Ex Parte Keers et al

Patent Trial and Appeal Board

Oct 16, 2018

12575648 (P.T.A.B. Oct. 16, 2018)

UNITED STA TES p A TENT AND TRADEMARK OFFICE
APPLICATION NO. FILING DATE
12/575,648 10/08/2009
28116 7590 10/18/2018
WestemGeco L.L.C.
10001 Richmond Avenue
IP Administration Center of Excellence
Houston, TX 77042
FIRST NAMED INVENTOR
HenkKeers
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
ATTORNEY DOCKET NO. CONFIRMATION NO.
14.0432-US-NP 1431
EXAMINER
BREIER, KRYSTINE E
ART UNIT PAPER NUMBER
3645
NOTIFICATION DATE DELIVERY MODE
10/18/2018 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):
USDocketing@slb.com
jalverson@slb.com
SMarckesoni@slb.com
PTOL-90A (Rev. 04/07)
UNITED STATES PATENT AND TRADEMARK OFFICE
BEFORE THE PATENT TRIAL AND APPEAL BOARD
Ex parte HENK KEERS, PHIL KITCHENSIDE,
DA VE NICHOLS, SUSANNE RENTSCH and
GABRIELE BUSANELLO
Appeal2016-006839
Application 12/575,648
Technology Center 3600
Before STEVEN D.A. McCARTHY, JILL D. HILL and
PAUL J. KORNICZKY, Administrative Patent Judges.
McCARTHY, Administrative Patent Judge.
DECISION ON APPEAL
1 STATEMENT OF THE CASE
2 The Appellants 1 appeal under 35 U.S.C. § 134(a) from the Examiner's
3 decision finally rejecting claims 1-7, 9-16, 18 and 19. Claims 8 and 17 are
4 cancelled. We have jurisdiction under 35 U.S.C. § 6(b ).
5 We sustain the rejection of claims 1-3, 6, 9-12, 15, 16 and 18 under
6 pre-AIA 35 U.S.C. § 103(a) as being unpatentable over Billette et al.,
7 Practical Aspects and Applications of 2D Stereotomography, 68
8 GEOPHYSICS 1008 (Soc'y Exploration Geophysicists, May-June 2003)
The Appellants identify WestemGeco, L.L.C., as the real party in
interest. (See Appeal Brief, dated Jan. 4, 2016, at 3).
Appeal 2016-006839
Application 12/575,648
1 (hereinafter "Billette"), in view of Singh (US 2006/0239117 Al, publ. Oct.
2 26, 2006) and Sherrill (US 7,373,252 B2, issued May 13, 2008). We also
3 sustain the rejection of claims 5 and 17 under§ I03(a) as being unpatentable
4 over Billette, Singh, Sherrill and Krebs (US 6,253,157 Bl, issued June 26,
5 2001); and of claim 19 under§ I03(a) as being unpatentable over Sherrill
6 and Singh.
7 We do not sustain the rejection of claims 4, 7 and 13 under§ I03(a) as
8 being unpatentable over Billette, Singh and Sherrill.
9
10 THE CLAIMED SUBJECT MATTER
11 The claims on appeal relate to techniques for use in marine seismic
12 surveys. (See Spec., paras. 1-3). We adopt the following findings of the
13 Examiner:
14 Seismic data can be obtained in various ways. In the current
15 application, the seismic data is obtained using what is called a
16 towed marine survey. In a towed marine survey a vessel is driven
1 7 over water while dragging equipment. Generally the equipment
18 includes cables, called streamers, which contain sensors for
19 sensing seismic waves. The equipment often also includes one
20 or more seismic sources. During the survey seismic waves are
21 generated by the seismic source, which then travel downward[ly]
22 and reflect or refract off of the various interfaces encountered,
23 such as for example the water bottom and the boundary between
24 different rock types. The seismic waves which return to the
25 surface are collected by the seismic sensors, recorded, and
26 analyzed to gain information about the subsurface.
27 (Examiner's Answer, mailed May 6, 2016 ("Ans."), at 2; see generally
28 Sherrill, col. 3, 1. 59 - col. 4, 1. 59 & Fig. 1; Spec., para 2).
29 According to the Specification, the "goal of the seismic acquisition is
30 to build up an image of a survey area for purposes of identifying
2
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Application 12/575,648
1 subterranean geological formations .... Subsequent analysis of the
2 representation may reveal probable locations of hydrocarbon deposits in
3 subterranean geological formations." (Spec., para. 22). The signals
4 produced by the sensors, referred to as "traces," must be processed to yield
5 useful geological information regarding the subterranean formations.
