SimSource IPR - Petition 1 FINALprinciples and elements of seismic surveying are provided in an...

IN THE UNITED STATES PATENT & TRADEMARK OFFICE ______________________

BEFORE THE PATENT TRIAL AND APPEAL BOARD ______________________

WESTERNGECO L.L.C.,

Petitioner,

v.

PGS GEOPHYSICAL AS, Patent Owner.

______________________

Case IPR2015-00309 Patent U.S. 6,906,981

______________________

PETITION FOR INTER PARTES REVIEW OF

CLAIMS 1-22 OF

U.S. PATENT NO. 6,906,981

UNDER 35 U.S.C. § 312 AND 37 C.F.R. § 42.104

Petition for Inter Partes Review of U.S. Patent No. 6,906,981

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TABLE OF CONTENTS

I. OVERVIEW OF THE PETITION .................................................................. 1

II. MANDATORY NOTICES - 37 C.F.R. § 42.8(a)(1) ...................................... 8

III. PAYMENT OF FEES - 37 C.F.R. § 42.103 ................................................... 9

IV. REQUIREMENTS FOR INTER PARTES REVIEW ...................................... 9

A. Grounds for Standing- 37 C.F.R. § 42.104(a) ......................................... 9

B. Identification of Claims for Which Review Is Requested and Relief Requested– 37 C.F.R. §§ 42.104(b)(1) and 42.22(a)(1) ........................... 9

1. Prior Art Patents and Printed Publications ................................ 10

2. Statutory Grounds of Challenge – 37 C.F.R. § 42.104(b)(2) ....... 10

V. THE ‘981 PATENT ....................................................................................... 11

A. Overview of the ‘981 Patent ................................................................ 11

B. Prosecution History of the ‘981 Patent ................................................ 12

VI. CLAIM CONSTRUCTION .......................................................................... 13

C. “wavelet time” ..................................................................................... 14

VII. LEVEL OF ORDINARY SKILL IN THE ART ........................................... 15

VIII. IDENTIFICATION OF HOW THE CHALLENGED CLAIMS ARE UNPATENTABLE - 37 C.F.R. §§ 42.104(b)(4)-(5) and 42.22(a)(2) .......... 15

A. Claims 1, 2, 7, and 10- 21 are anticipated by De Kok ........................... 15

B. Claims 1-22 are obvious in view of the combined teachings of Beasley and Timoshin ...................................................................................... 28

1. The proposed grounds based on Beasley and Timoshin are not redundant to the grounds based on De Kok. ............................ 28

2. Claim 1 ...................................................................................... 29

3. Claim 7 ...................................................................................... 34

4. Claims 2-6 and 8-10. .................................................................. 35

a. Claims 2 and 10. ........................................................................ 35

b. Claims 3 and 9. .......................................................................... 36

c. Claims 4 and 8. .......................................................................... 36


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d. Claim 5. ..................................................................................... 36

e. Claim 6. ..................................................................................... 37

5. Claims 11-20. ............................................................................ 37

6. Claims 21 and 22. ...................................................................... 42

C. Claims 1-22 are obvious in view of the combined teachings of Beasley and Edington ....................................................................................... 43

1. The proposed grounds based on Beasley and Edington are not redundant to the grounds based on De Kok or the grounds based on Beasley and Timoshin........................................................... 43

2. Claim 1 ..................................................................................... 45

3. Claim 7 ...................................................................................... 50

4. Claims 2-6 and 8-10. .................................................................. 51

a. Claims 2 and 10. ........................................................................ 51

b. Claims 3 and 9. .......................................................................... 52

c. Claims 4 and 8. .......................................................................... 52

d. Claim 5. ..................................................................................... 53

e. Claim 6. ..................................................................................... 53

5. Claims 11-20. ............................................................................ 54

6. Claims 21 and 22. ...................................................................... 58

IX. CONCLUSION .............................................................................................. 59


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I. OVERVIEW OF THE PETITION

WesternGeco L.L.C. (“Western” or “Petitioner”) respectfully requests inter

partes review (“IPR”) for claims 1-22 of U.S. Patent No. 6,906,981 (“the ‘981 patent,”

Ex. 1001) in accordance with 35 U.S.C. §§ 311-319 and 37 C.F.R. § 42.100 et seq.

The prior art cited in this Petition demonstrates that the seismic surveying method

recited in claims 1-22 of the ‘981 patent was widely known and used well before the

’981 patent’s purported priority date and, accordingly, claims 1-22 of the ‘981 patent

should not have issued.

The ‘981 patent is directed to seismic surveying, a well-known method of

mapping geological formations with sound wave reflections. A basic overview of the

principles and elements of seismic surveying are provided in an article titled “How

Modern Techniques Improve Seismic Interpretation” that appeared in the April, 1994

issue of World Oil magazine. (“World Oil Article,” Ex. 1008.) The Federal Circuit has

emphasized the importance of considering such background information as part of

the obviousness determination, stating:

In recognizing the role of common knowledge and common sense, we

have emphasized the importance of a factual foundation to support a

party’s claim about what one of ordinary skill in the relevant art would

have known. See, e.g., Mintz v. Dietz & Watson, Inc., 679 F.3d 1372, 1377

(Fed. Cir. 2012); Perfect Web Techs., Inc. v. InfoUSA, Inc., 587 F.3d 1324,

1328 (Fed. Cir. 2009). One form of evidence to provide such a


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foundation, perhaps the most reliable because not litigation-generated, is

documentary evidence consisting of prior art in the area.

Randall Mfg. v. Rea, 108 USPQ2d 1727, 1732-1733 (Fed. Cir. 2013).

As explained in the World Oil Article, reflection seismology was first applied in

the 1920s. (Ex. 1008, at 85.) Reflection seismology uses induced acoustic reflections

of rock layers. (Id.) Vibrations are generated in the earth with acoustic sources, and

reflections are recorded with receivers. (Id.) Most marine acquisition sound sources

are air guns that repeatedly displace water volumes, and marine receivers are pressure

sensitive devices called ‘hydrophones.’ (Ex. 1008, at 86.) On land, sources include

explosives or truck mounted vibrators, and receivers are ‘geophones’ that detect slight

ground movements. (Id.) Regardless of whether it is a land-based geophone or a

marine-based hydrophone, the basic principle of operation is the same – each receiver

converts pressure or ground disturbances to electrical impulses, and the digitally

recorded electrical pulses of an array or group of receivers are transmitted, via cable or

telemetry, to recording computers. (Id.)


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Figure 1 of the World Oil Article, reproduced below, is a simplified diagram of

the seismic principle used in both land and marine surveys.

In the example shown in Figure 1 of the World Oil Article, the Horizon 1 reflection

results from an impedance contrast between Layers 1 and 2; likewise for Reflection 2

emanating from Horizon 2. (Ex. 1008, at 86.) Ray paths are described by Snell’s Law

and bend at each layer interface (horizon). (Id.) Subsurface horizons are imaged

repeatedly by source-receiver pairs as shooting progresses to each consecutive line

location. (Id.)

Given the similarities in their principles of operation, it is not surprising that

both land-based and marine-based seismic surveys were known to share some

common methodologies to improve signal to noise ratios. The World Oil Article


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explains one such well-known methodology that was shared by both land-based and

marine-based seismic surveys: the common midpoint (CMP) gather. A CMP gather is

a collection of all combinations of source-receiver pairs which records energy from

the same midpoint location, therefore containing travel paths from near to far offset

traces. (Ex. 1008, at 86.) The World Oil Article explains that “[t]his redundancy

increases the signal to noise ratio when traces are processed and summed.” (Id.)

In towed marine surveying, a vessel tows one or more of the seismic energy

sources, and the same, or a different vessel tows one or more “streamers,” which are

series of seismic sensors affixed to a cable. Returning now to the ‘981 patent, Figure

1 of the ‘981 patent, reproduced below, shows two or more sources (SA1, SA2), such

as air guns, that are fired to generate seismic energy that travels through the earth. A

group of sensors (2a-2d), such as hydrophones, record the returning echoes as a

function of time. (Ex. 1001, 1:22-2:37.)


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As noted in the World Oil Article, “[i]t was common to use synchronized

source arrays to increase, or focus, energy at each shot.” (Ex. 1008, at 86.) For

example, as explained in the background portion of U.S. Patent No. 6,545,944 to de

Kok (“De Kok,” Ex. 1003), which was filed more than a year prior to the earliest

filing date claimed by the ‘981 patent, the use of multiple sources firing simultaneously

into the same recording system was known to be an attractive option to increase the

field survey efforts at relatively low incremental cost. (Ex. 1003, 2:27-30.) De Kok

explains that simultaneous firing is particularly economical when additional sources

can easily and cheaply be deployed, such as airgun arrays in a marine situation. (Ex.

1003, 2:30-33.)

As explained in the declaration of Luc T. Ikelle, Ph.D. (“the Ikelle declaration,”

Ex. 1002), the simultaneous activation of multiple sources can raise complications

relating to noise generation and distinguishing sources from each other. (Ex. 1002,

¶¶ 32-33.) It was long-known in the land seismic context that if two sources were

asynchronous, the interfering signal could be treated as “noise” and distinguished

through simple CMP binning. Soviet Union Patent No. 1,543,357 to Timoshin et al.

