DETAILED ACTION
This communication is a first office action on the merits. All currently pending claims have been considered below. The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Information Disclosure Statement
No IDS has been filed in the present case. If applicable, the Examiner respectfully notes Applicant's duty to submit to the Office information which is material to patentability, as per MPEP §609, and the time limits for such a filing set forth under 37 CFR 1.97.
Priority
The examiner acknowledges the preset case's claim of priority to PCT/IB2024/053640 (filed 4/13/2024) and provisional application PRO 63/500,835 (filed 5/8/2023).
However, the present application is not the same as the provisional application. The figures and claims are different between these documents and the provisional application and do not have explicit support for the full range of numerical limitations (discussed in more detail in the 112 section below). For example, "bulk density" is not used in the provisional document, and "ratio" is only used with respect to "joint strength to weight ratio" is ¶s 53-55 of the certified copy of the provisional filed 11/7/2025. Similarly, present figures 2A-2C, 3C-9B+, and 12 are all new from the provisional document. Present figures 3A & 3B are similar to figures 3A &3B in the provisional document but are also still different in final assessment. As such, the present claims are respectfully affording the filing date of the WIPO priority document: 4/13/2024.
Claim Objections
Claims 1, 4, 6, 8 are objected to because of the following informalities:
Claim 1 recites "a wall of the tubing", which lacks proper antecedent basis earlier in the claim. The claim previously recites "a drilling string". Therefore, the phrase "a wall of the tubing" should read "a wall of the drilling string". For the purposes of examination, the examiner has reviewed the dependent claims with this corrected phrasing in mind.
Claim 4 recites "interval coiled tubing". The phrase should read "interval of coiled tubing".
Claim 6 recites "a specified temperature of tubing in the drilling string" which should read "the specified temperature of tubing in the drilling string" because "a specified temperature..." is already recited in parent claim 5. Consistent antecedent terminology should be used through any given claim set.
Claim 8 recites "wherein diverting a portion... comprises diverting the fluid comprising a higher water to oil ratio than the drilling fluid into an annulus around..." which should read "wherein diverting the portion... comprises diverting the fluid comprising the higher water to oil ratio than the drilling fluid into the annulus around..." Consistent antecedent terminology should be used through any given claim set.
Appropriate correction is required.
Claim Rejections - 35 USC § 112
The following is a quotation of the first paragraph of 35 U.S.C. 112(a):
(a) IN GENERAL.—The specification shall contain a written description of the invention, and of the manner and process of making and using it, in such full, clear, concise, and exact terms as to enable any person skilled in the art to which it pertains, or with which it is most nearly connected, to make and use the same, and shall set forth the best mode contemplated by the inventor or joint inventor of carrying out the invention.
Claims 1-22 are rejected under 35 U.S.C. 112(a) for lack of enablement commensurate in scope with the claims. See MPEP 2164.08.
Independent claims 1 & 14 recite "a drilling string having a bulk, length normalized, radial thermal resistance to heat transfer through a wall of the [drilling string] of at least 0.008 m K/W" and "a ratio of a drilling string bulk density to a drilling fluid bulk density is 2 or less".
Citing MPEP 2164.08 (bolded & underlined emphasis added):
All questions of enablement are evaluated against the claimed subject matter. When considering whether claims in a utility patent application or patent are enabled, USPTO personnel will use the Wands factors to ascertain whether the amount of experimentation required to enable the full scope of the claimed invention is reasonable. See Guidelines for Assessing Enablement in Utility Applications and Patents in View of the Supreme Court Decision in Amgen Inc. et al. v. Sanofi et al., 89 FR 1563 (January 10, 2024). See also MPEP § 2164.01(a). The focus of the examination inquiry is whether everything within the scope of the claim is enabled. Accordingly, the first analytical step requires that the examiner determine exactly what subject matter is encompassed by the claims. See, e.g., AK Steel Corp. v. Sollac, 344 F.3d 1234, 1244, 68 USPQ2d 1280, 1287 (Fed. Cir. 2003) (When a range is claimed, there must be reasonable enablement of the scope of the range. Here, the claims at issue encompassed amounts of silicon as high as 10% by weight, however the specification included statements clearly and strongly warning that a silicon content above 0.5% by weight in an aluminum coating causes coating problems. Such statements indicate that higher amounts will not work in the claimed invention.)...
The courts have repeatedly held that "the specification must teach those skilled in the art how to make and use the full scope of the claimed invention without ‘undue experimentation’" or that any experimentation must be "reasonable"... Nevertheless, not everything necessary to practice the invention need be disclosed. In fact, what is well-known is best omitted. In re Buchner, 929 F.2d 660, 661, 18 USPQ2d 1331, 1332 (Fed. Cir. 1991). All that is necessary is that one skilled in the art be able to practice the claimed invention, given the level of knowledge and skill in the art. Further, the scope of enablement must only bear a "reasonable correlation" to the scope of the claims. See, e.g., In re Fisher, 427 F.2d 833, 839, 166 USPQ 18, 24 (CCPA 1970). See Amgen Inc. et al. v. Sanofi et al., 598 U.S. 594, 611, 2023 USPQ2d 602 (2023) (The Court stated that "[t]he more one claims, the more one must enable.")".
