f)...contacting a target zone within the subterranean formation with the treatment composition,...
TRANSCRIPT
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
9. (original) The method of claim 1, wherein a portion of the wellbore is deviated or
horizontal.
10. (original) The method of claim 1, further comprising repeating act e).
11. (original) The method of claim 1, further comprising repeating act a) and b) prior to
repeating acts c) through d).
12. (original) The method of claim 1, wherein the diversion agent consists of non-
degradable material.
13. (original) The method of claim 10, wherein the diversion agent is stored in the coiled
tubing between acts of introducing the diversion agent to an interval.
14. (currently amended) A method of treating more than one target zone of interest in a
subterranean formation, the method comprising:
a) pumping a treatment composition to contact at least one target zone of interest with
the treatment composition;
b) monitoring the pumping of the treatment composition and measuring a parameter
indicative of treatment;
c) pumping a diversion agent to a desired diversion interval in the well bore;
d) monitoring the pumping of the diversion agent and measuring a parameter indicative
of diversion wherein measuring comprises measuring microseismic activity;
e) pumping a treatment composition to contact at least one other target zone of interest;
f) modifying at least one of acts a) and c) based on at least one of the measured
parameters.
15. (original) The method of claim 14, wherein at least a portion of the wellbore
comprises a generally deviated or horizontal section.
16. (original) The method of claim 14, wherein at least one of the diversion interval and
the target zone of interest are located within said generally horizontal section.
17. (original) The method of claim 14, further comprising repeating acts a) through d).
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18. (original) The method of claim 14, further comprising injecting the treatment
composition in the annulus between a coiled tubing and the wellbore.
19. (canceled)
20. (previously presented) The method of claim 14, wherein the diversion agent
comprises a fiber, the fiber comprising a degradable material.
21. (currently amended) A method of treating a well, comprising:
a) deploying coiled tubing into a wellbore, wherein connectivity is established by one or
more of perforating, jetting, sliding sleeve, or opening a valve, and establishing fluid
connectivity between a wellbore and at least one target zone for treatment within a subterranean
formation intersected by the wellbore;
b) injecting a treatment composition into the wellbore to contact a hydrocarbon bearing
subterranean formation with the treatment composition;
c) providing a diversion agent through the coiled tubing to a desired interval in the
well bore;
d) measuring a wellbore parameter while performing at least one of act b) or act c ).,
wherein the act of measuring comprises measuring microseismic activity.
22-23. (canceled)
24. (canceled)
25-26. (canceled)
27. (currently amended) The method of claim 21, further comprising modifying at least
one of the act of providing a diversion and the act of injecting a treatment composition based on
the measured wellbore parameter.
28. (currently amended) A method of treating a well, comprising:
a) measuring a wellbore parameter to establish a baseline;
b) providing a diversion agent through the coiled tubing to a desired interval in the
well bore;
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c) injecting a treatment composition into the wellbore to contact a target zone in a
subterranean formation with the treatment composition; and
d) measuring the well bore parameter while performing at least one of act b) and act c)
wherein measuring comprises measuring microseismic activity.
29-32. (canceled)
33. (currently amended) A method of well treatment, comprising:
a) establishing fluid connectivity between a wellbore and at least one target zone for
treatment within a subterranean formation intersected by the wellbore;
b) deploying coiled tubing into the wellbore;
c) introducing a treatment composition into the wellbore;
d) contacting a target zone within the subterranean formation with the treatment
composition;
e) introducing a diversion agent through an annulus formed between the wellbore and the
coiled tubing to an interval within the wellbore and measuring a wellbore parameter wherein
measuring comprises measuring microseismic activity; and
repeating steps c) through e) for more than one target zone.
34. (currently amended) A system usable with a well, comprising:
a tubing string;
a treatment fluid source to communicate a treatment composition in the well to contact a
hydrocarbon bearing subterranean formation with the treatment composition; tHttl
a diversion agent source to communicate a diversion agent through the tubing string into
an interval of the well and
microseimic equipment to measure a wellbore parameter.
35-52. (canceled)
53. (currently amended) A method, comprising:
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establishing fluid connectivity between a wellbore and a first target zone, and between
the wellbore and a second target zone, wherein the first target zone and second target zone
comprise zones for treatment within a subterranean formation intersected by a wellbore;
positioning a coiled tubing into the wellbore;
performing a first treatment step on the first target zone, wherein the first treatment step
comprises contacting a treated zone with a treatment fluid;
performing a second treatment step on the first target zone, wherein the second treatment
step comprises introducing a diversion agent comprising a degradable material to the treated
zone;
performing the first treatment step on the second target zone; afttl
degrading the diversion agent after the performing the first treatment step on the second
target zone; and
measuring a wellbore parameter wherein measuring comprises measuring microseismic
activity.
54. (previously presented) The method of claim 53, further comprising establishing fluid
connectivity with at least one additional target zone, the method further comprising performing
the second treatment step on the second target zone, and successively treating each additional
target zone except a final target zone by performing the first treatment step and the second
treatment step on each additional target zone, and treating the final target zone by performing the
first treatment step on the final target zone.
55. (previously presented) The method of claim 54, wherein establishing fluid
connectivity with at least one additional target zone comprises performing a perforation
operation on the at least one additional target zone after performing the treatment step on the first
target zone and before removing the coiled tubing from the wellbore.
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56. (previously presented) The method of claim 54, wherein the first target zone, second
target zone, and additional target zones are treated in an order from a lowest in-situ stress to a
highest in-situ stress.
57. (previously presented) The method of claim 54, wherein the first target zone, second
target zone, and additional target zones are treated in an order from a top zone to a bottom zone.
58. (previously presented) The method of claim 53, wherein the second target zone is
above the first target zone.
59. (previously presented) The method of claim 53, wherein the diversion agent is
stored in the coiled tubing between acts of introducing the diversion agent to an interval.
60. (previously presented) The method of claim 53, further comprising measuring a
parameter indicative of diversion.
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Page 205 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
REMARKS
These remarks are submitted in response to the office action mailed February 4, 2009.
Claims 1-18, 20, 21, 24, 27, 28, 33, 34, and 53-60 are pending and rejected. Claims 1, 14, 21,
28, 33, 34, 53 are amended.
Claims 53-60 are rejected under 35 U.S.C. 112, first paragraph, as failing to comply with
the written description requirement. Specifically, the Examiner indicates the phrase, "degrading
the diversion agent after the performing the first treatment step on the second target zone" as
recited in pending claim 53 is not supported by the specification. Support for claim 53 is found
in Figures 2 and 3 and in the specification at paragraphs [0024] and [0046]-[0049] of the
published application. Withdrawal of the rejection is respectfully requested.
Claims 1, 3, 4, 8, 10-12, 33, and 34 are rejected under 35 U.S.C. § 102(b) as being
anticipated by United States Patent Application Publication Number 2003/0119680 (Chang).
Applicants respectfully traverse the rejection. Claims 1, 33, and 34 are amended. Chang uses
coiled tubing merely to provide stimulating and diverting fluid in one step (see paragraph
[0020]). The Examiner has not provided any substantive analysis or additional reference to
support extending Chang to encompass the pending claim limitations. Chang does not describe
deploying coiled tubing into the wellbore, introducing a treatment composition into the wellbore,
contacting a target zone within the subterranean formation with the treatment composition,
introducing a diversion agent through the coiled tubing to an interval within the wellbore, and
repeating steps for more than one target zone as recited in claim 1 and claims dependent thereon.
Further, Chang does not describe contacting a target zone within the subterranean formation with
the treatment composition; introducing a diversion agent through an annulus formed between
the wellbore and the coiled tubing to an interval within the wellbore; and repeating steps for
more than one target zone as recited in claim 33 and claim 34 dependent thereon. Withdrawal of
the rejection is respectfully requested.
Claims 1-7, 9-11, 13-18, 20, 21, 24, 27, 28, 33, 34, 53, 54, 59, and 60 are rejected under
35 USC 102(b) as being anticipated by United States Patent Application Publication Number
2003/0106690 (Boney). Applicants respectfully traverse the rejection. Claims 1, 14, 21, 28, 33,
34, and 53 are amended. Boney does not describe introducing a diversion agent through the
coiled tubing to an interval within the wellbore as recited in the pending claims. Boney discloses
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"these methods can also be used as a form of diversion." Paragraph [0024], lines 28-29. Boney
requires inducing a screenout during a fracture treatment at a desired time and location. See
Abstract, paragraph 0026 lines 30-36. When the methods in Boney are practiced as a form of
diversion, the pressure induced in the fracture due to the screenout causes the diversion. That is,
Boney describes no "diversion agent" introduced through the coiled tubing as recited in pending
claim 1. Independent claims 14, 21, 33, 34, and 53 and claims dependent thereon are also
allowable for at least the reasons stated above related to claim 1. Withdrawal of the rejection is
respectfully requested.