(“Timoshin,” Ex. 1005), published more than a decade prior to the earliest filing date

claimed by the ‘981 patent, discloses using random numbers as firing delays for

sources to distinguish between separate sources during CMP processing. U.S. Pat.

No. 4,953,657 to Edington (“Edington,” Ex. 1006), which was also filed more than a

decade prior to the earliest filing date claimed by the ‘981 patent, discloses shooting at


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least two seismic energy sources substantially simultaneously with a determinable time

delay between the activation of each source, and then shooting the sources at least a

second time substantially simultaneously with a different determinable time delay

between the activation of each source from the determinable time delay used in at

least one previous shooting. (Ex. 1006, 2:1-13.) Edington explains that “the

determinable time delays is preselected, and is selected so that the difference in time

delay between any two shootings enables the signal received from the first activated

source to be distinguished from the signal received from the second activated source.”

(Ex. 1006, 2:15-20.)

Further, U.S. Patent No. 5,924,049 to Beasley et al. (“Beasley,” Ex. 1004)

discloses a broad toolbox of techniques for separating simultaneous sources. As

explained in the Ikelle declaration, it was well known in the seismic surveying art prior

to the earliest filing date claimed by the ‘981 patent to encode signals for later

separation by modifying the source signatures. This included varying the amplitude,

frequency, and/or firing time of the source signature. (Ex. 1002, ¶¶ 34-35.) More

sophisticated techniques, such as those disclosed in De Kok, went beyond

distinguishing the two sources and disclosed timing techniques that would reinforce

the two signals to improve their informational content. Specifically, unlike the ‘981

patent, De Kok discloses time delay encoding techniques which rely on programmed

time delays in the field and polarity decoding in the processing center.

Nevertheless, the ‘981 patent purports to have invented the concept of time


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varying seismic source signals. Claim 1 of the ‘981 patent recites:

1. A method for seismic surveying, comprising:

towing a first seismic energy source and at least one seismic sensor

system;

towing a second seismic energy source at a selected distance from the

first seismic energy source; and

actuating the first seismic energy source and the second seismic

energy source in a plurality of firing sequences, each of the firing

sequences including firing of the first source and the second source and

recording signals generated by the at least one seismic sensor system, a

time interval between firing the first source and the second source varied

between successive ones of the firing sequences, the times of firing the

first and second source indexed so as to enable separate identification of

seismic events originating from the first source and seismic events

originating from the second source in detected seismic signals.

This time-variation was long-used in the prior art to separate simultaneous

sources. For example, De Kok discloses more sophisticated time delay encoding

techniques than those disclosed in the ‘981 patent, that nevertheless fully anticipate

claims 1, 2, 7, and 10- 21 of the ‘981 patent.

In addition, the combined teachings of Beasley and either of Timoshin or

Edington render all of the claims of the ‘981 patent obvious. Beasley is directed to

marine seismic surveys that include firing seismic sources simultaneously or near

simultaneously in which the “sources may be arranged to emit encoded wavefields

using any desired type of coding” and discloses time separation of the sources, but


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does not explicitly disclose the type of asynchronous time separation claimed in the

‘981 patent. (Ex. 1004, 7:54-56.) It would have been obvious to employ the known

time encoding techniques disclosed in either of Timoshin or Edington in the system

of Beasley to achieve the predictable result of distinguishing sources that are fired

either simultaneously or near simultaneously.

II. MANDATORY NOTICES - 37 C.F.R. § 42.8(A)(1)

Petitioner provides the following mandatory disclosures.

A. Real Parties-In-Interest - 37 C.F.R. § 42.8(b)(1)

WesternGeco, L.L.C., Schlumberger Technology Corporation, Schlumberger

Holdings Corporation; Schlumberger B.V., Schlumberger, Limited, and Schlumberger

Services, Inc. are the real parties-in-interest.

B. Related Matters- 37 C.F.R. § 42.8(b)(2)

The ‘981 patent is asserted in co-pending litigation captioned as WesternGeco

LLC v. Petroleum Geo-Services, Inc. et al., Southern District of Texas, Case No. 4:13-cv-

02725.

C. Lead and Back-Up Counsel- 37 C.F.R. § 42.8(b)(3)

Petitioner provides the following designation of counsel:

Lead Counsel: Scott McKeown (Registration No. 42,866)

Backup Counsel: Christopher A. Bullard (Reg. No. 57,644)

D. Service Information - 37 C.F.R. § 42.8(b)(4)

Papers concerning this matter should be served as follows:


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Email: [email protected]

[email protected]

Post: Oblon Spivak, 1940 Duke St., Alexandria, VA 22314

Telephone: 703-412-6297 Facsimile: 703-413-2220

III. PAYMENT OF FEES - 37 C.F.R. § 42.103

The undersigned authorizes the Office to charge the fees set forth in 37 C.F.R.

§42.15(a) as required by 37 C.F.R. § 42.103 for this Petition for Inter Partes Review to

Deposit Account No. 15-0030; any additional fees that might be due are also

authorized.

IV. REQUIREMENTS FOR INTER PARTES REVIEW

A. Grounds for Standing- 37 C.F.R. § 42.104(a)

Pursuant to 37 C.F.R. § 42.104(a), Petitioner hereby certifies that the ’981

patent is available for inter partes review and that the Petitioner is not barred or

estopped from requesting inter partes review challenging the claims of the ‘981 patent

on the grounds identified herein. This is because the ‘981 patent has not been subject

to a completed estoppel based proceeding of the AIA, and the counterclaim served on

Western referenced above in Section II(B) was served within the last 12 months.

B. Identification of Claims for Which Review Is Requested and Relief Requested– 37 C.F.R. §§ 42.104(b)(1) and 42.22(a)(1)

Pursuant to 37 C.F.R. §42.104(b) and (b)(1), Petitioner requests inter partes

review of claims 1-22 of the ‘981 patent, and that the Patent Trial and Appeal Board

(“PTAB”) determine the same to be unpatentable.


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1. Prior Art Patents and Printed Publications

Petitioner relies upon the following patents and printed publications:

Exhibit 1003 – U.S. Patent No. 6,545,944 to de Kok (“De Kok”), filed May

30, 2001 and issued April 8, 2003. De Kok is available as prior art under 35 U.S.C. §

102(e).

Exhibit 1004 – U.S. Patent No. 5,924,049 to Beasley et al. (“Beasley”), filed

January 30, 1998 and issued July 13, 1999. Beasley is available as prior art under 35

U.S.C. § 102(b).

Exhibit 1005 – Soviet Union Patent No. 1,543,357 to Timoshin et al.

(“Timoshin”), filed January 7, 1988 and published February 15, 1990. Timoshin is

available as prior art under 35 U.S.C. § 102(b).

Exhibit 1006 – U.S. Patent No. 4,953,657 to Edington (“Edington”), filed

February 14, 1989 and issued September 4, 1990. Edington is available as prior art

under 35 U.S.C. § 102(b).

2. Statutory Grounds of Challenge – 37 C.F.R. § 42.104(b)(2)

Petitioner requests cancellation of the challenged claims under the following

statutory grounds:

Ground 1 – Claims 1, 2, 7, 10- 21 are anticipated by De Kok (Ex. 1003) under

35 U.S.C. § 102(e).

Ground 2 – Claims 1-22 are obvious over Beasley (Ex. 1004) in view of

Timoshin (Ex. 1005) under 35 U.S.C. § 103(a).


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Ground 3 – Claims 1-22 are obvious over Beasley (Ex. 1004) in view of

Edington (Ex. 1006) under 35 U.S.C. § 103(a).

Pursuant to 37 C.F.R. § 42.204(b)(4), an explanation of how claims 1-22 of the

‘981 patent are unpatentable under the statutory grounds identified above, that the

Petitioner has at least a reasonable likelihood of prevailing on these grounds, including

the identification of where each element of the claim is found in the prior art, is

provided in Section VIII, below, in the form of claims charts. Pursuant to 37 C.F.R. §

42.204(b)(5), the exhibit numbers of the supporting evidence relied upon to support

the challenges and the relevance of the evidence to the challenges raised, including

identifying specific portions of the evidence that support the challenges, are provided

in Section VIII, below, in the form of claim charts.

V. THE ‘981 PATENT

A. Overview of the ‘981 Patent

As noted above, the ‘981 patent employs the commonly used technique known

as “simultaneous shooting,” in which multiple seismic energy sources are fired

simultaneously or near-simultaneously. The recorded data contains interference

because the shots overlap with one another, resulting in mixed data that includes

reflections from each fired source. In order to obtain useful information from the

recorded data, one must separate out the data received from each individual source.

With proper separation, simultaneous shooting allows for greater shot density, i.e.,

more shots during a given survey duration, which results in more robust seismic data.


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The ‘981 patent proposes to separate recorded signals by time encoding the

signals as they are generated. In particular, the ‘981 patent discloses firing a first

source, making a recording of the signal detected by the sensors that is indexed to a

known time reference with respect to time of firing the first source, firing a second

source at a known, selected time delay after the firing of the first source, while signal

recording continues. (Ex. 1001, 5:61-64.) The ‘981 patent defines a “firing sequence”

as firing the first source, waiting the predetermined delay and firing the second source

thereafter. (Ex. 1001, 5:65-6:2.) The ‘981 patent discloses that the firing sequence,

and contemporaneous signal recording, are repeated in a second firing sequence. (Ex.

