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 .
Response to Arguments
Applicant’s arguments filed 27 October, 2025, have been fully considered. Claims 1-21 have been canceled and claims 22-42 have been added. Claims 22-42 largely recite similar limitations as claims 1-21.
Applicant’s efforts to amend the claims to address objections to the claim language have been considered and are persuasive, therefore all objections to the claims have been dropped. Note the examiner’s mistake in the previous office action listing claim objections under the heading “Specification”.
Applicant’s efforts to address the 112(b) rejections have been considered. Most issues have been adequately addressed, however an issue remains. See 112(b) rejections below.
Applicant’s efforts to address the 112(d) rejections are satisfactory, therefore all 112(d) rejections are dropped.
Applicant’s arguments that the claims are distinguished over the prior art of record have been considered.
The applicant argues that Earl does not teach strengthening fractures because Earl uses diverting agents, and that there is no evidence that diverting agents strengthen fractures.
In ¶27 of the applicant’s specification, the applicant describes fracture tip strengthening as injecting fluid into the fracture so it will settle in the tip or end of the fracture to control unwanted fracture propagation. Since Earl’s diverting agent controls unwanted upward vertical fracture propagation (Col. 2, lines 33-64: “…extending the fracture with a second fluid comprising a carrier fluid and an inert, bouyant [sic], inorganic, diverting agent in an amount sufficient to inhibit or prevent the growth of an upward vertical fracture. The second fluid…[carries] the diverting agent into the fracture…[permitting] the diverting agent to accumulate in the upper portion of the fracture and form a compacted barrier zone which is capable of diverting subsequently injected fluids downwardly and horizontally”), the examiner considers Earl to teach fracture strengthening.
Furthermore, the applicant argues that because Earl forces fracture extension, Earl cannot teach fracture strengthening. The examiner disagrees with this conclusion; if a fracture is extended at some point in the fracture strengthening process, it does not mean that the entire process cannot result in a strengthened fracture. The result of Earl’s process is to inhibit or prevent upward growth of vertical fractures, so fracture strengthening does occur.
The applicant argues that if, during Earl’s injection process, a fracture is extended, then Earl cannot teach injecting a strengthening agent such that a log-log of pressure over time has positive slope. The examiner disagrees with this conclusion. As argued above, a fracture may be extended at some point and strengthened as the process continues. The injection process taught by Earl is not instantaneous, therefore the rate of injection and the pressure in time may vary. If at any point the injection at the first rate is such that a log-log of pressure over time is positive, this would satisfy the claim language. The examiner considers it reasonable that such a condition would occur, for example once sufficient diverting agent has been emplaced and subsequent fluid is being diverted from the upper portion of the fracture (see Col. 2, lines 33-64 of Earl above). As for the interpretation of the slope of a log-log plot, if a function’s slope on a log-log plot is positive at some point, so is its slope on a linear plot (a positive slope of
f
(
x
)
on a log-log plot means that an infinitesimally positive step in
x
results in an increase in
f
(
x
)
, and this would remain true in a linear plot).
The examiner relies upon Suarez-Rivera merely to provide a reference suggesting that fracture propagation acts to decrease pressure because it increases the volume of the container into which fluid may be injected. If one injects fluid carrying solid into a fracture and wishes to pack the solid into a fracture tip, it would be reasonable to provide increasing pressure in order to pack the solid tightly (Pascal’s law suggests that a pressure change is communicated throughout a fluid, so one of ordinary skill in the art would be motivated to increase pressure in order to pack solid more tightly into a fracture tip). If pressure is increasing, it suggests that the fracture is not propagating and therefore that solid is being packed more tightly into a fracture tip, strengthening its “barrier zone” (see Col. 2, lines 33-64 of Earl).
The applicant argues that no mention of fracture tips are made. The examiner agrees that Earl does not explicitly disclose injecting fluid or diverting agent into fracture tips. Earl does disclose inhibiting the growth of upward vertical fractures by emplacing buoyant diverting agent into the fracture. Since the tip of a vertically-growing fracture is the highest point of the fracture, and since the diverting agent is buoyant, the examiner concluded that the diverting agent would naturally be emplaced in the fracture tips, and that the fracture tips would therefore be strengthened (i.e. unwanted fracture propagation would be controlled or prevented).