Claims 55-58 are rejected under 35 U.S.C. § 103(a) as being unpatentable over Boney.
Applicants respectfully traverse the rejection. Independent claim 53 is amended. The Examiner
indicates that Boney does not describe the order that its zones receive treatment. Further, as
described above in more detail, Boney does not describe introducing a diversion agent as recited
in the independent claim 53 and claims 55-58 dependent thereon. The Examiner has not
provided substantive analysis or a reference to support the extension of Boney's teachings to
encompass the pending claim limitations. Withdrawal of the rejection is respectfully requested.
In summary, for the reasons and amendments detailed above, it is submitted that all
claims now presented in the application are in condition for allowance, and accordingly, such
action is respectfully requested. If the Examiner believes that the prosecution of the application
would be facilitated by a telephone interview, Applicants invite the Examiner to contact the
undersigned at 281-285-4925. No additional fees other than those authorized in the enclosed
request for continued examination are believed to be due. However, the Commissioner is hereby
authorized to charge any fees that may be required, or credit any overpayment, to Deposit
Account No. 04-1579 (56.0967).
Date: November 20, 2009
Respectfully Submitted,
Rachel E. Greene Attorney for Applicants Reg. No. 58,750
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/Rachel E. Greene/
Page 207 of 399Halliburton Energy Services, Inc.
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
SCHLUMBERGER TECHNOLOGY CORPORATION 555 Industrial Blvd. Sugar Land, Texas 77478 281.285 .4925
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Page 208 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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PTO/SB/06 (07-06) Approved for use through 1/31/2007. OMB 0651-0032
U.S. Patent and Trademark Office; U.S. DEPARTMENT OF COMMERCE Under the Paperwork Reduction Act of 1995, no persons are required to respond to a collection of information unless it displays a valid OMB control number.
PATENT APPLICATION FEE DETERMINATION RECORD Application or Docket Number Filing Date Substitute for Form PT0-875 11/751,172 05/21/2007 D To be Mailed
APPLICATION AS FILED - PART I OTHER THAN (Column 1) (Column 2) SMALL ENTITY D OR SMALL ENTITY
FOR NUMBER FILED NUMBER EXTRA RATE($) FEE($) RATE($) FEE($)
D BASIC FEE N/A N/A N/A N/A (37CFR1.16(a), (b), or (c))
D SEARCH FEE (37CFR1.16(k), (i), or (m)) N/A N/A N/A N/A
D EXAMINATION FEE (37CFR1.16(0), (p), or (q))
N/A N/A N/A N/A
TOTAL CLAIMS * x $ = OR x $ = (37 CFR 1.16(i)) minus 20 =
INDEPENDENT CLAIMS * x $ = x $ = (37 CFR 1.16(h)) minus 3 =
If the specification and drawings exceed 100
0APPLICATION SIZE FEE sheets of paper, the application size fee due is $250 ($125 for small entity) for each
(37 CFR 1.16(s)) additional 50 sheets or fraction thereof. See 35 U.S.C. 41 (a)(1)(G) and 37 CFR 1.16(s).
D MULTIPLE DEPENDENT CLAIM PRESENT (37 CFR 1.16U)) * If the difference in column 1 is less than zero, enter "O" in column 2. TOTAL TOTAL
APPLICATION AS AMENDED- PART II OTHER THAN
(Column 1) (Column 2) (Column 3) SMALL ENTITY OR SMALL ENTITY
CLAIMS HIGHEST
11/20/2009 REMAINING NUMBER PRESENT RATE($) ADDITIONAL RATE($) ADDITIONAL I- AFTER PREVIOUSLY EXTRA FEE($) FEE($) z AMENDMENT PAID FOR w
Total (37 CFR ~ 1.16(i)) * 32 Minus ** 52 = 0 x $ = OR x $52= 0 0 Independent z * 7 Minus ***8 = 0 x $ = OR x $220= 0 w 137 CFR 1.161h\\ ~ D Application Size Fee (37 CFR 1.16(s))
-
UNITED STA IBS p A IBNT AND TRADEMARK OFFICE
APPLICATION NO. FILING DATE FIRST NAMED INVENTOR
111751,172 05/21/2007 W.E. Clark
27452 7590 12/21/2009
SCHLUMBERGER IBCHNOLOGY CORPORATION David Cate IP DEPT., WELL STIMULATION 110 SCHLUMBERGER DRIVE, MDI SUGAR LAND, TX 77478
UNITED STA TES DEPARTMENT OF COMMERCE United States Patent and Trademark Office Address: COMMISSIONER FOR PATENTS
P.O. Box 1450 Alexandria, Virginia 22313-1450 www.uspto.gov
ATTORNEY DOCKET NO. CONFIRMATION NO.
56.0967 1527
EXAMINER
COY, NICOLE A
ART UNIT PAPER NUMBER
3672
NOTIFICATION DATE DELIVERY MODE
12/21/2009 ELECTRONIC
Please find below and/or attached an Office communication concerning this application or proceeding.
The time period for reply, if any, is set in the attached communication.
Notice of the Office communication was sent electronically on above-indicated "Notification Date" to the following e-mail address( es):
[email protected] [email protected]
PTOL-90A (Rev. 04/07) Page 210 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application No. Applicant(s)
11/751,172 CLARK ET AL.
Office Action Summary Examiner Art Unit
Nicole A. Coy 3672
-- The MAILING DA TE of this communication appears on the cover sheet with the correspondence address --Period for Reply
A SHORTENED STATUTORY PERIOD FOR REPLY IS SET TO EXPIRE ;l_ MONTH(S) OR THIRTY (30) DAYS, WHICHEVER IS LONGER, FROM THE MAILING DATE OF THIS COMMUNICATION. - Extensions of time may be available under the provisions of 37 CFR 1.136(a). In no event, however, may a reply be timely filed
after SIX (6) MONTHS from the mailing date of this communication. - If NO period for reply is specified above, the maximum statutory period will apply and will expire SIX (6) MONTHS from the mailing date of this communication. - Failure to reply within the set or extended period for reply will, by statute, cause the application to become ABANDONED (35 U.S.C. § 133).
Any reply received by the Office later than three months after the mailing date of this communication, even if timely filed, may reduce any earned patent term adjustment. See 37 CFR 1.704(b).
Status
1 )IZ! Responsive to communication(s) filed on 20 November 2009. 2a)0 This action is FINAL. 2b)[8J This action is non-final.
3)0 Since this application is in condition for allowance except for formal matters, prosecution as to the merits is
closed in accordance with the practice under Ex parte Quayle, 1935 C.D. 11, 453 O.G. 213.
Disposition of Claims
4)[8J Claim(s) 1-18.20.21.27.28.33.34 and 53-60 is/are pending in the application.
4a) Of the above claim(s) __ is/are withdrawn from consideration.
5)0 Claim(s) __ is/are allowed.
6)[8J Claim(s) 1-18.20.21.27.28.33.34 and 53-60 is/are rejected.
7)0 Claim(s) __ is/are objected to.
8)0 Claim(s) __ are subject to restriction and/or election requirement.
Application Papers
9)0 The specification is objected to by the Examiner.
10)0 The drawing(s) filed on __ is/are: a)O accepted or b)O objected to by the Examiner.
Applicant may not request that any objection to the drawing(s) be held in abeyance. See 37 CFR 1.85(a).
Replacement drawing sheet(s) including the correction is required if the drawing(s) is objected to. See 37 CFR 1.121 (d).
11 )0 The oath or declaration is objected to by the Examiner. Note the attached Office Action or form PT0-152.
Priority under 35 U.S.C. § 119
12)0 Acknowledgment is made of a claim for foreign priority under 35 U.S.C. § 119(a)-(d) or (f).
a)O All b)O Some* c)O None of:
1.0 Certified copies of the priority documents have been received.
2.0 Certified copies of the priority documents have been received in Application No. __ .
3.0 Copies of the certified copies of the priority documents have been received in this National Stage
application from the International Bureau (PCT Rule 17 .2(a)).