1001, 6:2-4.) The second firing sequence includes firing the first source, waiting a

different selected time delay and then firing the second source, while recording

seismic signals. (Ex. 1001, 6:4-7.) The known, selected time delay between firing the

first source and firing the second source is different for each successive firing

sequence. (Ex. 1001, 6:7-9.)

B. Prosecution History of the ‘981 Patent

During prosecution, in an attempt to distinguish the pending claims from the

prior art, the Applicant emphasized the importance of varying time delays by stating

that “[a]n important element of the Applicant’s invention is that a time interval

between firing the first source and firing the second source is varied between

successive ones of the firing sequences.” (Ex. 1007, at 31.) Applicant explained that

varying the time delays was an advantage because “the detected seismic signals can be


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identified with respect which caused the particular events in the detected seismic

signals.” (Ex. 1007, at 31.)

VI. CLAIM CONSTRUCTION

In an inter partes review, claim terms in an unexpired patent are interpreted

according to their broadest reasonable interpretation (“BRI”) in view of the

specification in which they appear. 37 C.F.R. § 42.100(b); Office Patent Trial Practice

Guide, 77 Fed. Reg. 48,756, 48,766 (Aug. 14, 2012). In determining the BRI, claim

terms receive their ordinary and customary meaning as would be understood by one

of ordinary skill in the art in the context of the entire disclosure. In re Translogic Tech.,

Inc., 504 F.3d 1249, 1257 (Fed. Cir. 2007).

The USPTO requires BRI, as the patentee is given opportunity to amend their

claims in this proceeding. See, e.g., Office Patent Trial Practice Guide, 77 Fed. Reg.

48,764 (Aug. 14, 2012). As required by these rules, this Petition applies the BRI of

claim terms, although BRI may be, and often is, different from a claim construction in

district court. See, e.g., In re Trans Texas Holdings Corp., 498 F.3d 1290, 1297 (Fed. Cir.

2007). Thus, the claim interpretations presented in this Petition, including where

Petitioner does not propose an express construction, do not necessarily reflect the

claim constructions that Petitioner believes should be adopted by a district court

under Phillips v. AWH Corp., 415 F.3d 1303 (Fed. Cir. 2005).


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A. “wavelet time”

This phrase appears in claim 6. Claim 6 recites “the time interval is at least as

long as a wavelet time of the first source.”

Although the specification of the ‘981 patent uses the phrase “wavelet time,” a

“wavelet” is not clearly defined in the ‘981 specification. For example, the ‘981 patent

states “[a]lthough the time delay varies from sequence to sequence, the time delay

between firing the first source and the second source in each firing sequence is

preferably selected to be at least as long as the ‘wavelet’ time of the seismic energy

generated by the first source to avoid interference between the first and second

sources.”

As discussed in the Ikelle declaration, one having ordinary skill in the art at the

time of the earliest filing date claimed by the ‘981 patent would understand the phrase

“wavelet time” to mean “the duration of the source signature.” (Ex. 1002, ¶¶ 61-62.)

The specification of the ‘981 patent indicates that time delays at least as long as the

wavelet time should be used to avoid interference between the sources. By waiting

“the duration of the source signature,” this interference between the source signatures

would be avoided. Only the interference between the reflected wavefields would

remain to be decoded. As noted by Dr. Ikelle, a person of ordinary skill in the art

would understand that it is incredibly difficult to decode simultaneous shooting data

when the source signatures interfere. (Ex. 1002, ¶ 63.)


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Accordingly, the broadest reasonable interpretation of the phrase “wavelet

time” is “the duration of the source signature.”

VII. LEVEL OF ORDINARY SKILL IN THE ART

The level of ordinary skill in the art is evidenced by the prior art. See In re

GPAC Inc., 57 F.3d 1573, 1579 (Fed. Cir. 1995) (determining that the Board did not

err in adopting the approach that the level of skill in the art was best determined by

references of record). The prior art discussed herein, and in the declaration of Dr.

Ikelle, demonstrates that a person of ordinary skill in the art, at the time the ‘981

patent was filed, was an engineer, seismologist, or technical equivalent, experienced in

seismic data acquisition systems, aware of various aspects of seismic acquisition and

seismic data processing pertaining to land or marine seismic surveys. (Ex. 1002, ¶¶

57-59.)

VIII. IDENTIFICATION OF HOW THE CHALLENGED CLAIMS ARE UNPATENTABLE - 37 C.F.R. §§ 42.104(B)(4)-(5) AND 42.22(A)(2)

Petitioner provides in the following discussion and claim charts a detailed

comparison of the claimed subject matter and the prior art specifying where each

element of the challenged claims are found in the prior art references.

A. Claims 1, 2, 7, and 10- 21 are anticipated by De Kok

De Kok discloses time delay encoding techniques which rely both on

programmed time delays in the field and polarity decoding in the processing center.

In this respect, the technique disclosed in De Kok is more sophisticated than the


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basic time delay encoding disclosed in the ‘981 patent. However, even though the

‘981 patent does not disclose polarity decoding in the processing center, claims 1, 2, 7,

and 10- 21 of the ‘981 patent do not exclude an additional step of polarity decoding in

the processing center. As such, at least under the “broadest reasonable

interpretation” standard that must be applied in this proceeding before the Board,

claims 1, 2, 7, and 10- 21 of the ‘981 patent encompasses the technique disclosed in

De Kok.

Referring to a standard airgun, the far field source signature is composed of a

positive pressure pulse followed by a negative pulse from the sea surface reflection.

(Ex. 1003, 3:54-57.) The negative pulse, called the ghost, is time separated from the

positive pulse by a time shift that may be referred to as the ghost time delay. (Ex.

1003, 3:57-59.) Figure 2 of De Kok, reproduced below, shows the sequences of two

sources firing simultaneously with polarity coding. (Ex. 1003, 4:28-29.) Figure 2

shows a source vessel 201 towing sources 203 and 205. (Ex. 1003, 4:32-33.) A source

vessel 201 may also tow a streamer containing sensors for receiving source signals, for

example streamer 207. (Ex. 1003, 4:33-35.) In Figure 2, Source 203 emits S1, in

which positive (P) and negative (N) polarity source signals alternate as depicted by the

positive and negative polarity representation through time. (Ex. 1003, 4:35-38.)

Source 205 emits positive signals S2 only. (Ex. 1003, 4:42.)


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Figures 5-7 of De Kok depict embodiments that include time delay encoding.

As noted above, De Kok discloses that the time delay encoding technique relies on

programmed time delays in the field and polarity decoding in the processing center.

(Ex. 1003, 5:66-6:2.) According to De Kok, the enhancement of data pertaining to a

particular desired source is accomplished through equalizing the polarity of

corresponding signal components and to align and average (mix or stack) the

responses. (Ex. 1003, 6:2-4.) This principle is illustrated with the impulse response

representations of FIG. 5A for a marine application, reproduced below.


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Most notably, in FIG. 5A, Source TD1 and Source TD2, which are sequential

series of simultaneous shots, have different delay codes for successive shots

(numbered 1 to 4 for each simultaneously activated source). (Ex. 1003, 6:17-21.) The

time delays in these figures are relative to an arbitrary reference, here labeled tr =0,

represented by the vertical dashed lines. (Ex. 1003, 6:21-23.) For example,

simultaneously fired shot 1 from TD1 (501) and shot 1 of TD2 (511) are initiated with

no relative time delays between them, but shot 2 from TD2 (513) is initiated before

shot 2 of TD1 (503), the time separation between the initiation of shot 2 of TD2

(513) relative to shot 2 of TD1 (503) being the time delay determined or chosen for

the acquisition program, which may be for example, the ghost delay. (Ex. 1003, 6:23-

30.)


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Thus, De Kok fully anticipates several of the claims of the ‘981 patent, as the

process disclosed in De Kok includes varying a time interval between firing a first

source and a second source between successive ones of firing sequences.

The following claim chart illustrates how De Kok meets all of the elements of

claims 1, 2, 7, and 21 of the ‘981 patent.

‘981 Patent Claims De Kok (Ex. 1003) 1. A method for seismic surveying, comprising:

Ex. 1003 at 3:38-39: “The present invention is a method for acquiring seismic data using simultaneously activated seismic energy sources.”

1.a. towing a first seismic energy source and at least one seismic sensor system;

Ex. 1003 at 4:32-35: “FIG. 2 shows a source vessel 201 towing sources 203 and 205. A source vessel 201 may also tow a streamer containing sensors for receiving source signals, for example streamer 207.”

Ex. 1003at Fig. 2.

1.b. towing a second seismic energy source at a selected distance from the first seismic energy source; and

Ex. 1003 at 5:23-24: “FIG. 4 depicts a four source (203, 205, 413, 415) shooting arrangement with two receiver cables (407, 409).”


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‘981 Patent Claims De Kok (Ex. 1003)

Ex. 1003 at Fig. 4. Ex. 1003 at 5:36-39: “In the configuration of FIG. 4 the two sources 203 and 205 preceding streamers 407 and 409 are relatively close to each other, and also sources 413 and 415 at the back of the streamers 407 and 409 are in relatively close proximity.

1.c. actuating the first seismic energy source and the second seismic energy source in a plurality of firing sequences, each of the firing sequences including firing of the first source and the second source and recording signals generated by the at least one seismic sensor system,

Ex. 1003 at 2:42-47: “An activation sequence for each of said plurality of seismic energy sources may be determined such that energy from separate seismic source positions may be recorded simultaneously and seismic energy responsive to individual seismic sources separated into separate source records.” Example firing sequences are shown in Figures sequences are 5A-5C, 6A-6B, and 7A-7B of De Kok.

