DECLARATION OF LISA STEWART
`
`
`
`
`I, Lisa Stewart, declare as follows:
`
`
`1.
`
`All statements herein made of my own knowledge are true, and all
`
`statements herein made based on information and belief are believed to be true. I
`
`am over 21 years of age and otherwise competent to make this declaration.
`
`2.
`
`I am the Executive Editor of Oilfield Review magazine, a quarterly
`
`publication by Schlumberger to communicate technical advances in finding and
`
`producing hydrocarbons to oilfield professionals. I have been the Executive Editor
`
`of Oilfield Review since 2011.
`
`3.
`
`I obtained my Ph.D. in Geophysics from Yale University in 1983, and
`
`have been an employee of Schlumberger since 1985. Until 1995, I was a Research
`
`Scientist in Geoacoustics and Seismic Interpretation at Schlumberger. From 1993
`
`until 1999 I served as an Editor of Oilfield Review. From 1997-1998 I also served
`
`as the Manager of VIP seminars for Oilfield Marketing and, from 1996-2002, I was
`
`the executive editor of Oilfield Review in the Russian language. From 2000-2004
`
`I was an Advisory Editor for Oilfield Review and, from 2004-2005, I was the
`
`Manager of Technical Communications for Schlumberger’s Research Downhole
`
`Sample Analysis program. Before becoming Executive Editor of Oilfield Review
`
`in 2011, I again served as an Advisory Editor of Oilfield Review from 2005-2011.
`
`
`
`1
`
`WesternGeco Ex. 1013, pg. 1
`
`

`
`4.
`
`As part of my current position as Executive Editor, and as part of my
`
`past positions as Editor and Advisory Editor, I am familiar with the publication and
`
`archival practices of the Oilfield Review magazine.
`
`5.
`
`I have been asked by counsel for WesternGeco L.L.C. to determine
`
`when the document attached hereto as Attachment A, “3D Seismic Survey Design,”
`
`was disseminated by Schlumberger and made available to the public.
`
`6.
`
`3D Seismic Survey Design was published by Schlumberger in its April
`
`1994 edition, volume 6, issue 2, of Oilfield Review. Attachment A is a true and
`
`correct copy from Schlumberger’s Archives of the 3D Seismic Survey Design
`
`article that was published in the April 1994 edition of Oilfield Review.
`
`7.
`
`The April 1994 edition of Oilfield Review containing the 3D Seismic
`
`Survey Design article would have been disseminated to university libraries,
`
`national laboratories, and customers to ensure that interested oilfield professionals,
`
`and the public in general, were well aware of the advancements ongoing at
`
`Schlumberger. As confirmed by Attachment B to my declaration, it was the
`
`custom of Schlumberger to disseminate Oilfield Review in this fashion beginning
`
`with the April 1989 edition of the magazine. Although electronic publication of
`
`Oilfield Review is now commonplace, our practice of disseminating hard copy
`
`editions to those noted above continues to this day.
`
`
`
`2
`
`WesternGeco Ex. 1013, pg. 2
`
`

`
`8.
`
`These statements are made with the knowledge that willful false
`
`statements are punishable bylfine or imprisonment, or both, under Section 1001 of
`
`Title 18 of the United States Code, and that such willful false statements may
`
`jeopardize the results of these proceedings.
`
`9.
`
`I declare under penalty of perjury under the laws of the United States
`
`of America that the foregoing is true and correct.
`
`Executed onthe 20thday ofNovember 2014.
`
`Lisa Stewart
`
`WesternGeco Ex. 1013, pg. 3
`
`

`
`Attachment A
`
`
`
`WesternGeco Ex. 1013, pg. 4
`
`

`
`WesternGeco Ex. 1013, pg. 5
`
`WesternGeco Ex. 1013, pg. 5
`
`

`
`SCHLUMBERGER
`
`Oilfield Review
`
`The Oilfield Review is published quarterly
`by Elsevrcr Science Publishers 3. V. to corn
`municate technical advances in finding and
`producing hydrocarbons to oilfield pro/es—
`sionals. Contributors listed with onlygeo-
`graphic location are employees Of5Cl‘llUl77‘
`berger or its affiliates.