*See the attached detailed Office action for a list of the certified copies not received.
Attachment(s)
1) [8J Notice of References Cited (PT0-892) 2) 0 Notice of Draftsperson's Patent Drawing Review (PT0-948)
4) 0 Interview Summary (PT0-413) Paper No(s)/Mail Date. __ .
5) 0 Notice of Informal Patent Application 3) 0 Information Disclosure Statement(s) (PTO/SB/08) Paper No(s)/Mail Date __ .
U.S. Patent and Trademark Office
PTOL-326 (Rev. 08-06)
6) 0 Other: __ .
Office Action Summary Part of Paper No./Mail Date 20091208
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Art Unit: 3672
DETAILED ACTION
Continued Examination Under 37 CFR 1.114
Page 2
1. 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
11 /20/09 has been entered.
Information Disclosure Statement
2. The listing of references in the specification is not a proper information disclosure
statement. 37 CFR 1.98(b) requires a list of all patents, publications, or other
information submitted for consideration by the Office, and MPEP § 609.04(a) states,
"the list may not be incorporated into the specification but must be submitted in a
separate paper." Therefore, unless the references have been cited by the examiner on
form PT0-892, they have not been considered.
Claim Rejections - 35 USC § 112
3. Claims 53-60 are rejected under 35 U.S.C. 112, first paragraph, as failing to
comply with the written description requirement. The claim(s) contains subject matter
which was not described in the specification in such a way as to reasonably convey to
one skilled in the relevant art that the inventor(s), at the time the application was filed,
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Page 3
had possession of the claimed invention. The Examiner cannot find support for the
limitation of "degrading the diversion agent after the performing the first treatment step
on the second target zone." It appears that there is support for a delayed degradable
particle - but the specification does not indicate that the delayed degradation occurs
after a treatment step on a second zone.
Claim Rejections - 35 USC§ 103
4. The following is a quotation of 35 U.S.C. 103(a) which forms the basis for all
obviousness rejections set forth in this Office action:
(a) A patent may not be obtained though the invention is not identically disclosed or described as set forth in section 102 of this title, if the differences between the subject matter sought to be patented and the prior art are such that the subject matter as a whole would have been obvious at the time the invention was made to a person having ordinary skill in the art to which said subject matter pertains. Patentability shall not be negatived by the manner in which the invention was made.
5. Claims 1, 3, 4, 8, 10, 11, 12, 33, and 34 are rejected under 35 U.S.C. 103(a) as
being unpatentable over Chang et al. (US 2003/0119680) in view of Lehman et al. (US
2007 /0272407).
With respect to claims 1, 33, and 34, teaches a method of well treatment,
comprising: a) establishing fluid connectivity between a wellbore and at least one target
zone for treatment within a subterranean formation intersected by the wellbore (lines 1-
3; the fluids of the invention can be pumped as a single fluid, which stimulate and divert
in one step - wherein diverting and stimulating fluids are inherently added to a target
zone of a formation in order to divert and stimulate) ;b) deploying coiled tubing into the
wellbore (line 5: using coiled tubing); c) introducing a treatment composition into the
wellbore (line 2: pumped as a single fluid); d) contacting a target zone within the
Page 213 of 399Halliburton Energy Services, Inc.
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Page 4
subterranean formation with the treatment composition (line 2: pumped as a single fluid
- wherein the fluid would be pumped to a treatment zone, in order to perform the
functions of diverting and stimulating); e) introducing a diversion agent through the
coiled tubing to an interval within the wellbore (lines 2 and 3: a single fluid which will
stimulate and divert); and repeating steps c) through d) for more than one target zone
(lines 5-6: using coiled tubing moved up and down while injecting - wherein moving the
coiled tubing up and down would inherently introduce the pumped fluid to more than
one zone). Chang et al. does not disclose measuring a parameter indicative of
diversion wherein the act of measuring comprises measuring microseismic activity.
Lehman et al. teach measuring microseismic activity of a fracture in order to measure
and monitor a fracturing operation, which is indicative of diversion (see paragraphs 27
and 29). It would have been obvious to one having ordinary skill in the art at the time of
the invention to modify Chang et al. by measuring microseismic activity in a fracture as
taught by Lehman et al. in order to monitor and measure a fracturing operation, which in
turn would indicate whether the diversion agent was diverting the treatment fluid.
With respect to claim 3, Chang et al. disclose that the treatment composition
comprises a stimulation fluid (see paragraph 2).
With respect to claim 4, Chang et al. disclose the act of introducing the treatment
composition comprises pumping the composition under pressure (see paragraph 22).
With respect to claim 8, Chang et al. disclose that after contacting the target
subterranean formation with the treatment composition, the diversion agent is
introduced into the formation (see paragraph 20).
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Page 5
With respect to claim 10, Chang et al. disclose repeating act e) (see paragraph
24).
With respect to claim 11, Chang et al. disclose repeating act a) and b) prior to
repeating acts c) through d) (see paragraph 20).
With respect to claim 12, Chang et al. disclose that the diversion agent consists
of non-degradable material (see abstract).
6. Claims 1-7, 9-11, 13-18, 20-21, 27, 28, 33, 34, 53, 54, 59, and 60 are rejected
under 35 U.S.C. 103(a) as being obvious over Boney et al. (US 2003/0106690) in view
of Lehman et al (US 2007/0272407).
With respect to claim 1, 33, and 34, Boney et al. disclose a method of well
treatment, comprising: a) establishing fluid connectivity between a wellbore and at least
one target zone for treatment within a subterranean formation intersected by the
wellbore;b) deploying coiled tubing into the wellbore (see paragraph 45); c) introducing
a treatment composition into the wellbore(see paragraph 25); d) contacting a target
zone within the subterranean formation with the treatment composition (see paragraph
25); e) introducing a diversion agent through the coiled tubing to an interval within the
wellbore(see paragraph 24; wherein the filter cake acts as a diversion agent, diverting
the fluid to form a new fracture without zonal isolation); and repeating steps c) through
d) for more than one target zone (see paragraph 25). Boney et al. does not disclose
measuring a parameter indicative of diversion wherein the act of measuring comprises
measuring microseismic activity. Lehman et al. teach measuring microseismic activity
Page 215 of 399Halliburton Energy Services, Inc.
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Art Unit: 3672
Page 6
of a fracture in order to measure and monitor a fracturing operation, which is indicative
of diversion (see paragraphs 27 and 29). It would have been obvious to one having
ordinary skill in the art at the time of the invention to modify Boney et al. by measuring
microseismic activity in a fracture as taught by Lehman et al. in order to monitor and
measure a fracturing operation, which in turn would indicate whether the diversion agent
was diverting the treatment fluid.
With respect to claim 2, Boney et al. disclose that the wellbore is cased and
further comprising the act of perforating the casing (see paragraph 47).
With respect to claim 3, Boney et al. disclose a stimulation fluid (see paragraphs
2 and 3).
With respect to claim 4, Boney et al. disclose introducing the treatment
composition comprises pumping the composition under pressure (see paragraph 3).
With respect to claim 5, Boney et al. disclose that at least a portion of the
wellbore comprises a generally horizontal section (see paragraph 52).
With respect to claim 6, Boney et al. teaches that the diversion agent comprises
fiber (see paragraph 45, wherein fiber may be added to the pad, which forms the filter
cake, which is the diversion agent).
With respect to claim 7, Boney et al. teaches that the diversion agent comprises
degradable material (see paragraphs 24 and 25).
With respect to claim 9, Boney et al. disclose that a portion of the wellbore is
deviated or horizontal (see paragraph 52).
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Page 7
With respect to claim 10, Boney et al. disclose repeating step (e) (see paragraph
45).
With respect to claim 11, Boney et al. disclose repeating steps a and b before c
and d (see paragraph 45.
With respect to claims 13 and 59, Boney et al. disclose that the diversion agent is
stored in the coiled tubing between acts of introducing the diversion agent to an interval
(see paragraph 45, wherein some of the agent would inherently be stored in the tubing
between fractures).
With respect to claims 14 and 28, Boney et al. disclose a method of treating more
than one target zone of interest in a subterranean formation, the method comprising:a)
pumping a treatment composition to contact at least one target zone of interest with the
treatment composition (see paragraph 25); b) monitoring the pumping of the treatment
composition and measuring a parameter indicative of treatment (see paragraph 5); c)
pumping a diversion agent to a desired diversion interval in the wellbore (see paragraph
24 ); d) monitoring the pumping of the diversion agent and measuring a parameter
indicative of diversion (see paragraph 31 ); e) pumping a treatment composition to
contact at least one other target zone of interest (see paragraph 25); f) modifying at
least one of acts a) and c) based on at least one of the measured parameters (see
paragraphs 5 and 31 ). Boney et al. does not disclose measuring a parameter indicative
of diversion wherein the act of measuring comprises measuring microseismic activity.
