Christopher Michael. Jones et al.

Patent Trials and Appeals Board

Dec 30, 2019

15074315 - (D) (P.T.A.B. Dec. 30, 2019)

UNITED STATES PATENT AND TRADEMARK OFFICE
UNITED STATES DEPARTMENT OF COMMERCE
United States Patent and Trademark Office
Address: COMMISSIONER FOR PATENTS
P.O. Box 1450
Alexandria, Virginia 22313-1450
www.uspto.gov
APPLICATION NO. FILING DATE FIRST NAMED INVENTOR ATTORNEY DOCKET NO. CONFIRMATION NO.
15/074,315 03/18/2016 Christopher Michael Jones 164.2003-
IP-012925 C1C1US
1805
138627 7590 12/30/2019
Gilliam IP PLLC (Halliburton)
7200 N. Mopac
Suite 440
Austin, TX 78731
EXAMINER
XU, XIAOYUN
ART UNIT PAPER NUMBER
1797
NOTIFICATION DATE DELIVERY MODE
12/30/2019 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):
uspto@gilliamip.com
PTOL-90A (Rev. 04/07)
UNITED STATES PATENT AND TRADEMARK OFFICE
____________

BEFORE THE PATENT TRIAL AND APPEAL BOARD
____________

Ex parte CHRISTOPHER MICHAEL JONES and LOUIS W. ELROD
____________

Appeal 2019-000069
Application 15/074,315
Technology Center 1700
____________

Before BEVERLY A. FRANKLIN, MARK NAGUMO, and
N. WHITNEY WILSON, Administrative Patent Judges.

WILSON, Administrative Patent Judge.

DECISION ON APPEAL
Appellant1 appeals under 35 U.S.C. § 134(a) from the Examiner’s
Oct. 3, 2017 decision finally rejecting claims 1–7, 11, 13, and 15–31 (“Final
Act.”). We have jurisdiction over the appeal under 35 U.S.C. § 6(b).
We affirm-in-part.2

1 We use the word “Appellant” to refer to “applicant” as defined in
37 C.F.R. § 1.42. Appellant identifies Halliburton Energy Services, Inc. as
the real party in interest (Appeal Br. 3).
2 The Board issued a decision in Appeal No. 2014-001831 on January 19,
2016 (“‘1831 Appeal Decision”). In that decision, we affirmed the
Examiner’s rejections. The application at issue in the present appeal is the
continuation of the application at issue in the ‘1831 Appeal, and the claims
are very similar in many respects, but not identical, and the applied prior art
is identical.
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Application 15/074,315

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CLAIMED SUBJECT MATTER
Appellant’s invention is directed to a method for determining
geological formation measurements (Abstract). In particular, it is said that
the formation rock properties — principally porosity and permeability — are
measured by diffusion for application in the oilfield industry (Spec. ¶ 2).
Independent claims 1 and 17 are representative of the claims on appeal and
are reproduced below from the Claims Appendix of the Appeal Brief.
1. A method to determine formation measurements, the
method comprising:
(1) collecting a plurality of formation samples from a
subsurface formation that includes a formation fluid;
(2) analyzing a first formation sample of the plurality to
determine a salinity of the first formation sample;
(3) adding a concentration fluid to a reservoir, wherein
the concentration fluid is an isotopic species of a component of
the formation fluid;
(4) sufficiently matching a salinity of the concentration
fluid in the reservoir to the salinity of the first formation
sample;
(5) placing a second formation sample of the plurality in
the concentration fluid of the reservoir; and
(6) analyzing the concentration fluid in the reservoir as
the second formation sample and fluid equilibrate sufficient to
provide diffusion measurements of the second formation
sample.

17. A method to determine formation measurements, the
method comprising:
(1) collecting a formation sample from a subsurface
formation that includes a formation fluid, wherein the formation
sample comprises a plurality of cutting from the subsurface
formation;
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(2) adding a concentration fluid to a reservoir, wherein
the concentration fluid is an isotopic species of a component of
the formation fluid;
(3) placing the formation sample in the concentration
fluid of the reservoir; and
(4) analyzing the concentration fluid as the formation
sample and the concentration fluid equilibrate, sufficient to
provide diffusion measurements of the formation sample.

[Step numbers added.]

