DETAILED ACTION
Applicant’s 05/21/2026 response to the previous 03/11/2026 Office action has been considered and entered.
This is the First Final Office Action on the Merits and is directed towards claims 1-20 as amended and/or filed on 05/21/2026.
Notice of Pre-AIA or AIA Status
No apparent Priority is claimed accordingly the earliest filing date is 03/30/2023 (20230330).
The present application filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Amendments/Arguments
Applicant’s 05/21/2026 amendments to the independent claims and arguments in support thereof with respect to the rejection(s) of the claim(s) as set forth in said previous 03/11/2026 Office action have been fully considered and are persuasive. Therefore, the rejection(s) set forth in said previous 03/11/2026 Office action has(have) been withdrawn. However, upon further consideration, a new ground(s) of rejection is made as set forth below.
Claim Rejections - 35 USC § 103
The following is a quotation of pre-AIA 35 U.S.C. 103(a) which forms the basis for all obviousness rejections set forth in this Office action:
(a) A patent may not be obtained though the invention is not identically disclosed or described as set forth in section 102 of this title, if the differences between the subject matter sought to be patented and the prior art are such that the subject matter as a whole would have been obvious at the time the invention was made to a person having ordinary skill in the art to which said subject matter pertains. Patentability shall not be negatived by the manner in which the invention was made.
The factual inquiries set forth in Graham v. John Deere Co., 383 U.S. 1, 148 USPQ 459 (1966), that are applied for establishing a background for determining obviousness under pre-AIA 35 U.S.C. 103(a) are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
Claims 1, 2, 6 and 10-20 are rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 20190085661 A1 to DANCER; William Wallace in view of US 20020070018 A1 to Buyaert, Jean P.
Regarding claim 1 DANCER teaches in for example the Figure(s) reproduced immediately below:
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and associated descriptive texts a system comprising:
a retrieving tool component comprising
a first engagement element disposed at a first radial distance from a retrieving tool centerline (given the Broadest Reasonable Interpretation (BRI) the claimed retrieving tool connotes “retrieval tool 500” and :engagement element” connotes “dogs 504” shown in for example fig. 5 above and explained in for example para:
“[0036] Referring now to FIG. 5, with continued reference to FIGS. 2 and 4, as previously discussed, the tool 200 may be retrieved using a retrieval tool after production of hydrocarbons is complete or at another desired time. A retrieval tool 500 may be advanced through the primary leg 240 of the multilateral tool 236 (shown in phantom) and into the borehole 505 of the whipstock 204. The retrieval tool 500 may be conveyed into the parent wellbore 102 on a tool string 501. The retrieval tool 500 may be operatively coupled to the whipstock 204 within the whipstock bore 502 via a coupling engagement 502. The coupling engagement 502 may comprise a variety of coupling mechanisms or methods capable of securing the retrieval tool 500 to the whipstock 204. In one embodiment, for instance, the coupling engagement 502 may include one or more dogs 504 disposed about the retrieval tool 500 and configured to locate and engage a whipstock profile 506 defined on the inner surface of the whipstock bore 505. In at least one embodiment, the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded. In other embodiments, the coupling engagement 502 may comprise a collet or the like..”);
an uphole component comprising a second engagement element ( given the BRI connotes latch anchor 206 shown in Fig. 2 and fig. 5 and explained in for example para:
“[0033] Referring now to FIG. 4, with continued reference to FIG. 2, illustrated is a lateral completion of lateral wellbore 404 using tool 200. The whipstock 204 is secured in the parent wellbore 102 by latch anchor 206, which includes a latch profile 214 releasably coupled to latch coupling 216 installed in the casing 106. Further, as shown, the whipstock 204 additionally includes a lower stinger assembly 218 that extends from the latch anchor 206 and is configured to be received within a seal bore 220 of the lower liner 116. The drill bit 226 has been sheared from the shear bolt 228 and deflected to mill through window 114 (FIG. 1) and to form lateral wellbore 404. As the drill bit 226 drills the lateral wellbore 404, as described above, the MWD tool 230, the motor 232, the screen(s) 234, and the lateral leg 238 of the multilateral junction 236 are conveyed into the lateral wellbore 404.”);