With respect to the breadth of a claim, the relevant concern is whether the scope of enablement provided to one skilled in the art by the disclosure is commensurate with the scope of protection sought by the claims. The Federal Circuit, citing McRO, provided guidance on the application of enablement to genus claims, holding that "[a]lthough a specification does not need to describe how to make and use every possible variant of the claimed invention, when a range is claimed, there must be reasonable enablement of the scope of the range."...
The propriety of a rejection based upon the scope of a claim relative to the scope of the enablement concerns (1) how broad the claim is with respect to the disclosure and (2) whether one skilled in the art could make and use the entire scope of the claimed invention without undue experimentation. A scope of enablement rejection must identify the claimed subject matter for which the specification is not enabling and explain why the specification is not enabling, applying the factors set forth in In re Wands, 858 F.2d 731, 737, 8 USPQ2d 1400, 1404 (Fed. Cir. 1998).
The Wands "undue experimentation factors" are discussed in MPEP 2164.01(a).
(A) The breadth of the claims - Claims 1 & 14 are extremely broad. They recite no specific material opting instead for thermal properties only that merely imply specific materials. The thermal properties could be met by an almost infinite combination / dimensions / thicknesses, etc. of materials at the level of broadness recited while only a few specific materials are actually disclosed. Further, the range of "at least 0.008 m K/W" is an unbounded range that extends upward to infinity. Similarly, the "ratio of a drilling string bulk density to a drilling fluid bulk density is 2 or less" takes the almost infinite combination of materials for the string and combines it with an equally almost infinite combination of drilling fluid mixtures. Finally, these ranges are "length normalized" which means that Applicant is expressly attempting to encompass varying materials along its length as well (see as-filed ¶ 97). So there is further viability in the depth of the bore being drilled.
(B) The nature of the invention - The invention attempts to encompass literally every combination of materials that meets a numerical range that extends to infinity, and links a similarly broad recitation of drilling fluid mixture to the nature of the string.
(C) The state of the prior art - Heat distribution and cooling in drilling system via drill strings and circulating drilling fluid is well known. However, the claimed ranges (as imparted by the un-claimed materials) are the inventive concept of the claims. In other words, the scope of the claims are the broadest at the exact point of asserted novelty.
(D) The level of one of ordinary skill - PHOSITA is versed in using drilling strings and circulating drilling fluid through the string to cool it.
(E) The level of predictability in the art - Heat in drilling operations is well known. But variability and unpredictability from one drilling operation to another is wide, and can also change within the same drilling operation, as Applicant discusses in as-filed ¶ 3. And as discussed at the end of (A) above, these ranges are "length normalized" which means that Applicant is expressly attempting to encompass varying materials along its length as well (see as-filed ¶ 97). So there is further viability in the depth of the bore being drilled.
(F) The amount of direction provided by the inventor - Applicant provides materials in as-filed ¶s 95-99. But the highest "length-normalized thermal resistance" material taught is "epoxy phenolic resins [that] have an average thermal conductivity of ~0.8 W/m K" (as-filed ¶ 95) and "carbon fiber has a thermal conductivity of about 0.8 W/m K" (as-filed ¶ 96).
¶ 98 describes "the length normalized thermal resistance of the wall of the tubing string... having a steel main body 350 and an inner coating layer 304... but no outer coating layer" with the highest disclosed numeral range of "0.0024 K m/W".
¶ 99 describes the same "plus an outer coating layer 306 ("jacket") with the highest disclosed numerical range of 0.011 K m/W"
(G) The existence of working examples - A few specific examples are given as discussed above, but which are of substantially narrower scope than the actual claims.
(H) The quantity of experimentation needed to make or use the invention based on the content of the disclosure - Applicant is claiming an unbounded range that extends infinitely beyond even the generically taught highest thermal resistance numerical value in the specification ("0.011 K m/W" with material specifics in ¶ 99).
The claimed range is "at least 0.008 m K/W" and therefore extends upward to infinity. But the highest disclosed "length normalized thermal resistance" with any material specifics is only "0.011 K m/W" (the examiner views the units "m K/W" as being equivalent to "K m/W". This appears to be merely an algebraic translation). To make a point through hyperbole, put simply, Applicant has not enabled a thermal resistance to heat transfer of, say, 1,000 or 1,000,000 or 1,000,000,000 m K/W but the claim expressly encompasses these values, repeatable ad nauseam for ever increasing values. Values of "0.5 W/m K" are discussed in ¶ 106 but (A) this is not "length normalized" and has entirely different units ("W/m K") than the claimed numerical value ("m K/W") and (B) this is still no where near commensurate in scope with the claimed range.
As cited above from MPEP 2164.08, "All questions of enablement are evaluated against the claimed subject matter"; "...to enable the full scope of the claimed invention"; "The focus of the examination inquiry is whether everything within the scope of the claim is enabled"; "The Court stated that '[t]he more one claims, the more one must enable'"; "...whether the scope of enablement provided to one skilled in the art by the disclosure is commensurate with the scope of protection sought by the claims"; "...when a range is claimed, there must be reasonable enablement of the scope of the range"; "the scope of a claim relative to the scope of the enablement concerns (1) how broad the claim is with respect to the disclosure and (2) whether one skilled in the art could make and use the entire scope of the claimed invention without undue experimentation..."
If it is Applicant's position that there is an implicit / inherent upper boundary to this range, this would merely be an admission that the range, as claimed, does, in fact, encompass a non-enabled thermal resistance.