1.d. a time interval between firing the first source and the second source varied between successive ones of the firing sequences,

Ex. 1003 at 6:18-23: “In FIG. 5A, Source TD1 and Source TD2, being sequential series of simultaneous shots, have different delay codes for successive shots (numbered 1 to 4 for each simultaneously activated source). The time delays in these figures are relative to an arbitrary reference, here labeled tr=0, represented by the vertical dashed lines.”


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Ex. 1003 at Fig. 5A.

1.e. the times of firing the first and second source indexed so as to enable separate identification of seismic events originating from the first source and seismic events originating from the second source in detected seismic signals.

Ex. 1003 at 2:47-50: “The seismic sources are activated using an activation sequence, the recorded seismic energy in the shot recordings may be separated into source recordings responsive to individual seismic sources.”

2. The method of claim 1, wherein the time interval is varied systematically.

Ex. 1003 at 5:67−6:1: “The time delay encoding technique relies on programmed time delays in the field . . . .” Ex. 1003 at 6:2-4: “The time shifts for encoding may be arbitrarily chosen per source, but they should preferably be equal to the ghost time delay in the marine case.”

7.a. The method as defined in claim 1 further comprising actuating at least one

Ex. 1003 at 5:6:53-58: “When using a sequence of four shots as in FIG. 5A and FIG. 5B, the method can accommodate three different sources. The


22


additional seismic energy source in each [f]iring1 sequence,

coding of a third source, Source TD3, is shown in FIG. 6A and FIG. 6B and consists of positive delay times for shot 1 (601) and shot 4 (607) with negative relative delay times for shot 2 (603) and shot 3 (605).”

Ex. 1003 at Fig. 6A, 6B.

7.b. the at least one additional seismic energy source actuated after an additional selected time interval after firing the second source, the additional time interval varied between successive ones of the firing sequences.

Ex. 1003 at 7:11-13: “In FIG. 7A and FIG. 7B three sources without ghosts are shown. All three sources have different amplitude and have been coded using different time delays.”

10. The method as defined in claim 7 wherein the additional time interval is varied systematically between firing sequences.

Ex. 1003 at 5:67−6:1: “The time delay encoding technique relies on programmed time delays in the field . . . .” Ex. 1003 at 6:2-4: “The time shifts for encoding may be arbitrarily chosen per source, but they should preferably be equal to the ghost time delay in the

1 It is clear from the prosecution history that the Applicant intended claim 7 to recite

“firing” instead of “tiring.” (See Ex. 1007, claim 7, p. 8.)


23


marine case.”

11. The method as defined in claim 7 further comprising extracting from the recorded sensor signals coherent seismic signals identified to each of the first, second and at least one additional seismic energy sources.

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are present may be used.” Ex. 1003 at 6:41-48: “Here the result of polarity decoding to enhance and separate energy for the Source TD1 shot series from the shot series of Source TD2 consists of reversing the contributions from shot 3 (505, 515) and shot 4 (507, 517), which causes energy from Source TD1 to reinforce and that of Source TD2 to cancel after mixing, K-filtering or stacking (also here the CMP gather may be the preferred domain to execute the source discrimination).” Ex. 1003 at 6:58-61: “In this case, the decoding for Source TD3, the third source, is achieved by inverting shot 2 (503, 513 and 603) and 3 (505, 515 and 605).”

12. The method as defined in claim 11 wherein the extracting the signals identified to the first source comprises determining trace to trace and shot to shot coherent components in the recorded sensor signals.

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are


24


present may be used.”

13. The method as defined in claim 12 wherein determining the shot to shot coherent component comprises generating a common mid point trace gather with respect to the first source.

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are present may be used.”

14.a. The method as defined in claim 12 wherein the extracting the signals identified to each of the second and at least one additional seismic source comprises, for each of the second and at least one additional source, time aligning the signals with respect to a firing time of each of the second and at least one additional source,

Ex. 1003 at 6:41-48: “Here the result of polarity decoding to enhance and separate energy for the Source TD1 shot series from the shot series of Source TD2 consists of reversing the contributions from shot 3 (505, 515) and shot 4 (507, 517), which causes energy from Source TD1 to reinforce and that of Source TD2 to cancel after mixing, K-filtering or stacking (also here the CMP gather may be the preferred domain to execute the source discrimination).” The polarity decoding technique is a form of time-alignment because the polarities are a direct function of the time delays. Decoding the polarities such that the polarities for one source stack while the polarities for the other sources cancel necessarily requires time-alignment. (Ex. 1002, ¶¶ 100-102.)

14.b. and determining trace to trace and shot to shot coherent components in the recorded sensor signals.

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the


25


contributions from successive shot records are present may be used.”

15. The method as defined in claim 14 wherein the determining the shot to shot coherent components comprises generating a common mid point trace gather with respect to each of the second and at least one additional sources.


16. The method as defined in claim 1 further comprising, extracting from the recorded sensor signals coherent seismic signals identified to each of the first seismic energy source and the second seismic energy source.

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are present may be used.” Ex. 1003 at 6:41-48: “Here the result of polarity decoding to enhance and separate energy for the Source TD1 shot series from the shot series of Source TD2 consists of reversing the contributions from shot 3 (505, 515) and shot 4 (507, 517), which causes energy from Source TD1 to reinforce and that of Source TD2 to cancel after mixing, K-filtering or stacking (also here the CMP gather may be the preferred domain to execute the source discrimination).”

17. The method as defined in claim 16 wherein the extracting the signals

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source position energy must be separated into source


26


identified to the first source comprises determining trace to trace and shot to shot coherent components in the recorded sensor signals.

records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are present may be used.”

18. The method as defined in claim 16 wherein the determining the shot to shot coherent components comprises generating a common mid point gather with respect to the first source.


19.a. The method as defined in claim 6 wherein the extracting the signals identified to the second source comprises time aligning the recorded signals with respect to firing the second source

Ex. 1003 at 6:41-48: “Here the result of polarity decoding to enhance and separate energy for the Source TD1 shot series from the shot series of Source TD2 consists of reversing the contributions from shot 3 (505, 515) and shot 4 (507, 517), which causes energy from Source TD1 to reinforce and that of Source TD2 to cancel after mixing, K-filtering or stacking (also here the CMP gather may be the preferred domain to execute the source discrimination).” The polarity decoding technique is a form of time-alignment because the polarities are a direct function of the time delays. Decoding the polarities such that the polarities for one source stack while the polarities for the other sources cancel necessarily requires time-alignment. (Ex. 1002, ¶¶ 100-102.)

19.b. and determining trace to trace and shot to shot

Ex. 1003 at 4:47-55: “The seismic energy returned from shot records containing multiple source


27


coherent components in the time-aligned recorded seismic signals.

position energy must be separated into source records containing energy responsive to the individual seismic sources. The separation of individual source contributions into source records (as opposed to shot records) is achieved during processing, preferably in the common mid-point (CMP) domain but any other domain where the contributions from successive shot records are present may be used.”

20. The method as defined in claim 19 wherein the determining the shot to shot coherent components comprises generating a common mid point gather with respect to the second source.


21. The method as defined in claim 1 wherein the second source is towed behind the first source.

Ex. 1003 at 5:23-24: “FIG. 4 depicts a four source (203, 205, 413, 415) shooting arrangement with two receiver cables (407, 409).”

Ex. 1003 at Fig. 4.


28

B. Claims 1-22 are obvious in view of the combined teachings of Beasley and Timoshin

1. The proposed grounds based on Beasley and Timoshin are not redundant to the grounds based on De Kok.

The grounds raised in the following sections based on the combined teachings

of Beasley and Timoshin are meaningfully distinct from the grounds raised above

based on De Kok. Beasley, unlike De Kok, does not explicitly disclose polarity

encoding for simultaneous source activation, but more generally discloses that any

desired type of encoding could be used for simultaneous or near simultaneous source

activation across both the marine and land survey contexts. Timoshin discloses one

such type of encoding that was known more than a decade prior to the earliest filing

date claimed by the ‘981 patent – a time delay encoding that more closely matches the

type of time delay encoding disclosed in the ‘981 patent than the time delay/polarity

encoding/decoding disclosed in De Kok. Specifically, Timoshin discloses using

random numbers as launch delays during overlapping source activations. (Ex. 1005,

p. 5.) During processing, the results of the effect from a single shot source are

summed in phase, while those from different sources are summed out of phase, as the

firing delays of the sources are random and independent. (Ex. 1005, p. 5.) Timoshin

further discloses that, because of the incoherence of the summation of the wave

fields, it is possible to separate the wave fields from different sources during data

processing by the common-depth-point method and by constructing seismic images

by the diffraction method. (Ex. 1005, p. 7.)


29

As such, the grounds raised in the following sections based on the combined

teachings of Beasley and Timoshin are meaningfully distinct from and are not

redundant to the grounds raised above based on De Kok.

2. Claim 1

Beasley is directed to marine seismic surveys that include firing seismic sources

simultaneously or near simultaneously in which the “sources may be arranged to emit

encoded wavefields using any desired type of coding” but does not explicitly disclose

the type of time encoding claimed in the ‘981 patent. (Ex. 1004, 7:54-56.) While

Beasley discusses the use of source encoding in the marine context, it discloses that

the same encoding techniques could be used in land seismic surveys. (Ex. 1004, 9:39-

44.)

