2D and 3D Land Seismic Data Acquisition and Seismic Data Processing
Kiran Kumar Talagapu M.Sc.(Tech.) Geophysics Department of Geophysics College of Science and Technology Andhra University Visakhaptanam - 530003 Andhra Pradesh, India
CERTIFICATE
This is to certify that Mr. Kiran Kumar Talagapu, a final year student of M. Sc. (Tech.) Geophysics, Department of Geophysics, Andhra University, Waltair, Visakhapatnam has participated in the project work “2-Dimensional and 3Dimensional Land Seismic Data Acquisition and Seismic Data Processing” from 10th December 2004 to 31st January 2005, at Oil and Natural Gas Corporation (ONGC) Chennai.
( R.V.S. MURTHY ) CHIEF GEOPHYSICIST (S)
CERTIFICATE
This is to certify that this training project report is bonafide work of Mr. T. Kiran Kumar, submitted in partial fulfillment of M.Sc. (Tech.) degree in Geophysics during the final year degree course.
(PROF. A. LAKSHMIPATHI RAJU) HEAD OF THE DEPARTMENT, DEPARTMENT OF GEOPHYSICS, ANDHRA UNIVERSITY, VISAKHAPATNAM.
Acknowledgements Every work we do is linked directly or indirectly to many different aspects, circumstances and people. Aspects which we try to understand, work on and come to a conclusion, circumstances which motivate us and people who help us and guide us to achieve what we are intend to. Recollecting the near past events of my training period I am deeply indebted to the people who were responsible for the successful completion of my work. To begin with I am thankful to our Head of the Department Prof. A. Lakshmipathi Raju for the initiation. He took all the pains of shuffling students and assigning the projects. My equivocal thanks are due to the General Manager – Head Geophysical Services, Chennai, Mr. D. Dutta who considered our request and allowed us to go through the training in this organization. I am thankful to Mr. R. V. S. Murthy who has prepared a flawless schedule. It was him who has insisted us to go through the rigorous field work and gave us an insight of what is called “the maximum utilization of resources”. I express my special sense of gratitude to the party chiefs of the geophysical parties we have visited. The immense cooperation given by them is unforgettable. Not to forget, the party members who have been equally helpful. I am also grateful to Mr. C.M. Varadarajan ,DGM(GP) who prepared the schedule of the second phase of the project (Seismic Data Processing). My sincere thanks are due to Mr. Kailash Prasad and his group members for guiding me all through the different dimensions of the “processing” aspects. They are pin point right when they say, “Information is Power”. This was the punchline which motivated me towards going through the excellent library facility of ONGC. My heartfelt thanks are due to my other project colleagues also as they had been great all through the period of project work. Last but not the least, I am thankful to my beloved parents and my brother. The fact that I am a part of my family forms firm good reason to be thankful. –
Kiran Kumar Talagapu
Preface This is a project report submitted to the Department of Geophysics, Andhra University in partial fulfillment of the M. Sc. (Tech.) degree in Geophysics. The project work forms a paper which is evaluated for a maximum of 100 marks as a part of the academic curriculum. Under this programme, the students of M. Sc. (Tech.) Geophysics undergo training at premier organizations like, Oil and Natural Gas Corporation (ONGC), National Geophysical Research Institute (NGRI), National Institute of Oceanography (NIO), Indian Institute of Geo-Magnetism (IIGM), etc., engaged in geophysical activities. Under the above program, I had training at Oil and Natural Gas Corporation (ONGC) Chennai, CMDA Towers, Egmore, Chennai, from 10th December, 2004 to 31st January, 2005. During my training at ONGC Chennai, I had associated with the 2D and 3D Land Seismic Data Acquisition undertaken by three of the geophysical parties (identity not revealed) exploring Oil and Natural Gas in the operational areas of the Krishna-Godavari basin. One of the three field parties GP ‘X’ is acquiring 2D land seismic data in West Godavari Sub-basin and. The second and third parties (GP ‘Y’ and GP ‘Z’) are deployed in the East-Godavari sub basin of the KG basin, acquiring 3D land seismic data. I have been associated with all these parties on a tentative schedule of 10 days (from 13th to 22nd of December, 2004) with GP ‘X’, 10 days (from 23rd to 31st of December, 2004) with GP ‘Y’ and 6 days (from 1st to 6th January, 2005) with the GP ‘Z’. Further I had training in Data Processing at Regional Computer Center, ONGC Chennai, from 10th to 31st of January, 2005 thus completing the full schedule of 7 weeks training. All through these 7 weeks, I was exposed to many aspects of the seismic data acquisition and processing. With first hand information on certain technical terms, I was taken through the deeper aspects of seismic survey designing, parameters considerations based on the previous data, experimental surveys for finalizing the parameters from stages of the production work, uphole survey technique, regular survey and through various steps of processing like De-convolution, Stacking, Migration etc. This report consists of all these aspects in a brief. Starting from the Introduction to the Seismic Methods in Chapter 1, the Next chapter deals with the Modern Seismic Data Acquisition. In Fundamentals of Seismic Prospecting (Chapter 3), I tried to give a brief introduction about the basics of the different types of waves. Chapter 4 is about the
Reflection Field Equipment where I described about the seismic sources, seismic receivers and the instrumentation. Chapters 5 and 6 deal with the 2D Survey Designing and 3D Survey Designing respectively. Reflection Field Layouts are discussed in chapter 7 while chapter 8 focuses on the Reflection Field Method for the land survey. In this I have included the field parameters that were assumed in the field with a brief theoretical background of each parameter. The end part of this chapter deals with the starting of the production work with parameters decided based on the experimental studies. The next chapter (chapter 9) deals with some of the basic concepts of Seismic Data Processing. The subsequent chapters (chapter 10, 11, 12 and 13) deal with some of the important aspects of the seismic data Processing in detail. In these I have given a detailed description of the various stages of data processing with the results shown in the form of seismic records. At the end of the report there is an appendix touching some of the important aspects which could not be explained in the due course of the chapters.