and a downhole component coupled to the uphole component and releasably connected to a wellbore (given the BRI connotes “other downhole tools or devices” taught in para:
“[0037] Once the retrieval tool 500 is suitably secured to the whipstock 204, the tool string 501 may then be pulled in the uphole direction (i.e., toward the surface of the well) to separate the whipstock 204 from the latch anchor 206, which remains firmly secured within the parent wellbore 102. More particularly, pulling on the tool string 501 in the uphole direction will place an axial load on the releasable connection 224 that eventually overcomes the engagement force provided or otherwise generated by the releasable connection 224. Upon overcoming the engagement force, the whipstock 204 may then be separated from the latch anchor 206 and the tool 200 retrieved to the surface as coupled to the tool string 501. Removing the whipstock 204 from the latch anchor 206 exposes a portion of the releasable connection 224, which may now be able to receive and otherwise couple to other downhole tools or devices.”);
wherein the retrieving tool component is configured to retrieve the uphole component and the downhole component from the wellbore using a connection component to release an axial lock thereby allowing an axial movement of the downhole component out the wellbore (see para [0037] above “More particularly, pulling on the tool string 501 in the uphole direction will place an axial load on the releasable connection 224 that eventually overcomes the engagement force provided or otherwise generated by the releasable connection 224.”).
Although the claims are interpreted in light of the specification, limitations from the specification are NOT imported into the claims. The Examiner must give the claim language the Broadest Reasonable Interpretation (BRI) the claims allow.
See MPEP 2111.01 Plain Meaning [R-10.2024], which states
II. IT IS IMPROPER TO IMPORT CLAIM LIMITATIONS FROM THE SPECIFICATION
"Though understanding the claim language may be aided by explanations contained in the written description, it is important not to import into a claim limitations that are not part of the claim. For example, a particular embodiment appearing in the written description may not be read into a claim when the claim language is broader than the embodiment." Superguide Corp. v. DirecTV Enterprises, Inc., 358 F.3d 870, 875, 69 USPQ2d 1865, 1868 (Fed. Cir. 2004). See also Liebel-Flarsheim Co. v. Medrad Inc., 358 F.3d 898, 906, 69 USPQ2d 1801, 1807 (Fed. Cir. 2004) (discussing recent cases wherein the court expressly rejected the contention that if a patent describes only a single embodiment, the claims of the patent must be construed as being limited to that embodiment); E-Pass Techs., Inc. v. 3Com Corp., 343 F.3d 1364, 1369, 67 USPQ2d 1947, 1950 (Fed. Cir. 2003) ("Inter US-20100280751-A1 1pretation of descriptive statements in a patent’s written description is a difficult task, as an inherent tension exists as to whether a statement is a clear lexicographic definition or a description of a preferred embodiment. The problem is to interpret claims ‘in view of the specification’ without unnecessarily importing limitations from the specification into the claims."); Altiris Inc. v. Symantec Corp., 318 F.3d 1363, 1371, 65 USPQ2d 1865, 1869-70 (Fed. Cir. 2003) (Although the specification discussed only a single embodiment, the court held that it was improper to read a specific order of steps into method claims where, as a matter of logic or grammar, the language of the method claims did not impose a specific order on the performance of the method steps, and the specification did not directly or implicitly require a particular order). See also subsection IV., below. When an element is claimed using language falling under the scope of 35 U.S.C. 112(f) or pre-AIA 35 U.S.C. 112, 6th paragraph (often broadly referred to as means- (or step-) plus- function language), the specification must be consulted to determine the structure, material, or acts corresponding to the function recited in the claim, and the claimed element is construed as limited to the corresponding structure, material, or acts described in the specification and equivalents thereof. In re Donaldson, 16 F.3d 1189, 29 USPQ2d 1845 (Fed. Cir. 1994) (see MPEP § 2181- MPEP § 2186).