Additionally, as Professor Ikelle explains, prior to the ‘981 patent it was already

commonplace to adapt land solutions to marine problems due to the clear relationship

between land and marine seismic surveying. (Ex. 1002, ¶¶ 28-31.) For example, the

World Oil article makes no distinction between land and marine seismic surveying

when discussing using a CMP gather to increase the signal to noise ratio when

processing and summing traces. (Ex. 1008, at 86.) Therefore, when assessing what

types of encoding techniques could be employed in marine surveying, one of ordinary

skill in the art would have known to look to what was being used in land seismic

surveying. (Ex. 1002, ¶¶ 149-150.)


30

Timoshin, which issued more than a decade before the ’981 patent was filed,

discloses the use of time encoding and time alignment to separate sources. (Ex. 1005,

p. 7, ¶ 2.) Timoshin discloses that by varying the launch delays of overlapping sources

based on random numbers, it becomes possible to separate the wave fields from

different sources during data processing by the common-depth-point method and by

constructing seismic images by the diffraction method. (Ex. 1005, p. 7.) Accordingly,

Beasley discloses it is desirable to employ signal encoding techniques, and Timoshin

discloses one such known technique.

The combination of the known time-encoding technique of Timoshin with the

known marine survey technique disclosed in Beasley would do no more than yield the

predictable result of making it possible to separate the wave fields from different

sources of Beasley during data processing by the common-depth-point method and

by constructing seismic images by the diffraction method, as disclosed in Timoshin.

(Ex. 1002, ¶ 151.) As such, it would have been obvious to employ the known time

encoding techniques disclosed in Timoshin in the marine survey of Beasley. (See KSR

Int'l Co. v. Teleflex, Inc., 550 U.S. 398, 416 (2007) (“The combination of familiar

elements according to known methods is likely to be obvious when it does no more

than yield predictable results.”).) Furthermore, both Beasley and Timoshin deal with

simultaneous shooting, encoding, and decoding. As Dr. Ikelle notes, these similarities

would have been enough to motivate a person of ordinary skill to combine Beasley


31

and Timoshin, especially given the natural fit between teachings in Beasley and

Timoshin. (Ex. 1002, ¶¶ 148-150.)

The following claim chart specifies where each element of claim 1 is found in

the combined teachings of Beasley and Timoshin:

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005) 1. A method for seismic surveying, comprising:

Ex. 1004 at 1:19-25: “The present invention, in certain aspects, is directed to seismic survey systems and methods in which two or more seismic sources are fired simultaneously, or significantly close together temporally, but which is, in one aspect, significantly spatially separated, and resulting seismic data is processed meaningfully utilizing data generated by both (or more) seismic sources.”


Ex. 1004 at 3:47-57: “The present invention, in certain aspects, discloses a seismic survey system for use at sea or on land with two, three, four, or more seismic sources (or one source moved form one location to another and fired at multiple locations) for generating an acoustic wavefield (e.g., but not limited to, acoustic sources, e.g. air guns); a plurality of spaced-apart seismic detectors for discrete sampling of the acoustic wavefield reflected and/or refracted from earth layers (e.g., but not limited to geophones or hydrophones); and, at sea, a vessel or vessels for carrying or towing the seismic sources and, in one aspect, the detectors.”

Ex. 1004 at Fig. 4 (SL, SL’). 1.b. towing a second seismic energy source at a selected distance from the first seismic

Ex. 1004 at 3:47-57: “The present invention, in certain aspects, discloses a seismic survey system for use at sea or on land with two, three, four, or more


32

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005) energy source; and seismic sources (or one source moved form one

location to another and fired at multiple locations) for generating an acoustic wavefield (e.g., but not limited to, acoustic sources, e.g. air guns); a plurality of spaced-apart seismic detectors for discrete sampling of the acoustic wavefield reflected and/or refracted from earth layers (e.g., but not limited to geophones or hydrophones); and, at sea, a vessel or vessels for carrying or towing the seismic sources and, in one aspect, the detectors.”

Ex. 1004 at Fig. 4 (ST, ST’). Beasley discloses that the second seismic energy source is at a selected distance from the first: Ex. 1004 at 3:57-59: “In one aspect, the seismic sources are activated simultaneously at a known location with the seismic sensors at a known location.” (emphasis added).


Ex. 1004 at 8:47-49: “It is within the scope of this invention for there to be any number of source firings from one to several hundred or more.” Ex. 1004 at 7:31-34: “The first and second sources are activated at timed intervals in alternate cycles to provide first and second reflected wavefields. The reflected wavefields are detected and converted to first and second data sets of reflected signals.”

1.d. a time interval between firing the first source and the second source varied between successive ones of the firing

Ex. 1004 at 7:31-34: “The first and second sources are activated at timed intervals in alternate cycles to provide first and second reflected wavefields. The reflected wavefields are detected and converted to


33

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005) sequences, first and second data sets of reflected signals.”

Ex. 1005 at page 5: “A sequence of P random numbers is generated for each position of the receiving device and a series of P excitation points. They are bounded on one side by the correlation radius of seismograms obtained from the different excitation points, and the other – by on-half of the seismogram’s duration. These random numbers are used as launch delays for sources positioned at P excitation points while the seismic waves from all these sources are recorded continuously. Launch times of the sources are stored in the memory and are used for the separation of the wave fields in processing the results. In performing summation by using the multifold reflection technique, the signals from one excitation source are summed in-phase, while those from different sources – out-of-phase, since the launch delays of the sources are random and independent.”


Ex. 1004 at 4:16-36: “To separate the sources’ data, the record is updated with one source's geometry information (e.g. x, y location coordinates and time of day identifiers, e.g. SEG standard format information, are attached to the seismic data traces by known methods, e.g. a header with the desired information is applied to a trace tape) . . . The process is then re-done with the attachment of the other source's geometry producing the seismic data related to the other seismic source.” Ex. 1005 at page 6: “The triggering moments of all sources (usually collected by the receivers installed near or directly on the sources or by the explosion marking circuits) are transmitted to station 7 and are stored there on the simultaneously recorded seismograms.”


34

3. Claim 7

Claim 7 depends from claim 1 and further recites actuating at least one

additional seismic energy source in each firing2sequence, the at least one additional

seismic energy source actuated after an additional selected time interval after firing the

second source. Claim 7 further recites the additional selected time interval is different

than the time interval between firing the first and second sources, and that the

additional time interval is varied between successive ones of the firing sequences.

Beasley discloses using three or more sources in a shot sequence, stating “[i]t is

within the scope of this invention for there to be any number of source firings from

one to several hundred or more…Alternatively, one vessel may tow multiple seismic

sources or each of two or more vessels may each tow two or more sources.” (Ex.

1004, 8: 47-56, emphasis added.) Further, for at least the same reasons discussed

above with respect to claim 1, it would have been obvious prior to the earliest filing

date claimed by the ‘981 patent to: (a) make the additional selected time interval

different than the time interval between firing the first and second sources, and (b)

vary the additional time interval between successive ones of the firing sequences. In

particular, such a technique is one known method of encoding signal sources and it

would have been obvious to apply this known technique to any number of sources

2 The prosecution history makes clear claim 7 was intended to recite “in each firing

sequence” instead of “in each tiring sequence.” (See Ex. 1007, claim 7, p. 8.)


35

used in the method of Beasley to achieve the predictable result of signal that are

encoded based on firing timing. Accordingly, claim 7 is obvious in view of the

combined teachings of Beasley and Timoshin.

4. Claims 2-6 and 8-10.

Claims 2-6 each directly depend from claim 1 and recite aspects of how the

time interval between firing the first source and the second source are varied.

Likewise, claims 8-10 each directly depend from claim 7 and recite aspects of how the

additional time interval is varied. As discussed above, the art cited herein establishes

that varying such time intervals was old and well known long before the earliest filing

date claimed by the ‘981 patent.

a. Claims 2 and 10.

Claim 2 depends from claim 1 and recites the time interval is varied

systematically. Claim 10 depends directly from claim 7 and recites the additional time

interval is varied systematically between firing sequences. Once one of ordinary skill

selects the known source signal encoding option of time interval variation, selecting

the time intervals at random, pseudo-randomly, or based on a predetermined

correlation were all obvious variants, the selection of which was well within the skill

of one having ordinary skill in the art prior to the earliest filing date claimed by the

‘981 patent. (Ex. 1002, ¶ 164.) Accordingly, claims 2 and 10 are obvious in view of

the combined teachings of Beasley and Timoshin.


36

b. Claims 3 and 9.

Claim 3 depends from claim 1 and recites the time interval is varied quasi-

randomly. Claim 9 depends directly from claim 7 and recites the additional time

interval is varied quasi-randomly between firing sequences. Once one of ordinary skill





‘981 patent. (Ex. 1002, ¶ 166.) Accordingly, claims 3 and 9 are obvious in view of the

combined teachings of Beasley and Timoshin.

c. Claims 4 and 8.

Claim 4 depends from claim 1 and recites the time interval varied is randomly.