The present situation could also be viewed as a "broadly claimed genus" (literally every combination of materials that meets "at least 0.008 m K/W) relative to a "narrowly disclosed species" (steel main body, an inner coating of epoxy novolac of 400 μm thick and a 5 mm jacket of e-glass on the exterior - ¶ 99). Again citing MPEP 2164.08 (third ¶): "... the application of enablement to genus claims, holding that '[a]lthough a specification does not need to describe how to make and use every possible variant of the claimed invention, when a range is claimed, there must be reasonable enablement of the scope of the range.'"
This could also be viewed as a written description failure per MPEP 2163.03, subsection V: Original Claim Not Sufficiently Described: "An original claim may lack written description support when (1) the claim defines the invention in functional language specifying a desired result but the disclosure fails to sufficiently identify how the function is performed or the result is achieved or (2) a broad genus claim is presented but the disclosure only describes a narrow species with no evidence that the genus is contemplated. See Ariad Pharms., Inc. v. Eli Lilly & Co., 598 F.3d 1336, 1349-50 (Fed. Cir. 2010) (en banc). The written description requirement is not necessarily met when the claim language appears in ipsis verbis in the specification. 'Even if a claim is supported by the specification, the language of the specification, to the extent possible, must describe the claimed invention so that one skilled in the art can recognize what is claimed. The appearance of mere indistinct words in a specification or a claim, even an original claim, does not necessarily satisfy that requirement.'"
That said, the examiner does not make a redundant written description rejection at this time, instead opting for the above scope of enablement rejection as most appropriate for the claims as currently worded.
The above logic is similarly applicable to "a ratio of a drilling string bulk density to a drilling fluid bulk density is 2 or less". The claim attempts to encompass literally every combination of drill string materials and drilling fluid materials, but actually only discloses generalized "modifying the inlet temperature, modifying inlet pressure (when operating with managed pressure drilling), changing the dissolved solids/salts and solids content in the fluid" (¶ 116) and "lower density oil phase and higher density water phase" (¶ 121). In other words, the "ratio" is dependent on the materials that make up both the string and the drilling fluid. But the claim does not recite such materials, nor any structure, additives, or adjustments to achieve the ratio, and therefore clearly attempts to encompass far more than what the disclosure actually reasonably teaches. And the "ratio" limitation is, itself, linked to the unbounded "at least 0.008 m K/W" range through the (unrecited) materials of the drill string and fails the scope of enablement requirement for the same reasons.
Claims 2-13 and 21 depend from claim 1. Claims 15-20 and 22 depend from claim 14.
Claims 9 & 19 recite "the drilling string comprises a non-metallic tubing having a bulk, length normalized radial thermal resistance to heat transfer through the wall of the tubing of at least 0.05 m K/W". The examiner holds this as failing the scope of enablement requirement as similarly described for claims 1 & 14 above, respectfully not repeated again here.
Claim 12 recites "a specific tensile strength of the drilling string is at least 150 kN*m/kg when submerged in the drilling fluid". Applicant has not enabled a drilling string with a tensile strength of, say, 1,000,000,000 kN*m/kg. And this unbounded rage in claim 12 is linked to the drilling fluid, which is, in turn, at least partially defined by the unbounded rage of claim 1 (the material of the string defines both its thermal resistance and its bulk density, which, in turn, defines the drilling fluid per claim 1). This means claim 12 basically fails the scope of enablement requirement twice, as similarly described for claims 1 & 14 above, respectfully not repeated again here.
Claim 20 recites "the drilling string comprises tubing having a bulk, length normalized radial thermal resistance to heat transfer of at least 0.2 m K/W". The examiner holds this as failing the scope of enablement requirement as similarly described for claims 1 & 14 above, respectfully not repeated again here.
The following is a quotation of 35 U.S.C. 112(b):
(b) CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
Claims 1-22 are rejected under 35 U.S.C. 112(b) as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor, regards as the invention.
Independent claims 1 & 14 recite "a bulk, length normalized radial thermal resistance to heat transfer of at least 0.2 m K/W". The examiner holds this to be indefinite for two reasons.
First, while "breadth is not indefiniteness" (MPEP 2173.04), this is an unbounded rage that extends to infinity. This is, by definition, lacking in metes and bounds. In other words, the examiner holds "at least 0.2 m K/W" to be indefinite not because it is broad, but because it is unbounded. And because this unbounded range defines the materials of both the drill string and the drilling fluid, it renders the structural metes and bounds of both the drill string and the drilling fluid indefinite. In other words, what materials produce a heat transfer resistance of 1,000,000,000 m K/W of the drill string, and what are the components of the drilling fluid responsive to those (unrecited) drill string materials?
Claims 2-13 and 21 depend from claim 1. Claims 15-20 and 22 depend from claim 14.
Claim 2 recites "drilling with a contactless type drill bit". The examiner holds the use of "type" to be indefinite because the it attempts to define the claim by what the bit is similar to, and not what it actually is. In other words, is the bit "a contactless drill bit" or not? The examiner contrasts the phrasing of claim 2 with the clearer wording of claim 15.
Claim 4 recites "the drilling string comprise an interval of jointed tubing and another interval coiled tubing". First, the phrase should read "interval of coiled tubing" as discussed in the claim objections above. Second, the examiner holds "another interval [of] coiled tubing" as being indefinite because no previous "coiled tubing" is recited in parent claim 1. "Coiled tubing" is recited in claim 3, which claim 4 does not depend from. It is therefore unclear how "another interval of coiled tubing" operates in a claim that does not recite a first / initial interval of coiled tubing.
