DETAILED ACTION
Claims 11-18, 21-24, and 26-31 are pending.
Notice of Pre-AIA or AIA Status
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 Arguments
Applicant's arguments filed 12/12/2025 have been fully considered but they are not persuasive.
Applicant’s representative argues the following:
“In response to the arguments presented in Applicant's Response to the Non- Final Office Action dated March 26, 2025, the Office Action attempts to provide the requisite articulated rationale required to establish a prima facie case of obviousness. The Office Action, however, still fails to establish a prima facie case of obviousness because it lacks an articulated rational as to "why" a person of ordinary skill in the art would arrive at the claimed ranges. More specifically, Office Action alleges that it would be obvious to "position the ESP in the wellbore comprising tangent sections, as taught by Duncan in view of Boulton, in specific section(s) dependent upon the pore pressure of the reservoir with respect to the bubble point pressure of the reservoir, as taught by the AAPA, to allow for [...] optimizing and maintaining a producing pressure that is greater than the bubble point pressure' which [...] enables single-phase oil production which is advantageous in both cost and time..." Office Action at pg. 6-7 (citation omitted). However, this argument does not articulate why a person or ordinary skill in the art would arrive at the claimed ranges that are admittedly not found in Duncan, Boulton, or the AAPA.
Due to the lack of a teaching, showing, or suggestion of "why" a person of ordinary skill in the art would arrive at the claimed ranges in any of Duncan, Boulton, or the AAPA, and the fact that such limitations are only present on the record in Applicant's specification, it logically follows that these limitations have been improperly gleaned from Applicant's own specification and that the combination of Duncan, Boulton, and the AAPA is an exercise of impermissible hindsight reasoning. MPEP § 2142.”
Examiner respectfully disagrees. Firstly, Examiner notes that the Applicant’s admitted prior art (AAPA) cites two factual evidentiary statements which are known in the art, as follows:
“To maximize hydrocarbon recovery, subterranean hydrocarbon-bearing reservoirs are ideally produced at pressures that are above the bubble point pressure of the oil solution immersed within said reservoirs. Recovery above bubble point enables single-phase oil production which is advantageous in both cost and time” (paragraph [0002] of the instant specification); and
“An electric submersible pump (ESP) and associated components are one such type of semi-permanent (or permanent) equipment that is often utilized to assist in artificially lifting (pumping) hydrocarbons to the well surface for production. Non-optimized placement of an ESP may inadvertently induce a larger pressure drop which can result in production pressure falling below bubble point” (paragraph [0003] of the instant specification).
Examiner reiterates that producing well fluids from a reservoir that has reservoir pressures above bubble point pressures is ideal/optimal. Placement of ESPs in a wellbore are critical with respect to the wellbore pressure environment, and the AAPA teaches that improper placements of ESPs in a wellbore can lead to potential unwanted, inadvertent substantial pressure drops which can result in production pressure falling below bubble point. In other words, having an ESP placed in a wellbore where the ESP is associated with reservoir pressure that is below bubble point, is adverse. With that being said, based off the AAPA’s disclosure, one skilled in the art would be motivated to place ESPs in a wellbore where reservoir pressures are higher than bubble point pressure.
The claim cites for placing an ESP in two areas (i.e., “first tangent” section and “second tangent” section) dependent on reservoir pressure conditions with respect to bubble point. Specifically, the claim cites a singular reservoir connected to the “first tangent” and “second tangent” sections of the wellbore. Furthermore, the claim requires that if reservoir pressure is “at or within 100 psi of bubble pressure of the reservoir”, for example, 100 psi above bubble point (i.e., an ideal producing condition, as suggested by AAPA), and if reservoir pressure is above 200 psi above bubble point (i.e., also an ideal producing condition, as suggested by AAPA), then the ESP should be placed in the “first tangent” section and “second tangent” section, respectively. With that being said, Examiner notes that one skilled in the art would be motivated to place the ESP in any location of the wellbore where ideal operating conditions are, i.e., where reservoir pressure is above bubble point pressure of the reservoir. Doing so (the question of “why”), allows for “[...] optimizing and maintaining a producing pressure that is greater than bubble point pressure” which “[...] enables single-phase oil production which is advantageous in both cost and time...” (paragraphs [0002-0003] of AAPA). If Applicant’s representative is stating that the combination of the references are incompatible due to one teaching away from another (or, something of the like), then detailed arguments need to be presented by the Applicant’s representative, as Examiner respectfully fails to see why a wellbore comprising “first tangent” and “second tangent” sections associated with a single reservoir, as taught by Duncan in view of Boulton, can’t have an ESP positioned (optimally placed) in the claimed section(s) where ideal operating conditions are met, as suggested by AAPA. If there is a critical feature in the claims that have a certain degree of importance, it is advised to include that language in the claim(s) in keeping with the instant specification for purposes of overcoming the most recent prior art rejection.