6 One technique for processing such traces, stated in very general terms,
7 is to collect traces into groups or "gathers" based on common characteristics,
8 such as a common seismic source; a common receiver; a common midpoint
9 between the source and the receiver; or a common offset between the source
10 and the receiver. The useful traces within a gather are "picked," thereby
11 minimizing the effect of "noise." If one may assume that the interfaces from
12 which the waves represented by the traces in the gather reflect are
13 horizontal, that is, parallel with the surface of the water, each picked trace
14 may be transformed so as to approximate the result that might be obtained
15 by a shot traveling straight down and up to a receiver coincident with the
16 shot. These approximations may then be averaged, or "stacked," across the
17 gather to produce useful geological information. (See generally Weiderhold,
18 Seismic Methods 33-50, reproduced at https://www.liag-hannover.de
19 /fileadmin/user_upload/ dokumente/Grundwassersysteme/BURV AL/buch
20 /033-050.pdf ( dated Feb. 4, 2015; last accessed October 2, 2018).
21 If the interface cannot be assumed to be parallel to the surface of the
22 water (that is, if a "zero dip approximation" or "ID assumption" is not
23 valid), more sophisticated techniques must be used to transform and stack
24 the traces within a gather. (See Billette 1008; see generally Sherrill, col. 6, 1.
25 20- col. 7, 1. 12 & col. 10, 11. 1-22). These more sophisticated processes
3
Appeal 2016-006839
Application 12/575,648
1 rely on knowledge of the local wave velocity. Once again we adopt the
2 findings of the Examiner:
3 The current application is directed to a method of migration
4 velocity analysis .... Basically, migration velocity analysis is a
5 method for creating a velocity model of the subsurface. A
6 velocity model of the subsurface is a stratified map which defines
7 the velocity at which a seismic wave will travel at different points
8 under the surface. This map is important in generating accurate
9 images of the subsurface and thus accurately determining the
10 location of important features such as a hydrocarbon deposit.
11 The first step of data migration is the process of taking data
12 recorded at the sensor point (near the surface of the water) and
13 using the current velocity model to essentially back trace the
14 sound wave to obtain an estimate of what a hypothetical sensor
15 positioned at a different point (generally below the surface)
16 would have recorded. Using this estimated data, an image is
17 generated at step two and then analyzed for [error]. Finally in
18 step three the [ error is] used to update the velocity model to be
19 more accurate. These steps can then be repeated until the model
20 is sufficiently accurate.
21 (Ans. 3 & 4, citing Migration Velocity Analysis, http://sepwww.stanford.edu
22 /data/media/public/sep/biondo/HTML/VelAn.html; see also Billette 1009 &
23 1010).
24 The Specification suggests performing the migration velocity analysis
25 using a technique called stereotomography. In particular, the Specification
26 suggests the use of the stereotomographic technique described in Billette,
27 which uses not only travel time curves, but also the slopes of the travel time
28 curves over time, to estimate local wave velocities. According to the
29 Specification, one advantage of Billette's technique is that "only locally
30 coherent events are used." (Spec., para. 26). Billette itself discloses a data
31 picking technique that automatically selects only locally coherent events.
32 (See Billette 1011-13).
4
Appeal 2016-006839
Application 12/575,648
1 The Specification describes a technique that might be implemented as
2 an improvement on Billette's method. More particularly, the Specification
3 teaches that:
4 particle motion data, such as the inline and crossline and vertical
5 particle velocity measurements ( as a non-limiting example) may
6 be used in addition to or as a replacement of the "slopes," which
7 are used in traditional stereotomography. A particular
8 implementation of the stereotomography measurement using the
9 particle motion data is described herein, although other
10 [ migration velocity analysis] techniques may be used with the
11 particle motion data, in accordance with other embodiments.
12 (Spec., para. 29). As further explanation, we again adopt the Examiner's
13 findings:
14 In the current application, the seismic data includes
15 particle motion data. Particle motion data is data which records
16 the movement of water particles. The most common type of
1 7 particle motion data is velocity data, although acceleration data
18 and pressure gradient data are also sometimes used. Velocity
19 data is measured by velocity sensors or velocimeters.