In Zletz, supra, the examiner and the Board had interpreted claims reading "normally solid polypropylene" and "normally solid polypropylene having a crystalline polypropylene content" as being limited to "normally solid linear high homopolymers of propylene which have a crystalline polypropylene content." The court ruled that limitations, not present in the claims, were improperly imported from the specification. See also In re Marosi, 710 F.2d 799, 802, 218 USPQ 289, 292 (Fed. Cir. 1983) ("'[C]laims are not to be read in a vacuum, and limitations therein are to be interpreted in light of the specification in giving them their ‘broadest reasonable interpretation.'" (quoting In re Okuzawa, 537 F.2d 545, 548, 190 USPQ 464, 466 (CCPA 1976)). The court looked to the specification to construe "essentially free of alkali metal" as including unavoidable levels of impurities but no more.).”
Dancer does not appear to expressly disclose wherein the retrieving tool component is configured to drill a new wellbore.
In analogous art Buyaert teaches in for example, the figures below:
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And associated descriptive texts a retrieving tool component is configured to drill a new wellbore and to retrieve the uphole component and the downhole component from the wellbore using a connection component to release an axial lock thereby allowing an axial movement of the downhole component out the wellbore (in for example para:
[0043] In summary, whipstock assembly 10 is run into wellbore 12 to the desired depth at which the new wellbore is to be kicked off from wellbore 12. Whipstock 10 automatically orients itself to the low side 24 of wellbore 12 as shown in FIG. 2 which position is known beforehand to the operator as discussed above. Lower clamping member 34 affixes orientation section 30 with respect to wellbore 12 in the first rotational position. The wellbore string including running tool 50 is reciprocated to thereby rotate whipstock 22 to the desired second rotational position. Upper clamping member 48 is then activated to affix whipstock 22 in position. Running tool 50 is removed and the milling or drilling assembly is then used to kickoff new wellbore 58. Once completed, whipstock assembly 10 can be retrieved by releasing upper and lower clamping members 48 and 34 after reconnecting with whipstock assembly 10 using retrieving tool 62. Retrieving tool 62 may be used to remove whipstock assembly 10 from wellbore 12 or relocate whipstock assembly 10 elsewhere in borehole 12 or new wellbore 58 to kick off another wellbore.”).
It would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to combine the teachings disclosed in Buyaert with the whipstock taught in Dancer with a reasonable expectation of success because it would have “improved the whipstock” as taught by Buyaert Para(s):
“[0006] Consequently, it would be desirable to provide a self-orienting whipstock assembly and method that is designed to orient itself in a known rotational orientation within the borehole and, where adjustment from the known rotational orientation is necessary, permits rotation of the whipstock from the known rotational orientation to the desired rotational position without the use of additional tools that require additional trips into the wellbore. Those skilled in the art will appreciate the present invention that addresses the above and other needs and problems.”.
Regarding claim 2 and the limitation the system of claim 1, wherein the axial lock comprises a slip selectively extendible between an unlocked position and a locked position;
wherein the slip is initially configured in the locked position to prevent the axial movement of the downhole component within the wellbore,
wherein the slip is moved into the unlocked position upon engagement by the retrieving tool component (see Dancer para:
“[0034] After the drill bit 226 reaches a desired depth or length for forming the lateral wellbore 404, the primary leg 240 of the multilateral junction 236 fluidically couples to the whipstock 204, such that fluid flow from the parent wellbore 102 can flow through the primary leg 240 (see FIG. 4 and deflector 308). The primary leg may be secured to the whipstock 204 by one or more seals 242 in the whipstock 204 (FIG. 2). In other embodiments, the primary leg may additionally be secured in the parent wellbore 102 by deploying slips against the casing 106, by expanding a portion of the multilateral junction 236 to engage the casing 106 or a liner hanger, or by another mechanism, without departing from the scope of the present disclosure.”).
Regarding claim 6 and the limitation the system of claim 1, wherein the retrieving tool component further comprises a drilling bit (given the BRI see the Dancer figures above and especially “drill bit 226”).
