DETAILED ACTION
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 .
Continued Examination Under 37 CFR 1.114
A request for continued examination under 37 CFR 1.114, including the fee set forth in 37 CFR 1.17(e), was filed in this application after final rejection. Since this application is eligible for continued examination under 37 CFR 1.114, and the fee set forth in 37 CFR 1.17(e) has been timely paid, the finality of the previous Office action has been withdrawn pursuant to 37 CFR 1.114. Applicant’s submission filed on 25 February 2026 has been entered.
Response to Arguments
Applicant’s arguments filed 25 February 2026 have been considered. Claims 22-42 are pending. Claims 22, 36, and 42 have been amended.
Applicant’s efforts to address the rejections under 35 USC 112(b) are satisfactory, therefore all 112(b) rejections are withdrawn.
Applicant’s arguments concerning the prior art rejections have been considered. However, new grounds of rejection are given in light of the amendments. See 103 rejections below.
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.
Claims 22-29 and 31-42 are rejected under 35 U.S.C. 103 as being unpatentable over Cohen (US 20130140031 A1) in view of Osiptsov (US 20110272159 A1) and Surjaatmadja (US 20060102344 A1).
Regarding claim 22, Cohen discloses a method of stimulating a reservoir for increased production of hydrocarbons (Abstract: “A method of performing a stimulation operation for an unconventional wellsite having natural fractures and hydraulic fractures”), said method comprising:
a) injecting a fracture fluid into a stage of a well in a reservoir to initiate one or more fractures in said stage (¶58: stimulation operations include fracturing, injection, etc.; ¶59: Once perforations are formed, fluid may be injected to create and/or expand fractures; ¶34: “These stimulation operations may involve…multi-stage oilfield operations”, see also Fig. 3.1 and Fig. 10 depicting multiple stages);
b) determining a fracture extension rate (¶78: “For some stimulation designs, a fracture modeling algorithm may be used to read a 3D MEM and run forward modeling to predict fracture growth”; ¶80: “Some complex hydraulic fracture propagation modeling and/or interpretation may also be performed”) and a primary fracture geometry (¶80: “Microseismic mapping may also be used in stimulation design to understand complex fracture growth…Fracture modeling may be used to predict the fracture geometry”); and
f) producing hydrocarbons from said well (Abstract: the purpose of the invention is to stimulate a well, which means to increase production; ¶2: the field is oilfield operations that gather hydrocarbons).
While Cohen does not explicitly recite e) repeating steps a)-b) for subsequent stages of said well, it would have been obvious to do so since multi-stage fracturing generally involves treating a wellbore as individual segments (“stages”) which are fractured separately.
Cohen does not explicitly disclose the remaining limitations.
Osiptsov discloses a method for creating a fracture that has a barrier at the top, bottom, or both top and bottom (Abstract). A fluid initiates a fracture, then another fluid with barrier particles is injected, and a lower-viscosity fluid is injected to promote rising or settling of the barrier particles (Abstract). Osiptsov teaches that one may wish to prevent vertical fracture growth both above and below to avoid fracturing outside of the productive zone and to avoid undesirable regions such as water zones and gas caps (¶2). Any kind of particle used in the oilfield as proppant can be a barrier particle, such as sand, ceramics, polymer beads, glass, etc. (¶38; note that some of the examples are non-dissolving). Osiptsov teaches that the method of creating a barrier may be applied before or during conventional hydraulic fracturing to limit undesired vertical growth (Abstract).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Osiptsov with the invention of Cohen by identifying one or more fracture tip(s) that require strengthening;
c) injecting a first tip strengthening fluid (first fluid) containing a first non-dissolving solid into said stage at a first rate, wherein said one or more fracture tip(s) are strengthened by depositing said first solid into said one or more fracture tip(s);
d) injecting a main treatment injection fluid into said stage at a second rate once it is determined that said one or more fracture tip(s) are strengthened and fracture vertical growth is contained during said injecting; and
e) repeating steps a)-d) for subsequent stages of said well.