20 Acceleration data is measured by accelerometers, and pressure
21 gradients2 are generally measured using pairs of pressure
22 sensors. Sensors are often grouped into a group of three or four
23 sensors which [ are then collectively] called a multicomponent
24 sensor. Three component sensors are made up of three
25 orthogonal particle motion sensors to sense particle motion in the
26 vertical, inline (parallel to the streamer cable), and crossline
27 (perpendicular to the streamer cable) directions. Four
28 component sensors are made up of three orthogonal particle
29 motion sensors and additionally a pressure sensor which senses
30 water pressure.
31 (Ans. 2 & 3; see also Singh, para. 90; Spec., paras. 14--16 & 21).
2 Pressure gradients are related to particle accelerations. (See Singh,
para. 106).
5
1
2
3
4
5
6
7
8
9
10
11
12
13
Appeal 2016-006839
Application 12/575,648
Claims 1, 10 and 19 are independent. Claims 1 and 19 recite:
1. A method comprising:
receiving seismic data acquired by an array of seismic
sensors during a towed marine survey of a subsurface; and
processing the seismic data in a processor-based machine
to perform migration velocity analysis to determine a
background velocity model of the subsurface based at least in
part on an indication of particle motion derived from the seismic
data, a covariance indicative of errors in the indication of the
particle motion and a covariance indicative of errors in a current
version of the model.
19. A method comprising:
14 receiving seismic data acquired by an array of seismic
15 sensors during a towed marine survey of a subsurface; and
16 processing the seismic data in a processor-based machine
17 to perform migration velocity analysis to determine a
18 background velocity model of the subsurface based at least in
19 part on an indication of particle motion derived from the seismic
20 data, the determination of the background model comprising
21 determining differences between ray take off angles and ray take
22 off angles calculated based on a current version of the model.
23
24 ISSUES
25 Independent claim 1 is representative of claims 1-3, 6, 9-12, 15, 16,
26 18 and 19 for purposes of their rejection under§ 103(a) as being
27 unpatentable over Billette, Singh and Sherrill. (See Appeal Brief, dated Jan.
28 4, 2016 ("App. Br."), at 12). In particular, although the Appellants argue
29 claim 19 under a separate subheading, their argument regarding the
30 patentability of claim 19 merely incorporates by reference their arguments
6
Appeal 2016-006839
Application 12/575,648
1 regarding the patentability of claim 1. (See App. Br. 12 & 13). As such, we
2 group claim 19 with claim 1 for purposes of this appeal.
3 The Appellants argue the patentability of claims 5 and 17 over
4 Billette, Singh, Sherrill and Krebs solely on the basis of those claims'
5 ultimate dependency on independent claims 1 and 10. (See App. Br. 13). In
6 view of our affirmance of the Examiner's decision rejecting claims 1 and 10,
7 we need not address claims 5 and 1 7 separately. On the other hand, the
8 Appellants argue the patentability of claims 4, 7 and 13 separately from the
9 patentability of claims 1 and 10. (See App. Br. 10-12). We have considered
10 the Appellants' arguments regarding claims 4, 7 and 13; however, we will
11 address the patentability of these claims 4, 7 and 13 in the course of our
12 discussion relating to the patentability of claim 1. Therefore, this appeal
13 turns on one issue:
14 Would one familiar with the combined teachings of Billette, Singh
15 and Sherrill have had reason to perform the step of:
16 processing the seismic data in a processor-based machine to
1 7 perform migration velocity analysis to determine a background
18 velocity model of the subsurface based at least in part on an
19 indication of particle motion derived from the seismic data, a
20 covariance indicative of errors in the indication of the particle
21 motion and a covariance indicative of errors in a current version
22 of the model,
23 as recited in representative claim 1 (italics added)?
24
25 FINDINGS OF FACT
26 The record supports the following findings of fact ("FF") by a
27 preponderance of the evidence.