Finally, the examiner respectfully asserts that, when combined into "an interval of jointed tubing and [an] interval [of] coiled tubing", it is unclear what, exactly is encompassed by "coiled tubing" if it is, itself, merely another joint / segment in the drill string. "Coiled tubing" is generally regarded as "continuous" as shown by claim 3. So if the coiled tubing is segmented and joined with "an interval of jointed tubing", how does the "interval of coiled tubing" differ from "jointed tubing" to begin with? Put another way, is "an interval of coiled tubing" not "an interval of tubing" when it is "jointed" into a drill string?
Claims 9 & 19 recite "the drilling string comprises a non-metallic tubing having a bulk, length normalized radial thermal resistance to heat transfer through the wall of the tubing of at least 0.05 m K/W". This range is unbounded and extends upward to infinity, which is, by definition lacking in metes and bounds, as similarly discussed for claim 1 above, respectfully not repeated again here.
Claim 10 recites "the drilling fluid have a first bulk density" and "a drilling fluid having a second, lower bulk density than the first bulk density". However, parent claim 1 already recites "a drilling fluid bulk density" thus making it unclear how or if the two "bulk densities" recited in claim 10 differ from the "bulk density" already recited in claim 1.
Similarly, it is unclear how or if the "flowing a drilling fluid having a second, lower bulk density while withdrawing the drilling string from the wellbore" differs from the "flowing a drilling fluid through the drilling string while drilling" already in parent claim 1. While claim 1 states "while drilling" and claim 10 states "while withdrawing", claim 10 also says the "drilling fluid having a first bulk density while running the drilling string into the wellbore" so it is not expressly states that "withdrawing" is distinct from "drilling". In other words, if running a string into the wellbore is "while drilling" (even before the bit touches bottom), then the same would appear to be true of withdrawing. These are all drilling operations at the level of generality currently recited.
Claim 12 recites "a specific tensile strength of the drilling string is at least 150 kN*m/kg when submerged in the drilling fluid". This range is unbounded and extends upward to infinity, which is, by definition lacking in metes and bounds, as similarly discussed for claim 1 above, respectfully not repeated again here.
The examiner also holds the claim to be indefinite for the limitation of "when submerged in the drilling fluid" due to the claim linking an indefinite range to an indefinitely recited "fluid" with no meaningful material / component limitations thereof. In other words, the claim attempts to encompass literally every fluid conceivable and then link that essentially unbounded fluid limitation to an unbounded material property range.
Claim 20 recites "the drilling string comprises tubing having a bulk, length normalized radial thermal resistance to heat transfer of at least 0.2 m K/W". This range is unbounded and extends upward to infinity, which is, by definition lacking in metes and bounds, as similarly discussed for claim 1 above, respectfully not repeated again here.
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.
Claim(s) 1, 2, 4, 5, 9, 11-15, 19, & 20 is/are rejected under 35 U.S.C. 103 as being unpatentable over WO 2022/043947 (Toews), published 3 March, 2022. A copy of Toews is included with this action. The independent claims will be addressed first so that similar dependent claims may be addressed together.
The examiner initially notes that, as similarly discussed above, much of the limitations of claim 1 are directed to material properties without actually reciting the specifics of the materials. Therefore, prior art which teaches the same materials as disclosed in the present case are presumed to inherently have the same properties. See MPEP 2112.01. For example, the present case teaches (emphasis added):
[0093] Each tubing 202 includes a main body 350. In some instances, the main body 350 is carbon or chrome moly steel, aluminum alloy, titanium alloy, fiber composite (e.g., a composite of carbon fiber, aramid fiber, fiberglass, e-glass and/or other structural fiber in a resin binder), and/or polymer (e.g., entirely polymer or polymer reinforced with fiber such as carbon, aramid, fiberglass, e-glass or other structural fiber). The tubing 302 includes an insulative inner coating layer 304 covering (entirely or partially) the inner circumferential surface of tubing 302...
[0095] In some instances, inner coating layer 304 comprises one or more of epoxy novolac resins and epoxy phenolic resins. In certain instances, the thickness of inner coating layer 304 comprising the epoxy phenolic resin ranges from 150 to 250 pm. In certain instances, the thickness inner coating layer 304 comprising the epoxy novolac resins ranges from 400 to 1270 pm. In certain instances, the epoxy phenolic resins have an average thermal conductivity of ~ 0.8 W/m K (Watts per meter Kelvin). In certain instances, the epoxy novolac resin has an average thermal conductivity of ~ 0.4 W/m K. Insulating particles can be added to these resins, or others, to further reduce the thermal conductivity.
For comparison, WO 2022/043947 (Toews) teaches (emphasis added):
[0077] Figure 8A illustrates cooling coatings applied to tubular segments 220 of drill string 206 of Figure 2 in accordance with an instance of the present disclosure. Tubular segments 220 are connected to each other at connection joints 222 and comprise a main body 802. In some instances of the present disclosure, main body 802 comprises a carbon steel body. In other instances of the present disclosure, main body 802 can comprise an aluminum alloy, a titanium alloy, and/or fiber composite (e.g., a composite of polymer binder with carbon fiber, aramid fiber, fiberglass, e- glass and/or other structural fiber), as described in more detail below. Inner coating layer 804 at least partially covers the inner circumferential surface of tubular segments 220...