Additionally, Applicant’s representative argues the following:
“[...] Biswas does not teach, disclose, or suggest an inclination angle from surface greater than 70° and less than 90°, as required by the claimed invention. Rather, Biswas teaches that the "optimization of the wellbore trajectory is constrained in two ways: by operational constraints and by the upper and lower limits of 17 tuning variables." Biswas at pg. 5. Table 1 of Biswas, reproduced below, shows "variable constraints" for the optimization of the wellbore trajectory. These "constraints" show minimum and maximum inclination angle values, none of which are greater than 70° and less than 90°.”
Examiner respectfully disagrees. In response to Applicant's representative’s arguments against the references individually, one cannot show nonobviousness by attacking references individually where the rejections are based on combinations of references. See In re Keller, 642 F.2d 413, 208 USPQ 871 (CCPA 1981); In re Merck & Co., 800 F.2d 1091, 231 USPQ 375 (Fed. Cir. 1986). With that being said, the table of Biswas shows that these inclined wellbore sections are known to have angles ranging from 10°(minimum) to 95° (maximum), as shown in table 1 and figure 1. These known inclined wellbore angle sections fall within the claimed range and are obvious to combine where express motivation to do so is to allow for optimal wellbore trajectory for oil and gas production purposes (abstract — Biswas). If Applicant’s representative is stating that the combination of the references are incompatible due to one teaching away from another (or, something of the like), then detailed arguments need to be presented by the Applicant’s representative, as Examiner respectfully fails to see why inclined wellbore sections, as taught by Duncan in view of Boulton, can’t have the claimed angle range, as suggested by Biswas. If there is a critical feature in the claims that have a certain degree of importance, it is advised to include that language in the claim(s) in keeping with the instant specification for purposes of overcoming the most recent prior art rejection.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries for establishing a background for determining obviousness under 35 U.S.C. 103 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.
Claim(s) 11-12 is/are rejected under 35 U.S.C. 103 as being unpatentable over Duncan et al. (US Publication Number 2016/0265905 A1; hereinafter “Duncan”) in view of Boulton et al. (US Patent Number 6,269,892 B1; hereinafter “Boulton”) in further view of Applicant’s Admitted Prior Art (hereinafter “AAPA”).
In regard to claim 11, Duncan discloses: A method (abstract and paragraphs [0007, 0014]), comprising:
conveying an electrical submersible pump (ESP) (202) into a primary wellbore (i.e., initial vertical section of wellbore, as shown in figure 2) extending vertical from a service rig (208) and penetrating a subterranean formation (220) including a hydrocarbon-bearing, undersaturated reservoir (paragraphs [0003, 0016, 0014, 0024-0031]), the primary wellbore including:
a tangent section extending at an inclination from vertical (paragraphs [0024-0031] and figure 2); and
positioning the ESP within the tangent section (paragraphs [0024-0031] and figure 2).
However, Duncan is silent in regard to: the primary wellbore including:
a first tangent section extending at a first inclination from vertical; and
a second tangent section extending from the first tangent section and at a second inclination from vertical; and
positioning the ESP within the second tangent section when a pore pressure of the reservoir is at or within 100 psi of a bubble point pressure of the reservoir; and
positioning the ESP within the first tangent section when the pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi.