– Kiran Kumar Talagapu
Contents Chapter 1 1.1 1.2
Introduction Historical Perspective 1.2.1 Milestones in Seismic Industry
Chapter 2 2.1 2.2 2.3
3.2
3.3
Fundamentals of Seismic Prospecting
Seismic Wave Fundamentals 3.1.1 Compressional Waves (P-waves) 3.1.2 Shear Waves (S-waves) 3.1.3 Air Wave 3.1.4 Mode-Converted Waves 3.1.5 Rayleigh Waves 3.1.6 Love Waves 3.1.7 Direct and Head Waves 3.1.8 Ground Waves Characteristics of Seismic Events 3.2.1 Reflections 3.2.2 Critical Reflection 3.2.3 Refractions 3.2.4 Diffractions 3.2.5 Multiples Seismic Noise 3.3.1 Coherent noise 3.3.2 Incoherent noise
Chapter 4 4.1
Modern Seismic Data Acquisition
Land Data Acquisition Marine Data Acquisition Transition – Zone Recording
Chapter 3 3.1
Introduction
Reflection Field Equipment
Seismic Sources 4.1.1 Land Energy sources 4.1.2 Explosive Sources 4.1.2.1 Charge Size 4.1.2.2 Charge Depth
4.2
4.3
4.1.3 Vibrators 4.1.4 Other sources Seismic Receivers 4.2.1 Geophones 4.2.1.1 Electrical Characteristics 4.2.2 Hydrophones 4.2.3 Dual Sensors Seismic Instrumentation 4.3.1 Basic components 4.3.1.1 Roll-along switch 4.3.1.2 Pre-amplifier 4.3.1.3 Multiplexer 4.3.1.4 Main Amplifier 4.3.1.5 A/D Converter 4.3.1.6 Gain Controller 4.3.1.7 Formatter 4.3.1.8 Tape Drive 4.3.2 Telemetry System 4.3.3 Storage
Chapter 5 5.1
Basic Concepts in 2D Surveys
Chapter 6 6.1 6.2 6.3 6.4
Reflection Field Layouts
Split-Dip and Common Midpoint Recording Spread Types Arrays Resolution
Chapter 8 8.1 8.2 8.3 8.4 8.5
Basics of 3D Survey Design
Why 3D Seismic Survey? Basic Concepts in 3D Surveys 6.2.1 Preliminary Parameters 3D Survey Design Sequence Land 3-D Layouts
Chapter 7 7.1 7.2 7.3 7.4
Basics of 2D Survey Design
Reflection Field Method for Land Survey
The Seismic Field Party Seismic Data Acquisition 2D Survey Parameters (Before the Experimental Survey) (GP ‘X’) 3D Survey Parameters (Before the Experimental Survey) Experimental Survey 8.5.1 Uphole Survey (Depth Optimization)
8.6 8.7
8.5.2 Noise Experiment (Determination of NTO and Array Length) 8.5.3 Fold Back Experiment (Element Spacing Determination ) 8.5.4 Shot Depth and Charge Size Optimization 2D Survey Parameters (After the Experimental Survey) (GP ‘X’) 3D Survey Parameters (After the Experimental Survey) (GP ‘Y’ and GP ‘Z’)
Chapter 9 9.1 9.2 9.3 9.4 9.5
Seismic Data Processing
Introduction Why Processing? Seismic Data Processing Objectives of Data Processing Basic Data Processing Sequence
Chapter 10 Seismic Data Processing Stage I (Pre-Processing) 10.1
Preprocessing 10.1.1 De-Multiplexing 10.1.2 Reformatting 10.1.3 Re-sampling 10.1.4 Editing 10.1.5 Geometry Merging (Labeling) 10.1.6 Static Corrections 10.1.7 Amplitude Recovery (Geometric Spreading Correction) 10.1.8 Muting 10.2 Sorting 10.3 Filtering
Chapter 11 Seismic Data Processing Stage II (De-convolution) 11.1 11.2 11.3 11.4
Introduction: Convolutional Model De-convolution De-convolution Methods 11.4.1 Deterministic De-convolution 11.4.2 Statistical De-convolution
Chapter 12 Seismic Data Processing Stage III (Velocity Analysis, NMO, DMO and Residual Static Corrections) 12.1 12.2
Velocity Analysis Normal Moveout Correctons (NMO)
12.3 12.4
Dip Moveout Correctons (DMO) Residual Statics Corrections
Chapter 13 Seismic Data Processing Stage IV (Stacking, Time Variant Filtering and Migration) 13.1 Stacking 13.2 Time Variant Filtering 13.3 Migration
Appendix Bibliography
List of Figures Figure 1(a) Figure 1(b) Figure 2(a) Figure 2(b)
Figure 2(c)
Figure 3 Figure 4 Figure 5
Figure 6 Figure 7(a) 2D Figure 7(b) Figure 8(a) Figure 8(b) Figure 8(c) Figure 9 Figure 10 Figure 11
Figure 12 Figure 13(a) Figure 13(b) Figure 14 Figure 15(a) Figure 15(b)
P – Wave Motion. S – Wave Motion. Surface Wave Motion. The particle motion in the wave front of a Rayleigh wave consists of a combination of P – Wave and SV – vibrations in the vertical plane. The particles move in retrograde sense around an ellipse that has its major axis vertical and minor axis in the direction of wave propagation. In a Love wave the particle motion is horizontal and perpendicular to direction of propagation. The amplitude of the wave decreases with depth below the free surface. Reflection of plane compress ional wave at interface. Refraction of plane compress ional wave across interface. Diffraction from the edge. The source a of diffracted radiation has been set into oscillation by waves generated on surface. Radial lines with arrows are ray paths; circular arcs are wave-fronts. Internal structure of a moving magnet geophone. Surface Geometry and Sub surface Nature and Behavior in Layout. Fresnel Zone. 3D Layout. 3D Cable Configuration used by GP “Y”. Shows the generalized stratigraphy of KG Basin. Field Geometry and the Structure of the Bore Hole dug for doing the UPHOLE Survey (at GP X and GP Y). Field Geometry and the Structure of the Bore Hole dug for doing the UPHOLE Survey (at GP Z). Shows a field record as obtained by the uphole survey team of GP ‘X’ for a source (1m of detonating cord) at a depth of 60m into a spread of geophones. The first four geophones are at an offset of 1m, 3m, 5m, 25m, and 50m. Geometric Correction for the Uphole Data. t-d plot drawn for the data obtained by the first three receivers of uphole A of GP ‘X’. t-d plot drawn for the data obtained by the last two receivers of uphole A of GP ‘X’. Noise Spread (Transposed Spread), G1, G2, … G108 represent the Geophones. Noise Section for Shot point 1 at GP ‘X’. Noise Section for Shot point 2 at GP ‘X’.
