f)...contacting a target zone within the subterranean formation with the treatment composition,...

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).

- 3 -

Page 201 of 399Halliburton Energy Services, Inc.

Exhibit 1008


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;

- 4 -


Exhibit 1008


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:

- 5 -


Exhibit 1008


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.

- 6 -


Exhibit 1008


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.


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 -


Exhibit 1008


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

- 8 -


Exhibit 1008


"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

- 9 -

/Rachel E. Greene/


Exhibit 1008


SCHLUMBERGER TECHNOLOGY CORPORATION 555 Industrial Blvd. Sugar Land, Texas 77478 281.285 .4925

- 10 -


Exhibit 1008

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

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


Exhibit 1008

Application/Control Number: 11/751 , 172

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,


Exhibit 1008


Art Unit: 3672

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


Exhibit 1008


Art Unit: 3672

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).


Exhibit 1008


Art Unit: 3672

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


Exhibit 1008


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


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).


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).


Exhibit 1008


Art Unit: 3672

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.




Exhibit 1008


Art Unit: 3672

Page 8


the invention to modify Boney et al. by measuring microseismic activity in a fracture as




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).


Exhibit 1008


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 ).


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.


Exhibit 1008


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


Exhibit 1008


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


Exhibit 1008

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-

L US-

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.


PT0-892 (Rev. 01-2001) Notice of References Cited Part of Paper No. 20091208


Exhibit 1008


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

1 ,/ ,/ ,/ ,/

2 ,/ ,/ ,/ ,/

3 ,/ ,/ ,/ ,/

4 ,/ ,/ ,/ ,/

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6 ,/ ,/ ,/ ,/

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19 - - - -

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33 ,/ ,/ ,/ ,/

34 ,/ ,/ ,/ ,/

35 - - - -

36 - - - -

U.S. Patent and Trademark Office Part of Paper No.: 20091208


Exhibit 1008


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

37 - - - -

38 - - - -

39 - - - -

40 - - - -

41 - - - -

42 - - - -

43 - - - -

44 - - - -

45 - - - -

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53 ,/ ,/ ,/

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57 ,/ ,/ ,/

58 ,/ ,/ ,/

59 ,/ ,/ ,/

60 ,/ ,/ ,/

U.S. Patent and Trademark Office Part of Paper No.: 20091208


Exhibit 1008

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


Exhibit 1008

SALANText Box

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


Exhibit 1008

SALANText Box

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


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

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 -


Exhibit 1008


THE PENDING CLAIMS

1. (Previously Presented) A method of well treatment, comprising:






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 -


Exhibit 1008


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 -


Exhibit 1008


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 -


Exhibit 1008

Application Serial No: 11/751,172 Response to Office Action mailed December 21, 2009






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 -


Exhibit 1008


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.

- 6 -


Exhibit 1008



target zone, and additional target zones are treated in an order from a lowest in-situ stress to a

highest in-situ stress.


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 -


Exhibit 1008


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


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,


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 -


Exhibit 1008


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 -


Exhibit 1008


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 -


Exhibit 1008

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


Exhibit 1008

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

This Acknowledgement Receipt evidences receipt on the noted date by the USPTO of the indicated documents, characterized by the applicant, and including page counts, where applicable. It serves as evidence of receipt similar to a Post Card, as described in MPEP 503.

New A~~lications Under 35 U.S.C. 111 If a new application is being filed and the application includes the necessary components for a filing date (see 37 CFR 1.53(b)-(d) and MPEP 506), a Filing Receipt (37 CFR 1.54) will be issued in due course and the date shown on this Acknowledgement Receipt will establish the filing date of the application.

National Stage of an International A~~lication under 35 U.S.C. 371 If a timely submission to enter the national stage of an international application is compliant with the conditions of 35 U.S.C. 371 and other applicable requirements a Form PCT/DO/E0/903 indicating acceptance of the application as a national stage submission under 35 U.S.C. 371 will be issued in addition to the Filing Receipt, in due course.

New International A~~lication Filed with the USPTO as a Receiving Office If a new international application is being filed and the international application includes the necessary components for an international filing date (see PCT Article 11 and MPEP 181 O), a Notification of the International Application Number and of the International Filing Date (Form PCT/R0/1 OS) will be issued in due course, subject to prescriptions concerning national security, and the date shown on this Acknowledgement Receipt will establish the international filing date of the application.


Exhibit 1008

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))

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

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 __ .


PTOL-326 (Rev. 08-06)

6) 0 Other: __ .

Office Action Summary Part of Paper No./Mail Date 20100421


Exhibit 1008


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


Exhibit 1008


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


Exhibit 1008


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.




the invention to modify Chang et al. by measuring microseismic activity in a fracture as



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


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).


Exhibit 1008


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


Exhibit 1008


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



wellbore comprises a generally horizontal section (see paragraph 52).


fiber (see paragraph 45, wherein fiber may be added to the pad, which forms the filter

cake, which is the diversion agent).


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).


Exhibit 1008


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.




the invention to modify Boney et al. by measuring microseismic activity in a fracture as


Exhibit 1008


Art Unit: 3672

Page 8




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).


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 ).


Exhibit 1008


Art Unit: 3672

Page 9


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.

Page 250 of 399

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