Nonetheless, Boulton teaches a primary wellbore (i.e., initial vertical section of the wellbore — figure 3) including:
a first tangent section (e.g., 64A) extending at a first inclination from vertical (figure 3); and
a second tangent section (e.g., 64B) extending from the first tangent section and at a second inclination from vertical (column 10, lines 21-36 and figure 3).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to simply substitute the ESP wellbore system, as taught by Duncan, to be conducted in a wellbore system, as taught by Boulton, to yield the predictable result of producing hydrocarbons from oil formations via alternative types of deviated borehole(s) (column 1, lines 14-19 and column 3, lines 3-16 — Boulton). See MPEP 2143, section I, subsection B.
Furthermore, though Duncan teaches determining the positioning of its ESP in the wellbore to be in an ideal/optimal location “[...] to assist in the removal of hydrocarbon-containing fluid from a formation and/or reservoir” (see paragraph [0003, 0014, 0024-0031] of Duncan), Duncan is silent in regard to: positioning the ESP within the second tangent section when a pore pressure of the reservoir is at or within 100 psi of a bubble point pressure of the reservoir; and
positioning the ESP within the first tangent section when the pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi.
Nonetheless, AAPA cites: “To maximize hydrocarbon recovery, subterranean hydrocarbon-bearing reservoirs are ideally produced at pressures that are above the bubble point pressure of the oil solution immersed within said reservoirs. Recovery above bubble point enables single-phase oil production which is advantageous in both cost and time” (paragraph [0002] of the instant specification). Furthermore, the AAPA cites: “An electric submersible pump (ESP) and associated components are one such type of semi-permanent (or permanent) equipment that is often utilized to assist in artificially lifting (pumping) hydrocarbons to the well surface for production. Non-optimized placement of an ESP may inadvertently induce a larger pressure drop which can result in production pressure falling below bubble point” (paragraph [0003] of the instant specification). Examiner notes that these known ideal operating conditions is when the reservoir pore pressure is at or above (exceeds) bubble point pressure.
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to position the ESP in the wellbore comprising tangent sections, as taught by Duncan in view of Boulton, in specific section(s) dependent upon the pore pressure of the reservoir with respect to the bubble point pressure of the reservoir, as taught by AAPA, to allow for “[...] optimizing and maintaining a producing pressure that is greater than bubble point pressure” which “[...] enables single-phase oil production which is advantageous in both cost and time...” (paragraphs [0002-0003] of AAPA).
In regard to claim 12, in view of the modification of the preceding claim, Boulton further discloses: wherein the primary wellbore further includes:
a first build section (66A) extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination (column 10, lines 21-36 and figure 3); and
a second build section (66B) extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination (column 10, lines 21-36 and figure 3).
Claim(s) 13-14 is/are rejected under 35 U.S.C. 103 as being unpatentable over Duncan et al. (US Publication Number 2016/0265905 A1; hereinafter “Duncan”) in view of Boulton et al. (US Patent Number 6,269,892 B1; hereinafter “Boulton”) in further view of Applicant’s Admitted Prior Art (hereinafter “AAPA”) and Biswas et al. (PLOS ONE 17(1): e0261427; hereinafter “Biswas”).
In regard to claim 13, in view of the modification of the preceding claim, Boulton further discloses: wherein the first inclination from surface ranges between 1° and 55° (figure 3).
However, Duncan in view of Boulton and AAPA are explicitly silent in regard to: wherein the first inclination from surface ranges between 1° and 55° from vertical.
Nonetheless, Biswas teaches that the wellbore comprising tangent sections (as shown in figure 1) can have inclination angles from 10° and 95° (table 1 and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the first inclination angle, as taught by Duncan in view of Boulton, to be from surface ranges between 1° and 55°, as taught by Biswas, to allow for optimal wellbore trajectory for oil and gas production purposes (abstract — Biswas).
In regard to claim 14, in view of the modification of the preceding claim, Boulton further discloses: wherein the first inclination from surface ranges between 1° and 55° (figure 3).
However, Duncan in view of Boulton and AAPA are explicitly silent in regard to: wherein the first inclination is greater than 70° and less than 90° from vertical.