Figure 15(c) Figure 15(d) Figure 16 Figure 17 Figure 18 Figure 19(a) Figure 19(b) Figure 20(a) Figure 20(b) Figure 21(a) Figure 21(b) Figure 22(a) Figure 22(b) Figure 23(a) Figure 23(b) Figure 24 Figure 25 Figure 26(a) Figure 26(b) Figure 26(c) Figure 26(d) Figure 27(a) Figure 27(b) Figure 28(a) Figure 28(b) Figure 29 Figure 30 Figure 31 Figure 32(a) Figure 32(b) Figure 33
Noise Section for Shot point 3 at GP ‘X’. Noise Section for Shot point 4 at GP ‘X’. Noise Section prepared by GP ‘Y’. Layout for the Fold Back Experiment, G1, G2, … G216 represent the Geophone strings (12 Geophones per string). Seismic Section obtained by conducting Fold Back Experiment by GP “X”. Seismic Section obtained by conducting Fold Back Experiment, without the application of filter, by GP “Y”. Seismic Section obtained by conducting Fold Back Experiment, after the application of filter, by GP “Y”. 1st Shot gather obtained during the regular production work by GP ‘X’ 2nd Shot gather obtained during the regular production work by GP ‘X’. Seismic data volume in processing coordinates – midpoint, offset and time. Conventional processing flowchart. Raw Field record in SEG – D format. Raw Field record in SEG – Y format. Editing (Raw Field Record). Record Obtained after Editing. Seismic Data Merging. Amplitude Decay with time/depth. Uncorrected Record. Seismic Record obtained after doing the Spherical Divergence Correction. Seismic Record obtained after doing the Amplitude Correction. Seismic Record obtained after doing the Amplitude Correction and applying filter. Time – Variant Filtering (Record without the application of filter). Time – Variant Filtering (Application of High Pass Filter – 816Hz). Spiking Deconvolution. Specturm of the Raw Data and the Decon Data. Velocity Analysis. Selection of Velocity Function. NMO Stack. Surface – consistent statics model to establish the travel time model equation. Picking travel time deviations from NMO corrected gathers. Decon and Residual Stack.
Figure 34 Figure 35 Figure 36 Figure 37 Figure 38 Figure 39(a)
Figure 39(b)
Brute Stack. Final Stack. Geometrical representation of Migration. Migration Stack. Aerial Network Principle (Master Slave Relation). A Hypothetical stacking chart – Each dot represents a single trace with the time axis perpendicular to the plane of the page. Different types of Gathers.
Chapter 1 Introduction 1.1
Introduction
method has three important/principal applications The seismic a. Delineation of near-surface geology for engineering studies, and coal and mineral exploration within a depth of up to 1km: the seismic method applied to the near – surface studies is known as engineering seismology. b. Hydrocarbon exploration and development within a depth of up to 10 km: seismic method applied to the exploration and development of oil and gas fields is known as exploration seismology. c. Investigation of the earth’s crustal structure within a depth of up to 100 km: the seismic method applies to the crustal and earthquake studies is known as earthquake seismology. Definition by Robert E. Sheriff: Seismic survey is a program for mapping geologic structure by observation of seismic waves, especially by creating seismic waves with artificial sources and observing the arrival time of the waves reflected from acousticimpedance contrasts or refracted through high velocity members. 1.2
Historical Perspective •
A.D. 100 – The earliest known seismic instrument, called the seismoscope, was produced in China to indicate the direction form which the tremor came during an earthquake motion.
•
1848 – In France, Mallet began studying the Earth’s crust by using Acoustic waves. This science developed into earthquake seismology, solid earth or crustal geophysics.
•
1914 – In Germany, Mintrop devised the first seismograph, it was used for locating enemy artillery during World War I.
•
1917 – In the United States, Fessendon patented a method and apparatus for locating ore bodies.
•
1920 – The introduction of “refraction methods” for locating salt domes in the Gulf Coast region of the United States began.
•
1923 – A German seismic service company known as Seismos went international (to Mexico and Texas) using the refraction method to locate oil traps.
1.2.1 Milestones in Seismic Industry As the search for oil moved to deeper targets, the technique of using reflected seismic waves, known as the “seismic reflection method”, became more popular during World War II, because it aided delineation of other structural features apart from simple salt domes. During 1960’s the so-called digital revolution ushered in what some historians now are calling the Information Age. This had a tremendous impact on the seismic exploration industry. The ability to record digitized seismic data on magnetic tape, then process that data in a computer, not only greatly improved the productivity of seismic crews but also greatly improved the fidelity with which the processed data imaged earth structure. Modern Seismic Data Acquisition could not have evolved without the digital computer. The late 1970’s saw the development of the 3D seismic survey, in which the data imaged not just a vertical cross-section of earth but an entire volume of earth. The technology improved during the 1980’s, leading to more accurate and realistic imaging of earth. In 1990’s depth section preparation got focused from the prevailing time section preparation after processing the data. In 2000’s data is being acquired with an additional parameter of “time” as the 4th dimension of the existing 3D data acquisition system. This is called 4D data acquisition. As the seismic industry made one breakthrough after another during its history, it also created new challenges for itself. Now we record not just p-waves but also converted s-waves for a wide range of objectives. Using the multi-component seismic method, commonly known as the 4-C seismic method, we are now able to see through gas plumes caused by the reservoir below. We are able to sometimes better image the sub-salt and sub-basalt targets with the 4C seismic method. Using the converted s-waves, we are able to detect the oil-water contact, and the top or base of the reservoir unit that we sometimes could not delineate using only p-waves.