Doing so would enable one to limit fractures from growing vertically into undesired regions (outside of a productive zone, into a water zone, etc.) before proceeding with further fracturing in desired regions for a multi-stage well.
Cohen in view of Osiptsov does not explicitly teach the remaining limitations.
Surjaatmadja teaches initiating a fracture tip screenout comprising reducing flow rate below a fracture initiation flow point to initiate a fracture tip screenout (Abstract). Surjaatmadja also teaches that pressure increases as flow rate into a formation increases until a fracture is initiated which releases the pressure and allows greater flow rates without increased pressure (see Fig. 4, line 402).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Surjaatmadja with the invention of Cohen in view of Osiptsov by injecting the first fluid at the first rate such that a slope of a log-log plot of net pressure versus time is positive (i.e. pressure increases with time) and monitoring pressure during said injecting to determine if said slope is trending in a negative direction (indicating some change in the formation which is relieving the buildup of pressure) and reducing said first rate until a positive slope is observed (thereby avoiding unintentionally extending a fracture); and
by determining that said one or more fracture tip(s) are strengthened from injection pressure diagnostics (the above procedure).
Doing so would enable one to pack the barrier particles more tightly while ensuring that a vertical fracture isn’t being inadvertently created or extended.
Finally, considering the above, it would have been obvious for one of ordinary skill in the art practicing the invention of Cohen in view of Osiptsov and Surjaatmadja to cause the second rate to not exceed the first rate to avoid pressures that might extend the vertical fractures.
Regarding claim 23, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Furthermore, Osiptsov teaches separately placing particles that settle (see Fig. 4) and placing particles that rise (see Fig. 5).
It would have been obvious to inject a second tip strengthening fluid (second fluid) containing a second non-dissolving solid into said stage, said injecting being done at said first rate and before step d). Doing so would enable one to place buoyant and settling particles to strengthen vertical fractures above and below in a two-step process.
There is no particular teaching suggesting that the second solid should be larger than the first solid; however, it would be natural for two different solids to have different sizes, such as sand with different mesh sizes. Note also that the first and second solids are not distinguished by density or any other characteristic except size. Considering finally that the injection of the first tip strengthening fluid and the injection of the second tip strengthening fluid may happen in any order, it would have been obvious to try injecting the smaller solid before the larger solid. In such a case, the second solid would be larger than the first solid.
Regarding claim 24, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Osiptsov teaches separately placing particles that settle (see Fig. 4) and placing particles that rise (see Fig. 5). Osiptsov further teaches that its method can be applied during a conventional hydraulic fracturing treatment (Abstract).
It would have been obvious to combine a second tip strengthening fluid (second fluid) with said main treatment injection fluid, said second fluid containing a second non-dissolving solid that is larger than said first solid.
Doing so would enable one to place either buoyant or settling particles in a two-step process, where the second step is also applied during a conventional hydraulic fracturing treatment.
Regarding claim 25, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 23. Furthermore, Osiptsov teaches that a fluid can introduce buoyant and settling particles in one treatment (Abstract).
It would have been obvious to combine said first fluid and said second fluid (which may be the same fluid) for injecting step c), and to cause said first solid and said second solid to be in a 60/40 to 40/60 ratio. Doing so would enable one to save time by supplying buoyant and settling particles at once, and to mitigate upward and downward growth roughly equally.
Regarding claim 26, claim 26 is rejected for the same reasons as claim 25.
Regarding claim 27, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Furthermore, Surjaatmadja teaches including a flush stage to force proppant from prior stages out of a work string (¶55).
It would have been obvious to cause injecting step d) to comprise injecting a first pad injection followed by a proppant injection followed by a flush injection. Doing so would enable one to initiate or extend un-strengthened fractures, prop them to encourage hydrocarbon production, then clean out proppant to mitigate clogging.