Nonetheless, Biswas teaches that the wellbore comprising tangent sections (as shown in figure 1) can have inclination angles from 10° and 95° (table 1 and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the first inclination angle, as taught by Duncan in view of Boulton, to be from surface ranges greater than 70° and less than 90° from vertical, as taught by Biswas, to allow for optimal wellbore trajectory for oil and gas production purposes (abstract — Biswas).
Claim(s) 15-22 and 26-31 is/are rejected under 35 U.S.C. 103 as being unpatentable over Duncan et al. (US Publication Number 2016/0265905 A1; hereinafter “Duncan”) in view of Boulton et al. (US Patent Number 6,269,892 B1; hereinafter “Boulton”) in further view of Applicant’s Admitted Prior Art (hereinafter “AAPA”) and Al-Mousa (US Publication Number 2023/0099319 A1; hereinafter “Al-Mousa”).
In regard to claim 15, Duncan teaches: conveying a completion string into the wellbore, the completion string being located downhole from the ESP (figure 2).
However, Duncan in view of Boulton and AAPA are silent in regard to: wherein the primary wellbore further includes one or more lateral wellbores extending from the primary wellbore, the method further comprising:
conveying a completion string into the wellbore, the completion string being located downhole from the ESP;
positioning one or more inflow control valves included in the completion string adjacent the one or more lateral wellbores; and
regulating hydrocarbon flow into the completion string from the one or more inflow control valves.
Nonetheless, Al-Mousa teaches: wherein the primary wellbore further includes one or more lateral wellbores extending from the primary wellbore (paragraphs [0029-0034] and figure 3), the method further comprising:
conveying a completion string into the wellbore, the completion string being located downhole from the ESP (as shown in figure 3);
positioning one or more inflow control valves (320, 322) included in the completion string adjacent the one or more lateral wellbores (figure 3); and
regulating hydrocarbon flow into the completion string from the one or more inflow control valves (paragraphs [0029-0034]).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the well system, as taught by Duncan, to include the claimed well structure, as taught by Al-Mousa, “[...] to help with the production of hydrocarbons” (paragraph [0001] — Al-Mousa).
In regard to claim 16, Duncan in view of Boulton and AAPA teach claim 11 above.
However, Duncan in view of Boulton and AAPA are silent in regard to: controlling operation of the ESP with a controller and a variable speed drive positioned at the service rig.
Nonetheless, Al-Mousa teaches controlling operation of the ESP with a controller and a variable speed drive positioned at the service rig (paragraph [0022] and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the ESP system, as taught by Duncan, to include the claimed well structure, as taught by Al-Mousa, “[...] to optimize the pump efficiency and production rate” (paragraph [0022] — Al-Mousa).
In regard to claim 17, in view of the preceding modification(s), Al-Mousa further discloses: setting the variable speed drive to a predetermined pump intake pressure; and adjusting a speed of the variable speed drive when the predetermined pump intake pressure is achieved (paragraph [0022]).
In regard to claim 18, Duncan discloses: A well system (abstract and paragraphs [0007, 0014] and figure 2), comprising:
a primary wellbore (i.e., initial vertical section of wellbore, as shown in figure 2) extending vertical from a service rig (208) and penetrating a subterranean formation (220) including a hydrocarbon-bearing, undersaturated reservoir (paragraphs [0003, 0016, 0014, 0024-0031]), the primary wellbore including:
a tangent section extending at an inclination from vertical (paragraphs [0024-0031] and figure 2); and
a completion string (as shown in figure 2); and
an electrical submersible pump (ESP) (202) positioned in the primary wellbore (paragraphs [0024-0031] and figure 2).
However, Duncan is silent in regard to: a first tangent section extending at a first inclination from vertical; and
a second tangent section extending from the first tangent section and at a second inclination from vertical;
one or more lateral wellbores extending from the primary wellbore;
a completion string including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow; and
an electrical submersible pump (ESP) positioned in the primary wellbore based on a bubble point pressure of the hydrocarbon-bearing reservoir,
wherein the ESP is positioned within the first tangent section when a pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi and positioned within the second tangent section when the pore pressure of the reservoir is at or within 100 psi of the bubble point pressure of the reservoir.