Regarding claim 10 and the limitation the system of claim 1 further comprising:
an extending driver configured to extend the second engagement element from a recessed position to an extended position (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 11 and the limitation the system of claim 10, wherein the extending driver is powered by a power supply (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 12 and the limitation the system of claim 11, wherein the second engagement element is electro-mechanically actuated (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 13 and the limitation the system of claim 12 further comprising:
a retainer configured to cooperate with the uphole component to retain the second engagement element in the recessed position using a retainer driver operable by an electronics module (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 14 and the limitation the system of claim 13, wherein the electronics module comprises a sensor configured to sense an activation device (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 15 and the limitation A method for retrieving an uphole component coupled to a downhole component deployed in a wellbore, the method comprising:
deploying a retrieving tool component into the wellbore, the retrieving tool component comprising a first engagement element;
drilling a lateral wellbore section with the retrieving tool component;
extending a second engagement element disposed on the uphole component; engaging the second engagement element with the first engagement element;
applying an uphole tension on the second engagement element to unlock the downhole component from the wellbore;
and removing the retrieving tool component connected to the uphole component and the downhole component from the wellbore (see the rejection of corresponding parts of claim 1 above incorporated herein by reference and the discussion of Dancer figures 4 and 5 and the use of retrieval tool 500 and for example para:
“[0039] A method comprising: releasably connecting a latch anchor component within a parent wellbore lined at least partially with casing; deflecting a drill bit component and a whipstock component to mill a window in the casing; drilling a lateral wellbore through the window with the drill bit, the lateral wellbore extending from the parent wellbore; landing a multilateral junction component with lateral leg in the lateral wellbore and a primary leg in the parent wellbore; and actuating the at least one screen component, wherein each of the latch anchor component, the drill bit component, the whipstock component, the multilateral junction component, and the at least one screen component comprise a multilateral tool and are operatively coupled together such that movement of a component correspondingly moves the adjacent component.”).
Regarding claim 16 and the limitation the method of claim 15, wherein deploying a retrieving tool component comprises deploying a drill bit (see Dancer para [0039] above “drilling a lateral wellbore through the window with the drill bit “).
Regarding claim 17 and the limitation the method of claim 15, wherein extending the second engagement element comprises electro-mechanically actuating the second engagement element (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 18 and the limitation the method of claim 15, wherein extending the second engagement element comprises signaling an electronics module to activate a retainer driver to shift a retainer to unlatch the second engagement element (given the BRI see Dancer para [0036] “the dogs 504 may be actuatable (e.g., mechanically, electromechanically, hydraulically, pneumatically, etc.), but may alternatively be spring-loaded.”).
Regarding claim 19 and the limitation the method of claim 15, wherein unlocking the downhole component from the wellbore further comprises transferring the uphole tension through a connection component to release an axial lock to axially move the downhole component from the wellbore (given the BRI see Dancer para [0037] “More particularly, pulling on the tool string 501 in the uphole direction will place an axial load on the releasable connection 224 that eventually overcomes the engagement force provided or otherwise generated by the releasable connection 224.”).
Regarding claim 20 and the limitation the method of claim 15, wherein drilling the lateral wellbore section, removing the retrieving tool component, removing the uphole component, releasing the downhole component, and removing the downhole component are completed in a single trip into and out of the wellbore (see Dancer paras:
“[0011] The embodiments described herein improve the efficiency of drilling and completing multilateral wellbores, and thereby improve or maximize production of each lateral wellbore extending from a parent wellbore. Additionally, the embodiments described herein improve the costs associated with traditional drilling and completion of multilateral wellbores. More specifically, the one-trip multilateral tool described herein employs a single tool that enters a parent wellbore only once to achieve drilling and completion of a lateral wellbore.
[0012] The efficiency of the one-trip multilateral tool and associated systems and methods described herein is characterized by reducing the downhole trip requirements for installing and using the tool to drill and complete a lateral wellbore. Such trip savings translate into eliminating one to four, or even more, trips downhole to perform the same operation at significant cost savings. Indeed, it is estimated that each trip downhole costs approximately $500,000 USD. Thus, the one-trip multilateral tool of the present disclosure results in significant financial benefits, as well as increased efficiencies related to shorter installation time, reduced rig time, safety advantages, and the like.