7
Appeal 2016-006839
Application 12/575,648
1 Billette
2 1. As mentioned earlier, Billette describes a method for processing
3 seismic data to perform migration velocity analysis to determine a
4 background velocity model of a subsurface. Billette' s method begins with
5 the step of picking events within a gather based on coherency (see Billette
6 1011-13). Next, an a priori local velocity model is generated. A local
7 velocity model may be represented by a vector:
8 m = [ [(X, f3s, f3R, Ts, TR)t]f=1, [ Cj ]~=1],
9 where "X'' is a position; "/Js" and "/J/' are takeoff angles; "Ts" and "T/' are
10 one-way travel times; and "C/' are weighting factors used in calculating
11 modeled velocity. (See Billette 1010). Estimated data is calculated based on
12 the local velocity model; and the velocity model vector is updated according
13 to the formula:
14 mk+l = mk - (Gi Cv1 (g(mk) - dr) Gk+ c;/)-1 X
15 Gi Cv1 (g(mk) - dr) + c;/ ( mk - mprior ),
16 where "mk" is the current velocity model vector; "mk+/' is the updated
1 7 velocity model vector; "mpnor" is the a priori velocity model vector; "g(m )"
18 is the estimated data calculated based on the local velocity model; "dm is the
19 measured data; "G/' is the Frechet derivative of the data with respect to
20 "mk;" "CJv!' is a covariance matrix indicative of errors in a current version of
21 the model; and "Cn" is a covariance matrix indicative of errors in the data
22 space. (See Billette 1010 & 1011 ). Estimated data is calculated, and the
23 velocity model vector is updated, until the velocity model vector converges
24 to a desired degree.
8
1
Appeal 2016-006839
Application 12/575,648
2. Billette teaches that "[a]nother very promising extension of
2 stereotomography concerns the joint estimation of [compression] and [shear]
3 velocity fields from multicomponent data." (Billette 1019).
4
5 Singh
6 3. Singh teaches that, during a marine survey, a seismic wave
7 reflected from the seabed or from subsea strata propagates upwardly through
8 the water toward the receivers in the towed stream. A portion of the
9 reflected wave propagates past the receivers and reflects downwardly from
10 the water/air interface at the surface. The secondarily reflected wave may
11 then propagate downwardly, back toward the receivers. The receivers may
12 then register the secondarily reflected waves as "ghost" data. Depending on
13 the strength of the shot and the properties of the environment, the receivers
14 may register additional ghost reflections from the same wave. (See Singh,
15 para. 61 ). Singh teaches that it is desirable to remove such ghost data, as
16 well as other multiple reflections or "multiples," from the traces processed to
17 produce useful geological information. (See Singh, para. 63).
18
19
20
21
22
23
24
25
26
4. Singh addresses this problem by decomposing the signals
generated by the receivers into components representing up-going and
down-going wavefields. (See Singh, para. 72). More specifically, the up-
going part of the vertical component of particle velocity, "Vz u;" the vertical
component of particle velocity, "Vz;'' and the pressure, "P, are related by the
formula:
V.: U = .!_ (v: -~ P)
z 2 z pw '
where, "kz'' is the absolute value of the vertical wave number, "w" is
frequency and "p" is the density of water. (See Singh, paras. 94--101).
9
Appeal 2016-006839
Application 12/575,648
1 Singh teaches measuring the pressure and the vertical component of particle
2 velocity at or near a given location (see Singh, para. 90); using the formula
3 quoted above to decompose either the pressure or the vertical component of
4 velocity into up-going and down-going part (see Singh, para. 94); and then
5 using the decomposition to deghost the data measured at the location (see
6 Singh, paras. 101-103).
7
8 Sherrill
9 5. Sherrill describes conducting a marine seismic survey by
10 towing a seismic recording array behind a vessel; generating a plurality of
11 seismic survey signals; and acquiring seismic data by means of seismic
12 sensors in the array. (See generally Sherrill, col. 3, 1. 59- col. 4, 1. 59). A
13 data collection unit collects traces generated by the seismic sensors and
14 either processes the traces itself; stores the traces for later processing; or
15 transmits the traces to a remote location for processing. (See Sherrill, col. 4,
16 11. 44--50).
17 6. For example, the data may be transmitted from the vessel to a
18 processing center. (See Sherrill, col. 4, 11. 53-56). The processing center
19 includes computing apparatus 3 00. The computing apparatus 3 00, as
20 depicted in Figure 3, includes a processor 305 in communication with
21 storage 310. (See Sherrill, col. 5, 1. 66 - col. 6, 1. 3). The storage 310 stores
22 an application 265 including instructions for processing traces collected by
23 the seismic sensors. (See Sherrill, col. 18, 11. 32-37). As detailed in col. 12,
24 lines 10-23, the determination of the background model comprises
25 determining differences between ray take off angles and ray take off angles
26 calculated based on a current version of the model.