[0079] In some instances of the present disclosure, inner coating layer 804 comprises one or more of epoxy novolac resins, TK340XT and CP -2060, and epoxy phenolic resins, TK34XT and CP-2050. The TK products are available from NOV, Inc. while the CP products are available from Aremco products Inc. The thickness of inner coating layer 804 comprising the epoxy phenolic resin can range from 150 to 250 pm while the thickness inner coating layer 804 comprising the epoxy novolac resins can range from 400 to 1270 pm. The epoxy phenolic resins can have an average thermal conductivity of ~ 0.8 K/w m while the epoxy novolac resin can have an average thermal conductivity of ~ 0.4 k/w m. Insulating particles can be added to these resins, or others, to further reduce the thermal conductivity.
The Toews reference teaches the same materials in the same combination with the same thickness for the same purpose. Therefore, the tubing taught by Toews must also read on the limitation of "having a bulk, length normalized, radial thermal resistance to heat transfer through a wall of the tubing of at least 0.008 m K/W" for the same reasons that the presently disclosed materials do. In other words, it is not a novel patentable distinction to only claim the properties resulting from known materials used in the same manner while eschewing reciting the materials themselves.
Similarly, the present case teaches (emphasis added):
[0100] In certain instances, tubing 302 as illustrated in FIG. 3A has an inner coating layer 304 of an epoxy novolac resin with a thickness of about 400 microns and an e-glass outer coating layer 306 with a thickness of about 5 millimeters. In such an instance, assuming a subterranean zone with a thermal gradient of about 600 C/km and drilling string with a length of about 8,000 m and water-based drilling fluid with a circulation rate of about 3 m3/min
[0114] In certain instances, the tubing 202 construction can be selected, together with the drilling fluid, to enable the drill string 200 to be buoyed or at least partially buoyed by the drilling fluid in the wellbore. For example, in drilling with a contactless type drill bit, significant weight on bit is not required to effect the drilling. The bit simply needs to be maintained in close proximity to the rock face it is drilling. Selection of main bodies 350 that are composite and/or polymer enables achieving a ratio of tubing and/or drilling string bulk density to drilling fluid bulk density of 2, and in certain instances 1.5 or less, so that drilling string 200 is at least partially buoyed by the fluid and the string's floating weight to be much less than main bodies 350 of steel. The target ratio can account for things in the drilling string that are not tubing, such as the BHA and umbilical cable, and the mix of different types of tubing 202 (e.g., different main body materials) so that the total ratio is 2.0 or greater...
[0115] In one example, a tubing 202 with a composite and/or polymer main body 350 can have a density of approximately 1.3 SG (typical of polymers) to 2 SG (typical fiber composites range from 1.5-2 SG), and for the sake of this example, approximately 1.5 SG. When submerged with a drilling fluid that is primarily water (i.e., approximately 1 SG), the ratio of densities is 1.5. By comparison, typical steel is 7.8 SG, so a tubing 202 with a steel main body 350 in a water drilling fluid will have a ratio of densities of approximately 7.8.
For comparison, WO 2022/043947 (Toews) teaches (emphasis added):
[0061] ... drilling bit 208 of Figure 2 can be a contactless drilling bit configured to break formation material at the rock face 214 of the subterranean zone 204 at the downhole end of wellbore 202 without requiring contact between bit 208 and rock face 214...
[0077] ... the present disclosure, main body 802 can comprise an aluminum alloy, a titanium alloy, and/or fiber composite (e.g., a composite of polymer binder with carbon fiber, aramid fiber, fiberglass, e- glass and/or other structural fiber)...
[0084] ...drill string 206 of Figure 2 comprises tubular segments 220 as illustrated in Figure 8A comprising inner coating layer 804 of an epoxy novolac resin TK340XT with a thickness of about 400 microns and an e-glass outer coating layer 806 with a thickness of about 5 millimeters. In such an instance, assuming a subterranean zone with a thermal gradient of about 60°C/km and drill string with a length of about 8,000m and water-based drilling fluid with a circulation rate of about 3 m3/min...
See also Toews, ¶s 80, 85, 87, & 104. In other words, Toews teaches the same materials for the drill string in the same drilling fluids circulated at the same rates as the present case. Therefore the relative bulk densities between the drill string and the drilling fluid reasonably read on the "ratio... is 2 or less" limitation in the same manner as in the present case.
While the examiner asserts that Toews reasonably anticipates the claimed numerical values by the above logic, Toews does not explicitly teach the specific numerical values in claim 1. Therefore, the examiner respectfully opts for a single reference 103 rejection of claim 1 per MPEP 2144.05.
Independent claim 1. Toews discloses a method comprising:
drilling a wellbore (fig 2; "wellbore 202..." - ¶ 56) in a subterranean zone ("...is formed in a subterranean zone 204..." - ¶ 56) with a drilling string ("...by drilling with drill string 206 positioned in wellbore 202" - ¶ 56) having a bulk, length normalized, radial thermal resistance to heat transfer through a wall of the tubing of at least 0.008 m K/W (Toews teaches the same materials in the same combination with the same thickness for the same reasons and to the same effect as the present case. See Towes ¶s 77 & 79 vs the present as-filed specification at ¶s 93 & 95, as discussed above); and
flowing a drilling fluid through the drilling string while drilling ("The interior of drill string 206 defines a conduit for flowing a drilling fluid 212 to the downhole end of the wellbore to displace broken formation material from rock face 214, which then is carried by drilling fluid 212 up the annulus 216 that is defined between the exterior of drill string 206 and the interior surface of wellbore 202" - ¶ 57).