Chapter 2 Modern Seismic Data Acquisition ubsurface geologic structures containing hydrocarbons are found beneath either land
Sor sea. So there is a land data-acquisition method and a marine data-acquisition method. The two methods have a common-goal, imaging the earth. But because the environments differ, so each required unique technology and terminology. 2.1
Land Data Acquisition: In land acquisition, a shot is fired (i.e., energy is
transmitted) and reflections from the boundaries of various Lithological units within the subsurface are recorded at a number of fixed receiver stations on the surface. These geophone stations are usually in-line although the shot source may not be. When the source is in-line with the receivers – at either end of the receiver line or positioned in the middle of the receiver line – a two-dimensional (2D) profile through the earth is generated. If the source moves around the receiver line causing reflections to be recorded form points out of the plane of the in line profile, then a three-dimensional (3D) image is possible (the third dimension being distance, orthogonal to the in-line receiver-line). The majority of land survey effort is expended in moving the line equipment along and / or across farm fields or through populated communities. Hence, land operations often are conducted only during daylight thus making it a slow process. 2.2
Marine Data Acquisition: In a marine operation, a ship tows one or more
energy sources fastened parallel with one or more towed seismic receiver lines. In this case, the receiver lines take the form of cable called Steamer containing a number of hydrophones. The vessel moves along and fires a shot, with reflections recorded by the streamers. If a single streamer and a single source are used, a single seismic profile may be recorded in like manner to the land operation. If a number of parallel sources and/or streamers are towed at the same time, the result is a number of parallel lines recorded at the same time. If many
closely spaced parallel lines are recorded, a 3D data volume is recorded. More than one vessel may be employed to acquire data on 24-hour basis, since there is no need to curtail operations in nights. 2.3
Transition – Zone Recording: Because ships are limited by the water depth in
which they safely can conduct operations, and because land operations must terminate when the source approaches the water edge, or shore lines, transition-zone recording techniques have been developed to provide a continuous seismic coverage required over the land and then into the sea. Geophones that can be placed on the sea bed or used with both marine and land shots fired into them. Techniques have been developed to use both Geophones and hydrophones in the surface area where the shore line / water edge is likely to migrate towards land and sea depending on the tide of sea a day. The combination of such hydrophone / geophones is called a “Dual Sensor”. The advantage of why this is to see that either of the receiver of Dual Sensor pickups the surveyed from the slots recorded using a land or marine source and data gaps all along the coast within the area of prospect. In this report, though the principle of all sorts of seismic operations like land, marine and TZ are discussed, the ultimate emphasis is given on the land acquisition only as the training has been in this regard.
Chapter 3 Fundamentals of Seismic Prospecting 3.1
Seismic Wave Fundamentals
he transmission of energy into the earth can be explained by assuming that the Earth T has the elastic properties of a solid. The Earth’s crust is considered as completely elastic (except in the immediate vicinity of the shot), and hence the name given to this type of acoustic wave transmission is elastic wave propagation. Several kinds of wave phenomenon can occur in an elastic solid. They are classified according to how the particles that make up the solid move as the wave travels through the material. 3.1.1 Compress ional Waves (P-waves): On firing an energy source, a compress ional force causes an initial volume decrease of the medium upon which the force acts. The elastic character of rock then caused an immediate rebound or expansion, followed by a dilation force as shown in figure 1(a). This response of the medium constitutes a primary “compress ional wave” or P-wave. Particle motion in a P-wave is in the direction of wave propagation. The P-wave velocity is a function of the rigidity and density of the medium. In dense rock, it can vary from 2500 to 7000 m/sec, while in spongy sand, form 300 to 500 m/sec. 3.1.2 Shear Waves (S-waves): Shear strain occurs when a sideways force is exerted on a medium;(figure 1(b)) a shear wave may be generated that travels perpendicularly to the direction of the applied force. Particle motion of a shear wave is at right angles to the direction of propagation. A shear wave’s velocity is a function of the resistance to shear stress of the material through which the wave is traveling and if often approximately half of the material’s compress ional wave velocity. In liquids such as water, there is no shear wave possible because shear stress and strain cannot occur in liquids.
3.1.3 Air Wave: On land the energy source (shot) generates an airwave known as the air blast, which itself can set up an air-coupled wave, a secondary wave-front in the surface layer. This wave generally travels by about 350 m/sec velocity slower, than the compress ional wave, the speed of the airwave depends mainly on temperature and humidity, as shown below: V = 1051 + 1.1F ft/sec where F = Fahrenheit temperature V = 331.5 + 0.607C m/sec
where C = Celsius temperature.
3.1.4 Mode-Converted Waves: Each time a wave impinges on a boundary, a portion of the energy is reflected and the remaining transmitted. Depending upon the elastic properties of the boundary, the incident P-wave or S-wave may convert to one or the other or to a proportion of each. Such converted waves sometimes, degrade the signal-to-noise ratio. This degradation causes problems during data processing. 3.1.5 Raleigh Waves: It is a type of seismic surface wave propagated along the free surface of a semi-infinite medium. Figure 2(a) shows surface wave motion.This medium is known as weathering layer or low-velocity layer (LVL). Raleigh waves are of low frequency nature, traveling horizontally with retrograde elliptical motion and away from the energy source (shot). The particle motion of this wave reduces (amplitude) with increase in depth, eventually reversing in direction. This point is in the vicinity of the base of the weathering layer. Because the motion of the ground appears to roll, this wave is commonly known as ground roll (figure 2(b)). 3.1.6 Love Waves: The Love wave (figure 2(c)) is a surface wave borne within the LVL, which has horizontal motion perpendicular to the direction of propagation with, theoretically no vertical motion. Also known as the horizontal SH-wave, Q-wave, Lq-wave or G-wave in crustal studies, such waves often propagate by multiple reflection within the LVL, dependent upon the LVL material. If such waves undergo mode conversion, a number of noise trains appear across the seismic record, obscuring reflected energy content even further. 3.1.7 Direct and Head Waves: The expanding energy wave front that moves along the air-surface interface outward form shot commonly is observed as the direct wave and has
the velocity of the surface layer through which it travels. Head waves are the portions of the initial wavefront that are transmitted down to the base of the weathering layer or the water bottom and are refracted along the weathering base. They return to the surface as refracted energy or refractions. Sometimes the refracted velocity is higher than the velocity of propagation in the surface layer. In that case, refracted head waves appear in the mid-to-faroffset traces before arrival of the direct wave. 3.1.8 Ground Waves: When a layer of the Earth has an extreme density or velocity contrast at both its upper and lower boundaries, a wave traveling along the layer may undergo internal reflection (i.e., stay within the layer, reflecting from upper interface to lower, back up again, and so on). Such waves are called guided waves and exhibit mainly vertical particle motion. They appear as short shingled waves, repeating on the shot record. 3.2
Characteristics of Seismic Events
Seismic wave created by an explosive source emanate outward from the shot point in a 3D sense. Huygen’s principle is commonly used to explain the response of the wave. Every point on an expanding wave front can be considered as the source point of a secondary wave front. The envelope of the secondary wave fronts produces the primary wave fronts after a small time increment. The trajectory of a point moving outward is known in optics as a ray, and hence in seismics as a raypath. 3.2.1 Reflections: The phenomenon in which the energy or wave from a seismic source has been returned from an interface having acoustic impedance contrast (reflector) or series of contrasts within the earth is called reflection. This phenomenon is pictorially represented in figure 3. The amplitude and polarity of reflections depend on the acoustic properties of the material on both sides of discontinuity. Acoustic impedance is the product of density and velocity. The relationship among incident amplitude Ai, reflected amplitude Ar, and reflection coefficient Rc, is:
, where,
Where velocity is constant, a density contrast will cause a reflection and vice versa. In other words, any abrupt change in acoustic impedance causes a reflection to occur. Energy not reflected is transmitted. With a large Rc, less transmission occurs and, hence signal-to-noise ratio reduces below such an interface. 3.2.2 Critical Reflection: When an impinging wave arrives at such an angle of incidence that energy travels horizontally along the interface at the velocity of the second medium, then critical reflection occurs. The incident angle ic, at which critical reflection occurs can be found using Snell’s Law.