10
1
Appeal 2016-006839
Application 12/575,648
7. Sherrill describes processing the traces to perform migration
2 velocity analysis to determine a background velocity model of the
3 subsurface. More specifically, Sherrill teaches a reflection tomographic
4 method similar in its general contours to the method described by Billette.
5 (See Sherrill, col. 7, 11. 9-12; see generally id., col. 9, 1. 33 - col. 11, 1. 33 &
6 Figs. 9-11 ). Sherrill' s method uses residual move-out, which captures the
7 relationship between the travel time of the reflected wave, on the one hand,
8 and the offset between the shot and the receiver, on the other, as a parameter
9 estimating local velocity. (See Sherrill, col. 7, 11. 13-19). Sherrill teaches
10 that "contamination from multiples can present difficulties in the automated
11 determination of residual moveout." (Sherrill, col. 8, 11. 22-24).
12
13 ANALYSIS
14 Turning to claim 1, Billette teaches a method comprising receiving
15 seismic data acquired by an array of seismic sensors during a towed marine
16 survey of a subsurface; and processing the seismic data to perform migration
17 velocity analysis to determine a background velocity model of the
18 subsurface based at least in part on a covariance indicative of errors in the
19 indication of the particle motion and a covariance indicative of errors in a
20 current version of the model. (See FF 1 ). Sherrill teaches performing at
21 least a portion of the calculations required for performing a similar migration
22 velocity analysis on processor-based computing apparatus. (See FF 6 & 7).
23 Given the complexity of the calculations involved, the Examiner correctly
24 finds that one familiar with the teachings of Billette and Sherrill would have
25 had reason to modify Billette's method so as to process the seismic data in a
26 processor-based machine to perform migration velocity analysis to
11
Appeal 2016-006839
Application 12/575,648
1 determine a background velocity model of the subsurface based at least in
2 part on a covariance indicative of errors in the indication of the particle
3 motion and a covariance indicative of errors in a current version of the
4 model. (See Final Office Action, mailed May 26, 2015 ("Final Office
5 Action" or "Final Act."), at 3 & 4). The Appellants do not appear to
6 challenge these findings in this appeal.
7 Sherrill teaches that tomographic analyses are sensitive to the
8 presence of the effects of multiple reflections, or multiples. (See FF 7).
9 Billette teaches that stereotomographic analyses are sensitive to the level of
10 coherency of the data (see FF 1 ); and multiples can reduce coherency. Singh
11 teaches using vertical particle velocity measurements to "deghost" traces,
12 that is, to filter out multiples, particularly, multiples caused by reflections
13 from the surface of the water. (See FF 3 & 4). As the Examiner explains in
14 the Final Office Action:
15 Applicant argues that Singh does not teach using an indication of
16 particle motion in a velocity model determination. However,
17 Singh does discuss using the deghosted data provided by his
18 method, which as discussed uses an indication of particle motion
19 data, in velocity model estimation (see paragraph [0081 ]). Thus,
20 Singh does teach the use of particle motion data for purposes of
21 determining a deghosted data set which in tum can then be used
22 for purposes of determining a deghosted data set which in tum
23 can then be used for purposes of determining a background
24 velocity model of the subsurface as required by the claim.
25 (Final Act. 2). Therefore, one familiar with the teachings of Billette, Singh
26 and Sherrill would have had reason to modify the teachings of Billette to:
27 [process] the seismic data in a processor-based machine to
28 perform migration velocity analysis to determine a background
29 velocity model of the subsurface based at least in part on an
30 indication of particle motion derived from the seismic data, a
31 covariance indicative of errors in the indication of the particle
12
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Application 12/575,648
1 motion and a covariance indicative of errors in a current version
2 of the model,
3 as recited in the second step of claim 1.
4 The Appellants argue that "Singh discusses the use of pressure and
5 particle velocity measurements for purposes of deghosting, and not for
6 purposes of determining a background velocity model of the subsurface."