Claim 8 depends directly from claim 7 and recites the additional time interval is varied

randomly between firing sequences. Timoshin explicitly discloses using random

numbers for the firing delays. (Ex. 1005, Abstract.) Accordingly, claims 4 and 8 are

obvious in view of the combined teachings of Beasley and Timoshin.

d. Claim 5.

Claim 5 depends from claim 1 and recites the time interval is varied in steps of

about 100 milliseconds. Given the use of time delay encoding, it would have been

obvious to a person of ordinary skill in the art to use time intervals that vary in steps

of about 100 milliseconds. Dr. Ikelle states that a person of ordinary skill in the art


37

would understand the advantages of using such time variations. Specifically, 100

milliseconds is slightly longer than the duration of the source signature for most

marine seismic sources. Thus, it would be obvious to a person of ordinary skill to use

time delays that vary in this manner in order to avoid interference between the source

signatures which would make separation of the sources very difficult. (Ex. 1002, ¶¶

170-171.)

e. Claim 6.

Claim 6 depends from claim 1 and recites the time interval is at least as long as

a wavelet time of the first source. Just as with the 100 millisecond time interval

variations, it would have been obvious to a person of ordinary skill to use time

intervals at least as long as the wavelet time of the first source. Dr. Ikelle states that a

person of ordinary skill in the art would understand the advantage of waiting at least

the wavelet time is that it prevents the source signatures from interfering. The

interference of source signatures greatly hinders attempts to separate the data and

thus it would be obvious to a person of ordinary skill to avoid this interference by

waiting at least the wavelet time of the first source. (Ex. 1002, ¶¶ 61-63, 173.)

5. Claims 11-20.

Claims 11-13, 15-18, and 20 recite various aspects data processing that are fully

encompassed by prior art signal sorting techniques, such as mid-point trace gathers,

that were basic tools of those of ordinary skill in the art in the technical field of

seismic surveys well before the earliest filing date claimed by the ‘981 patent. Claims


38

14 and 19 additionally recite time aligning the signals – a step that necessarily occurs

when signals are encoded based on their timing, as fully evidenced by the citations to

Timoshin in the claim charts below. Thus, the modification of Beasley in view of

Timoshin, discussed above, would also result in the time aligning of claims 14 and 19

of the ‘981 patent.

A CMP gather is a collection of all the data with respect to a particular

subsurface location. More specifically, a CMP gather constitutes all the traces for

which the midpoint between a given source and receiver is the same, which

correspond to the same set of reflections being detected.

The figure above shows the common midpoints between a number of sources

and receivers. With multiple sources and receivers at different locations, there is a

common midpoint between different source-receiver pairs. A CMP gather involves

collecting the traces that result from reflections off this common location which

improves the signal to noise ratio of the data. (Ex. 1002, ¶ 30.)


39

Not surprisingly, Beasley does not waste text explaining these basic techniques

for sorting data, instead referring to them as “known”:

To separate the sources' data, the record is updated with one source's

geometry information (e.g. x, y location coordinates and time of day

identifiers, e.g. SEG standard format information, are attached to the

seismic data traces by known methods, e.g. a header with the desired

information is applied to a trace tape); optionally sorted to order, e.g.

by known common mid-point (CMP) sorting methods or known

methods such as common shot order, common detector order or

common offset order and/or combinations thereof; optionally trace

interpolated to theoretically produce a well-sampled curve between

known data points by known methods, and spatially paneled, i.e., a

portion of the data is isolated that includes data from both sources.

(Ex. 1004, 4:16-29, emphasis added. See also Ex. 1004, Fig. 14; 10:11-15, “FIG.

14 illustrates a portion of the trace data from FIG. 13 by sorting the data according to

shared common mid-points by known ‘CMP’ sorting methods and then selecting two

sets of data traces from the sorted data, the sets designated as ‘Panel A’ and Panel

B.’”)

Even with a limited explicit discussion of the “known ‘CMP’ sorting methods”

in Beasley, Beasley nevertheless includes sufficient disclosure of these known

techniques to fully encompass the “extracting” or “determining” “coherent”

components from the recorded seismic signals as they are recited in claims 11-20 of

the ‘981 patent.


40

The following claim chart specifies where each element of claims 11-20 is

found in the combined teachings of Beasley and Timoshin:

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005) 11. The method as defined in claim 7 further comprising extracting from the recorded sensor signals coherent seismic signals identified to each of the first, second and at least one additional seismic energy sources.

Ex. 1004 at 4:6-8: “The resulting seismic data contains reflections, refractions, etc., due to each source and is processed to separately distinguish data related to each source.” (See also Ex. 1004, 4:16-29; Fig. 14; 10:11-15; 11:6-9.)


Ex. 1004 at 11:6-9: “In the ‘CMP Sort’ step, individual data traces are sorted into those that share common midpoints to make each trace distinct and can be discriminated e.g. so that move out is hyperbolic and distance from other source data.” (See also Ex. 1004, 4:6-29; Fig. 14; 10:11-15; 11:6-9.)



14.a. The method as defined in claim 12 wherein the extracting the signals identified to each of the second and at least one additional seismic source comprises, for each of the second and at least one additional source, time aligning the signals with respect to a firing time of

Ex. 1005 at p. 7, ¶ 2: “Due to the incoherence of the summation of wave fields, it is possible to separate the wave fields from different sources during data processing by the CDP method and to perform seismic imaging by the diffraction method. This is achieved when restoring the compressed records by introducing the time delays of equal magnitude but opposite sign to the delays applied and stored during wave recording.”


41

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005)

each of the second and at least one additional source, and determining trace to trace and shot to shot coherent components in the recorded sensor signals.










42

‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005)




Ex. 1005 at p. 7, ¶ 2: “Due to the incoherence of the summation of wave fields, it is possible to separate the wave fields from different sources during data processing by the CDP method and to perform seismic imaging by the diffraction method. This is achieved when restoring the compressed records by introducing the time delays of equal magnitude but opposite sign to the delays applied and stored during wave recording.”

19.b. and determining trace to trace and shot to shot coherent components in the time-aligned recorded seismic signals.


6. Claims 21 and 22.

Claims 21 and 22 each depend from claim 1. Claims 21 and 22 recite towing

configurations for shot sources that are disclosed in Beasley, as evidenced by the

following claim chart:

‘981 Patent Claims Beasley (Ex. 1004)

Claim 21. The method as defined in claim 1 wherein the second source is towed behind the first source.

Ex. 1004 at 6:48-51: “A second ship 24, towing an acoustic source ST launches a wavefield from the trailing end of swatch 13.”


43


Ex. 1004 at Fig. 4 (ST, ST’).

Claim 22. The method as defined in claim 1 wherein the first source and the at least one sensor system are towed by a first vessel and the second source is towed by a second vessel.

Ex. 1004 at 5:68−6:12: “FIG. 4 is a plan view of a 3-D swath 13 of six parallel seismic cable arrays A1-A6 which are being towed through a body of water by a ship 14. . . . A discrete acoustic source SL is towed by ship 14 near the leading end of swath 13, substantially at the center of the swath.” Ex. 1004 at 6:48-51: “A second ship 24, towing an acoustic source ST launches a wavefield from the trailing end of swatch 13.”

Ex. 1004 at Fig. 4 (ST, ST’).

C. Claims 1-22 are obvious in view of the combined teachings of Beasley and Edington

1. The proposed grounds based on Beasley and Edington are not redundant to the grounds based on De Kok or the grounds based on Beasley and Timoshin.

The grounds raised in the following sections based on the combined teachings

of Beasley and Edington are meaningfully distinct from the grounds raised above

based on De Kok. Unlike the ‘981 patent, De Kok discloses time delay encoding

techniques which rely on programmed time delays in the field and polarity decoding


44

in the processing center. However, even though the ‘981 patent does not disclose

polarity decoding in the processing center, claims 1, 2, 7, and 10- 21 of the ‘981 patent

do not exclude an additional step of polarity decoding in the processing center. As

such, at least under the “broadest reasonable interpretation” standard that must be

applied in this proceeding before the Board, claims 1, 2, 7, and 10- 21 of the ‘981

patent encompasses the technique disclosed in De Kok.

Beasley, on the other hand, does not explicitly disclose polarity encoding for

simultaneous source activation, but more generally discloses that any desired type of

encoding could be used for simultaneous or near simultaneous source activation

across both the marine and land survey contexts. Edington discloses one such type of

encoding that was known more than a decade prior to the earliest filing date claimed

by the ‘981 patent – a time delay encoding that more closely matches the type of time

delay encoding disclosed in the ‘981 patent than the time delay/polarity

encoding/decoding disclosed in De Kok. Specifically, Edington discloses the

difference in time delay between any two shootings is selected so as to enable the

signal received from a first activated source to be distinguished from the signal

received from a second activated source. (Ex. 1006, 2:44-48.)

Despite the fact that both Timoshin and Edington generally relate to time-

encoding, the teachings of Edington are not redundant to the teachings of Timoshin.

For example, Edington includes a more explicit discussion of the variation of timing

of firing across multiple sequences of shots than Timoshin. (See Ex. 1006, 4:37-49,


45

noting, for example, “for each shot point there must be some variation in the

activation time delay between sources 24 and 26 for different shots, and this delay is

preferably different for each shot made at one shot point.”) On the other hand,

Timoshin includes more explicit teachings of the combination of time-aligning signals

and coherence gathering. (See Ex. 1005, p. 7, for example, “[d]ue to the incoherence

of the summation of wave fields, it is possible to separate the wave fields from

different sources during data processing by the CDP method and to perform seismic

imaging by the diffraction method.”)