3.2.3 Refractions: The change in direction of a seismic ray upon passing into a medium with a different velocity, is called refraction. Snell’s law describes how waves refract. It states that the sine of the incident angle of a ray, (sin i), divided by the initial medium velocity V1 equals the sine of the refracted angle of a ray (sin r), divided by the lower medium velocity V2, that is:
when a wave encounters an abrupt change in elastic properties, part of the energy is reflected, and part is transmitted or refracted (figure 4) with a change in the direction of propagation occurring at the interface.
3.2.4 Diffractions: Diffractions (figure 5) occur at sharp discontinuities, such as at the edge of a bed, fault, or geologic pillow. When the wave front arrives at the edge, a portion of the energy travels through into the higher velocity region, but much of it is reflected. The reflected wave front arrives at the receivers get aligned along the trajectory of a parabola on the seismic record. In conventional in-line recording, diffractions may arrive from out of the plane of the seismic line / profile. Such diffractions are considered as noise and reduce the signal-to-noise ratio. However, in 3D recording, in which specialized data processing techniques are used (i.e.,, the 3D seismic migration), the diffractions are considered as useful scattered energy because the data-processing routines transfer the diffracted energy back to the point from which is generated, thereby enhancing the subsurface image. Hence in 3D surveys, out-of-the plane diffractions events are considered part of the signal. 3.2.5 Multiples: Seismic energy that has been reflected more than once is called multiple while virtually all seismic energy involves some multiples. The important distinction between long-path and short-path multiples is that a long-path multiple arrives as a distinct event whereas a short-path multiple arrives soon after the primary and changes the wave shape. 3.3
Seismic Noise The reliability of seismic mapping is strongly dependent on the quality of the records
/ data. We use the term “signal” to denote any event on the seismic record from which we wish to obtain information. Everything else is “noise”, including coherent events that interfere with the observation and measurement of signals. The signal-to-noise ratio (S/N), is the ratio of the signal energy in a specified portion of the record to the total noise energy in the same portion. Poor records result whenever the signal-to-noise ratio is small. Seismic noise may be either a) Coherent or b) Incoherent Another important distinction is between a) noise that is repeatable and b) noise that is non repeatable. The properties – coherence, travel direction and repeatability – form the basis of most methods of improving record quality.
3.3.1 Coherent noise includes surface waves, reflections or reflected refractions from near-surface structures such as fault planes or buried stream channels, refractions carried by high-velocity stringers, noise caused by vehicular traffic or farm tractors, multiples and so forth. All the preceding except multiples travel essentially horizontally and all except vehicular noise are repeatable on successive shots. Coherent noise is sometimes subdivided into: a) energy that travels essentially horizontally and b) energy that reaches the spread more or less vertically 3.3.2 Incoherent noise is often referred to as random noise (spatially random), which implies not only non-predictability but also certain statistical properties. Incoherent noise is due to scattering from near-surface irregularities and in homogeneities such as boulders, small-scale faulting, and so froth. Non repeatable random noise may be due to wind shaking a geophone or causing the roots of trees to move, which generates seismic waves, stones ejected by the shot and falling back on the earth near a geophone, ocean waves beating on a seashore, distant earthquakes, a person walking near a geophone, and so on.
Chapter 4 Reflection Field Equipment 4.1
S
Seismic Sources
eismic sources can be broadly divided into two categories: land energy sources and
marine energy sources. 4.1.1 Land Energy sources: The choice of energy source is critical in land data acquisition because resolution and signal-to-noise ratio quality are limited by the source characteristics. A geophysicist should select a source based on the following five criteria: •
Penetration to the required depth: Knowing what the exploration objectives are, the geophysicist should select a source that has adequate energy to illuminate the target horizons. Past experience can help here.
•
Bandwidth for the require resolution: If high resolution reflections are required to delineate subtle geological features such as a stratigraphic traps, the source must transmit a broad range of frequencies, both high and low. For very shallow targets, a detonator may possess adequate energy and frequency bandwidth. For deeper reflections, the longer travel path to a deep reflector requires the selection of a source that has enough energy at the higher frequencies to maintain a broad reflection bandwidth.
•
Signal-to-noise- characteristics: Different areas have different noise problems. They may dictate the source selection.
•
Environment: When working in populated areas, there are special safety requirements to which geophysicists must adhere.
•
Availability and Cost: The time of arrival of a crew can be extremely important.
Land Energy Sources are of two types: Explosive sources and Non Explosive sources.