`
`Annual subscription including postage is
`195.00 US do/lars/367,00 Dutch guilders.
`Biannual subscription is 316.00 US dol-
`lars/560. 00 Dutch guilders. Dutch guiltler
`prices are definitive; US dollar prices are
`subject to FEXL hange rate fluctuations.
`
`4 C
`
`orrosion in the Oil Industry
`
`Corrosion costs the oil industry billions of dollars a year, a fact that
`makes the role of the corrosion engineer an increasingly important one.
`This article focuses on how corrosion affects every aspect of exploration
`and production, from offshore rigs to casing, and reviews the role of cor-
`rosion agents such as drilling and production fluids. We discuss methods
`of control and techniques to monitor corrosion, along with an explana—
`tion of the chemical causes of corrosion.
`
`19
`
`3D Seismic Survey Design
`
`Planning a seismic survey calls for juggling four balls at once: getting the
`best illumination of the target at the lowest cost while obtaining data
`that will satisfying present and future demands. An investment in plan-
`ning can mean the difference between data that make a field and data
`that are uninterpretahle. We look at the two key ingredients of seismic
`survey planning: how to get a good signal, and how to balance signal
`quality with cost constraints. Two case studies are highlighted.
`
`33
`
`Designing and Managing Drilling Fluid
`
`Drilling fluid—or mud—can contribute to virtually any drilling problem.
`Stuck pipe, poor completion, inadequate logs and production difficulties
`may all be laid at mud’s door. In recent years, oil—base mud (OBM) suc~
`cessfully eliminated many of these concerns, but environmental regula-
`tions increasingly limit its use. This article discusses the issues that must
`now be considered when designing a mud program without OBM, looks
`into new types ofdrilling fluid, and examines how improved drilling flu-
`ids management can yield substantial efficiency benefits.
`
`kXECUT|VE EDITOR
`Henry N. Edmundson
`
`EDITORS
`james M. Kent
`Chris Fox
`Andy Martin
`Lisa Stewart
`CONTRIBUTING EDITORS
`Rana Rottenberg
`
`MANAGING EDITOR
`Therese A. Lloyd
`
`DESIGN
`l,&'l'lEl(el‘ Design
`ILLUSTRATORS
`/ane Hassall
`George Stewart
`
`April 1994
`Volume 6
`Number 2
`
`Advisory Panel
`Terry Adams
`BP Exploration
`Stock/ey Park, England
`Svend Aage Andersen
`Maersk Oil Qatar A5
`Doha, State of Qatar
`Michael Fetkovich
`Phillips Petroleum Company
`Bartlesville, Oklahoma, USA
`Gordon (jreve
`Amoco Production Company
`Houston, Texas, USA
`Jim Stewart
`PanCanadian Petroleum Limited
`Calgary, Alberta, Canada
`' Richard Woodhouse
`Independent consultant
`Surrey, England
`Review Board
`Trevor Burgess
`Anadrill
`Sugar Land, Texas, USA
`Bill Diggons
`Wireline, Testing & Anadrill
`Sugar Land, Texas, USA
`Richard Chiselin
`Wireline, Testing & Anadrill
`Sugar Land, Texas, USA
`Denis Poisson
`Sedco Forex
`Montrouge, France
`Howard Neal
`CeoQuest
`Houston, Texas, USA
`Svein Kjellesvik
`Ceco-Prakla
`Gatwick, West Sussex, UK
`Dennis O’Brien
`Dowell
`Sugar land, Texas, USA
`David Pinnington
`Services Techniques Schlumberger
`Montrouge, France
`
`WesternGeco Ex. 1013, pg. 6
`
`

`
`3D Seismic Survey Design
`
`There’s more to designing a seismic survey than just choosing sources and receivers and shooting away. To
`
`get the best signal at the lowest cost, geophysicists are tapping an arsenal of technology from integration of
`
`borehole data to survey simulation in 3D.