REJECTIONS3
I. Claims 1–7, 11, 15–22, and 25–31 are rejected under
35 U.S.C. § 103(a) as being unpatentable over Rees4 in view of Loon.5
II. Claims 13, 23, and 24 are rejected under 35 U.S.C. § 103(a) as
being unpatentable over Rees in view of Loon, and further in view of
O’hira.6

3 The rejection of claims 1–7, 11, 13, and 15–31 under 35 U.S.C. § 112,
second paragraph was withdrawn by the Examiner (Ans. 7). Accordingly,
that rejection is not on appeal and will not be addressed by the Board.
4 Van Rees et al., Evaluation of Laboratory Techniques for Measuring
Diffusion Coefficients in Sediments, 25 ENVIRON. SCI. TECHNOL. 1805–11
(1991).
5 L. R. Van Loon & A. Jakob, Evidence for a Second Transport Porosity for the
Diffusion of Tritiated Water (HTO) in a Sedimentary Rock (Opalinus Clay – OPA):
Application of Through- and Out-Diffusion Techniques, 61 TRANSPORT IN POROUS
MEDIA 193–214 (2005).
6 O’hira et al., Tritium Safety-Related Studies at TPL of JAERI, 16 JOURNAL OF FUSION
ENERGY 219–224 (1997).
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DISCUSSION
Appellant argues the claims in three groups: (1) claims 1–7, 15, 16,
and 25, (2) claims 17–24 and 26, and (3) claims 27–31. We will address
each group in turn (Appeal Br. 2).
Claims 1–7, 15, 16, and 25. These claims are all subject to Rejection I.
The Examiner’s findings supporting this rejection are set forth at pages 3–6 of
the Final Action. The Examiner finds that Rees discloses a method which
includes each of steps (1), (3), (5), and (6) from claim 1 (Final Act. 3, citing
Rees, p. 1605, col. 1 ¶¶ 0, 1, and col. 2, ¶¶ 5, 6). The Examiner also finds that
Rees does not explicitly teach step (4) (matching the salinity7 of the
concentration fluid in the reservoir with the formation sample) (Final Act. 3).
The Examiner further finds that Rees teaches that a concentration
gradient between the overlying water and the sediment pore-water can
develop as a consequence of added contaminants to the overlying water, that
Rees teaches that salinity differences influence diffusion, and that Loon
teaches using synthetic OPA8 pore water to match the salinity of the fluid in
a reservoir to the salinity of the formation sample before a diffusion
measurement (Ans. 3–4, citing Rees, p. 1605, col. 1,¶ 2, and Loon, p. 196,
¶ 2, and Table III). The Examiner determines that a person of skill in the art:
would have been motivated to analyze the [salinity] of a first
sample of the plurality and sufficiently match the salinity to the
fluid in the reservoir to the salinity of the formation sample
without regard to a specific composition of the fluid (salinity
only concerns the salt concentration), in order to reduce salinity

7 The Examiner finds that “salinity” is the concentration of salt in a solution
(Ans. 3).
8 OPA is Opalinus clay, which is a compacted argillaceous rock containing
mainly kaolinite, illite and illite/smectite clay minerals (Loon, p. 195).
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difference caused diffusion between the sample and the
reservoir and remove one variable from the diffusion
measurements. An experimentalist would have been motivated
to check, by experiment, the assumption of equilibrium
between the substrate and the fluid in the reservoir. Verification
of the validity of the assumption would indicate that the salinity
of the fluid has been "sufficiently matched" to the salinity of the
first formation.

(Final Act. 4).
Appellant disagrees with the Examiner’s reasoning as set forth above
(Appeal Br. 10). According to Appellant, the section of Loon relied upon by
the Examiner indicates that “the composition of the artificial pore water is
assumed to be in equilibrium with the Opalinus clay according to Table III”
(id.). Appellant contends that the Examiner “is attempting to equate the
artificial pore water with concentration fluid and the Opalinus clay with the
first formation sample” (id.). Appellant argues that equilibrating between the
pore water and the Opalinus clay does not result in equal salinity between the
two, but only causes their respective salinities to change to a point where they
would not change further over time (i.e., be in equilibrium) (id.).
In response, the Examiner finds that because salt diffuses from the high
concentration side to the low concentration side (a finding that Appellant does
not appear to contest), at equilibrium the salinity of pore water will match the
salinity of the Opalinus clay (corresponding to the formation) (Ans. 8). While
Appellant argues that equilibration does not require matching (Reply Br. 2–3),
Appellant does not explain why the equilibrium described by Loon would not
be “sufficiently matched” in salinity, as required by the claims.
Moreover, regardless of the teachings of Loon, as explained by the
Examiner, a person of skill in the art
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would have been motivated to analyze the [salinity] of a first
sample of the plurality and sufficiently match the salinity to the
fluid in the reservoir to the salinity of the formation sample
without regard to a specific composition of the fluid (salinity
only concerns the salt concentration), in order to reduce salinity
difference caused diffusion between the sample and the
reservoir and remove one variable from the diffusion
measurements