Toews discloses the same materials as the present case as cited above. Toews similarly teaches the same drilling fluid as the present disclosure (Towes at ¶s 61, 77, 84 vs the present as-filed specification at ¶s 100, 114, 115). That said, Toews does not explicitly disclose the numerical ratio of the drilling string bulk density to the drilling fluid bulk density.
However, it would have been considered obvious to one of ordinary skill in the art at the time the invention was made to have a ratio of 2 or less, since it has been held that where the general conditions of a claim are disclosed in the prior art (as cited above), discovering the optimum or workable range involves only routine skill in the art. In other words, narrowing a general condition taught by the prior art to a specific numerical value has been held to be an obvious variation thereof. In re Aller, 105 USPQ 233 and In re Boesch, 205 USPQ 215. Toews teaches the use of "a contactless drilling bit" that is used "without requiring contact between bit 208 and rock face 214" (¶ 61 of Toews). Therefore, ensuring a low ratio of relative specific densities reduces the amount of weight of the string that must be supported by the surface equipment while drilling; weight that would otherwise by taken up by direct physical contact with the borehole bottom and a rotary drag bit, for example. In other words, using a contactless bit means that the surface equipment must continuously support the more of the weight of the drill string and a less dense drill string relative to the drilling fluid will naturally lighten that load.
Independent claim 14 is a system claim that is structurally commensurate with claim 1, and is similarly rejected as described for claim 1 above, respectfully not repeated again here.
2 & 15. The method of claim 1 / system of claim 14, where drilling comprises drilling with a contactless type drill bit ("a contactless drilling bit" - ¶ 61).
4. The method of claim 1, where the drilling string comprises an interval of jointed tubing (figs 8A, 8B, 11; ¶s 77, 78, 87, & 104) and [an] interval [of] coiled tubing (As discussed in the 112(b) rejection of claim 4 above, the distinction of "an interval of coiled tubing" versus "an interval of jointed tubing" is unclear when they are all jointed together as claimed. The drill string taught by Toews may bend and flex - necessary to drill the wellbore shown in figs 1A & 1B; ¶ 53 - and therefore would appear to broadly read on "coiled tubing" at the level of generality currently claimed).
5. The method of claim 1, comprising controlling the flowing drilling fluid based on a specified temperature of tubing in the drilling string ("downhole electronics, circuit boards, batteries, and other components can have temperature limits of 150-200 °C. (Some downhole components can have a different (higher or lower) temperature limit.) By using a cooling system of the present disclosure these components are kept below their temperature limits even when drilling very hot rock" - ¶ 73 - "Likewise, by cooling the magnetometers and other downhole components of directional drilling systems, some instances described in the present disclosure can enable the use of directional drilling in higher temperature rock environments than was possible previously" - ¶ 74. See also ¶s 46, 59, 63
figs 9A-9D).
9, 19, & 20. The method of claim 1 / system of claim 14, where the drilling string comprises a non-metallic tubing having a bulk, length normalized radial thermal resistance to heat transfer through the wall of the tubing of at least 0.05 m K/W [claims 9 & 1] / of at least 0.2 m K/W [claim 20] (Toews teaches the same materials in the same combination with the same thickness for the same reasons and to the same effect as the present case. See Towes ¶s 77 & 79 vs the present as-filed specification at ¶s 93 & 95, as discussed above).
11. The examiner initially notes that Toews incorporates several documents by reference in ¶s 52 & 62, including US 2019/0346181 (¶ 52). The method of claim 1, where drilling comprises drilling, with the drill string, a lateral wellbore having a measured depth from the surface, along the path of the wellbore, of at least 7 km ("lateral wellbores 110 can be anywhere from 2000 meters to 8000 meters or more in length " - ¶ 53. Fig 4 of US 2019/0346181 shows the drilling of horizontal laterals of up to 8 km).
12. The method of claim 1, where a specific tensile strength of the drilling string is at least 150 kN*m/kg when submerged in the drilling fluid (Toews teaches the same materials for the drilling string and the same fluid for the drilling fluid, as cited for claim 1 above, and therefore the properties of the string when in the drilling fluid will be the same as the present case).
13. The method of claim 1, where the drilling string comprises metallic tubing comprising an insulative coating (fig 8A; ¶ 77: "main body 802 can comprise an aluminum alloy, a titanium alloy, and/or fiber composite (e.g., a composite of polymer binder with carbon fiber, aramid fiber, fiberglass, e- glass and/or other structural fiber), as described in more detail below. Inner coating layer 804 at least partially covers the inner circumferential surface of tubular segments 220...).
Claim(s) 3 is/are rejected under 35 U.S.C. 103 as being unpatentable over WO 2022/043947 (Toews) in view of US 2017/0009529 (Oluwafemi).
Claim 3. Toews discloses all the limitations of the parent claims but does not expressly disclose those of the present. However Oluwafemi discloses drilling extended reach lateral / horizontal drilling (title, abstract) using a drilling string comprising coiled tubing ("coiled tubing 10" - ¶ 15) deployed from a spool at a terranean surface ("Coiled tubing 10 may comprise of a single tube that may be spun around as reel, not illustrated, and straightened before entering a well" - ¶ 15).