`
`C. Peter Ashton
`Maersk Olie og Gas AS
`Copenhagen, Denmark
`
`Brad Bacon
`
`Angus Mann
`Nick Moldoveanu
`Houston, Texas, USA
`
`Christian Déplanté
`E/f/‘lquitaine
`Pau, France
`
`Dick lreson
`Thor Sinclair
`Gatwick, England
`
`Glen Redekop
`Maersk Oil Qatar AS
`Doha, Qatar
`
`For help in preparation of this article, thanks to Jack
`Caldwell and Greg Leriger, Geco-Prakla, Houston, USA;
`Mandy Coxon and Dominique Pajot, Geco-Prakla,
`Gatwick, England; Jacques Estival, Elf Petroleum Nigeria,
`Lagos, Nigeria; Dietmar Kluge, Geco-Prakla, Hannover,
`Germany; Lloyd Peardon, Schlumberger Cambridge
`Research, England; Lars Sonneland, Geco-Prakla,
`Stavanger, Norway; and Tim Spencer, British Gas,
`Reading, England.
`Appreciation is expressed to Qatar General Petroleum
`Corporation (QGPC) for its consent to the release of data.
`QUAD-QUAD is a mark of Geco-Prakla. TWST
`(Tlirough-Tubing Well Seismic Tool) is a mark of Schlum-
`berger.
`1. For the most recent worldwide figures:
`Riley DC: "Special Report Geophysical Activity in
`1991,” The Leading Edge 1 2, no. 11 (November
`i993): 1094-1117.
`2. Personal communication: Thor Sinclair.
`
`April 7994
`
`Cost of Marine 3D Seismic Survey per km?
`
`Cost of marine 3D
`seismic surveys for
`one 0121 company.
`Since 1990, the cost
`of a marine 3D sur-
`vey has decreased
`by more than 50%.
`(Courtesy of [cm Jack,
`BP Exploration, Stock-
`Iey Pork, England.)
`
`w
`
`taken into account. This article investigates
`the objectives and methods of seismic sur-
`vey design and reviews field examples of
`state—of-the-art techniques.
`The ideal 3D survey serves multiple pur-
`poses.
`lnitially, the data may be used to
`enhance a structural interpretation based on
`two—dimensional (2D) data, yielding new
`drilling locations. Later in the life of a field,
`seismic data may be revisited to answer
`questions about fine-scale reservoir architec-
`ture or fluid contacts, or may be compared
`with a later monitor survey to infer fluid—front
`movement. All these stages of interpretation
`rely on satisfactory processing, which in turn
`relies on adequate seismic signal to process.
`The greatest processing in the world cannot
`fix flawed signal acquisition.
`
`Dollars.inthousands
`
`Year
`
`Increased efficiency has brought the cost of
`marine three-dimensional (3D) seismic data
`to its lowest level ever, expanding the popu-
`larity of 3D surveys (above). In the past five
`years, oil companies have increased expen-
`ditures on seismic surveys by almost 60%,
`to $2.2 billion.‘ However, an estimated
`10% of surveys fail to achieve their primary
`objective—some because the technology
`does not exist to process the data, some
`because the surveys are improperly
`planned? Careful planning can result in
`more cost—effective acquisition and process-
`ing, and in data of sufficient quality to bene-
`fit from the most advanced processing.
`But before the first shot is fired or the first
`trace recorded, survey designers must deter-
`mine the best way to reveal the subsurface
`target. As basics, they consider locations
`and types of sources and receivers, and the
`time and labor required for acquisition.
`Many additional factors, including health,
`safety and environmental
`issues, must be
`
`WesternGeco Ex. 1013, pg. 7
`
`

`
`l:lTemporal and
`spatial aliasing
`caused by sam-
`pling less than
`twice per cycle.
`Temporal aliasing
`(top) occurs when
`insufficient sam-
`pling renders a 50-
`Hz signal and a
`200-Hz signal indis-
`tinguishable
`(arrows represent
`sample points). The
`50-Hz signal is ade-
`quately sampled,
`but not the 200-Hz.
`(Adapted from Sheriff.
`reference 4.) Spatial
`aliasing (bottom)
`occurs when
`receiver spacing is
`more than: half the
`spatial wavelength.
`With minor aliasing
`(left) arrivals can be
`tracked at near off-
`sets as time
`increases, but
`become difficult to
`follow at far offsets.
`With extreme alias-
`ing (right) anivals
`even appear to be
`traveling back-
`wards, toward near
`offsets as time
`increases. (Adapted
`from Claerbout, refer-
`ence 6.)