Lehman et al. teach measuring microseismic activity of a fracture in order to measure
and monitor a fracturing operation, which is indicative of diversion (see paragraphs 27
Page 217 of 399Halliburton Energy Services, Inc.
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Page 8
and 29). It would have been obvious to one having ordinary skill in the art at the time of
the invention to modify Boney et al. by measuring microseismic activity in a fracture as
taught by Lehman et al. in order to monitor and measure a fracturing operation, which in
turn would indicate whether the diversion agent was diverting the treatment fluid.
With respect to claim 15, Boney et al. disclose that at least a portion of the
wellbore comprises a generally deviated or horizontal section (see paragraph 52).
With respect to claim 16, Boney et al. disclose that at least one of the diversion
interval and the target zone of interest are located within said generally horizontal
section (see paragraph 45).
With respect to claim 17, Boney et al. disclose repeating acts a) through d) (see
paragraph 45).
With respect to claim 18, Boney et al. disclose injecting the treatment
composition in the annulus between a coiled tubing and the wellbore (see paragraph 25;
wherein some treatment fluid would inherently be in the annulus).
With respect to claim 20, Boney et al. disclose that the fiber comprises a
degradable material (see paragraphs 24, 25 and 45).
With respect to claim 21, see the rejection of claim 1. In addition, Boney et al.
disclose deploying coiled tubing into a wellbore, wherein connectivity is established by
one or more of perforating, jetting, sliding sleeve, or opening a valve, and establishing
fluid connectivity between a wellbore and at least one target zone for treatment within a
subterranean formation intersected by the wellbore (see paragraph 47).
Page 218 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 9
With respect to claim 27, Boney et al. disclose the modifying at least one of the
act of providing a diversion and the act of injecting a treatment composition based on
the measured well bore parameter (see paragraphs 5 and 31 ).
With respect to claim 53, see the rejection of claim 1. In addition, Boney et al.
disclose degrading the diversion agent after the performing the first step on the second
target zone (see paragraph 25).
With respect to claim 54, Boney et al. disclose successively treating each
addition target zone (see paragraphs 24, 25, and 45).
With respect to claims 55-58, Boney et al. discloses the claimed invention except
for the order the zones are treated in. It would have been an obvious matter of design
choice to target the zones as claimed, since applicant has not disclosed that targeting
the zones in a certain order solves any stated problem or is for any particular purpose
and it appears that the invention would equally well with targeting the zones in the order
presented in Boney et al.
With respect to claim 60, Boney et al. disclose measuring a parameter indicative
of diversion (see paragraph 31 ).
Response to Arguments
7. Applicant's arguments filed 11/20/09 have been fully considered but they are not
persuasive. Applicant appears to have submitted the same remarks that were filed
5/4/09 and which were addressed in the final rejection mailed 8/24/09.
Page 219 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
With respect to the rejection under Chang, the Applicant argues that the
Page 10
Examiner has not provided any substantive analysis or additional reference to support
extending Chang to encompass the pending claim limitations. The Examiner has very
clearly set forth in the rejection above how Chang reads on the claim. The Applicant
has not specifically pointed out what claim limitations Chang does not teach, but merely
asserts that Chang doesn't teach the entire claim. As noted above, Chang et al. does
teach the claimed limitations. Furthermore, with respect to the amendment, as noted
above, it would have been obvious to one having ordinary skill in the art to measure
microseismic data.
With respect to the rejection of the claims over Boney, the Applicant argues that
Boney does not describe introducing a diversion agent through the coiled tubing to an
interval within the wellbore as recited in the pending claims. Applicant argues that when
the methods are practiced as a form of diversion the pressure induced in the fracture
due to the screenout causes the diversion. The Examiner is unclear where Boney
states this. In paragraph 24, Boney teaches that the method of breaking or dissolving
the filter cake can be used as a form of diversion. Boney teaches that breaking or
dissolving the filter cake is done by adding filter cake degradation aids. Thus, the filter
cake can act as a diversion agent, diverting the fluid to another fracture. The fluid which
forms the filter cake is inserted through coiled tubing. Thus, Boney et al. teaches
introducing a diversion agent through the coiled tubing.
Conclusion
Page 220 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 11
8. Any inquiry concerning this communication or earlier communications from the
examiner should be directed to Nicole A. Coy whose telephone number is (571 )272-
5405. The examiner can normally be reached on M, Tu, F, and every other
Wednesday from 8:30am-4pm.
If attempts to reach the examiner by telephone are unsuccessful, the examiner's
supervisor, David Bagnell can be reached on 571-272-6999. The fax phone number for
the organization where this application or proceeding is assigned is 571-273-8300.
Information regarding the status of an application may be obtained from the
Patent Application Information Retrieval (PAIR) system. Status information for
published applications may be obtained from either Private PAIR or Public PAIR.
Status information for unpublished applications is available through Private PAIR only.
For more information about the PAIR system, see http://pair-direct.uspto.gov. Should
you have questions on access to the Private PAIR system, contact the Electronic
Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a
USPTO Customer Service Representative or access to the automated information
system, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000.
/Nicole A Coy/ Examiner, Art Unit 3672
Page 221 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control No. Applicant(s)/Patent Under Reexamination
11/751,172 CLARK ET AL. Notice of References Cited
Examiner Art Unit
Nicole A. Coy 3672 Page 1 of 1
U.S. PATENT DOCUMENTS
* Document Number
Country Code-Number-Kind Code Date
MM-YYYY Name Classification
* A US-2007 /0272407 11-2007 Lehman et al. 166/250.1 B US-
c US-
D US-
E US-
F US-
G US-
H US-
I US-
J US-
K US-
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M US-
FOREIGN PATENT DOCUMENTS
* Document Number Date
Country Code-Number-Kind Code MM-YYYY Country Name Classification
N
0
p
Q
R
s T
NON-PATENT DOCUMENTS
* Include as applicable: Author, Title Date, Publisher, Edition or Volume, Pertinent Pages)
u
v
w
x
*A copy of this reference 1s not being furnished with this Office action. (See MPEP § 707.05(a).) Dates in MM-YYYY format are publication dates. Classifications may be US or foreign.
U.S. Patent and Trademark Office
PT0-892 (Rev. 01-2001) Notice of References Cited Part of Paper No. 20091208
Page 222 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control No. Applicant(s)/Patent Under Reexamination
Index of Claims 11751172 CLARK ET AL.
Examiner Art Unit
KERRY W LEONARD 3676
Rejected Cancelled N Non-Elected A Appeal
= Allowed Restricted Interference 0 Objected
D Claims renumbered in the same order as presented by applicant D CPA D T.D. D R.1.47
CLAIM DATE Final Original 03/31/2008 01/30/2009 08/17/2009 12/08/2009
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Page 223 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control No. Applicant(s)/Patent Under Reexamination
Index of Claims 11751172 CLARK ET AL.
Examiner Art Unit
KERRY W LEONARD 3676
Rejected Cancelled N Non-Elected A Appeal
= Allowed Restricted Interference 0 Objected
D Claims renumbered in the same order as presented by applicant D CPA D T.D. D R.1.47
CLAIM DATE Final Original 03/31/2008 01/30/2009 08/17/2009 12/08/2009
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U.S. Patent and Trademark Office Part of Paper No.: 20091208
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EAST Search History
EAST Search History
EAST Search History (Prior Art)
file:///Cl/Documents%20and%20Settings/ncoy/My%20Docu ... 172/EASTSearchHistory.11751172_AccessibleVersion.htm (1 of 2)12/9/2009 8:40:42 AM
Page 225 of 399Halliburton Energy Services, Inc.
Exhibit 1008
SALANText Box
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EAST Search History
EAST Search History (Interference)
12/ 9/ 2009 8:40:25 AM C:\ Documents and Settings\ ncoy\ My Documents\ EAST\ Workspaces\ 11751172.wsp
file:///Cl/Documents%20and%20Settings/ncoy/My%20Docu ... 172/EASTSearchHistory.11751172_AccessibleVersion.htm (2 of 2)12/9/2009 8:40:42 AM
Page 226 of 399Halliburton Energy Services, Inc.