As such, the grounds raised in the following sections based on the combined

teachings of Beasley and Edington are meaningfully distinct from and are not

redundant to the grounds raised above based on De Kok or the grounds raised above

based on the combined teachings of Beasley and Timoshin.

2. Claim 1

Beasley is directed to marine seismic surveys that include firing seismic sources

simultaneously or near simultaneously in which the “sources may be arranged to emit

encoded wavefields using any desired type of coding,” but does not explicitly disclose

the type of time encoding claimed in the ‘981 patent. (Ex. 1004, 7:54-56.) While

Beasley discusses the use of source encoding in the marine context, it discloses that

the same encoding techniques could be used in land seismic surveys. (Ex. 1004, 9:39-

44.)


46

As discussed above and as explained in Professor Ikelle’s declaration, prior to

the ‘981 patent it was commonplace to adapt land solutions to marine problems in

seismic surveying. (Ex. 1002, ¶¶ 28-31) Accordingly, when assessing what types of

encoding techniques could be employed in marine surveying, one of ordinary skill in

the art would have known to look to what was being used in land surveying. (Ex.

1002, ¶¶ 242-243.) Edington, which issued more than a decade before the ‘981 patent

was filed, discloses using a time encoding technique for simultaneous shooting

surveys. (Ex. 1006, Abstract.)

Edington discloses that varying the time delay between the firing of multiple

seismic sources during successive shots allows for the separation of the signal

originating from each seismic source. (Ex. 1006, 3:9-14, 4:32-40.) It would have been

obvious to employ the known time encoding techniques disclosed in Edington in the

system of Beasley to achieve the predictable result of distinguishing sources that are

fired either simultaneously or near simultaneously. (Ex. 1002, ¶ 244.) Furthermore,

both Beasley and Edington deal with simultaneous shooting, encoding, and decoding.

As Dr. Ikelle notes, these similarities would have been enough to motivate a person of

ordinary skill to combine Beasley and Edington, especially given the natural fit

between teachings in Beasley and Edington. (Ex. 1002, ¶¶ 241-243.)

The following claim chart specifies where each element of claim 1 is found in

the combined teachings of Beasley and Edington:


47

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006) 1. A method for seismic surveying, comprising:

Ex. 1004 at 1:19-25: “The present invention, in certain aspects, is directed to seismic survey systems and methods in which two or more seismic sources are fired simultaneously, or significantly close together temporally, but which is, in one aspect, significantly spatially separated, and resulting seismic data is processed meaningfully utilizing data generated by both (or more) seismic sources.”


Ex. 1004 at 3:47-57: “The present invention, in certain aspects, discloses a seismic survey system for use at sea or on land with two, three, four, or more seismic sources (or one source moved form one location to another and fired at multiple locations) for generating an acoustic wavefield (e.g., but not limited to, acoustic sources, e.g. air guns); a plurality of spaced-apart seismic detectors for discrete sampling of the acoustic wavefield reflected and/or refracted from earth layers (e.g., but not limited to geophones or hydrophones); and, at sea, a vessel or vessels for carrying or towing the seismic sources and, in one aspect, the detectors.”

Ex. 1004 at Fig. 4 (SL, SL’). 1.b. towing a second seismic energy source at a selected distance from the first seismic energy source; and

Ex. 1004 at 3:47-57: “The present invention, in certain aspects, discloses a seismic survey system for use at sea or on land with two, three, four, or more seismic sources (or one source moved form one location to another and fired at multiple locations) for generating an acoustic wavefield (e.g., but not limited to, acoustic sources, e.g. air guns); a plurality of spaced-apart seismic detectors for discrete sampling of the acoustic wavefield reflected and/or refracted from earth layers (e.g., but not limited to geophones or hydrophones); and, at sea, a vessel or


48

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006) vessels for carrying or towing the seismic sources and, in one aspect, the detectors.”

Ex. 1004 at Fig. 4 (ST, ST’). Beasley discloses that the second seismic energy source is at a selected distance from the first: Ex. 1004 at 3:57-59: “In one aspect, the seismic sources are activated simultaneously at a known location with the seismic sensors at a known location.” (emphasis added).


Ex. 1004 at 8:47-49: “It is within the scope of this invention for there to be any number of source firings from one to several hundred or more.” Ex. 1004 at 7:31-34: “The first and second sources are activated at timed intervals in alternate cycles to provide first and second reflected wavefields. The reflected wavefields are detected and converted to first and second data sets of reflected signals.”

1.d. a time interval between firing the first source and the second source varied between successive ones of the firing sequences,

Ex. 1004 at 7:31-34: “The first and second sources are activated at timed intervals in alternate cycles to provide first and second reflected wavefields. The reflected wavefields are detected and converted to first and second data sets of reflected signals.” Edington discloses that the time interval would vary between successive shots. Ex. 1006 at 2:1-13: “In particular, the method of obtaining the seismic data for a geophysical survey comprises shooting at least two seismic energy


49

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006) sources substantially simultaneously with a determinable time delay between the activation of each source, shooting the sources at least a second time substantially simultaneously with a different determinable time delay between the activation of each source from the determinable time delay used in at least one previous shooting and, for each shooting, recording as a function of time the amplitude of the seismic signals must be received at at least one point in the survey area spaced apart from the seismic energy sources.” (emphasis added). Ex. 1006 at 4:32-40: “Preferably, seismic energy sources 24 and 26 are activated at certain variable times relative to time zero on the recording system. The activation time relative to time zero of the recorder may be repeated at a specified shot point from shot to shot for either source. However, for each shot point there must be some variation in the activation time delay between sources 24 and 26 for different shots, and this delay is preferably different for each shot made at one shot point.” (emphasis added).


Ex. 1004 at 4:16-36: “To separate the sources’ data, the record is updated with one source's geometry information (e.g. x, y location coordinates and time of day identifiers, e.g. SEG standard format information, are attached to the seismic data traces by known methods, e.g. a header with the desired information is applied to a trace tape) . . . The process is then re-done with the attachment of the other source's geometry producing the seismic data related to the other seismic source.”


50

3. Claim 7

Claim 7 depends from claim 1 and further recites actuating at least one

additional seismic energy source in each firing3sequence, the at least one additional

seismic energy source actuated after an additional selected time interval after firing the

second source. Claim 7 further recites the additional selected time interval is different

than the time interval between firing the first and second sources, and that the

additional time interval is varied between successive ones of the firing sequences.

Beasley discloses using three or more sources in a shot sequence, stating “[i]t is

within the scope of this invention for there to be any number of source firings from

one to several hundred or more…Alternatively, one vessel may tow multiple seismic

sources or each of two or more vessels may each tow two or more sources.” (Ex.

1004, 8: 47-56, emphasis added.) Further, for at least the same reasons discussed

above with respect to claim 1, it would have been obvious prior to the earliest filing

date claimed by the ‘981 patent to: (a) make the additional selected time interval

different than the time interval between firing the first and second sources, and (b)

vary the additional time interval between successive ones of the firing sequences. In

particular, such a technique is one known method of encoding signal sources and it

would have been obvious to apply this known technique to any number of sources

3 The prosecution history makes clear claim 7 was intended to recite “in each firing

sequence” instead of “in each tiring sequence.” (See Ex. 1007, claim 7, p. 8.)


51

used in the method of Beasley to achieve the predictable result of signal that are

encoded based on firing timing. Accordingly, claim 7 is obvious in view of the

combined teachings of Beasley and Edington.

4. Claims 2-6 and 8-10.

Claims 2-6 each directly depend from claim 1 and recite aspects of how the

time interval between firing the first source and the second source are varied.

Likewise, claims 8-10 each directly depend from claim 7 and recite aspects of how the

additional time interval is varied. As discussed above, the art cited herein establishes

that varying such time intervals was old and well known long before the earliest filing

date claimed by the ‘981 patent.

a. Claims 2 and 10.

Claim 2 depends from claim 1 and recites the time interval is varied

systematically. Claim 10 depends directly from claim 7 and recites the additional time

interval is varied systematically between firing sequences. The systematic application

of the time variation can also include a formulaic approach to variation. (Ex. 1002, ¶

257). For example, Edington discloses an example where “the time delay between the

activation of the first and second sources is increased for each subsequent shot by a

constant amount.” (Ex. 1006, 5:27-36.) Accordingly, claims 2 and 10 are obvious in

view of the combined teachings of Beasley and Edington.


52

b. Claims 3 and 9.

Claim 3 depends from claim 1 and recites the time interval is varied quasi-

randomly. Claim 9 depends directly from claim 7 and recites the additional time

interval is varied quasi-randomly between firing sequences. Once one of ordinary skill





‘981 patent. (Ex. 1002, ¶ 259.) Accordingly, claims 3 and 9 are obvious in view of the

combined teachings of Beasley and Edington.

c. Claims 4 and 8.

Claim 4 depends from claim 1 and recites the time interval varied is randomly.

Claim 8 depends directly from claim 7 and recites the additional time interval is varied

randomly between firing sequences. As with pseudo-random time intervals, selecting

the time intervals at random is merely an obvious variant for time-encoding source

signals. (Ex. 1002, ¶ 261.) Indeed, Edington specifically contemplates ways to utilize

random aspects of time delays that are unavoidable. (See Ex. 1006, 46-50, “for

sources which exhibit considerable random variation in operation from the selected

activation time, the true time of activation should be measured and recorded to

improve the accuracy of the separation process.”) Accordingly, claims 4 and 8 are

obvious in view of the combined teachings of Beasley and Edington.