`
`Temporal Aliasing
`
`50 Hz
`
`200 HZ
`
`l_J_iilii.i_J_Ii_i_L_i_I.i_l_i_i_i_liiil:ii_Li_i__iJ__i_.i_il
`O
`8
`16
`24
`32
`
`Minor Aliasing
`
`_l'—LJ_
`
`Extreme Aliasing
`
`.:i
`
`*7” tlfi
`
`
`
`Two—vvaytime
`
`
`
`Two—waytime
`
`T»
`
`—
`
`Increasing offset
`
`increasing offset
`
`+ Stacking _
`velocity “
`
`OMP gather
`
`Corrected
`CMP gather
`
`Stacked
`CMP trace
`
`Better stacking from a wide and evenly spaced set of offsets.
`Reflection arrival times from different offsets are assumed to fol-
`low a hyperbola. The shape of the hyperbola is computed from
`the arrivals. Traces are aligned by flattening the best-fitting
`hyperbola into a straight line, then summed, or stacked. Perfect
`alignment should yield maximum signal amplitude at the time
`corresponding to zero offset. A wide range of evenly spaced off-
`sets gives a better-fitting hyperbola, and so a better stack.
`
`Elements of a Good Signal
`What makes a good seismic signal? Process-
`ing specialists list three vital require-
`ments—good signal-to—noise ratio (S/N),
`high resolving power and adequate spatial
`coverage of the target. These basic elements,
`along with some geophysical guidelines (see
`”Guidelines from Geophysics,” page 22),
`form the foundation of survey design.
`High S/N means the seismic trace has
`high amplitudes at times that correspond to
`reflections, and little or no amplitude at
`other times. During acquisition, high S/N is
`achieved by maximizing signal with a seis-
`mic source of sufficient power and directiv-
`ity, and by minimizing noise} Noise can
`either be generated by the source~shot-
`generated or coherent noise, sometimes
`orders of magnitude stronger than deep seis-
`mic ref|ections—or be random. Limitations
`in the dynamic range of acquisition equip-
`ment require that shot-generated noise be
`minimized with proper source and receiver
`geometry. Proper geometry avoids spatial
`aliasing of the signal, attenuates noise and
`obtains signals that can benefit from subse-
`quent processing. Aliasing is the ambiguity
`that arises when a signal
`is sampled less
`than twice per cycle (left). Noise and signal
`cannot be distinguished when their sam-
`pling is aliased.
`A common type of coherent noise that
`can be aliased comes from low—frequency
`waves trapped near the surface, called sur-
`face waves. On land, these are known as
`ground roll, and create major problems for
`processors. They pass the receivers at a
`much slower velocity than the signal, and
`so need closer receiver spacing to be prop-
`erly sampled. Planners always try to design
`surveys so that surface waves do not con-
`taminate the signal. But if this is not possi-
`ble, the surface waves must be adequately
`sampled spatially so they can be removed.
`During processing, S/N is enhanced
`through filters that suppress noise. Coherent
`noise is reduced by removing temporal and
`spatial frequencies different from those of
`the desired signal,
`if known. Both coherent
`and random noise are suppressed by stack-
`ing—summing traces from a set of source-
`receiver pairs associated with reflections at
`a common midpoint, or CMP.4 The source-
`receiver spacing is called offset. To be
`stacked, every CMP set needs a wide and
`evenly sampled range of offsets to define the
`reflection travel-time curve, known as the
`normal moveout curve. Flattening that
`curve, called normal moveout correction,
`will make reflections from different offsets
`arrive at the time of the zero—offset reflec-
`tion. They are then summed to produce a
`stack trace (left).
`In 3D surveys, with the
`
`WesternGeco Ex. 1013, pg. 8
`
`

`
`Offsets and Azimuths in a CMP Bin
`
`
`
`‘Iflflfl-3flflfififlflEEEEMMEIR
`
`- Receiver
`
`x Source
`Bin
`
`..