The applicant argues that Kresse does not mention fracture extension rate. The examiner agrees. Rather, Kresse teaches that its UFM model accounts for the length of a fracture at a given time,
l
(
t
)
(see ¶55 of Kresse). A fracture extension rate would be the time derivative of
l
(
t
)
, that is,
d
l
/
d
t
. The examiner considers that it would have been obvious to one of ordinary skill in the art practicing the invention of Kresse to calculate fracture extension rate as Kresse is interested in simulating fracture network propagation (see ¶54) and calculating the rate of change is useful for understanding propagation.
The applicant argues that Kresse does not mention tip strengthening. The examiner agrees but notes that the primary reference, Earl, is interested in tip strengthening as argued above. Finally, the applicant further argues that Kresse does not identify fracture tips in need of strengthening. Again, the examiner considers that motivation to be from Earl, which would be interested in using Kresse’s simulation to identify fracture tips in need of strengthening.
Finally, the amendments have necessitated new grounds of rejection. See 103 rejection below.
Claim Rejections - 35 USC § 112
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.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
Claims 36-41 are rejected under 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph, as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor (or for applications subject to pre-AIA 35 U.S.C. 112, the applicant), regards as the invention.
Claim 36: in step e), the first instance of “said one or more fracture tip(s)” has insufficient antecedent basis, as previous references to fracture tips refer to “one or more simulated fracture tip(s)”; the examiner assumes that the applicant intends here to drop “said”.
Claims 37-41 depend from claim 36, therefore they inherit the issues of claim 36 and are rejected for the same reasons.
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 22 is rejected under 35 U.S.C. 103 as being unpatentable over Earl et al (US 4509598 A) in view of Kresse et al (US 20140305638 A1) and Suarez-Rivera et al (US 20130140020 A1).
Regarding claim 22, Earl discloses a method of stimulating a reservoir for increased production of hydrocarbons (Abstract: fracture fluid is used to complete a fracturing process; Col. 1, lines 17-19: the field is hydrocarbon extraction), said method comprising:
injecting a fracture fluid into a well in said reservoir to initiate one or more fractures in said well (Col. 2, Summary of the Invention, ¶1: the method includes “(1) initiating the fracture with a first fluid”);
injecting a first tip strengthening fluid (first fluid) containing a first non-dissolving solid into said well at a first rate (Col. 2, lines 33-64: the method includes “(2) extending the fracture with a second fluid comprising a carrier fluid and an inert, bouyant [sic], inorganic, diverting agent in an amount sufficient to inhibit or prevent the growth of an upward vertical fracture.” Cols. 3, line 60 – Col. 4, line 19: “The diverting agent used herein is likewise selected from a known class of particulate materials, any one (or mixture) of which can be used herein. Preferred materials are glass or ceramic spheres” which are non-dissolving), such that said one or more fracture tip(s) are strengthened by depositing said first non-dissolving solid into said one or more fracture tip(s) (Col. 2, lines 33-64: “The second fluid…[carries] the diverting agent into the fracture…[permitting] the diverting agent to accumulate in the upper portion of the fracture and form a compacted barrier zone which is capable of diverting subsequently injected fluids downwardly and horizontally.”); and
injecting a main treatment injection fluid at a second rate (Col. 2, lines 33-64: “The fracturing process is then continued by subsequently injecting a viscous pad fluid and a proppant-bearing or acid fracturing fluid at fracture rates and pressure to extend the fracture.”).
Earl does not explicitly disclose that the well comprises stages. However, Kresse teaches that multi-stage stimulation may be used in unconventional reservoirs (i.e. reservoirs where oil and gas are tightly bound to the rock) (¶41: “multi-stage stimulation may be the norm for unconventional reservoir development”). Therefore, it would have been obvious to one of ordinary skill in the art to use this method in a staged fracturing of an unconventional reservoir. Considering this, it would have been obvious to repeat steps a)-d) for each stage of a well to perform the method over the whole extraction region. Finally, it would have been obvious to produce hydrocarbons from the well as this is the purpose of performing hydraulic fracturing.
In light of the above arguments, Earl does not explicitly disclose b) determining a fracture extension rate and a primary fracture geometry and identifying one or more fracture tip(s) that require strengthening.