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SALANText Box
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Application/Control No.
Search Notes 11751172
Examiner
KERRY W LEONARD
SEARCHED
Class Subclass 166 281, 250.01, 250.17 updated above updated above
SEARCH NOTES
Search Notes Search in EAST and Google Patents EAST text search Inventor Name search
INTERFERENCE SEARCH
Class I Subclass I
U.S. Patent and Trademark Office
I I
Applicant(s)/Patent Under Reexamination
CLARK ET AL.
Art Unit
3676
Date Examiner 1/30/09 8/17/09 nae 12/8/09 nae
Date Examiner KWL
12/8/09 nae 12/8/09 nae
Date I Examiner I
Part of Paper No. : 20091208 Page 227 of 399
Halliburton Energy Services, Inc.Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action Mailed December 21, 2009
IN THE UNITED STATES PATENT AND TRADEMARK OFFICE
In re Application Clark, et al.
Filed: May 21, 2007
Serial No.: 11/751, 172
For: METHOD AND SYSTEM FOR TREATING A SUBTERRANEAN FORMATION USING DIVERSION
§ Customer no.: 27452 § § Confirmation No.: 1527 § § Art Unit: 3676 § § Examiner: Nicole A. Coy § § § Attorney Docket No.: 56.0967 § § §
RESPONSE TO OFFICE ACTION MAILED DECEMBER 21, 2009
Commissioner for Patents P.O. Box 1450 Alexandria, VA 22313-14 5 0
Dear Examiner:
In response to the Office Action mailed December 21, 2009, please consider the
following amendments and remarks.
The Pending Claims begin on page 2 of this paper.
Remarks begin on page 8 of this paper.
- 1 -
Page 228 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
THE PENDING CLAIMS
1. (Previously Presented) A method of well treatment, comprising:
a) establishing fluid connectivity between a wellbore and at least one target zone for
treatment within a subterranean formation intersected by the wellbore;
b) deploying coiled tubing into the wellbore;
c) introducing a treatment composition into the wellbore;
d) contacting a target zone within the subterranean formation with the treatment
composition;
e) introducing a diversion agent through the coiled tubing to an interval within the
wellbore and measuring a parameter indicative of diversion wherein the act of measuring
comprises measuring microseismic activity; and
repeating steps c) through d) for more than one target zone.
2. (previously presented) The method of 1, wherein the wellbore is cased, the method
further comprising perforating the casing.
3. (original) The method of claim 1, wherein the treatment composition comprises a
stimulation fluid.
4. (original) The method of claim 3, wherein the act of introducing the treatment
composition comprises pumping the composition under pressure.
5. (original) The method of claim 1, wherein at least a portion of the wellbore comprises
a generally horizontal section.
6. (original) The method of claim 1, wherein the diversion agent comprises fiber.
7. (original) The method of claim 1, wherein the diversion agent comprises degradable
material.
8. (original) The method of claim 1, wherein after contacting the target subterranean
formation with the treatment composition, the diversion agent is introduced into the formation.
9. (original) The method of claim 1, wherein a portion of the wellbore is deviated or
horizontal.
- 2 -
Page 229 of 399Halliburton Energy Services, Inc.
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
10. (original) The method of claim 1, further comprising repeating act e).
11. (original) The method of claim 1, further comprising repeating act a) and b) prior to
repeating acts c) through d).
12. (original) The method of claim 1, wherein the diversion agent consists of non-
degradable material.
13. (original) The method of claim 10, wherein the diversion agent is stored in the coiled
tubing between acts of introducing the diversion agent to an interval.
14. (previously presented) A method of treating more than one target zone of interest in a
subterranean formation, the method comprising:
a) pumping a treatment composition to contact at least one target zone of interest with
the treatment composition;
b) monitoring the pumping of the treatment composition and measuring a parameter
indicative of treatment;
c) pumping a diversion agent to a desired diversion interval in the well bore;
d) monitoring the pumping of the diversion agent and measuring a parameter indicative
of diversion wherein measuring comprises measuring microseismic activity;
e) pumping a treatment composition to contact at least one other target zone of interest;
f) modifying at least one of acts a) and c) based on at least one of the measured
parameters.
15. (original) The method of claim 14, wherein at least a portion of the wellbore
comprises a generally deviated or horizontal section.
16. (original) The method of claim 14, wherein at least one of the diversion interval and
the target zone of interest are located within said generally horizontal section.
17. (original) The method of claim 14, further comprising repeating acts a) through d).
18. (original) The method of claim 14, further comprising injecting the treatment
composition in the annulus between a coiled tubing and the wellbore.
19. (canceled)
- 3 -
Page 230 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed August 24, 2009
20. (previously presented) The method of claim 14, wherein the diversion agent
comprises a fiber, the fiber comprising a degradable material.
21. (previously presented) A method of treating a well, comprising:
a) deploying coiled tubing into a wellbore, wherein connectivity is established by one or
more of perforating, jetting, sliding sleeve, or opening a valve, and establishing fluid
connectivity between a wellbore and at least one target zone for treatment within a subterranean
formation intersected by the wellbore;
b) injecting a treatment composition into the wellbore to contact a hydrocarbon bearing
subterranean formation with the treatment composition;
c) providing a diversion agent through the coiled tubing to a desired interval in the
well bore;
d) measuring a wellbore parameter while performing at least one of act b) or act c ),
wherein the act of measuring comprises measuring microseismic activity.
22-26. (canceled)
27. (previously presented) The method of claim 21, further comprising modifying at
least one of the act of providing a diversion and the act of injecting a treatment composition
based on the measured wellbore parameter.
28. (previously presented) A method of treating a well, comprising:
a) measuring a wellbore parameter to establish a baseline;
b) providing a diversion agent through the coiled tubing to a desired interval in the
well bore;
c) injecting a treatment composition into the wellbore to contact a target zone in a
subterranean formation with the treatment composition; and
d) measuring the well bore parameter while performing at least one of act b) and act c)
wherein measuring comprises measuring microseismic activity.
29-32. (canceled)
33. (previously presented) A method of well treatment, comprising:
- 4 -
Page 231 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
a) establishing fluid connectivity between a wellbore and at least one target zone for
treatment within a subterranean formation intersected by the wellbore;
b) deploying coiled tubing into the wellbore;
c) introducing a treatment composition into the wellbore;
d) contacting a target zone within the subterranean formation with the treatment
composition;
e) introducing a diversion agent through an annulus formed between the wellbore and the
coiled tubing to an interval within the wellbore and measuring a wellbore parameter wherein
measuring comprises measuring microseismic activity; and
repeating steps c) through e) for more than one target zone.
34. (previously presented) A system usable with a well, comprising:
a tubing string;
a treatment fluid source to communicate a treatment composition in the well to contact a
hydrocarbon bearing subterranean formation with the treatment composition; tHttl
a diversion agent source to communicate a diversion agent through the tubing string into
an interval of the well and
microseimic equipment to measure a wellbore parameter.
35-52. (canceled)
- 5 -
Page 232 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
53. (previously presented) A method, comprising:
establishing fluid connectivity between a wellbore and a first target zone, and between
the wellbore and a second target zone, wherein the first target zone and second target zone
comprise zones for treatment within a subterranean formation intersected by a wellbore;
positioning a coiled tubing into the wellbore;
performing a first treatment step on the first target zone, wherein the first treatment step
comprises contacting a treated zone with a treatment fluid;
performing a second treatment step on the first target zone, wherein the second treatment
step comprises introducing a diversion agent comprising a degradable material to the treated
zone;
performing the first treatment step on the second target zone; arul
degrading the diversion agent after the performing the first treatment step on the second
target zone; and
measuring a wellbore parameter wherein measuring comprises measuring microseismic
activity.
54. (previously presented) The method of claim 53, further comprising establishing fluid
connectivity with at least one additional target zone, the method further comprising performing
the second treatment step on the second target zone, and successively treating each additional
target zone except a final target zone by performing the first treatment step and the second
treatment step on each additional target zone, and treating the final target zone by performing the
first treatment step on the final target zone.
55. (previously presented) The method of claim 54, wherein establishing fluid
connectivity with at least one additional target zone comprises performing a perforation
operation on the at least one additional target zone after performing the treatment step on the first
target zone and before removing the coiled tubing from the wellbore.
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Page 233 of 399Halliburton Energy Services, Inc.