Nonetheless, Boulton teaches a primary wellbore (i.e., initial vertical section of the wellbore — figure 3) including:
a first tangent section (e.g., 64A) extending at a first inclination from vertical (figure 3); and
a second tangent section (e.g., 64B) extending from the first tangent section and at a second inclination from vertical (column 10, lines 21-36 and figure 3).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to simply substitute the ESP wellbore system, as taught by Duncan, to be conducted in a wellbore system, as taught by Boulton, to yield the predictable result of producing hydrocarbons from oil formations via alternative types of deviated borehole(s) (column 1, lines 14-19 and column 3, lines 3-16 — Boulton). See MPEP 2143, section I, subsection B.
Furthermore, though Duncan teaches determining the positioning of its ESP in the wellbore to be in an ideal/optimal location “[...] to assist in the removal of hydrocarbon-containing fluid from a formation and/or reservoir” (see paragraph [0003, 0014, 0024-0031] of Duncan), Duncan is silent in regard to: an electrical submersible pump (ESP) positioned in the primary wellbore based on a bubble point pressure of the hydrocarbon-bearing reservoir, wherein the ESP is positioned within the first tangent section when a pore pressure of the reservoir exceeds the bubble point pressure of the reservoir by at least 200 psi and positioned within the second tangent section when the pore pressure of the reservoir is at or within 100 psi of the bubble point pressure of the reservoir.
Nonetheless, AAPA cites: “To maximize hydrocarbon recovery, subterranean hydrocarbon-bearing reservoirs are ideally produced at pressures that are above the bubble point pressure of the oil solution immersed within said reservoirs. Recovery above bubble point enables single-phase oil production which is advantageous in both cost and time” (paragraph [0002] of the instant specification). Furthermore, the AAPA cites: “An electric submersible pump (ESP) and associated components are one such type of semi-permanent (or permanent) equipment that is often utilized to assist in artificially lifting (pumping) hydrocarbons to the well surface for production. Non-optimized placement of an ESP may inadvertently induce a larger pressure drop which can result in production pressure falling below bubble point” (paragraph [0003] of the instant specification).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to position the ESP in the wellbore comprising tangent sections, as taught by Duncan in view of Boulton, in specific section(s) dependent upon the pore pressure of the reservoir with respect to the bubble point pressure of the reservoir, as taught by AAPA, to allow for “[...] optimizing and maintaining a producing pressure that is greater than bubble point pressure” which “[...] enables single-phase oil production which is advantageous in both cost and time...” (paragraphs [0002-0003] of AAPA).
Lastly, Duncan in view of Boulton and AAPA are silent in regard to: one or more lateral wellbores extending from the primary wellbore;
a completion string including one or more inflow control valves positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow.
Nonetheless, Al-Mousa teaches: one or more lateral wellbores extending from the primary wellbore (figure 3);
a completion string including one or more inflow control valves (320, 322) positioned adjacent the one or more lateral wellbores and operable to regulate hydrocarbon flow (paragraphs [0029-0034] and figure 3).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the well system, as taught by Duncan, to include the claimed well structure, as taught by Al-Mousa, “[...] to help with the production of hydrocarbons” (paragraph [0001] — Al-Mousa).
In regard to claim 21, in view of the modification of the preceding claim, Al-Mousa further discloses: a first wellbore isolation device (316) and a second wellbore isolation device (318) straddling a lateral wellbore (314) of the one or more lateral wellbores and sealing against a surface of the primary wellbore, the first and second wellbore isolation devices being downhole from the ESP (112 — paragraphs [0013, 0032-0034] and figure 3); and
the one or more inflow control valves including an inflow control valve interposing the first and second wellbore isolation devices, wherein the completion string is attached to a production tubing (117) including the ESP at a matable interface (paragraphs [0013, 0032-0034] and figure 3).
In regard to claim 22, in view of the modification of the preceding claim, Boulton further discloses: wherein the primary wellbore further includes:
a first build section (66A) extending from vertical to the first tangent section, the first build section transitioning the primary wellbore from vertical to the first inclination (column 10, lines 21-36 and figure 3); and
a second build section (66B) extending from the first tangent section and transitioning the primary wellbore from the first inclination to the second inclination (column 10, lines 21-36 and figure 3).
In regard to claim 26, Duncan in view of Boulton, AAPA and Al-Mousa disclose claim 18 above.