Kresse discloses a method of performing a fracture operation (Abstract). As part of this operation, Kresse discloses simulating fracture geometry using a computer model (¶31: “An unconventional fracture model (UFM) (or complex model) may be used to simulate complex fracture network propagation in a formation with pre-existing natural fractures.”). The UFM model simulates fracture extension (under “UFM Model Description”, ¶55: “The fracture tips propagate as a sharp front, and the length of the hydraulic fracture at any given time t is defined as l(t).” Note that while fracture extension rate dl/dt is not explicitly recited, the UFM model simulates propagation, implying an interest in understanding the rate of change of fracture length.).
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 Kresse with the invention of Earl by using a fracture model to determine a fracture extension rate and a primary fracture geometry and identify one or more fracture tip(s) that require strengthening. Doing so would aid one in determining where crack growth prevention or mitigation may be important.
Earl in view of Kresse does not explicitly teach: c) injecting a first tip strengthening fluid (first fluid) containing a first non-dissolving solid into said stage at a first rate such that a slope of a log-log plot of net pressure versus time is positive; and e) injecting a main treatment injection fluid at a second rate that does not exceed said first rate once it is determined from injection pressure diagnostics that said one or more fracture tip(s) are strengthened and fracture vertical growth is contained during said injecting.
Suarez-Rivera provides a method for increasing fracture area (Abstract). Suarez-Rivera teaches that pressure reduction over time “is in line with the behavior of [a] growing fracture in the absence of discontinuities” (¶54).
In light of the teachings of Suarez-Rivera, it would have been obvious to one of ordinary skill in the art to inject the first tip strengthening fluid at a first rate such that a slope of a log-log plot of net pressure versus time is positive. Pressure decreasing with time would suggest a leak or growing fracture, which is undesirable. Pressure increasing with time would suggest no leaking or fracture growth, which is desirable for one packing solid particulates into fracture tips. Considering this, it would have been obvious to inject the main treatment injection fluid once it is determined from injection pressure diagnostics that said one or more fracture tip(s) are strengthened and fracture vertical growth is contained during said injecting. Injecting the main treatment fluid without first determining that the one or more fracture tip(s) are strengthened would invite risk of unwanted vertical fracture.
Finally, Earl discloses that a “third fluid” may be injected after a second fluid, the second fluid being the one containing buoyant diverting agent, and teaches: “Usually, the injection rate and pressure is chosen to be essentially the same for the second and third fluids as a matter of operating convenience” (Col. 2, lines 33-64). Considering this teaching, it would have been obvious to inject the main treatment injection fluid at a second rate that does not exceed said first rate. Doing so would be useful for avoiding exceeding the highest tested pressure for which crack growth does not occur, and it would also be convenient for operations.
Claims 23-26, 31-32, and 34-42 are rejected under 35 U.S.C. 103 as being unpatentable over Earl (US 4509598 A) in view of Kresse (US 20140305638 A1) and Suarez-Rivera (US 20130140020 A1) and Osiptsov et al (US 20110272159 A1).
Regarding claim 23, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22.
Osiptsov teaches a method of hydraulic fracturing which may prevent upward and downward vertical growth (Abstract: “A method is given for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom”). This includes injecting a fluid containing “barrier particles” which may either float or settle to form a barrier (¶7). The particles used may be proppant (¶38: “particles used in the oilfield as a proppant…may be used as the barrier particles. Mixtures of particles may be used…for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres.”). Osiptsov teaches that one may wish to prevent downward growth to avoid a water zone below a reservoir (¶2).
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 Earl in view of Kresse and Suarez-Rivera by injecting 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). By doing so, one may also inject settling particles into the stage of the well to prevent undesirable downward growth, such as to avoid an underlying water zone.
There is no particular teaching which suggests 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 36, many limitations of claim 36 are found in claims 22 and 23 and are rejected for the same reasons. As for the remaining limitations, in the rejection of claim 22 it was stated that Kresse discloses simulating fracture geometry in a model reservoir having characteristics of said reservoir (¶31: “An unconventional fracture model (UFM) (or complex model) may be used to simulate complex fracture network propagation in a formation with pre-existing natural fractures.”). 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 Kresse with the invention of Earl in view of Kresse and Suarez-Rivera by simulating fracture geometry and fracture extension rate in a model reservoir having characteristics of a reservoir to identify one or more simulated fracture tip(s) that require strengthening. Doing so would aid one in determining where crack growth prevention or mitigation may be important.