[0013] According to the embodiments described herein, a one-trip multilateral tool can be conveyed into a parent wellbore lined at least partially with casing and used to drill and complete a lateral wellbore in a single trip downhole. The one-trip multilateral tool comprises a plural of components operatively coupled together. As used herein, the term “operatively coupled” refers to a direct or indirect coupling engagement between at least two components such that movement of a first component correspondingly moves the second component. Accordingly, a plurality of components may be operatively coupled such that movement of any one component correspondingly moves the plurality of components. The plurality of components operatively coupled together to form the one-trip multilateral tool of the present disclosure includes a whipstock having a latch anchor, a drill bit, a measurement while drilling (MWD) tool, a motor, at least one well screen, and a multilateral junction having a primary leg and a lateral leg.“).
Claim(s) 3-5 and 7-9 is/are rejected under 35 U.S.C. 103 as being unpatentable over US 20190085661 A1 to DANCER; William Wallace in view of US 20020070018 A1 to Buyaert, Jean P. as applied to the claims above in view of US 5467821 A to Sieber; Bobby G.
Regarding claim 3 and the limitation the system of claim 2, the combination of DANCER does not appear to expressly disclose however in analogous art Sieber teaches in for example, the figures below:
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And associated descriptive texts wherein the slip comprises a slip release (in for example paras:
“(55) The anchor packer used with a retrievable whipstock, be it mechanically set or hydraulically set, is chosen so that it incorporates shear screws in the upper set of slips (or wedges). As the whipstock/packer is raised, the pulling force will increase and shear the upper slip shear screws. This releases the upper slips on the anchor packer and the packer can now move upward. As the packer moves upwards, the packing will collapse as the packer extends against the bottom set of slips, which should release. It should be noted that the lower set of slips on a packer are designed to grip in the downward direction; thus, if the lower slips do not release, the packer can still be pulled out of the well bore. The entire whipstock/packer assembly is now free to be withdrawn from the well bore and a standard trip operation now follows.
(143) Once the hook has engaged, the latch pin mechanism, 28, will ensure that the hook does not come out of the retrieval slot if the Whip-Anchor service representative has to reciprocate the drill string in order to free the Whip-Anchor. Once hook engagement has occurred, the Whip-Anchor service representative will slowly increase the pull on the drill stem to the point of known slip shear screw release force. The actual pull force will be greater than the slip shear screw release force because of well bore friction. Once the shear screws have sheared the slips on the anchor will release, the packing will collapse, and the anchor will free itself from the well bore. All that the Whip-Anchor service representative must do is trip out of the well bore.”.
It would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to combine the slip release disclosed in Sieber with the slips taught in the combination of DANCER with a reasonable expectation of success because it would have “been invaluable” as taught by Sieber Para(s):
“(8) This invention standardizes the whipstock tool to three varieties to fit hole sizes from 33/4 inches up to 121/2 inches. The invention proposes one style of whipstock for use with both mechanically set packers and hydraulically set packers. And finally, the invention proposes an apparatus and method for retrieval of the valuable and expensive downhole assembly after the deviated hole is completed. This retrievable whipstock would be invaluable in multiple drain holes in a single well bore and would be used in both cased and open hole (uncased) conditions.”.
Regarding claim 4 and the limitation the system of claim 1, the combination of DANCER does not appear to expressly disclose however in analogous art Sieber teaches wherein the first engagement element comprises an engagement hook in for example paras 15A-D hood 177 as explained in para:
“(80) The preferred embodiment will find greatest use with Type I and Type II Whip-Anchors because the ID of the bore hole limits the size of the Retrieval Tool. Turning then to FIG. 12A, the Retrieval Tool simply consists of a tool joint, 180, a bar, 178, and a specially shaped hook, 177. Although the hook could be welded to the bar, it is much better to manufacture the hook and bar as a unit because of the tremendous forces or weight that the Retrieval Tool will have to endure in releasing the anchor packer (not shown). The tool joint, 180, can have a threaded fitting or a weld fitting for attachment to other Bottom Hole Assembly (BHA) tools, such as the piston sleeve valve assembly or sub, 140, shown in FIG. 12C and which will be discussed shortly. The tool joint is attached to the Retrieval Tool bar, 178, and to the hook, 177, either during manufacture of the Retrieval Tool as a complete unit or by welding the bar to the tool joint. The preference is for a complete integral unit due to, again, the tremendous forces that will present. There is a recess, 179, whose depth, 168, is set by the type of Whip-Anchor being used. The recess permits the Retrieval Tool to centralize itself in the setting slot, 13, of the Whip-Anchor, thus, the depth, 168, will vary with tool type. The retrieval tool latching mechanism, 28, is located on the face of the bar (at location 27) that will engage the retrieval slot. This mechanism and its embodiments will be discussed later.”) .