However, Duncan in view of Boulton, AAPA and Al-Mousa is/are silent in regard to: a controller and a variable speed drive positioned at the service rig and operable to control operation of the ESP.
Nonetheless, Al-Mousa teaches controlling operation of the ESP with a controller and a variable speed drive positioned at the service rig (paragraph [0022] and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the ESP system, as taught by Duncan, to include the claimed well structure, as taught by Al-Mousa, “[...] to optimize the pump efficiency and production rate” (paragraph [0022] — Al-Mousa).
In regard to claim 27, in view of the preceding modification(s), Al-Mousa further discloses: wherein the variable speed drive is programmed to maintain a predetermined pump intake pressure (paragraph [0022]).
In regard to claim 28, in view of the modification of the preceding claim(s), Duncan in view of Boulton and APPA further discloses: wherein the predetermined pump intake pressure is set to 100 psi above the bubble point pressure of the reservoir (see claim 18 rejection).
In regard to claim 29, in view of the modification of the preceding claim, Al-Mousa further discloses: wherein the completion string includes a pair of wellbore isolation devices (316, 318) straddling each of the one or more inflow control valves, wherein each wellbore isolation device seals against a surface of the primary wellbore (paragraphs [0013, 0032-0034] and figure 3).
In regard to claim 30, in view of the modification of the preceding claim, Al-Mousa further discloses: wherein the completion string is attached to a production tubing (117) that includes the ESP at a matable interface (paragraphs [0013, 0032-0034] and figure 3).
In regard to claim 31, in view of the modification of the preceding claim, Al-Mousa further discloses: wherein the one or more inflow control valves are automatic inflow control valves (“The first ICV (320) and the second ICV (322) may be controlled from the surface location (114) to maintain flow conformance and, as the formation(s) deplete, to stop unwanted produced fluids (102) from entering the pipe (314)” — paragraph [0037]).
Claim(s) 23-24 is/are rejected under 35 U.S.C. 103 as being unpatentable over Duncan et al. (US Publication Number 2016/0265905 A1; hereinafter “Duncan”) in view of Boulton et al. (US Patent Number 6,269,892 B1; hereinafter “Boulton”) in further view of Applicant’s Admitted Prior Art (hereinafter “AAPA”) and Al-Mousa (US Publication Number 2023/0099319 A1; hereinafter “Al-Mousa”) and Biswas et al. (PLOS ONE 17(1): e0261427; hereinafter “Biswas”).
In regard to claim 23, in view of the modification of the preceding claim, Boulton further discloses: wherein the first inclination from surface ranges between 1° and 55° (figure 3).
However, Duncan in view of Boulton, AAPA and Al-Mousa are explicitly silent in regard to: wherein the first inclination from surface ranges between 1° and 55° from vertical.
Nonetheless, Biswas teaches that the wellbore comprising tangent sections (as shown in figure 1) can have inclination angles from 10° and 95° (table 1 and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the first inclination angle, as taught by Duncan in view of Boulton, to be from surface ranges between 1° and 55°, as taught by Biswas, to allow for optimal wellbore trajectory for oil and gas production purposes (abstract — Biswas).
In regard to claim 24, in view of the modification of the preceding claim, Boulton further discloses: wherein the first inclination from surface ranges between 1° and 55° (figure 3).
However, Duncan in view of Boulton, AAPA and Al-Mousa are explicitly silent in regard to: wherein the first inclination is greater than 70° and less than 90° from vertical.
Nonetheless, Biswas teaches that the wellbore comprising tangent sections (as shown in figure 1) can have inclination angles from 10° and 95° (table 1 and figure 1).
Therefore, it would have been considered obvious to one of ordinary skill in the art, before the effective filing date of the invention (AIA ), to modify the first inclination angle, as taught by Duncan in view of Boulton, to be from surface ranges greater than 70° and less than 90°, as taught by Biswas, to allow for optimal wellbore trajectory for oil and gas production purposes (abstract — Biswas).
Conclusion
THIS ACTION IS MADE FINAL. Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
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/NEEL GIRISH PATEL/Primary Patent Examiner, Art Unit 3676