53

d. Claim 5.

Claim 5 depends from claim 1 and recites the time interval is varied in steps of

about 100 milliseconds. Given the use of time delay encoding, it would have been

obvious to a person of ordinary skill in the art to use time intervals that vary in steps

of about 100 milliseconds. Dr. Ikelle states that a person of ordinary skill in the art

would understand the advantages of using such time variations. Specifically, 100

milliseconds is slightly longer than the duration of the source signature for most

marine seismic sources. Thus, it would be obvious to a person of ordinary skill to use

time delays that vary in this manner in order to avoid interference between the source

signatures which would make separation of the sources very difficult. (Ex. 1002, ¶¶

263-264.)

e. Claim 6.

Claim 6 depends from claim 1 and recites the time interval is at least as long as

a wavelet time of the first source. Just as with the 100 millisecond time interval

variations, it would have been obvious to a person of ordinary skill to use time

intervals at least as long as the wavelet time of the first source. Dr. Ikelle states that a

person of ordinary skill in the art would understand the advantage of waiting at least

the wavelet time is that it prevents the source signatures from interfering. The

interference of source signatures greatly hinders attempts to separate the data and

thus it would be obvious to a person of ordinary skill to avoid this interference by

waiting at least the wavelet time of the first source. (Ex. 1002, ¶¶ 61-63, 266.)


54

5. Claims 11-20.

Claims 11-13, 15-18, and 20 recite various aspects data processing that are fully

encompassed by prior art signal sorting techniques, such as mid-point trace gathers,

that were basic tools of those of ordinary skill in the art in the technical field of

seismic surveys well before the earliest filing date claimed by the ‘981 patent. Claims

14 and 19 additionally recite time aligning the signals – a step that necessarily occurs

when signals are encoded based on their timing, as fully evidenced by the citations to

Edington in the claim charts below. Thus, the modification of Beasley in view of

Edington, discussed above, would also result in the time aligning of claims 14 and 19

of the ‘981 patent.

As discussed above in Section VIII(C), Beasley discloses optionally sorting

signals using “known” common mid-point (CMP) sorting methods or “known

methods” such as common shot order, common detector order or common offset

order and/or combinations thereof. (Ex. 1004, 4:16-29, emphasis added. See also Ex.

1004, Fig. 14; 10:11-15, “FIG. 14 illustrates a portion of the trace data from FIG. 13

by sorting the data according to shared common mid-points by known ‘CMP’ sorting

methods and then selecting two sets of data traces from the sorted data, the sets

designated as ‘Panel A’ and Panel B.’”) Even with a limited explicit discussion of the

“known ‘CMP’ sorting methods” in Beasley, Beasley nevertheless includes sufficient

disclosure of these known techniques to fully encompass the “extracting” or


55

“determining” “coherent” components from the recorded seismic signals as they are

recited in claims 11-20 of the ‘981 patent.

The following claim chart specifies where each element of claims 11-20 is

found in the combined teachings of Beasley and Edington:

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006) 11. The method as defined in claim 7 further comprising extracting from the recorded sensor signals coherent seismic signals identified to each of the first, second and at least one additional seismic energy sources.






14.a. The method as defined in claim 12 wherein the extracting the signals identified to each of the second and at least one additional seismic source comprises, for each of the

Ex. 1006 at 5:59-63: “The signals shown in FIG. 4. are then time shifted as shown in FIG. 5. so that the signals 38 are aligned on straight line 44 and signals 36 are on sloping line 46, and the time shifted signals are summed.”


56

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006)

second and at least one additional source, time aligning the signals with respect to a firing time of each of the second and at least one additional source,

Ex. 1006 at Fig. 5.







17. The method as defined in claim 16 wherein the extracting the signals identified to the first source

Ex. 1004 at 11:6-9: “In the ‘CMP Sort’ step, individual data traces are sorted into those that share common midpoints to make each trace distinct and can be discriminated e.g. so that move out is


57

‘981 Patent Claims Beasley (Ex. 1004) and Edington (Ex. 1006)

comprises determining trace to trace and shot to shot coherent components in the recorded sensor signals.

hyperbolic and distance from other source data.” (See also Ex. 1004, 4:6-29; Fig. 14; 10:11-15; 11:6-9.)




Ex. 1006 at 5:59-63: “The signals shown in FIG. 4. are then time shifted as shown in FIG. 5. so that the signals 38 are aligned on straight line 44 and signals 36 are on sloping line 46, and the time shifted signals are summed.”

Ex. 1006 at Fig. 5.

19.b. and determining trace to trace and shot to shot coherent components in the time-aligned recorded seismic signals.



58

6. Claims 21 and 22.

Claims 21 and 22 each depend from claim 1. Claims 21 and 22 recite towing

configurations for shot sources that are disclosed in Beasley, as evidenced by the

following claim chart:


Claim 21. The method as defined in claim 1 wherein the second source is towed behind the first source.

Ex. 1004 at 6:48-51: “A second ship 24, towing an acoustic source ST launches a wavefield from the trailing end of swatch 13.”

Ex. 1004 at Fig. 4 (ST, ST’).

Claim 22. The method as defined in claim 1 wherein the first source and the at least one sensor system are towed by a first vessel and the second source is towed by a second vessel.

Ex. 1004 at 5:68−6:12: “FIG. 4 is a plan view of a 3-D swath 13 of six parallel seismic cable arrays A1-A6 which are being towed through a body of water by a ship 14. . . . A discrete acoustic source SL is towed by ship 14 near the leading end of swath 13, substantially at the center of the swath.” Ex. 1004 at 6:48-51: “A second ship 24, towing an acoustic source ST launches a wavefield from the trailing end of swatch 13.”

Ex. 1004 at Fig. 4 (ST, ST’).


59

IX. CONCLUSION

For the foregoing reasons, claims 1-22 of the ‘981 patent are unpatentable.

Based on the substantial evidence presented in this Petition, there is a reasonable

likelihood that Petitioner will prevail as to each of these claims. Inter Partes review of

claims 1-22 is accordingly requested.

Respectfully submitted,

Date: November 26, 2014 /Scott A. McKeown/

Scott A. McKeown Registration No. 42,866 Christopher A. Bullard Registration No. 57,644

OBLON, SPIVAK, MCCLELLAND, MAIER & NEUSTADT, LLP

Customer Number

22850 Tel: (703) 413-3000 Fax: (703) 413 -2220 (OSMMN 07/09)


EXHIBIT APPENDIX

Ex. Description 1001 U.S. Patent No. 6,906,981 to Vaage 1002 Declaration of Luc T. Ikelle, Ph.D. 1003 U.S. Patent No. 6,545,944 to de Kok 1004 U.S. Patent No. 5,924,049 to Beasley et al.

1005 Soviet Union Patent No. 1,543,357 to Timoshin et al. (original text and a certified English translation)

1006 U.S. Patent No. 4,953,657 to Edington 1007 Excerpts of File History of U.S. Patent No. 6,906,981

1008 Risch DL, Chodhury AN, Hannan AE and Jamieson GA, “How Modern Techniques Improve Seismic Interpretation,” World Oil 215, Part I (April 1994):85-94.

1009 Kim NW and Seriff AJ, “Marine PSSP reflections with a bottom velocity transition zone,” Geophysics, Vol. 57, No. 1 (January 1992):161-170.

1010 Berg E, Svenning B, and Martin J, “SUMIC: Multicomponent sea-bottom seismic surveying in the North Sea–Data interpretation and applications,” SEG Expanded Abstracts (1999).

1011 Beasley CJ, Chambers RE, and Jiang Z, “A new look at simultaneous sources,” SEG Expanded Abstracts (1998).

1012 Ikelle L, Coding and Decoding: Seismic Data: The concept of multishooting (2010).

1013 Womack JE, Cruz JR, Rigdon HK, and Hoover GM, “Encoding techniques for multiple source point seismic data acquisition,” Geophysics, Vol. 55, No. 10 (October 1990):1389-1396.

1014 Ottolini R and Claerbout JF, “The migration of common midpoint slant stacks,” Geophysics, Vol. 49, No. 3 (Mar 1984):237-249.


CERTIFICATE OF SERVICE

I hereby certify that, on November 26, 2014, I caused a true and correct copy

of the foregoing Petition for Inter Partes Review of U.S. Patent No. 6,906,981 and

supporting materials to be served via UPS Next Day Air at the correspondence

address of record for the ‘981 patent:

E. Eugene Thigpen Petroleum Geo-Services, Inc. P.O. Box 42805 Houston TX 77242-2805

Courtesy copies of the foregoing Petition for Inter Partes Review and supporting

materials have also been served via UPS Next Day Air on Patent Owner’s counsel in

the co-pending litigation and Patent Owner’s counsel in co-pending Inter Partes Review

proceedings challenging the claims of WesternGeco’s patents:

Ellisen Turner Irell and Manella 1800 Ave of the Stars Ste 900 Los Angeles, CA 90067

David I. Berl Williams & Connolly, LLP 725 12th St., NW Washington, DC 20005 /Scott A. McKeown/ Scott A. McKeown Reg. No. 42,866

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