It would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to combine the hook disclosed in Sieber with the removal device in the combination of DANCER with a reasonable expectation of success because it would have been able to work on different types of wells and also would have “been invaluable” as taught by Sieber Para(s):
“(8) This invention standardizes the whipstock tool to three varieties to fit hole sizes from 33/4 inches up to 121/2 inches. The invention proposes one style of whipstock for use with both mechanically set packers and hydraulically set packers. And finally, the invention proposes an apparatus and method for retrieval of the valuable and expensive downhole assembly after the deviated hole is completed. This retrievable whipstock would be invaluable in multiple drain holes in a single well bore and would be used in both cased and open hole (uncased) conditions.”.
Regarding claim 5 and the limitation the system of claim 4, wherein the engagement hook has a tapered length and a reduced distance from the retrieving tool centerline (see the motivation to combine and the rejection of corresponding parts of claim 4 above incorporated herein by reference and especially figure 15 of Sieber).
Regarding claim 7 and the limitation the system of claim 1, wherein the second engagement element comprises a catch (given the BRI connotes hinge pin 87 as explained in for example Sieber para:
“(48) The upper and base sections of the whipstock are hinged together using a hinge pin, 87, which passes through the hinge pin opening, 81, in the base, and through the corresponding hinge pin opening, 80 in the upper section of the whipstock. It should be noted that the center of the hinge pin is offset towards the front of the whipstock by about 3/4-inch; unlike the present art. This offset assures that the spring retainer shear pin, 88, will shear whenever weight is applied in the downward direction on the Whip-Anchor as it is set. Careful observation of FIG. 5B will show that a large downward force will tend to push the upper section of the whipstock backwards or away from the tool face. This is the direction that the whipstock must fall (or move towards) in order for proper hole deviation to occur. The downward force will pivot about the off-set hinge, 87, shearing the spring retaining pin, 88. This releases the hinge springs which will hold the back of the whipstock against the well bore. The back of the hinge base, 89, is sloped to assure that the upper hinge section 82, is not prohibited from its backward motion while shearing the spring retainer shear pin, 88. In a similar manner the top of the back of the hinge base, 90, is also sloped to avoid any chance of interference.”).
Regarding claim 8 and the limitation the system of claim 7, wherein the catch comprises a catch first end and a catch opening, the catch opening configured to receive the first engagement element;
wherein the catch is hingedly connected to the uphole component with a catch hinge at a catch second end;
wherein the catch hinge comprises a catch hinge axle (given the BRI connotes hinge pin 87 as explained in for example Sieber para:
“(48) The upper and base sections of the whipstock are hinged together using a hinge pin, 87, which passes through the hinge pin opening, 81, in the base, and through the corresponding hinge pin opening, 80 in the upper section of the whipstock. It should be noted that the center of the hinge pin is offset towards the front of the whipstock by about 3/4-inch; unlike the present art. This offset assures that the spring retainer shear pin, 88, will shear whenever weight is applied in the downward direction on the Whip-Anchor as it is set. Careful observation of FIG. 5B will show that a large downward force will tend to push the upper section of the whipstock backwards or away from the tool face. This is the direction that the whipstock must fall (or move towards) in order for proper hole deviation to occur. The downward force will pivot about the off-set hinge, 87, shearing the spring retaining pin, 88. This releases the hinge springs which will hold the back of the whipstock against the well bore. The back of the hinge base, 89, is sloped to assure that the upper hinge section 82, is not prohibited from its backward motion while shearing the spring retainer shear pin, 88. In a similar manner the top of the back of the hinge base, 90, is also sloped to avoid any chance of interference.”).