Therefore it would have been obvious to PHOSITA at the time of filing to use coiled tubing as taught by Oluwafemi for the drill string taught by Toews. Coiled tubing may be carbon fiber (¶ 15) just as in Toews (¶ 77) and the present case (as cited in the 112a rejection above) and allows for the drilling of extended reach horizontal wellbores (¶s 2 & 3) which is similarly a goal of Toews (fig 1B; "lateral wellbores 110 can be anywhere from 2000 meters to 8000 meters or more in length and from 1000 meters to 20000 meters in depth from the surface 114" - ¶ 53).
Claim(s) 10, 21 & 22 is/are rejected under 35 U.S.C. 103 as being unpatentable over WO 2022/043947 (Toews) in view of US 2014/0131045 (Loiseau).
Claim 10. Toews does not expressly disclose the limitations of claim 10. However Loiseau discloses a downhole tool positioning system and method (title) where the drilling fluid at least partially buoys the string in the wellbore (abstract; ¶s 8, 31, 36, among many other places) where the circulated fluid has a first bulk density while running the string into the wellbore (fluid circulated into 114 during run-in, fig 3; "a lighter fluid is removed from or supplied to the wellbore below the tool in the wellbore section 112, and/or wherein the relatively denser slurry may be respectively supplied to or removed from the annulus 114 above the tool" - ¶ 56. "[T]he circulation of the fluid in the wellbore 100 may simultaneously push on the tool 106 by introducing fluid into the annulus 114 behind or above the tool and pull on the tool by removing fluid via the central flow passage 116 from the wellbore ahead of or below the tool, to move the tool in the direction of insertion toward the bottom of the wellbore..." - ¶ 58. "...the relatively denser slurry may be respectively supplied to or removed from the annulus 114... The presence of a lighter treatment fluid in the central passage 116 relative to the denser fluid in the annulus 114 provides positive buoyancy equal to the product of the density difference between the two fluids times the volume of the fluid in the central passage" - ¶ 56) and circulating a fluid having a second, lower bulk density than the first bulk density (fluid circulated into 112 during withdrawal: "a lighter fluid is removed from or supplied to the wellbore below the tool in the wellbore section 112, and/or wherein the relatively denser slurry may be respectively supplied to or removed from the annulus 114 above the tool" - ¶ 56. "...Conversely, to move the tool 106 in the direction of retrieval toward the surface, the circulation of the fluid may simultaneously push on the tool 106 by introducing fluid via the central flow passage 116 into the wellbore 100 below the tool, and pull on the tool by removing fluid from the annulus 114 above the tool." - ¶ 58) while withdrawing the drilling string from the wellbore ("in the direction of retrieval toward the surface" - ibid).
Therefore it would have been obvious to PHOSITA at the time of filing to circulate less dense fluid during retrieval than run-in as taught by Loiseau with the string taught by Toews. This allows for much improved translation in a deviated or lateral wellbore at extended distances (abstract; ¶s 6, 8, 48, 49). Toews teaches horizontal laterals of over 8 km ("lateral wellbores 110 can be anywhere from 2000 meters to 8000 meters or more in length " - ¶ 53. Fig 4 of US 2019/0346181 shows the drilling of horizontal laterals of up to 8 km) thus clearly showing applicability to Toews.
Claims 21 & 22. As discussed at length above, Toews discloses the same materials for both the drilling string and for the circulating drilling fluid, and therefore reasonably teaches the effect of them in combination. But Toews dose not explicitly disclose that the drilling fluid at least partially buoys the drilling string in the wellbore.
Loiseau discloses a downhole tool positioning system and method (title) where the drilling fluid at least partially buoys the string in the wellbore (abstract; ¶s 8, 31, 36, among many other places).
Therefore it would have been obvious to PHOSITA at the time of filing to have the drilling fluid at least partially buoy the string taught by Toews as taught by Loiseau. This allows for much improved translation in a deviated or lateral wellbore at extended distances (abstract; ¶s 6, 8, 48, 49). Toews teaches horizontal laterals of over 8 km ("lateral wellbores 110 can be anywhere from 2000 meters to 8000 meters or more in length " - ¶ 53. Fig 4 of US 2019/0346181 shows the drilling of horizontal laterals of up to 8 km) thus clearly showing applicability to Toews.
Claim(s) 6 is/are rejected under 35 U.S.C. 103 as being unpatentable over WO 2022/043947 (Toews) in view of US 2014/070881 (Ye).
Claim 6. Toews discloses all the limitations of the parent claim and further discloses using the drilling fluid to cool portions of the drilling string to keep them at or below a specified temperature (¶s 63, 73), but does not expressly disclose controlling a ratio of water to oil in the drilling fluid.
However Ye discloses monitoring the oil to water ratio in drilling fluid (title) that comprises controlling a ratio of water to oil in the drilling fluid (¶ 1; "quickly and efficiently ascertain a drilling fluid's O/W ratio and then adjust the compositional makeup of the drilling fluid to counter changes from exposure to the formation or to anticipate changes in the formation that will occur as drilling continues" - ¶ 12).
A primary function of drilling fluid is to cool the drill string and bit, as is exceedingly well understood in the art, as discussed by Towes (¶s 2, 63, 73, 95), and acknowledged by Applicant in as-filed ¶ 3. This is all "based on a specified temperature of tubing in the drilling string" at the level of generality recited because cooling the tubing is, again, a primary goal. The claim does not say, for example, monitoring a temperature of the drilling string and changing the ratio based off the sensed temperature. Toews discusses specific temperature thresholds in ¶ 63 & 73.