`
`Illlllllllllll
`
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`
`Offset Distribution
`
`.. llllllllllzlllll
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`
`..iiiiIllllllllllllllll
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`
`Reflections from source-receiver pairs bounce in a bin, a rectan-
`gulca, horizontal area defined during planning. In a 3D survey a
`CMP trace is formed by stacking traces that arrive from a range of
`azimuths and offsets (top). The distribution of offsets is displayed in
`a histogram within each bin (bottom). The vertical axis of the his-
`togram shows the amount of offset, and the horizontal axis indi-
`cates the position ot the trace in offset.
`
`Shotpoint number
`150
`
`190
`
`HA fold plot showing 40-fold coverage over the heart of the survey.
`The edge of the survey has partial fold because several of the first
`and last shots do not reach as many receivers as in the central part
`of the survey.
`
`advent of multielement marine acquisi-
`tion—multistreamer, multisource seismic
`vessels-—and complex land acquisition
`geometries, reflections at a CMP come from
`a range of azimuths as well as a range of
`offsets (right).5 A 3D CMP trace is formed by
`stacking traces from source-receiver pairs
`whose midpoints share a more or less com-
`mon position in a rectangular horizontal
`area defined during planning, called a bin.
`The number of traces stacked is called
`fold—in 24-fold data every stack trace rep-
`resents the average of 24 traces. Theoreti-
`cally, the S/N of a survey increases as the
`square root of the fold, provided the noise is
`random. Experience has shown, however,
`that for a given target time, there is an opti-
`mum fold, beyond which almost no S/N
`improvement can be made.
`Many survey designers use rules of thumb
`and previous experience from 2D data to
`choose an optimal fold for certain targets or
`certain conditions. A fringe—called the fold
`taper or halo—around the edge of the sur-
`vey will have partial fold, thus lower S/N,
`because several of the first and last shots do
`not reach as many receivers as in the central
`part of the survey (below, right). Getting full
`fold over the whole target means expanding
`the survey area beyond the dimensions of
`the target, sometimes by 100% or more.
`Many experts believe that 3D surveys do not
`require the level of fold of 2D surveys. This
`is because 3D processing correctly positions
`energy coming from outside the plane con-
`taining the source and receiver, which in the
`2D case would be noise. The density of data
`in a 3D survey also permits the use of noise-
`reduction processing, which performs better
`on 3D data than on 2D.
`
`Filtering and stacking go a long way
`toward reducing noise, but one kind of
`noise that often remains is caused by multi-
`ple reflections, ”multiples” for short. Multi-
`ples are particularly problematic where
`there is a high contrast in seismic properties
`near the surface. Typical multiples are rever-
`berations within a low-velocity zone, such
`as between the sea surface and sea bottom,
`
`3. Directivity is the property of some sources whereby
`seismic wave amplitude varies with direction.
`4. For a full description of terms used in seismic data
`processing see Sheriff RE: Encyclopedic Dictionary of
`Exploration Geophysics. Tulsa, Oklahoma, USA: Soci-
`ety of Exploration Geophysicists, 1991.
`. Streamers are cables equipped with hydrophone
`receivers. Multistreamer vessels tow more than one
`receiver cable to multiply the amount of data acquired
`in one pass. For a review of marine seismic acquisition
`and processing see Boreham D, Kingston J, Shaw P
`and van Zee|stJ: "3D Marine Seismic Data Process-
`ing,” Oilfield Revie-w3, no. 1 (January 1991): 41-55.
`
`.
`
`April 1994
`
`WesternGeco Ex. 1013, pg. 9
`
`

`
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`
`Seafloor multiple
`
`Seafloor multiple
`
`or between the earth’s surface and the bot-
`tom of a layer of unconsolidated rock
`(below,
`left). Multiples can appear as later
`arrivals on a seismic section, and are easy to
`confuse with deep reflections (Ieft).6 And
`because they can have the same character-
`istics as the desired signa|—same frequency
`content and similar ve|ocities—they are
`often difficult to suppress through filtering
`and stacking. Sometimes they can be
`removed through other processing tech-
`niques, called demultiple processing, but
`researchers continue to look for better ways
`to treat multiples.