Regarding claim 9 and the limitation the system of claim 8, wherein the catch is selectively extendable between a recessed position and an extended position;
wherein the catch is disposed in a pocket disposed in the uphole component;
and wherein the catch further comprises a shear element coupling the catch with the pocket such that the shear element prevents an axial catch movement of the catch relative to the pocket;
wherein the shear element comprises the catch hinge axle (see Sieber fig. 32
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paras:
“(67) The shear pin, 39, is made of mild steel and is threaded to fit the threaded aperture, 105, in the setting tool. The shear pin passes through a corresponding aperture, 62, in the whipstock. This opening is larger than the shear pin and allows for slight movement of the shear pin within that opening. This is to give the shear pin some relaxation from any applied downward or torsional forces exerted by the Setting Tool in reaction to forces applied to the drill string. This allows the downward force to be applied directly to the bottom of the setting slot and the torsional forces to be directly applied to the side walls of the setting slot. Additionally, this loose fit of the shear pin, 39, in the whipstock aperture, 62, ensures that if sufficient downward force is applied on the setting tool, then the bottom face of the setting tool will fully set down on the bottom of the setting slot. This action will impart a shear force to the spring retaining shear pin, 88, because of the combination of the offset hinge, 6, and the bottom tool face angle, 106, on the setting tool.
(68) It should be noted that if the spring retainer pin, 88, is sheared while the Whip-Anchor is being run into the well bore, the hinge section of the instant invention reverts back to the prior art employed by current whipstock/packer systems using an unpinned hinge. This condition, which could be brought about by having to force the whipstock through a particularly tortuous path and having to exert a great amount of downward force on the setting tool, does not cause any problems in using the instant device. This is because the base of the anchor packer has a larger OD than the slips (wedges or scaling) elements section of the packer and further more is "bullet shaped." (See FIG. 3) The instant invention will operate better than the prior art in a tortuous path for two reasons:
(69) a) a great amount of downward force (of weight) can be applied without any fear of shearing the shear pin because the force is applied directly to the Whip-Anchor via the setting tool sitting in the bottom of the setting slot, and
(70) b) because the Whip-Anchor can be rotated without fear of shearing the shear pin due because the torsional force (rotation) is applied directly to the walls of the setting slot.
(71) Additionally the shear pin has a groove, 38, cut axially around the pin at such a location so that when the pin is installed the groove is located slightly inside the setting slot face. This groove assures that the shear pin will shear at the groove. This means that, once the pin has sheared, there will be no material extending from the whipstock shear pin aperture, 62, into the setting slot. The back of the whipstock has a recess, 63, which accepts the Allen Cap Head of the shear pin and assures that no material extends beyond the back side of the whipstock.“).
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure as teaching, inter alia, the state of the art wellbore retrieval tools at the time of the invention. For example:
US 20190010786 A1 to DURST; Douglas Glenn teaches, inter alia EXPANDABLE REENTRY COMPLETION DEVICE in for example the ABSTRACT, Figures and/or Paragraphs below:
“A method includes severing a liner positioned in a first wellbore at least partially lined with casing and thereby providing a severed end, conveying a mid-completion assembly into the first wellbore and receiving the severed end within a tail pipe assembly of the mid-completion assembly, wherein a smallest inner diameter of the mid-completion assembly is greater than or equal to a smallest inner diameter of the liner and thereby permits tools sized for operations in the liner to pass through the mid-completion assembly, actuating an expandable device of the mid-completion assembly to sealingly engage an inner surface of the casing uphole from the severed end, and drilling a second wellbore extending from the first wellbore.”
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Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to DANIEL LAWSON GREENE JR whose telephone number is (571)272-6876. The examiner can normally be reached on MON-THUR 7-5:30PM (EST) or via email at DanielL.GreeneJr@USPTO.GOV under the guidance of MPEP [R-09.2017] Section 502.03 Communications via Internet Electronic Mail (email) [R-07.2015].
Examiner interviews are available via telephone and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Hunter Lonsberry can be reached on (571) 272-7298. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/DANIEL L GREENE/Primary Examiner, Art Unit 3665
20260613
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