Therefore it would have been obvious to PHOSITA at the time of filing to cool components of the drilling string below a specified temperature as taught by Towes by controlling a ratio of water to oil in the drilling fluid as taught by Ye. "With any drilling fluid comprising an emulsion, the ratio of oil to water ("O/W ratio") and the amount of additives in the drilling fluid typically should be maintained in a careful balance so as to provide a strong, stable emulsion." (¶ 12). Undesirable change in this is necessary for the effective and proper functioning of the drilling fluid (¶ 3).
Claim(s) 7, 16 & 18 is/are rejected under 35 U.S.C. 103 as being unpatentable over WO 2022/043947 (Toews) in view of US 2009/0321141 (Kotsonis).
Claim 7. Toews discloses all the limitations of the parent claim and further discloses using the drilling fluid to cool portions of the drilling string to keep them at or below a specified temperature (¶s 63, 73), but does not expressly disclose diverting fluid into the annulus.
However Kotsonis discloses a system for drilling laterals (¶ 36) with a drilling string ("tubular conveyance system (18)" - abstract) with a diverter in the drilling string ("connection unit 30 may also comprise a flow diverter as is shown in more detail in FIG. 2" - ¶ 39) that diverts a portion of the flowing drilling fluid from the interior of the drilling string to an annulus around the exterior of the drilling string ("Flow channel 32 is connected to the interior of the CT so that fluid flowing down the CT is vented into the annulus surrounding the CT and drilling assembly 20 via lower ports 36 in the lower part of the connector 30. Fluid exiting these lower ports 36 flows mainly back to the surface in the annulus but a portion of this fluid also flows down the annulus around the drilling assembly 20 to be drawn up through the bit 24 by the action of the pump" - ¶ 39) based on a specified temperature of tubing in the drilling string (discussed below).
A primary function of drilling fluid is to cool the drill string and bit, as is exceedingly well understood in the art, as discussed by Towes (¶s 2, 63, 73, 95), and acknowledged by Applicant in as-filed ¶ 3. This is all "based on a specified temperature of tubing in the drilling string" at the level of generality recited because cooling the tubing is, again, a primary goal. The claim does not say, for example, monitoring a temperature and changing the diverting based off the sensed temperature. Toews discusses specific temperature thresholds in ¶ 63 & 73.
Therefore it would have been obvious to PHOSITA at the time of filing to cool components of the drilling string below a specified temperature as taught by Towes by diverting fluid to the annulus taught by Kotsonis. The diverting provides "fresh" drilling fluid to the annulus, bit, and the components therebetween (¶ 39) as well as improves cutting removal (ibid). The improved removal of cuttings will similarly reduce friction and heat buildup in the drilling string.
Claim 16. Toews discloses all the limitations of the parent claim but does not expressly disclose those of the present. However Kotsonis discloses a system for drilling laterals (¶ 36) with a drilling string ("tubular conveyance system (18)" - abstract) with a diverter in the drilling string ("connection unit 30 may also comprise a flow diverter as is shown in more detail in FIG. 2" - ¶ 39), the diverter configured to divert a portion of the drilling fluid from an interior of the drilling string into an annulus around the exterior of the drilling string while drilling ("Flow channel 32 is connected to the interior of the CT so that fluid flowing down the CT is vented into the annulus surrounding the CT and drilling assembly 20 via lower ports 36 in the lower part of the connector 30. Fluid exiting these lower ports 36 flows mainly back to the surface in the annulus..." - ¶ 39).
Therefore it would have been obvious to PHOSITA at the time of filing to use the diverter taught by Kotsonis in the drilling string taught by Toews. First, Kotsonis is directed toward drilling extended reach laterals (¶ 36) just as Toews (fig 1B; "lateral wellbores 110 can be anywhere from 2000 meters to 8000 meters or more in length and from 1000 meters to 20000 meters in depth from the surface 114" - ¶ 53). Second, the diverter aids in pulling cuttings uphole in the circulating drilling fluid (¶ 39). "In this way, cuttings are kept out of the region of the annulus around the drilling assembly 20, so reducing the likelihood of build-up and sticking in the smaller annular space. Venting to the annulus above the drilling assembly 20 allows normal well control to be exercised and avoids the possibility of hydrocarbons returning to the surface in the CT" (ibid).
18. The system of claim 16, where the drilling string comprises, downhole of the diverter (30, fig 1 of Kotsonis), at least on of a tractor ("crawler unit 26" - ¶ 37) or a fluid turbine electric generator.
Therefore it would have been obvious to PHOSITA at the time of filing to use the tractor taught by Kotsonis in the drilling string taught by Toews. Tractors / "crawlers" / thrust generating tools are commonly used in horizontal drilling to aid in overcome the friction between the drill string and the wellbore that is increased in horizontal drilling, as is well understood in the art and which PHOSITA would readily appreciate.
Conclusion
The examiner notes that no prior art rejections are presented for claims 8 & 17. However, in light of the 112 issues above, they are not allowable at this time.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to Blake Michener whose telephone number is (571)270-5736. The examiner can normally be reached Approximately 9:00am to 6:00pm CT.
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/BLAKE MICHENER/
Primary Examiner, Art Unit 3676
Prosecution Insights