(Final Act. 4). Appellant has not persuasively disputed this reasoning.
Accordingly, Appellant has not, by a preponderance of the evidence,
shown reversible error in the Examiner’s determination that the limitation at
issue would have been obvious. Therefore, we affirm the rejection of claims
1–7, 15, 16, and 25.
Claims 17–24 and 26. Appellant argues that the rejection of claim 17
suggests that the Examiner has correlated the following elements of claim 17
to the disclosures of Rees as follows:

(Appeal Br. 12). According to Appellant, “Rees is limited to [the] use of the
fluid (the lake water) from which the sample (sediment) is retrieved in order
to obtain its desired results,” while claim 17 requires adding a separate fluid
that is an isotropic species of a component of the formation fluid (id.).
Although Appellant concedes that Rees’s lake water is “spiked with a tritium
tracer,” Appellant argues that this spiking cannot correspond to the
“concentration fluid” recited in claim 17 because “claim 17 specifically recites
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that a different concentration fluid is added to the reservoir, wherein the
concentration fluid is an isot[r]opic species of a component of the formation
fluid” (Appeal Br. 12–13) (emphasis omitted).
Appellant’s argument is not persuasive. As explained by the Examiner
(Ans. 9), Rees teaches adding tritium water (corresponding to the
concentration fluid) to a reservoir. Tritium water is an isotropic species of a
component (water) of the formation, meeting the claim terms. Appellant
argues that claim 17 requires a concentration fluid which is different from the
formation fluid, which is not taught by Rees (Reply Br. 3–4). This argument
is also not persuasive. As explained by the Examiner, tritium water
(corresponding to the claimed concentration fluid) is different from the
formation fluid (water). Appellant has not directed our attention to, and our
review has not yielded, a definition in the Specification of the terms
“concentration fluid” or “component of the formation fluid” that would
exclude any component of a fluid in the formation, including water.
Claims 27–31. Claims 27–31 each recite
maintaining a salinity of the second formation sample based on
placement of a semi-permeable membrane in the reservoir
between the concentration fluid and the second formation
sample.

In rejecting these claims, the Examiner finds that Rees does not
specifically teach placement of a semi-permeable membrane in the reservoir
between the concentration fluid and the second formation sample, but that
“placing a semi-permeable membrane between two diffusible spaces is
conventional” such that “[n]o inventive step is invol[v]ed” (Final Act. 6). In
the Answer, the Examiner expanded on the rationale, finding that:
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Rees teaches placement of a semi-permeable membrane (glass
microfiber paper) in the reservoir between the concentration
fluid and the second formation sample (page 1605, col. 2, par
6). Rees-Loon teaches matching the salinity of the
concentration fluid and the salinity of the second formation
sample. Therefore, Rees-Loon teaches maintaining a salinity of
the second formation sample based on placement of a semi-
permeable membrane in the reservoir between the concentration
fluid and the second formation sample, by matching the salinity
at the fluid side of the membrane with the salinity of the
formation side of the membrane.

(Ans. 9). However, as correctly noted by Appellant (Reply Br. 5–6), Rees
explicitly states that the glass micro-fiber paper is of sufficiently small
diameter so as not to inhibit the diffusion process between the overlying
reservoir solution and the sediment column, and thus cannot satisfy the claim
requirement that the semi-permeable membrane maintain a salinity of the
second formation sample (i.e., prevent diffusion).
Accordingly, we reverse the rejection of claims 27–31.

CONCLUSION
In summary:

Claims
Rejected
35 U.S.C. §   Reference(s)/Basis Affirmed Reversed
1–7, 11,
15–22,
25–31
103 Rees, Loon 1–7, 11,
15–22,
25, 26
27–31
13, 23, 24 103 Rees, Loon, O’hira 13, 23, 24
Overall
Outcome
1–7, 11,
13, 15–26
27–31

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No time period for taking any subsequent action in connection with
this appeal may be extended under 37 C.F.R. § 1.136(a). See
37 C.F.R. § 1.136(a)(1)(iv).

AFFIRMED-IN-PART