7 (App. Br. 9; see generally id. at 7-10; Reply Brief, dated June 27, 2016
8 ("Reply Br."), at 1-3). The broadest reasonable interpretation of claim 1
9 permits the phrase "based at least in part on an indication of particle motion
10 derived from the seismic data" to modify "processing the seismic data in a
11 processor-based machine." The same may be said of the broadest
12 reasonable interpretation of the second step of claim 19. Therefore, whether
13 one reads Singh to describe deghosting, or the removal of multiples, as a part
14 of the migration velocity analysis itself, or as a precedent to such an
15 analysis, Singh teaches the use of vertical particle velocity measurements
16 during the processing of the seismic data during which migration velocity
1 7 analysis is also performed.
18 Even were one to restrict the second step of claim 1 or of claim 19 to
19 require that the vertical particle velocity be used as part of the migration
20 velocity analysis, one familiar with the teachings of Billette, Singh and
21 Sherrill, or of Sherrill and Singh apart from Billette, would have had reason
22 to incorporate deghosting into the data picking step described by Billette, or
23 an equivalent step in Sherrill, to improve coherence within the picked events
24 in a gather. (See FF 1 & 7). Therefore, the combined teachings of Billette,
25 Singh, and Sherrill would have suggested the performance of the entire
26 second step as recited in claim 1. For similar reasons, the combined
13
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Application 12/575,648
1 teachings of Sherrill and Singh would have suggested the performance of the
2 entire second step as recited in claim 19.
3 Therefore, we sustain the rejection of claims 1-3, 6, 9-12, 15, 16 and
4 18 under§ 103(a) as being unpatentable over Billette, Singh and Sherrill.
5 (See App. Br. 12). Because the Appellants argue the patentability of claims
6 5 and 1 7 solely on the basis of the asserted patentability of independent
7 claims 1 and 10 (see App. Br. 13), we also sustain the rejection of claims 5
8 and 17 under§ 103(a) as being unpatentable over Billette, Singh, Sherrill
9 and Krebs. (See App. Br. 12). We also sustain the rejection of claim 19
10 under § 103 (a) as being unpatentable over Sherrill and Singh.
11 That said, claim 4 recites:
12 The method of claim 1, wherein the act of processing the
13 seismic data to perform the migration velocity analysis
14 comprises determining differences between particle motion
15 measurements indicated by the seismic data and particle motion
16 measurements calculated based on a current version of the
17 model.
18 Claim 7 recites:
19 The method of claim 1, wherein the act of processing the
20 seismic data to perform the migration velocity analysis
21 compnses:
22 in a first iteration, performing an inversion to determine a
23 next version of the model based on at least in part a current
24 version of the model and the indication of particle motion; and
25 repeating performing the inversion in at least one
26 subsequent iteration until a predetermined convergence criteria
27 is met.
28 Claim 13 recites:
29 The system of claim 10, wherein the processor is adapted
30 to determine differences between particle motion measurements
14
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1 indicated by the seismic data and particle motion measurements
2 calculated based on a current version of the model.
3 The combined teachings of Billette, Singh and Sherrill fail to teach or
4 suggest updating the velocity model based on an indication of particle
5 motion, such as the vertical component of particle velocity, during the
6 iterative portion of migration velocity analysis. (See App. Br. 10-12; Reply
7 Br. 3 & 4). Therefore, we do not sustain the rejection of claims 4, 7 and 13
8 under§ 103(a) as being unpatentable over Billette, Singh and Sherrill.
9
10 DECISION
11 We AFFIRM the Examiner's decision rejecting claims 1-3, 5, 6, 9-12
12 and 15-19.
13 More specifically, we sustain the rejection of claims 1-3, 6, 9-12, 15,
14 16 and 18 under§ 103(a) as being unpatentable over Billette, Singh and
15 Sherrill; the rejection of claims 5 and 17 under § 103 (a) as being
16 unpatentable over Billette, Singh, Sherrill and Krebs; and the rejection of
17 claim 19 under§ 103(a) as being unpatentable over Sherrill and Singh.
18 We REVERSE the Examiner's decision rejecting claims 4, 7 and 13.
19 More specifically, we do not sustain the rejection of claims 4, 7 and
20 13 under§ 103(a) as being unpatentable over Billette, Singh and Sherrill.
21 No time period for taking any subsequent action in connection with
22 this appeal may be extended under 37 C.F.R. § 1.136(a). See 37 C.F.R.
23 § 1.136(a).
AFFIRMED-IN-PART
15