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
i
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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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:
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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Email: [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.
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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).
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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.
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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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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‘981 Patent Claims De Kok (Ex. 1003)
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
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‘981 Patent Claims De Kok (Ex. 1003)
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.)
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‘981 Patent Claims De Kok (Ex. 1003)
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
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‘981 Patent Claims De Kok (Ex. 1003)
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
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‘981 Patent Claims De Kok (Ex. 1003)
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.
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.”
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
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‘981 Patent Claims De Kok (Ex. 1003)
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.
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.”
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
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‘981 Patent Claims De Kok (Ex. 1003)
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.
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.”
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.
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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.)
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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.)
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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
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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.”
1.a. towing a first seismic energy source and at least one seismic sensor system;
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
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‘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).
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. 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
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‘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.”
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. 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.”
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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.)
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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.
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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
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, ¶ 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
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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
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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.)
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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.
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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.)
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. 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.)
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. 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.”
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‘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.
14.b. and determining trace to trace and shot to shot coherent components in the recorded sensor signals.
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.)
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.
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.)
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. 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.)
17. The method as defined in claim 16 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. 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.)
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‘981 Patent Claims Beasley (Ex. 1004) and Timoshin (Ex. 1005)
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.
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.)
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. 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.
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.)
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.”
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‘981 Patent Claims Beasley (Ex. 1004)
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
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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,
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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.)
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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:
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‘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.”
1.a. towing a first seismic energy source and at least one seismic sensor system;
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
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‘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).
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. 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
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‘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).
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. 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.”
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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.)
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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.
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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
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, ¶ 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.
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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.)
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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
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“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.
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.)
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. 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.)
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. 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
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.”
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‘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.
14.b. and determining trace to trace and shot to shot coherent components in the recorded sensor signals.
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.)
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.
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.)
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. 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.)
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
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‘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.)
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.
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.)
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. 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.
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.)
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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.”
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’).
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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)
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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.
Petition for Inter Partes Review of U.S. Patent No. 6,906,981
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