4.1.2 Explosive Sources: Explosive sources produce robust P-waves. The selection of explosives as the sources of choice depends primarily on near-surface conditions and the accessibility of other energy sources. If drilling is fast and efficient, single shot hole filled with explosives might be the most economical source option. The explosive source consists of a detonator and an explosive charge. In the seismic industry, the explosive charge is commonly referred to as ‘powder’ and the detonators are referred to as ‘caps’ or ‘primers’. 4.1.2.1 Charge Size: The choice of charge size depends largely on the depth to the horizon of interest. The best charge size is that which achieved the maximum signal-to-noise ratio (S/N) at the target depth. Deeper targets usually require larger charge sizes. Generally, larger charge sizes cause more ground roll and air blast contamination of the record. Alternatively, smaller charge sizes mean higher frequency content, but less energy going into the ground. De convolution enhances the frequency content such that the bandwidth will be higher and have an improved S/N ratio compared to a record with a smaller charge size. 4.1.2.2 Charge Depth: The charge depth depends on the depth of the weathering layer and the level of noise interference one encounters when testing. Generally, the shallower the source, the stronger the air-blast and the ground-roll. On the other hand, it is usually not economical to go much beyond 50m depth. If the drilling is really tough and expensive, one may have to limit the shot hole depth to as little as 2m or a surface shot may be used instead. 4.1.3 Vibrators: Vertical vibrators produce and asymmetric radiation pattern of P-waves and S-waves. Horizontal vibratos produce weak P-waves and robust S-waves. If multiple dynamite patterns do not pump enough energy into the ground, vibrators may be preferred on technical grounds, regardless of relative cost. Vibrators are designed in two basic groups: Buggy-mounted and truck-mounted units. 4.1.4 Other sources: Although dynamite and Vibroseis are used in majority of surveys, other sources can be and are used in the field 3D surveys, such as: •
Airguns and mud guns (used in transition zone surveys)
•
Shotgun (Betsy)
•
Mini-Seis (Thumper)
•
Land air gun
•
Dinoseis
•
Elastic wave generator (EWG)
•
Mini-vibes
4.2
Seismic Receivers
4.2.1 Geophones: Conventional geophones are based on Faraday’s law of electromagnetic induction. This law states that relative motion of a conductor through a magnetic field induces an electromagnetic force (EMF) which causes a current to flow through the conductor, if the conductor is an element of an electrical circuit. The two types of geophones widely used in geophysical surveys are 1. moving coil geophone and 2. moving magnet geophone(figure 6) The essential ingredients to make a geophone are a permanent magnet, a conductor and a spring which positions either the conductor in the magnetic field space (in moving coil geophone) or the permanent magnet in the electric field space (as in moving magnet geophone). The conductor in reality is a length of copper wire wrapped into a cylindrical coil shape. It is often referred to as the coil or element. The conductor’s or the magnet’s motion through the magnetic/electrical field, according to Faraday’s law, causes an EMF to be induced that is proportional to the velocity of the earth’s motion. Hence, such a geophone is called a velocity phone because its output is proportional to the velocity of the earth’s motion. The large amount of subsurface information carried by seismic signal would be fully available for interpretation only if the geophones follow ground movement faithfully with minimum distortion. 4.2.1.1 Electrical Characteristics: •
Sensitivity: Geophones are available with a wide range of sensitivities. For example, at one end of the sensitivity scale, a geophone can produce 0.1V output for a 2.5cm/sec velocity, while another geophone can produce as much as 0.4mV output for a tiny movement of 2.5 X 10 m/sec.
•
Tolerances: Geophones have typical tolerances. That are as follows: o Natural frequency within + 0.5Hz. of the manufacturer stated value o Natural frequency distortion with a maximum 20 tilt, + 0.1Hz. o Sensitivity within + 5% of the manufacturer stated value. A large variety of modern geophones are available today to meet the specific
requirement of the user. Close tolerance digital grade geophones have distortions as low as 0.03%, tolerance of 2-2.5% on frequency, sensitivity and damping, and very high geophone-
to-geophone uniformity. To modern geophones has done away with the shunt resistance, resulting in very low distortion and high spurious response up to 250Hz. These geophones maintain their natural frequency specifications with high tilt angles. The particular receiver type depends on the characteristics of the data to be recorded and the environment where the data acquired. In normal land operations, geophones have a resonant frequency of 10 or 14Hz., but in some parts of the world it is still normal practice to use 6 to 8Hz phones. However, geophones with resonant frequencies up to 40Hz are being manufactured. Receivers are usually wired in groups of 1, 4, 6, 9, 12 or 24. While the trend is towards higher number of phones (9, 12, 24 on even 72 in the Middle East), however numbers (e.g., 6) are still used in certain areas, e.g., South America. In hilly, terrain, where the height difference between the ends of any receiver group exceeds 2m, geophones may be clustered in a small area. In steep terrain (over 5m. elevation difference) one can spread the phones out parallel to topographic contours to minimize inter-array statics smear. Threecomponent 3D recording requires three times the number channels of recording capacity since each component is recorded separately. This increased number of channels may make it difficult to create a patch that creates sufficient fold. Since shear-wave reflections contain a lower frequency bandwidth, phones with lower resonant/natural frequencies are used. 4.2.2 Hydrophones: The hydrophone is an electro acoustic transducer that converts a pressure pulse into an electrical signal by means of the piezoelectric effect. If mechanical stress is applied on tow opposite faces of a piezoelectric crystal, then electrical charges appear on some other pair of faces. If such a crystal is placed in an environment experiencing changes in pressure, it will produce a voltage proportional to that variations in pressure. 4.2.3 Dual Sensors: For ocean bottom cable (OBC) applications, combining the output of geophones and a hydrophone is now widely accepted technique for reducing the ghosting effect caused by the water/air interface. To overcome the disadvantage of using two separate sensors, both geophone and hydrophone are available in a single unit known as dual sensors or the 4-component (4C) receivers consist of a hydrophone, two horizontal geophones and a vertical geophone installed in a single water proof enclosure for recording P, SV and SH waves.
4.3 Seismic Instrumentation Once a seismic signal is transmitted and received, it must be recorded. The different types signals are as follows: •
Source Signal: The pressure field created by the seismic source.
•
Reflectivity Signal: The earth’s reflection sequence convolved with the source wavelet.