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
56. (previously presented) The method of claim 54, wherein the first target zone, second
target zone, and additional target zones are treated in an order from a lowest in-situ stress to a
highest in-situ stress.
57. (previously presented) The method of claim 54, wherein the first target zone, second
target zone, and additional target zones are treated in an order from a top zone to a bottom zone.
58. (previously presented) The method of claim 53, wherein the second target zone is
above the first target zone.
59. (previously presented) The method of claim 53, wherein the diversion agent is
stored in the coiled tubing between acts of introducing the diversion agent to an interval.
60. (previously presented) The method of claim 53, further comprising measuring a
parameter indicative of diversion.
- 7 -
Page 234 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
REMARKS
These remarks are submitted in response to the office action mailed December 21,
Claims 1-18, 20, 21, 27, 28, 33, 34, and 53-60 are pending and rejected.
Claims 53-60 are rejected under 35 U.S.C. 112, first paragraph, as failing to comply with
the written description requirement. Specifically, the Examiner indicates the phrase, "degrading
the diversion agent after the performing the first treatment step on the second target zone" as
recited in pending claim 53 is not supported by the specification. Support for claim 53 is found
in Figures 2 and 3 and in the specification at paragraphs [0024] and [0046]-[0049] of the
published application. Withdrawal of the rejection is respectfully requested.
Claims 1, 3, 4, 8, 10-12, 33, and 34 are rejected under 35 U.S.C. § 103(a) as being
anticipated by United States Patent Application Publication Number 2003/0119680 (Chang) in
view of United States Patent Application Number 2007 /0272407 (Lehman). Applicants
respectfully traverse the rejection. Chang uses coiled tubing merely to provide stimulating and
diverting fluid in one step (see paragraph [0020]). Further, the Examiner indicates Chang does
not describe measuring microseismic activity. That is, Chang does not describe deploying coiled
tubing into the wellbore, introducing a treatment composition into the wellbore, contacting a
target zone within the subterranean formation with the treatment composition, introducing a
diversion agent through the coiled tubing to an interval within the wellbore wherein the act of
measuring comprises measuring microseismic activity, and repeating steps for more than one
target zone as recited in claim 1 and claims dependent thereon. Further, Chang does not describe
contacting a target zone within the subterranean formation with the treatment composition,
introducing a diversion agent through an annulus formed between the wellbore and the coiled
tubing to an interval within the wellbore, wherein the act of measuring comprises measuring
microseismic activity, and repeating steps for more than one target zone as recited in claim 33
and claim 34 dependent thereon.
Lehman does resolve the shortcomings of Chang. Lehman also does not describe
deploying coiled tubing into the wellbore, introducing a treatment composition into the wellbore,
contacting a target zone within the subterranean formation with the treatment composition,
introducing a diversion agent through the coiled tubing to an interval within the wellbore
wherein the act of measuring comprises measuring microseismic activity, and repeating steps for
- 8 -
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Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
more than one target zone as recited in claim 1 and claims dependent thereon. Further, Lehman
does not describe contacting a target zone within the subterranean formation with the treatment
composition, introducing a diversion agent through an annulus formed between the wellbore and
the coiled tubing to an interval within the wellbore, wherein the act of measuring comprises
measuring microseismic activity, and repeating steps for more than one target zone as recited in
claim 33 and claim 34 dependent thereon.
Finally, the combination of references IS not supported by substantive analysis or a
reference. The Examiner's motivation to combine, "to monitor and measure a fracturing
operation" does not encompass the pending claim limitations. Withdrawal of the rejection is
respectfully requested.
Claims 1-7, 9-11, 13-18, 20, 21, 24, 27, 28, 33, 34, 53, 54, 59, and 60 are rejected under
35 USC 103 (a) as being obvious over United States Patent Application Publication Number
2003/0106690 (Boney) in view of Lehman. Applicants respectfully traverse the rejection. Boney
does not describe introducing a diversion agent through the coiled tubing to an interval within
the wellbore as recited in the pending claims. Boney discloses "these methods can also be used
as a form of diversion." Paragraph [0024], lines 28-29. Boney requires inducing a screenout
during a fracture treatment at a desired time and location. See Abstract, paragraph 0026 lines 30-
36. When the methods in Boney are practiced as a form of diversion, the pressure induced in the
fracture due to the screenout causes the diversion. That is, Boney describes no "diversion agent"
introduced through the coiled tubing as recited in pending claim 1.
Lehman does resolve the shortcomings of Boney. As detailed above, Lehman does not
describe the pending claim limitations.
Finally, the combination of references IS not supported by substantive analysis or a
reference. The Examiner's motivation to combine, "to monitor and measure a fracturing
operation" does not encompass the pending claim limitations. Independent claims 14, 21, 33, 34,
and 53 and claims dependent thereon are also allowable for at least the reasons stated above
related to claim 1. Withdrawal of the rejection is respectfully requested.
In summary, for the reasons and amendments detailed above, it is submitted that all
claims now presented in the application are in condition for allowance, and accordingly, such
- 9 -
Page 236 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009
action is respectfully requested. If the Examiner believes that the prosecution of the application
would be facilitated by a telephone interview, Applicants invite the Examiner to contact the
undersigned at 281-285-4925. No additional fees other than those authorized in the enclosed
request for continued examination are believed to be due. However, the Commissioner is hereby
authorized to charge any fees that may be required, or credit any overpayment, to Deposit
Account No. 04-1579 (56.0967).
Date: March 12, 2010
Respectfully Submitted,
/Rachel E. Greene/ Rachel E. Greene Attorney for Applicants Reg. No. 58,750
SCHLUMBERGER TECHNOLOGY CORPORATION 555 Industrial Blvd. Sugar Land, Texas 77478 281.285 .4925
- 10 -
Page 237 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Electronic Acknowledgement Receipt
EFSID: 7201726
Application Number: 11751172
International Application Number:
Confirmation Number: 1527
Title of Invention: Method and System for Treating a Subterraean Formation Using Diversion
First Named Inventor/Applicant Name: W.E. Clark
Customer Number: 27452
Filer: David Lynn Cate/Push pa Mohan
Filer Authorized By: David Lynn Cate
Attorney Docket Number: 56.0967
Receipt Date: 12-MAR-2010
Filing Date: 21-MAY-2007
Time Stamp: 16:30:19
Application Type: Utility under 35 USC 111 (a)
Payment information:
Submitted with Payment I no
File Listing:
Document Document Description File Name
File Size( Bytes)/ Multi Pages Number Message Digest Part /.zip (if appl.)
113861
1 560967 _Resp_OfficeAction_03-
yes 10 12-1 O.pdf
Ob4cedebde3ba4b062782a3698d27aef57c 42625
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Multipart Description/PDF files in .zip description
Document Description Start End
Amendment/Req. Reconsideration-After Non-Final Reject 1 1
Claims 2 7
Applicant Arguments/Remarks Made in an Amendment 8 10
Warnings:
Information:
Total Files Size (in bytes) 113861
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Page 239 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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PTO/SB/06 (07-06) Approved for use through 1/31/2007. OMB 0651-0032
U.S. Patent and Trademark Office; U.S. DEPARTMENT OF COMMERCE Under the Paperwork Reduction Act of 1995, no persons are required to respond to a collection of information unless it displays a valid OMB control number.
PATENT APPLICATION FEE DETERMINATION RECORD Application or Docket Number Filing Date Substitute for Form PT0-875 11/751,172 05/21/2007 D To be Mailed
APPLICATION AS FILED - PART I OTHER THAN (Column 1) (Column 2) SMALL ENTITY D OR SMALL ENTITY
FOR NUMBER FILED NUMBER EXTRA RATE($) FEE($) RATE($) FEE($)
D BASIC FEE N/A N/A N/A N/A (37CFR1.16(a), (b), or (c))
D SEARCH FEE (37CFR1.16(k), (i), or (m)) N/A N/A N/A N/A
D EXAMINATION FEE (37CFR1.16(0), (p), or (q))
N/A N/A N/A N/A
TOTAL CLAIMS * x $ = OR x $ = (37 CFR 1.16(i)) minus 20 =
INDEPENDENT CLAIMS * x $ = x $ = (37 CFR 1.16(h)) minus 3 =
If the specification and drawings exceed 100
0APPLICATION SIZE FEE sheets of paper, the application size fee due is $250 ($125 for small entity) for each
(37 CFR 1.16(s)) additional 50 sheets or fraction thereof. See 35 U.S.C. 41 (a)(1)(G) and 37 CFR 1.16(s).