Earl in view of Kresse and Suarez-Rivera does not explicitly disclose simulating solid settling into said one or more simulated fracture tip(s) in said model reservoir.
Osiptsov discloses a method “for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom” (Abstract). As part of the invention, Osiptsov discloses simulating solid settling into a fracture tip (¶38: “particles used in the oilfield as a proppant…may be used as the barrier particles. Mixtures of particles may be used…for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres.” 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 Earl in view of Kresse and Suarez-Rivera by simulating solid settling into said one or more simulated fracture tip(s) in said model reservoir; then repeating steps a) and b) 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. Doing so would enable one to estimate the effectiveness of a proposed treatment method on the fracture tips of interest before performing the method.
Regarding claim 42, the limitations of claim 42 are found in claims 22 and 36, therefore claim 42 is rejected for the same reasons.
Regarding claim 24, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22. Furthermore, it would have been obvious to inject a second tip strengthening fluid (second fluid), said second fluid containing a second non-dissolving solid that is larger than said first solid, for the reasons given in the rejection of claim 23 (see rejection of claim 23). Furthermore, as shown in the rejection of claim 22, Earl discloses injecting a “viscous pad fluid and a proppant-bearing” fluid as the main treatment injection fluid. Osiptsov teaches that the barrier particles used to prevent upward or downward growth may be proppant (¶38). Therefore, 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 Earl and Osiptsov with the invention of Earl in view of Kresse and Suarez-Rivera and Osiptsov by combining said second tip strengthening fluid with said main treatment injection fluid. Doing so would be more convenient as, for example, one may use one fluid to deposit proppant into downward growing fractures and prevent downward growth, then use the same fluid as part of a main treatment to cause horizontal crack growth.
Regarding claim 40, Earl in view of Kresse and Suarez-Rivera and Osiptsov teaches the limitations of claim 36. Furthermore, it would have been obvious to combine said second fluid and said main treatment injection fluid for the reasons given in the rejection of claim 24 (see rejection of claim 24).
Regarding claim 25, Earl in view of Kresse and Suarez-Rivera and Osiptsov teaches the limitations of claims 23. Furthermore, it would have been obvious to combine said first and second fluids for injecting step c) and said first solid and second solid to be in a 60/40 to 40/60 ratio. Injecting both fluids at once saves time, and introducing both solids at roughly a 1:1 ratio would strengthen the upper and lower fractures roughly equally, which would be natural to do absent knowledge that either the upper or lower fractures require more strengthening relative to the other.
Regarding claim 41, the limitations of claim 41 would have been obvious for the reasons given in the rejection of claim 25.
Regarding claim 26, the limitations of claim 26 would have been obvious for the reasons given in the rejection of claim 25.
Regarding claim 31, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22. Furthermore, Earl discloses that said first solid is lighter than said first fluid and floats or is neutral buoyant (Col. 2, lines 33-64: the method includes “(2) extending the fracture with a second fluid comprising a carrier fluid and an inert, bouyant [sic], inorganic, diverting agent in an amount sufficient to inhibit or prevent the growth of an upward vertical fracture.”).
Earl in view of Kresse and Suarez-Rivera does not explicitly teach the remaining limitations of claim 31.
Osiptsov teaches a method of hydraulic fracturing which may prevent upward and downward vertical growth (Abstract: “A method is given for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom”). This includes injecting a fluid containing “barrier particles” which may either float or settle to form a barrier (¶7). The particles used may be proppant (¶38: “particles used in the oilfield as a proppant…may be used as the barrier particles. Mixtures of particles may be used…for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres.”). Osiptsov teaches that one may wish to prevent downward growth to avoid a water zone below a reservoir (¶2).
Furthermore, while Earl in view of Kresse and Suarez-Rivera does not explicitly teach that said one or more fracture tip(s) are predominantly downward or upward growing fracture tip(s), it would be reasonable to suppose that in some fracking situations the fracture tip(s) would be predominantly upward growing, in others the fracture tip(s) would be predominantly downward growing, and in still other situations the fracture tips would be relatively balanced between upward and downward growing. Therefore, in some situations one may wish primarily to prevent downward growth, and in others one may wish to prevent upward growth.