`The second characteristic of a good seis-
`mic signal
`is high resolution, or resolving
`power—the ability to detect reflectors and
`quantify the strength of the reflection. This is
`achieved by recording a high bandwidth, or
`wide range of frequencies. The greater the
`bandwidth, the greater the resolving power
`of the seismic wave. A common objective of
`seismic surveys is to distinguish the top and
`bottom of the target. The target thickness
`determines the minimum wavelength
`required in the survey, generally considered
`to be four times the thickness.7 That wave-
`length is used to calculate the maximum
`required frequency in the bandwidth—
`average seismic velocity to the target
`divided by minimum wavelength equals
`maximum frequency. The minimum fre-
`quency is related to the depth of the target.
`Lower frequencies can travel deeper. Some
`seismic sources are designed to emit energy
`in particular frequency bands, and receivers
`normally operate over a wider band. ideally,
`sources that operate in the optimum fre-
`quency band are selected during survey
`design. More often, however, surveys are
`shot with whatever equipment is proposed
`by the lowest bidder.
`
`Seismic section with strong multiple noise. Multiples can
`appear as a repetition of a shallower or deeper portion of the
`seismic image. [Adapted from Morley 1. and C1aerboutJF: "Predic-
`tive Deconvolution in Shot—Rece1‘vor Space,
`"Geophysics 48 (May 1983):
`51 5-53 1 .]
`
`Primary
`reflection
`
`Ghost
`
`Near—surface
`multiples
`
`Long—path
`multiple
`
`Multiple reflec-
`tions. Alter leav-
`ing the source,
`seismic energy
`can be reflected a
`number or times
`before arriving at
`the receiver.
`
`Guidelines from Geophysics
`
`Many of the rules that guide 3D survey design are
`simple geometric formulas derived for a single
`plane layer over a half-space: the equation
`describing the hyperbola used in normal moveout
`correction is one example. Others are approxima-
`tions from signal processing theory. Sometimes
`survey parameters are achieved through trial and
`error. The following formulas hold for some sim-
`ple 3D surveys:
`Bin size, Amy, is calculated to satisfy vertical
`and lateral resolution requirements. For a flat
`reflector, bin length, Ax, can be the radius of the
`Fresnel zone or larger. The Fresnel zone is the
`area on a reflector from which reflected energy
`
`22
`
`can reach a receiver within a half-wavelength of
`the first reflected energy. For a dipping reflector
`
`where V,,,,s is the root mean square average of
`velocities down to the target, f,,,,,, is the maxi-
`mum nonaliased frequency required to resolve
`the target, and 19 is the structural dip. Normally
`Ay= AX.
`3D told is determined from estimated S/N of
`
`previous seismic data, usually 2D. 3D fold must
`be greater than or equal to
`
`2Dfold 4/ MAY
`zmdx
`
`,
`
`where this the radius of the Fresnel zone and (IX
`is the CMP interval in the 2D data.
`
`Maximum offset, X,,,,.,,,, is chosen after consid-
`ering conflicting factors—velocity resolution,
`normal moveout stretch and multiple
`attenuation.1 For a velocity resolution Av/v
`
`required to distinguish velocities at time 7',
`
`xm =
`
`2 Tvz
`A'(A—i”)
`where Afis f,,,,.,,,— f,,,,-,,, or the bandwidth. As X,,,,,,
`increases, Av/v increases, or improves. But with
`long offsets, normal moveout stretch increases
`and multiples can become worse.
`
`1. Normal moveout stretch is the distortion in wave-
`shape caused by normal moveout correction.
`
`WesternGeco Ex. 1013, pg. 10
`
`

`
`Another variable influencing resolution is
`source and receiver deplh—on land, the
`depth of the hole containing the explosive
`source (receivers are usually on the surface),
`and at sea, how far below the surface the
`sources and receivers are towed. The
`source-receiver geometry may produce
`short—path multiples between the sources,
`receivers, and the earth or sea surface. If the
`path of the multiple is short enough, the
`multiple~sometimes called a ghost—will
`closely trail the direct signal, affecting the
`signa|'s frequency content. The two—way
`travel time of the ghost is associated with a
`frequency, called the ghost notch, at which
`signals cancel out. This leaves the seismic
`record virtually devoid of signal amplitude
`at the notch frequency. The shorter the dis-
`tance between the source or receiver and
`the reflector generating the multiple, the
`higher the notch frequency. It is important to
`choose a source and receiver depth that
`places the notch outside the desired band-
`width.