D MULTIPLE DEPENDENT CLAIM PRESENT (37 CFR 1.16U)) * If the difference in column 1 is less than zero, enter "O" in column 2. TOTAL TOTAL
APPLICATION AS AMENDED- PART II OTHER THAN
(Column 1) (Column 2) (Column 3) SMALL ENTITY OR SMALL ENTITY
CLAIMS HIGHEST
03/12/2010 REMAINING NUMBER PRESENT RATE($) ADDITIONAL RATE($) ADDITIONAL I- AFTER PREVIOUSLY EXTRA FEE($) FEE($) z AMENDMENT PAID FOR w
Total (37 CFR ~ 1.16(i)) * 24 Minus ** 52 = 0 x $ = OR x $52= 0 0 Independent z * 6 Minus ***8 = 0 x $ = OR x $220= 0 w 137 CFR 1.161h\\ ~ D Application Size Fee (37 CFR 1.16(s))
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UNITED STA IBS p A IBNT AND TRADEMARK OFFICE
APPLICATION NO. FILING DATE FIRST NAMED INVENTOR
111751,172 05/21/2007 W.E. Clark
27452 7590 04/26/2010
SCHLUMBERGER IBCHNOLOGY CORPORATION David Cate IP DEPT., WELL STIMULATION 110 SCHLUMBERGER DRIVE, MDI SUGAR LAND, TX 77478
UNITED STA TES DEPARTMENT OF COMMERCE United States Patent and Trademark Office Address: COMMISSIONER FOR PATENTS
P.O. Box 1450 Alexandria, Virginia 22313-1450 www.uspto.gov
ATTORNEY DOCKET NO. CONFIRMATION NO.
56.0967 1527
EXAMINER
COY, NICOLE A
ART UNIT PAPER NUMBER
3672
NOTIFICATION DATE DELIVERY MODE
04/26/2010 ELECTRONIC
Please find below and/or attached an Office communication concerning this application or proceeding.
The time period for reply, if any, is set in the attached communication.
Notice of the Office communication was sent electronically on above-indicated "Notification Date" to the following e-mail address( es):
[email protected] KY [email protected] KJ ohnsonl [email protected]
PTOL-90A (Rev. 04/07) Page 241 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application No. Applicant(s)
11/751,172 CLARK ET AL.
Office Action Summary Examiner Art Unit
Nicole A. Coy 3672
-- The MAILING DA TE of this communication appears on the cover sheet with the correspondence address --Period for Reply
A SHORTENED STATUTORY PERIOD FOR REPLY IS SET TO EXPIRE ;l_ MONTH(S) OR THIRTY (30) DAYS, WHICHEVER IS LONGER, FROM THE MAILING DATE OF THIS COMMUNICATION. - Extensions of time may be available under the provisions of 37 CFR 1.136(a). In no event, however, may a reply be timely filed
after SIX (6) MONTHS from the mailing date of this communication. - If NO period for reply is specified above, the maximum statutory period will apply and will expire SIX (6) MONTHS from the mailing date of this communication. - Failure to reply within the set or extended period for reply will, by statute, cause the application to become ABANDONED (35 U.S.C. § 133).
Any reply received by the Office later than three months after the mailing date of this communication, even if timely filed, may reduce any earned patent term adjustment. See 37 CFR 1.704(b).
Status
1)[8J Responsive to communication(s) filed on 12 March 2010.
2a)[8J This action is FINAL. 2b)0 This action is non-final.
3)0 Since this application is in condition for allowance except for formal matters, prosecution as to the merits is
closed in accordance with the practice under Ex parte Quayle, 1935 C.D. 11, 453 O.G. 213.
Disposition of Claims
4)[8J Claim(s) 1-18.20.21.27.28.33.34 and 53-60 is/are pending in the application.
4a) Of the above claim(s) __ is/are withdrawn from consideration.
5)0 Claim(s) __ is/are allowed.
6)[8J Claim(s) 1-18. 20. 21. 27. 28. 33. 34. 53-60 is/are rejected.
7)0 Claim(s) __ is/are objected to.
8)0 Claim(s) __ are subject to restriction and/or election requirement.
Application Papers
9)0 The specification is objected to by the Examiner.
10)0 The drawing(s) filed on __ is/are: a)O accepted or b)O objected to by the Examiner.
Applicant may not request that any objection to the drawing(s) be held in abeyance. See 37 CFR 1.85(a).
Replacement drawing sheet(s) including the correction is required if the drawing(s) is objected to. See 37 CFR 1.121 (d).
11 )0 The oath or declaration is objected to by the Examiner. Note the attached Office Action or form PT0-152.
Priority under 35 U.S.C. § 119
12)0 Acknowledgment is made of a claim for foreign priority under 35 U.S.C. § 119(a)-(d) or (f).
a)O All b)O Some* c)O None of:
1.0 Certified copies of the priority documents have been received.
2.0 Certified copies of the priority documents have been received in Application No. __ .
3.0 Copies of the certified copies of the priority documents have been received in this National Stage
application from the International Bureau (PCT Rule 17 .2(a)).
*See the attached detailed Office action for a list of the certified copies not received.
Attachment(s)
1) 0 Notice of References Cited (PT0-892) 2) 0 Notice of Draftsperson's Patent Drawing Review (PT0-948)
4) 0 Interview Summary (PT0-413) Paper No(s)/Mail Date. __ .
5) 0 Notice of Informal Patent Application 3) 0 Information Disclosure Statement(s) (PTO/SB/08) Paper No(s)/Mail Date __ .
U.S. Patent and Trademark Office
PTOL-326 (Rev. 08-06)
6) 0 Other: __ .
Office Action Summary Part of Paper No./Mail Date 20100421
Page 242 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
DETAILED ACTION
Information Disclosure Statement
Page 2
1. The listing of references in the specification is not a proper information disclosure
statement. 37 CFR 1.98(b) requires a list of all patents, publications, or other
information submitted for consideration by the Office, and MPEP § 609.04(a) states,
"the list may not be incorporated into the specification but must be submitted in a
separate paper." Therefore, unless the references have been cited by the examiner on
form PT0-892, they have not been considered.
Claim Rejections - 35 USC § 112
2. The following is a quotation of the first paragraph of 35 U.S.C. 112:
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 of carrying out his invention.
3. Claims 53-60 are rejected under 35 U.S.C. 112, first paragraph, as failing to
comply with the written description requirement. The claim(s) contains subject matter
which was not described in the specification in such a way as to reasonably convey to
one skilled in the relevant art that the inventor(s), at the time the application was filed,
had possession of the claimed invention. The Examiner cannot find support for the
limitation of "degrading the diversion agent after the performing the first treatment step
on the second target zone." It appears that there is support for a delayed degradable
Page 243 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 3
particle - but the specification does not indicate that the delayed degradation occurs
after a treatment step on a second zone.
Claim Rejections - 35 USC§ 103
4. The following is a quotation of 35 U.S.C. 103(a) which forms the basis for all
obviousness rejections set forth in this Office action:
(a) A patent may not be obtained though the invention is not identically disclosed or described as set forth in section 102 of this title, if the differences between the subject matter sought to be patented and the prior art are such that the subject matter as a whole would have been obvious at the time the invention was made to a person having ordinary skill in the art to which said subject matter pertains. Patentability shall not be negatived by the manner in which the invention was made.
5. Claims 1, 3, 4, 8, 10, 11, 12, 33, and 34 are rejected under 35 U.S.C. 103(a) as
being unpatentable over Chang et al. (US 2003/0119680) in view of Lehman et al. (US
2007 /0272407).
With respect to claims 1, 33, and 34, teaches a method of well treatment,
comprising: a) establishing fluid connectivity between a wellbore and at least one target
zone for treatment within a subterranean formation intersected by the wellbore (lines 1-
3; the fluids of the invention can be pumped as a single fluid, which stimulate and divert
in one step - wherein diverting and stimulating fluids are inherently added to a target
zone of a formation in order to divert and stimulate) ;b) deploying coiled tubing into the
wellbore (line 5: using coiled tubing); c) introducing a treatment composition into the
wellbore (line 2: pumped as a single fluid); d) contacting a target zone within the
subterranean formation with the treatment composition (line 2: pumped as a single fluid
- wherein the fluid would be pumped to a treatment zone, in order to perform the
functions of diverting and stimulating); e) introducing a diversion agent through the
Page 244 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 4
coiled tubing to an interval within the wellbore (lines 2 and 3: a single fluid which will
stimulate and divert); and repeating steps c) through d) for more than one target zone
(lines 5-6: using coiled tubing moved up and down while injecting - wherein moving the
coiled tubing up and down would inherently introduce the pumped fluid to more than
one zone). Chang et al. does not disclose measuring a parameter indicative of
diversion wherein the act of measuring comprises measuring microseismic activity.