Therefore, 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 Earl in view of Kresse and Suarez-Rivera by causing the method of claim 23 to:
when said one or more fracture tip(s) are predominantly downward growing fracture tip(s), cause said first solid to be heavier than said first fluid and sink; or
when said one or more fracture tip(s) are predominantly upward growing fracture tip(s), cause said first solid to be lighter than said first fluid and float or be neutral buoyant; or
cause said first solid to be a mix of a heavier solid that sinks and a lighter solid that floats or is neutral buoyant.
By doing so, one may inject settling or rising particles, as needed, to prevent undesirable downward or upward growth, or both. Taking steps to prevent downward growth would be useful to avoid leaking into an underlying water zone, for example.
Regarding claim 32, Earl in view of Kresse and Suarez-Rivera and Osiptsov teaches the limitations of claim 23. As argued in the rejection of claim 31, it would be reasonable to suppose that in some fracking situations the fracture tip(s) would be predominantly upward growing, in others the fracture tip(s) would be predominantly downward growing, and in still other situations the fracture tips would be relatively balanced between upward and downward growing. Furthermore, Osiptsov teaches that one may wish to prevent only upward growth, or only downward growth (Abstract: “A method is given for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom”). In the rejection of claim 23 the second fluid and second solid were identified with Osiptsov’s fluid and barrier particles. Therefore, 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 Earl in view of Kresse and Suarez-Rivera and Osiptsov by:
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), 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; or
cause said first solid and said second solid to be a mix of a heavy solid that sinks and a lighter solid that floats or is neutral buoyant.
It would be useful for both solids to sink when wishing only to prevent downward fracture growth; for both solids to float or be neutral buoyant when wishing only to prevent upward fracture growth; or to have a mix when wishing to prevent both upward and downward fracture growth.
Regarding claims 34 and 35, the limitations of claims 34 and 35 are found in claim 36 and are rejected for the same reasons.
Regarding claims 37 and 38, these claims are rejected for the same reasons as given in the rejection of claim 32 (see rejection of claim 32), noting that claims 37 and 38 depend from claim 36 which simulates fractures in a model and selects one or more simulated fracture tip(s) that require strengthening.
Regarding claim 39, it would have been obvious to cause the first and second solids to be a mix of dense solids that sink and less dense solids that float or are neutral buoyant for the same reasons as given in the rejection of claim 32 (see rejection of claim 32). Furthermore, it would have been obvious to combine said first fluid and said second fluid in order to save time (see rejection of claim 25).
Claims 27 and 33 are rejected under 35 U.S.C. 103 as being unpatentable over Earl (US 4509598 A) in view of Kresse (US 20140305638 A1) and Suarez-Rivera (US 20130140020 A1), and further in view of Tang et al (US 20140144638 A1).
Regarding claim 27, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22. Earl further discloses that injecting said main treatment injection fluid (step d) in claim 22) comprises a first pad injection followed by a proppant injection (Col. 2, lines 33-64: “The fracturing process is then continued by subsequently injecting a viscous pad fluid and a proppant-bearing or acid fracturing fluid at fracture rates and pressure to extend the fracture.”).
Earl does not explicitly disclose injecting a final flush injection.
Tang teaches that “The presence of unconsolidated particulates in a formation during production is undesirable because they may damage or abrade producing equipment or reduce well production. For example, unconsolidated particulates may migrate into wellbore casings, perforations, or the interstitial spaces between packed proppants within a fracture and clog or hinder well production” (¶3). Tang further teaches that “post-flush fluid may facilitate removal of excess treatment fluid from the pore spaces in the subterranean formation and/or to reduce permeability loss between consolidated particulates (e.g., between the interstitial spaces between the unconsolidated particulates that have been consolidated)” (¶26).
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 Tang with the invention of Earl in view of Kresse and Suarez-Rivera and Osiptsov by following up the first pad injection followed by a proppant injection with a final flush injection in order to reduce permeability loss and remove excess treatment fluid.