•
Seismic Signal: Everything received as a result of the source firing. The seismic signal includes the reflectivity signal as well as ground roll, refractions, diffractions, sidesweep, channel waves etc.
•
Received Signal: The electrical output of the receiver group. This is the seismic signal plus all environmental noise.
•
Recorded Signal: The data, that is the instrument filtered signal plus any addition instrument noise, which goes onto the tape.
The information contained in a signal can be characterized by three quantities: Signal-to-noise ratio, Bandwidth and Duration In seismic exploration, the recorded signal bandwidth is usually 0-250Hz. or lower. Often, data are processed in a narrower band, say 5-80Hz., even though they may be recorded in a broader band. The duration of recorded signals depends on the nature of the source and target depth. A reflection is a physical event caused by a change in the acoustic impedance of the earth. It is recorded signal, that event is represented by a wavelet that has two components – the earth filter and the acquisition wavelet. The wavelet can be described in the time domain or alternately, in the frequency domain. The Fourier transform can be used to move form one representation to the other. If a wavelet has a short extent in a time and appears like a spike, it is likely to be composed of a broad band of frequencies, each separate frequency having its own phase value. The amplitude and phase of a wavelet contain all the spectral information of a wavelet. These spectra are called the frequency-domain representation of the wavelet, whereas the wavelet in time is considered to be in the time domain. When seismic recording first began in a 1920s the recording systems consisted of heavy, metal cased geophones connected by wire cables to a recording truck. The signal was
recorded on a rotating photographic drum. Drums were replaced by analog magnetic tape recorders during the late 1950s but these often failed to operate well. In the early 1960s they were replaced by digital tape recorders, each of which had an analog-to-digital converter at the input stage to the tape drive. The individual analog amplifiers also were unreliable, and by late 1960s, they were being replaced in recording devices by a single multiplexed analog amplifier. In late 1970s, distributed systems were introduced that performed amplification, filtering, digitization and multiplexing at or near the receiver stations. By the mid 1980s distributed systems were in wide use throughout the industry. 4.3.1 Basic components: The basic components of the land recording systems are: 4.3.1.1 Roll-along switch: It allows the observer to record a selected subset of the geophones connected to the recording truck. It minimizes the need to move the recording truck. 4.3.1.2 Pre-amplifier: This is a fixed gain amplifier that raises the incoming seismic signal above the background instrument noise level. The preamplifier has low noise, high input impedance and low distortion. Its input impedance is equal to or greater than the cable impedance to the farthest station so that no signal amplitude is lost because of mismatching of impedances. The amplifier must be completely linear throughout its operating range. 4.3.1.3 Multiplexer: This is an electronic switch that time shares data form multiple channels. It changes multiple parallel inputs to a serial output relay for amplification, digitization and recording. The multiplexer cycles through all of the inputs during each digital sampling interval. 4.3.1.4 Main Amplifier: This amplifier receives all analog signals input to it and passes then on to the A/D converter with an amount of gain determined by the gain controller. 4.3.1.5 A/D Converter: Analog signals are converted to digital signals with this device. It allows the analog stream of data to be recorded in digital form. The received incoming signal must be filtered to prevent aliasing prior to conversion to a digital form.
4.3.1.6 Gain Controller: The received signal includes, reflections, refractions, ground roll and environmental noise, all of which may have amplitudes varying in a range from microvolts to volts. A fixed form of amplification with only a relatively small number of data bits cannot handle that range without some dipping at the most significant bit end of the converter. Instead a variable or automatic gain control (AGC) level is determined for application by the main amplifier in the feedback loop with the A/D converter to reduce or amplify incoming signal to keep signal levels within the desired converter range. The controller sets the amount of gain while the amplifier applies it to the incoming signal. The AGC level set at each sample is recorded on tape as part of the gain word. 4.3.1.7 Formatter: The formatter arranges the data stream (in the form of voltage and gain levels) into a binary code for writing onto magnetic tape. In addition, instrument operational commands are distributed by the formatter to all the other components, making the formatter the “brain” of the recording operation. 4.3.1.8 Tape Drive: Data finally are recorded on tape in digital form, ready to be passed on to the processing center for further processing. Magnetic tape may be replaced by floppy disks, depending upon the system in use. In land using recording a non-distributed system, an analog seismic signal travels from the geophones along electrical conductors (the cable) to a roll-along switch in the recording truck (or “doghouse” or “dog box”), after which it is converted to a digital signal and recorded on tape or disk. In contrast, in a distributed system, the seismic signal passes from the geophone string directly into an amplifier and/or A/D converter, after which it travels in digital form along a cable to the recording truck. Because digital transmission of multiplexed data uses many fewer cables than analog transmission, layout of the large receiver spreads often used for 3D acquisition became considerably simpler. Today, majority of the acquisition systems provide 24-bit recording technology. A 24-bit technology system offers high fidelity because it records data over a large dynamic range. Peculiarities for each system need to be examined for the task at hand. In land operations, these recording units are usually truck or buggy mounted and can, therefore, travel easily to areas of data acquisition. Lower channel count systems with higher sampling rates, such as the DMT/SUMMIT and the 24-bit OYO DAS, can be used for small, nearsurface 3D surveys. In the case of very low channel count systems (e.g. less than 120), it is
normal practice for several recorders to be used together in a master-slave pattern to reach sufficient channel capacity even for small 3D surveys. If a 3D survey crosses a variety of terrains (e.g., mountain, plain, transition zone), it is desirable to use one type of recorder to cover all the survey areas. Thus shots of different types in the mountains or in the swamp can be recorded by the same instrument. If more than one recorder is used, amplitude and phase matching will be required to compensate for the recorder differences. “Seam less” receiver coverage from a variety of sources enables application of surface-consistent processes as de convolution, statics, and amplitude correction. Different Types of Seismic Recorders Manufacturer
System
T/D/R
Boxes
Stations
Line Units
per Box Sercel
SN388
Distributed System
Station Unit
Sercel
408UL
Telemetry
Field Digitizer
System
1-6
(SU)
Central
Crossing
Central Control
Station Unit
Unit
1
(SU)
(SU)
Line
Central Module (CMU)
System/Distributed
Unit
Acquisition
System/Remote
(FPU)
Unit Cross
Seismic Recording
(LAUX)
4.3.2 Telemetry System True telemetry system has no physical connection between the station recording unit and the control system in the recording truck. These systems should be used where access is limited due to rugged terrain, permit problems, or any other reason. Sercel Eagle system is an example of such systems. The SAR (Seismic Acquisition Remote unit) records the signal and sends it via radio frequencies to the CRS (Central Recording Station). Some telemetry systems can receive data in real time. Other telemetry systems have a disadvantage over distributed system in that the radio transmission of the data from the boxes to the recording unit takes longer than real time. For some systems, data transmission time may be on the order of minutes per source point, which may slow down the shooting crew. Tree cover may also cause a problem for the signal transmission, and FM interference may be significant in populated areas. Mixed systems may be used to cross-rivers or roads at select locations.