Lehman et al. teach measuring microseismic activity of a fracture in order to measure
and monitor a fracturing operation, which is indicative of diversion (see paragraphs 27
and 29). It would have been obvious to one having ordinary skill in the art at the time of
the invention to modify Chang et al. by measuring microseismic activity in a fracture as
taught by Lehman et al. in order to monitor and measure a fracturing operation, which in
turn would indicate whether the diversion agent was diverting the treatment fluid.
With respect to claim 3, Chang et al. disclose that the treatment composition
comprises a stimulation fluid (see paragraph 2).
With respect to claim 4, Chang et al. disclose the act of introducing the treatment
composition comprises pumping the composition under pressure (see paragraph 22).
With respect to claim 8, Chang et al. disclose that after contacting the target
subterranean formation with the treatment composition, the diversion agent is
introduced into the formation (see paragraph 20).
With respect to claim 10, Chang et al. disclose repeating act e) (see paragraph
24).
Page 245 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 5
With respect to claim 11, Chang et al. disclose repeating act a) and b) prior to
repeating acts c) through d) (see paragraph 20).
With respect to claim 12, Chang et al. disclose that the diversion agent consists
of non-degradable material (see abstract).
6. Claims 1-7, 9-11, 13-18, 20-21, 27, 28, 33, 34, 53, 54, 59, and 60 are rejected
under 35 U.S.C. 103(a) as being obvious over Boney et al. (US 2003/0106690) in view
of Lehman et al (US 2007/0272407).
With respect to claim 1, 33, and 34, Boney et al. disclose a method of well
treatment, comprising: a) establishing fluid connectivity between a wellbore and at least
one target zone for treatment within a subterranean formation intersected by the
wellbore;b) deploying coiled tubing into the wellbore (see paragraph 45); c) introducing
a treatment composition into the wellbore(see paragraph 25); d) contacting a target
zone within the subterranean formation with the treatment composition (see paragraph
25); e) introducing a diversion agent through the coiled tubing to an interval within the
wellbore(see paragraph 24; wherein the filter cake acts as a diversion agent, diverting
the fluid to form a new fracture without zonal isolation); and repeating steps c) through
d) for more than one target zone (see paragraph 25). Boney et al. does not disclose
measuring a parameter indicative of diversion wherein the act of measuring comprises
measuring microseismic activity. Lehman et al. teach measuring microseismic activity
of a fracture in order to measure and monitor a fracturing operation, which is indicative
of diversion (see paragraphs 27 and 29). It would have been obvious to one having
Page 246 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 6
ordinary skill in the art at the time of the invention to modify Boney et al. by measuring
microseismic activity in a fracture as taught by Lehman et al. in order to monitor and
measure a fracturing operation, which in turn would indicate whether the diversion agent
was diverting the treatment fluid.
With respect to claim 2, Boney et al. disclose that the wellbore is cased and
further comprising the act of perforating the casing (see paragraph 47).
With respect to claim 3, Boney et al. disclose a stimulation fluid (see paragraphs
2 and 3).
With respect to claim 4, Boney et al. disclose introducing the treatment
composition comprises pumping the composition under pressure (see paragraph 3).
With respect to claim 5, Boney et al. disclose that at least a portion of the
wellbore comprises a generally horizontal section (see paragraph 52).
With respect to claim 6, Boney et al. teaches that the diversion agent comprises
fiber (see paragraph 45, wherein fiber may be added to the pad, which forms the filter
cake, which is the diversion agent).
With respect to claim 7, Boney et al. teaches that the diversion agent comprises
degradable material (see paragraphs 24 and 25).
With respect to claim 9, Boney et al. disclose that a portion of the wellbore is
deviated or horizontal (see paragraph 52).
With respect to claim 10, Boney et al. disclose repeating step (e) (see paragraph
45).
Page 247 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 7
With respect to claim 11, Boney et al. disclose repeating steps a and b before c
and d (see paragraph 45.
With respect to claims 13 and 59, Boney et al. disclose that the diversion agent is
stored in the coiled tubing between acts of introducing the diversion agent to an interval
(see paragraph 45, wherein some of the agent would inherently be stored in the tubing
between fractures).
With respect to claims 14 and 28, Boney et al. disclose a method of treating more
than one target zone of interest in a subterranean formation, the method comprising:a)
pumping a treatment composition to contact at least one target zone of interest with the
treatment composition (see paragraph 25); b) monitoring the pumping of the treatment
composition and measuring a parameter indicative of treatment (see paragraph 5); c)
pumping a diversion agent to a desired diversion interval in the wellbore (see paragraph
24 ); d) monitoring the pumping of the diversion agent and measuring a parameter
indicative of diversion (see paragraph 31 ); e) pumping a treatment composition to
contact at least one other target zone of interest (see paragraph 25); f) modifying at
least one of acts a) and c) based on at least one of the measured parameters (see
paragraphs 5 and 31 ). Boney et al. does not disclose measuring a parameter indicative
of diversion wherein the act of measuring comprises measuring microseismic activity.
Lehman et al. teach measuring microseismic activity of a fracture in order to measure
and monitor a fracturing operation, which is indicative of diversion (see paragraphs 27
and 29). It would have been obvious to one having ordinary skill in the art at the time of
the invention to modify Boney et al. by measuring microseismic activity in a fracture as
Page 248 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 8
taught by Lehman et al. in order to monitor and measure a fracturing operation, which in
turn would indicate whether the diversion agent was diverting the treatment fluid.
With respect to claim 15, Boney et al. disclose that at least a portion of the
wellbore comprises a generally deviated or horizontal section (see paragraph 52).
With respect to claim 16, Boney et al. disclose that at least one of the diversion
interval and the target zone of interest are located within said generally horizontal
section (see paragraph 45).
With respect to claim 17, Boney et al. disclose repeating acts a) through d) (see
paragraph 45).
With respect to claim 18, Boney et al. disclose injecting the treatment
composition in the annulus between a coiled tubing and the wellbore (see paragraph 25;
wherein some treatment fluid would inherently be in the annulus).
With respect to claim 20, Boney et al. disclose that the fiber comprises a
degradable material (see paragraphs 24, 25 and 45).
With respect to claim 21, see the rejection of claim 1. In addition, Boney et al.
disclose deploying coiled tubing into a wellbore, wherein connectivity is established by
one or more of perforating, jetting, sliding sleeve, or opening a valve, and establishing
fluid connectivity between a wellbore and at least one target zone for treatment within a
subterranean formation intersected by the wellbore (see paragraph 47).
With respect to claim 27, Boney et al. disclose the modifying at least one of the
act of providing a diversion and the act of injecting a treatment composition based on
the measured well bore parameter (see paragraphs 5 and 31 ).
Page 249 of 399Halliburton Energy Services, Inc.
Exhibit 1008
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Application/Control Number: 11/751 , 172
Art Unit: 3672
Page 9
With respect to claim 53, see the rejection of claim 1. In addition, Boney et al.
disclose degrading the diversion agent after the performing the first step on the second
target zone (see paragraph 25).
With respect to claim 54, Boney et al. disclose successively treating each
addition target zone (see paragraphs 24, 25, and 45).
With respect to claims 55-58, Boney et al. discloses the claimed invention except
for the order the zones are treated in. It would have been an obvious matter of design
choice to target the zones as claimed, since applicant has not disclosed that targeting
the zones in a certain order solves any stated problem or is for any particular purpose
and it appears that the invention would equally well with targeting the zones in the order
presented in Boney et al.
With respect to claim 60, Boney et al. disclose measuring a parameter indicative
of diversion (see paragraph 31 ).
Response to Arguments
7. Applicant's arguments filed 3/12/10 have been fully considered but they are not
persuasive. Applicant argues that support for claim 53 is found in figures 2, 3 and in
paragraphs 24 and 46-49. While the figures and paragraphs indicate that a diversion
agent can be inserted into multiple zones, there is nothing that teaches degrading the
diversion agent after performing the first treatment step on the second target zone.
There is no teaching of when the diversion agent is degraded.
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