`It would seem desirable to plan a
`survey with the shallowest possible sources
`and receivers, but this is not always optimal,
`especially for deep targets. On land, short-
`path multiples can reflect off near-surface
`layers, making deeper sources preferable. in
`marine surveys, waves add noise and insta-
`bility, necessitating deeper placement of
`both sources and receivers.
`in both cases,
`survey design helps reach a compromise.
`The third requirement for good seismic
`data is adequate subsurface coverage. The
`lateral distance between CMPs at the target
`is the bin length (for computation of bin
`length, see ”Guidelines from Geophysics,”
`previous page). Assuming a smooth hori-
`zontal reflector, the minimum source spac-
`ing and receiver spacing on the surface
`must be twice the CMP spacing at the tar-
`get. If the reflector dips, reflection points are
`not CMPs (above, right). Reflected waves
`may be spatially aliased if the receiver spac-
`ing is incorrect. A survey designed with good
`spatial coverage but assuming flat layers
`might fail
`in complex structure. To record
`reflections from a clipping layer involves
`more distant sources and receivers than
`reflections from a flat layer, requiring expan-
`
`April 1994
`
`Horizontal Reflector
`430 M W \\|// NL M
`
`Dipping Reflector
`
`Alb Shotpoint
`I Receiver
`
`Eflect of retlector dip on the reflection point. When the reflector is
`flat (top) the CMP is C!’ common reflection point. When the rellector
`dips (bottom) there is no CMP. A dipping reflector may require
`changes in survey parameters, because reflections may involve
`more distant sources and receivers than reflections from a flat layer.
`
`6. Claerbout JF: Imaging the Earths Interior. Boston,
`Massachusetts, USA: Blarkwell Scientific Publications
`(1985): 356.
`7. This is the criterion for resolving target thickness visu-
`ally. By studying other attributes of a seismic trace
`such as amplitude or signal phase, thinner layers can
`be resolved.
`8. Survey design and survey planning are sometimes
`used interchangeably, but most specialists prefer to
`think of planning as the part of the design process that
`considers cost constraints and logistics.
`
`sion of the survey areafcalled migration
`aperture—to obtain full fold over the target.
`In general, survey planners use simple
`trigonometric formulas to estimate optimal
`CMP spacing and maximum source-receiver
`offset on dipping targets. As geophysicists
`seek more information from seismic data,
`making the technique more cost-effective,
`simple rules of thumb will no longer pro-
`vide optimum results. Forward modeling of
`seismic raypaths, sometimes called raytrace
`modeling, provides a better estimate of sub-
`surface coverage, but is not done routinely
`during survey planning because of cost and
`time constraints. An exception is a recent
`evaluation by Geco—Prakla for a survey in
`the Ship Shoal South Addition area of the
`Gulf of Mexico (page 37).
`
`Balancing Geophysics with other
`Constraints
`
`is expensive.
`Acquiring good seismic signal
`On land or at sea, hardware and labor costs
`constrain the survey size and acquisition
`time. The job of the survey planner is to bal-
`ance geophysics and economy, achieving
`the best possible signal at the lowest possi-
`ble cost.8 On land, source lines can be
`aligned with receiver lines, or they can be at
`angles to each other. Different source-
`receiver patterns have different cost and sig-
`nal advantages, and the planner must
`
`WesternGeco Ex. 1013, pg. 11
`
`

`
`Checkerboard Pattern
`II III “II III
`
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`Brick Pattern
`f II II II
`
`I
`
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`
`II II II I
`
`Zigzag Pattern
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`I
`* Source
`- Receiver
`
`Common source-receiver layouts for land
`acquisition. The checkerboard pattern
`(top), sometimes called the straight-line or
`cross-array pattern, is preferred when the
`source is a vibrator truck, because it
`requires the least maneuvering. The brick
`pattern, (Hliddle) sometimes called stag-
`gered-line, can provide better coverage at
`short offsets than the checkerboard, butris
`more time-consuming, and so costlier. ‘I'he
`zigzag pattern (bottom) is highly etllctent in
`areas of excellent access, such cs deserts,
`where vibrator trucks can zigzag between
`receiver lines.
