report and Written Opinion in International Appln. No. PCT/US2021/064294, dated Mar. 21, 2022, 16 pages.
Related Publications (1)
Number Date Country
20220195834 A1 Jun 2022 US