Regarding claim 33, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22 but does not teach the limitations of claim 33
Tang teaches that “The presence of unconsolidated particulates in a formation during production is undesirable because they may damage or abrade producing equipment or reduce well production. For example, unconsolidated particulates may migrate into wellbore casings, perforations, or the interstitial spaces between packed proppants within a fracture and clog or hinder well production” (¶3). Tang further teaches that “post-flush fluid may facilitate removal of excess treatment fluid from the pore spaces in the subterranean formation and/or to reduce permeability loss between consolidated particulates (e.g., between the interstitial spaces between the unconsolidated particulates that have been consolidated)” (¶26).
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 Tang with the invention of Earl in view of Kresse and Suarez-Rivera and Osiptsov by causing a fluish fluid to be injected after each of steps c) and e) in order to reduce permeability loss and remove excess treatment fluid.
Claims 28 and 29 are rejected under 35 U.S.C. 103 as being unpatentable over Earl (US 4509598 A) in view of Kresse (US 20140305638 A1) and Suarez-Rivera (US 20130140020 A1) and Osiptsov (US 20110272159 A1), and further in view of Cohen (US 20130140031 A1).
Regarding claim 28, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22, but does not teach the limitations of claim 28.
Osiptsov discloses a method “for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom” (Abstract). As part of the invention, Osiptsov discloses using sand as a solid for strengthening fracture tips (Abstract: “a higher-viscosity fluid containing barrier particles is then injected; a lower-viscosity particle-free fluid is then injected to promote settling (or rising) of the barrier particles”; ¶38: “particles used in the oilfield as a proppant…may be used as the barrier particles. Mixtures of particles may be used…for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres.”).
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 Earl in view of Kresse and Suarez-Rivera by using sand as the first solid in order to prevent or mitigate the downward growth of fracture tips.
Earl in view of Kresse and Suarez-Rivera and Osiptsov does not explicitly teach what mesh sand the first solid is.
Cohen describes a method of stimulating a well during a hydraulic fracturing operation (Abstract). 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 one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Cohen with the invention of Earl in view of Kresse and Suarez-Rivera and Osiptsov by causing the first solid to be 40/70 US mesh sand or 30/50 US mesh sand, because these are common proppants.
Regarding claim 29, Earl in view of Kresse and Suarez-Rivera and Osiptsov teaches the limitations of claim 23, but does not teach the limitations of claim 29. However, as given in the rejection of claim 23, the second non-dissolving solid may be sand (Osiptsov, ¶38: “particles used in the oilfield as a proppant…may be used as the barrier particles. Mixtures of particles may be used…for example, sand”).
Cohen describes a method of stimulating a well during a hydraulic fracturing operation (Abstract). 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 one of ordinary skill in the art before the effective filing date of the invention to incorporate the teachings of Cohen with the invention of Earl in view of Kresse and Suarez-Rivera and Osiptsov by causing the second solid to be 100 US mesh sand, because this is a common proppant.
Claim 30 is rejected under 35 U.S.C. 103 as being unpatentable over Earl (US 4509598 A) in view of Kresse (US 20140305638 A1) and Suarez-Rivera (US 20130140020 A1) and Cohen (US 20130140031 A1), and further in view of Nguyen et al (US 20180127643 A1).
Regarding claim 30, Earl in view of Kresse and Suarez-Rivera teaches the limitations of claim 22. Earl further discloses pumping 100 US mesh sand with said main treatment injection fluid (Col. 5, lines 45-63: in an experiment, after a first pad fluid, a second fluid, and a third fluid, a “viscous aqueous pad fluid” was injected with 100 mesh sand; the pad fluid and fracture fluid are part of the main treatment injection fluid; see rejection of claim 22).
Earl in view of Kresse and Suarez-Rivera does not explicitly disclose pumping 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 Earl in view of Kresse and Suarez-Rivera 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.
Todd (US 20110005753 A1) teaches injecting proppant into a fracture tip (Abstract), showing that it is known in the art to emplace proppant in a fracture tip.
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
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ETHAN WESLEY EDWARDS
Examiner
Art Unit 2857
/E.W.E./Examiner, Art Unit 2857
/ANDREW SCHECHTER/Supervisory Patent Examiner, Art Unit 2857
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