`
`face rights are separately and privately held,
`such as in the US, landowners must give
`permission and can charge an access fee.
`Other constraints that can affect survey
`planning include hunting seasons, per-
`mafrost, population centers, breeding sea-
`sons, animals migrating or chewing cables,
`and crops that limit vibrator source trucks to
`farm roads.
`Marine survey planners consider different
`constraints. Hardware is a major cost;
`sources and recording equipment are a siz-
`able expense, but additionally, seismic ves-
`sels cost $35 to $40 million to build, and
`
`Oilfield Review
`
`choose the one that best suits the survey
`(right). Once a survey pattern is selected,
`subsurface coverage can be computed in
`terms of fold and distribution of offset and
`azimuth.
`If the coverage has systematic
`holes, the pattern must be modified. in com-
`plex te‘rrain, planned and actual surveys
`may differ significantly (Ieft).9
`Land acquisition hardware can cost $5
`million to $10 million for recording equip-
`ment and sources—usually vibrating trucks
`or dynamite——but labor is the major survey
`cost. Cost can be controlled by limiting the
`number of vibrator points or shotpoints, or
`the number of receivers. But limiting
`receivers limits the area that can be shot at
`one time.
`If a greater area is required,
`receivers must be picked up and moved,
`increasing labor costs. The most efficient
`surveys balance source and receiver
`l'eqUlreme“t5 50 that most Of the time l5
`spent recording seismic data and not wait-
`ing for equipment to be moved. Land prepa-
`ration, such as surveying source and
`receiver locations and cutting paths through
`vegetation or topography, must be included
`on the cost side of the planning equation. In
`countries where mineral rights and land sur-
`
`Random Technique
`
`:
`
`I-no-no-an...-I............................
`
`:...:...:...:...:..........:...:........
`uu--u--o-no--ugo
`I
`u
`
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`
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`
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`o
`.
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`
`Source line
`----- Receiver line
`
`x Source
`- Receiver
`
`Planned versus actual surveys. A survey planned in West Texas,
`USA (top, left) calls for a checkerboard of receiver lines (blue) and
`source lines (red). The actual survey shot (bottom, left) came very
`close to plan. Other cities present acquisition challenges. A survey
`in lVlila:n, Italy (light) used a random arrangement of sources and
`receivers. (Adapted from Bertelli et al, reference 9.)
`
`WesternGeco Ex. 1013, pg. 12
`
`

`
`clock starts ticking once acreage is licensed.
`Exploration and development contracts
`require oil companies to drill a certain
`number of wells, spend a certain amount of
`money, or shoot a certain amount of seis-
`mic tlata before a given date. There is often
`little time between gaining approval to
`explore or develop an area and having to
`drill.
`in some cases, oil companies plan
`every detail of the acquisition before putting
`the job out to bid.
`in other cases,
`to
`increase efficiency, oil companies and seis-
`mic service companies share the planning.
`in many cases, service companies plan the
`survey from beginning to end based on
`what the oil company wishes to achieve. in
`the quest for cost savings, however, seismic
`signal is often compromised.
`
`Cost-Effective Seismic Planning
`How would 3D seismic acquisition, pro-
`cessing and interpretation be different if a
`little more emphasis were given to survey
`design? Geco-Prakla’s Survey Evaluation
`and Design team in Gatwick, England, has
`shown that by taking a bit more care, signal
`can be improved, quality assured and cost
`optimized simultaneously. There are three
`parts to the process as practiced by Geco-
`Prakla——specification, evaluation and design
`(next page). Specification defines the survey
`objectives in terms of a particular depth or
`target formation, and the level of interpreta-
`tion and resolution required. The level of
`interpretation must be defined early; data to
`be used solely for structural
`interpretation
`can be of lesser quality, leading to lower
`
`|'JMm-ine acquisi-
`tion geometry
`slzowlng seismic
`vessels looping in
`oblong circuits.
`The length of
`straight segments is
`calculated from
`{old plots, and must
`include additional
`leng'th—“run in”
`and "run out"—to
`allow cable to
`straighten after
`each turn.
`
`tens of thousands of dollars per day to oper-
`ate. Sources are clusters of air guns of differ-
`ent volum