Regarding claim 28, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Furthermore, Cohen describes using proppants including 40/70 mesh sand, 80/100 mesh sand, and 30/50 mesh sand (¶171).
It would have been obvious to cause the first solid to be 40/70 US mesh sand or 30/50 US mesh sand because these are common proppants.
Regarding claim 29, claim 29 is rejected for the same reasons as claim 28.
Regarding claim 31, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Furthermore, Osiptsov teaches separately placing particles that settle (see Fig. 4) and placing particles that rise (see Fig. 5), or that a fluid can introduce buoyant and settling particles in one treatment (Abstract).
It would be natural for some reservoirs to have predominantly downward growing fracture tips, or predominantly upward growing fracture tips, or to have an even amount (this is simply a partition of the possibilities of a fractured reservoir containing both upward and downward growing fractures). If the fracture tips grow mostly upward it would be reasonable to use buoyant particles; if the fracture tips grow mostly downward it would be reasonable to use settling particles; and if they grow roughly equally in both directions it would be reasonable to use both buoyant and settling particles. Therefore, it would have been obvious for:
i) said one or more fracture tip(s) to be predominantly downward growing fracture tip(s) and said first solid to be heavier than said first fluid and sink; or
ii) said one or more fracture tip(s) to be predominantly upward growing fracture tip(s) and said first solid to be lighter than said first fluid and float or be neutral buoyant; and it would have been obvious to
iii) cause said first solid to be a mix of a heavier solid that sinks and a lighter solid that floats or is neutral buoyant.
Regarding claim 32, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 23, and further teaches that said first solid and said second solid may be a mix of a heavy solid that sinks and a lighter solid that floats or is neutral buoyant (see rejection of claim 23).
Furthermore, Osiptsov teaches that a mixture of particles can be used (¶38; see also ¶7: “the particles may be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0” or “particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5.0”). A mixture could be used where the particles only float, or only settle. Additionally, Cohen teaches that multiple proppants can be injected separately, and that this is a configurable parameter which can be chosen for its effect on production (¶135).
From the above teachings, it would have been obvious to one of ordinary skill in the art practicing the invention of Cohen in view of Osiptsov and Surjaatmadja to cause said first and second solids to be either both floating or both settling and, when said one or more fracture tip(s) are predominantly downward growing fracture tip(s), cause said first solid and said second solid to be heavier than said first fluid and said second fluid, respectively, and sink; or when said one or more fracture tip(s) are predominantly upward growing fracture tip(s), to cause said first solid and said second solid to be lighter than said first fluid and said second fluid, respectively, and float or be neutral buoyant. Doing so would enable one to prevent upward fracture growth or downward fracture growth using multiple barrier particles, and to determine the effectiveness of emplacing the different kinds of barrier particles separately at different times. Finally, it would have been obvious for the second solid to be larger than the first solid for the reasons given in the rejection of claim 23 (see rejection of claim 23).
Regarding claim 33, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22, and it would have been obvious to inject a flush fluid after each of steps c) and d) for the reasons given in the rejection of claim 27 (see rejection of claim 27).
Regarding claim 34, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22, and further teaches that said method includes simulating fracture geometry and fracture extension rate in a model reservoir having characteristics of said reservoir (see the MEM described from Cohen in the rejection of claim 22; also Cohen, ¶69: “Reservoir characterization 460 may involve capturing a variety of information, such as data associated with the underground formation and developing one or more models of the reservoir…The reservoir characterization 460 may be performed such that information concerning the stimulation operation is included in pre-stimulation evaluations. Generating the MEM 462 may simulate the subterranean formation under development.” Also the microseismic mapping described in claim 22 is part of a model of the reservoir; see ¶79).
Furthermore, it would have been obvious cause the identification of said one or more fracture tip(s) that require strengthening to be based on the above simulation because the simulation provides information about fracture geometry, therefore one could identify fractures at risk of reaching undesired zones from the simulation.
Regarding claim 35, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22, and Osiptsov further teaches simulating solid settling into a fracture tip (Fig. 7 and ¶49: “The calculation shows the position of the barrier at the start of the subsequent fracture treatment. FIG. 7 shows the calculated results...When a similar treatment was modeled…the proppant was distributed throughout the fracture with the highest concentration centered (between the top and the bottom) about two thirds of the way to the tip.”). Fluids of different viscosities are simulated to determine effect (¶25: “the suitable balance between a viscosity sufficiently high to initiate and propagate a fracture and sufficiently low to allow barrier particle settling(rising) may be determined by numerical simulation” also see for example Table 3 and ¶52: “The next example illustrates the effect of the rheology of the fluid injected before the slug on the final pattern inside the fracture”).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Osiptsov with the invention of Cohen in view of Osiptsov and Surjaatmadja by simulating solid settling in said model reservoir. Doing so would enable one to estimate the effectiveness of a proposed treatment method on fracture tips of interest before performing the method.
Regarding claim 36, most of the limitations of claim 36 are found in claims 22, 23, and 35, and are rejected for the same reasons. Claim 36 also recites repeating steps a) and b) (simulating fracture geometry and extension rate to identify tips that need strengthening, and simulating solid settling) as needed to select a first tip strengthening fluid (first fluid) containing a first non-dissolving solid, and a second tip strengthening fluid (second fluid) containing a second non-dissolving solid. It would have been obvious to one of ordinary skill in the art practicing the invention of Cohen in view of Osiptsov and Surjaatmadja to do so in order to estimate the effectiveness of multiple treatment methods on fracture tips of interest before choosing the most promising treatment method.
Regarding claims 37 and 38, these claims are rejected for the same reasons as given in the rejection of claim 32.
Regarding claim 39, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 36. Furthermore, it would have been obvious to combine said first fluid and said second fluid where said first and second solids are a mix of dense solids that sink and less dense solids that float or are neutral buoyant for the reasons given in the rejection of claim 25 (see the rejection of claim 25).
Regarding claim 40, claim 40 is rejected for the same reasons as claim 24.
Regarding claim 41, claim 41 is rejected for the same reasons as claim 25.
Regarding claim 42, the limitations of claim 42 are found in claims 22 and 36, therefore claim 42 is rejected for the same reasons.
Claim 30 is rejected under 35 U.S.C. 103 as being unpatentable over Cohen (US 20130140031 A1) in view of Osiptsov (US 20110272159 A1) and Surjaatmadja (US 20060102344 A1), and further in view of Nguyen (US 20180127643 A1).
Regarding claim 30, Cohen in view of Osiptsov and Surjaatmadja teaches the limitations of claim 22. Furthermore, it would have been obvious to pump proppant with said main treatment injection fluid for the same reasons as given in the rejection of claim 27 (see rejection of claim 27), and to cause said proppant to be 100 US mesh sand for the same reasons as given in the rejection of claim 28 (see rejection of claim 28).
Cohen in view of Osiptsov and Surjaatmadja does not explicitly teach that the sand is injected at 0.5 lbm/gal concentration.
Nguyen discloses methods of treating a subterranean formation having a vertically oriented fracture with a treatment fluid comprising proppant (Abstract). Nguyen describes including proppant in a treatment fluid in a range including 0.5 lbm/gal (¶49).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Nguyen with the invention of Cohen in view of Osiptsov and Surjaatmadja by pumping at 0.5 lbm/gal concentration because this is a known concentration of proppant to use in a treatment fluid.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure. Brannon (US 20070193746 A1) controls fracture height using proppant (Abstract).
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ETHAN WESLEY EDWARDS
Examiner
Art Unit 2857
/E.W.E./ Examiner, Art Unit 2857
/LINA CORDERO/ Primary Examiner, Art Unit 2857
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