4.3.3 Storage: The data obtained in the seismic field survey is stored on magnetic tapes or cartridges. While the conventional storage devices are the tape drives the latest equipment uses the cartridges with 10 GB memory capacity for storing the data. The data is stored in SEG D format. Previously it used to get recorded in SEG B format or SEG C formats.
Chapter 5 2D Survey Design Basics 5.1
Basic Concepts in 2D Surveys
he guiding principle should be to design a seismic survey that will image the T selected target in the most economical way for costs and time. Resolution parameters, such as the frequency required to image the target, are starting design factors. Shallow horizon of interest and deeper horizons may be interpretational needs; thus, the definition of the representative horizons is the beginning of the design. 5.1.1 Near Surface layer: The velocity of the surface layer is used as a factor in computing offsets and determining the effect of ground roll. Usually the weathered layer is very low velocity because of exposure and erosion, but it may be quite complex and have several layers of variant velocity. The velocity and maximum dip of each layer are initial parameters. This information can be obtained in approximate form from existing well logs or seismic data in the area. If the area is frontier area, then noise tests, experience, or geologic theory can be the source of this information. 5.1.2 Shallow Layer: While the target layer is most important for imaging, a shallow layer may be necessary for processing or interpretation. Good data in the shallow part is needed to use the velocity analysis with confidence. The velocity Vs and the approximate arrival time are the needed parameters. These parameters allow computation of depth of the layer Zs by the familiar time-distance formula
where: t
=
two-way travel time to the shallow horizon
Vs
=
average velocity to the layer, and
Zs
=
depth to the shallow layer
This formula provides the information needed for the near offset, i.e.,
5.1.3 Target Layer: The layer is the horizon of primary interest for the survey. When parameters conflicts arise during the design, the requirements for the target layer should prevail. For imaging the target horizon, geologic knowledge of the expected thickness and reflectivity is needed to estimate the frequency range 5.1.4 Group Interval: Group Interval is the basic sampling on the earth’s surface by the survey. It is the distance on the ground between receiver stations. Group interval represents which largest spatial sampling shall prevent aliasing during migration:
where, Vmin
= minimum velocity,
θ
= maximum dip of the target horizon in degrees, and
Fmax
= maximum frequency expected
5.1.5 Fresnel Zone: Fresnel zone (figure 7 (b)) is the smallest part of the reflector making an unambiguous image of the individual event and is circular at zero offset but elliptical with offset. Fresnel zone is given by:
where, tz
=
two-way record time of the target horizon
Maximum group interval
=
5.1.6 Far Offset: Far offset is a function of the depth modified by the velocity field. The far offset required should be computed first for the target horizon and then for the deep horizon. The velocity of the surface layer is involved because of the initial angular influence on the down going seismic waveform at the depth of the horizon. Once the maximum offset
is computed in combination with the near / offset, the group interval, the ideal parameters can be evaluated within the framework of the available equipment.
where, Z is the depth of horizon, Vs is the velocity of the surface layer, and V the average velocity to the target. If the horizon is dipping, then the distance, Hmax should be extended by:
where, Z
=
depth of horizon and
θ
=
dip
This extension is quite important in 3D exploration (Migration aperture). Neglect of this factor can result in underestimating field costs. The well-founded rule of thumb says that the spread length should be equal to or a little greater than the depth of the reflection being imaged. The far-trace distance should preserve full fold on the target horizon. Data processing often requires considerable muting of the shallow data on the greater offsets because of NMO stretch, noise trains, and other factors. The target horizon should be protected by the survey for the mute. The custom is to automatically mute below the “20 to 30 percent stretch factor” the formula most used for this step is:
where H = offset distance, V= velocity at time Tz and Tz = arrival time of the event at H = 0. When Tm exceeds 0.3, then data processing will probably form an automatic mute. Too large on offset range for a given number of receiver stations may result in inadequate fold for the shallow layer or even the target layer. On the other hand, if the offset
range is not long enough, accurate velocity analysis and the suppression of multiples during the processing can be endangered. 5.1.7 Record Length: Part of the survey design is to determine the required sampling rate in time and the record length is a function of depth and velocity of the deepest horizon.
Where Td = two-way arrival time of the deepest horizon of interest at the maximum offset Tr = required record length in time, and L = length in time of the longest processing filter. Normally 200ms is adequate for the filter length. The extra time in recording is balanced against the possible benefits from data from very deep horizons. Signal length becomes more important when the source is vibratory in nature. Some allowance should also be made for migration. 5.1.8 Sample Rate: The sampling rate in time is more or less standard, ranging from 2 to 4 ms depending on the resolution needed. The rule is
A sample rate of 2ms is used for most seismic surveys. 5.1.9 Group Interval and Field Equipment: The group interval possible with a particular recording equipment given by
where, Hmax = far offset, Hmin = near offset, and NC = the number of channels available for recording.
5.1.10 Fold Coverage: Each source position yields a certain amount of subsurface coverage. For flat layers, the sampled point is half the distance from source to receiver. The subsurface sampling is half the interval of the surface coverage. Foldage is defined as the number of times a particular sub-surface sampling point (CMP) is covered by different sources receiver locations. The maximum fold of coverage is given by
Where, S is the number of units of group interval in the source spacing and NC the number of channels available. 5.1.11 Source Interval: The source interval in the distance between source positions. The source interval is function of the desired fold coverage and the number of channels available.
Where, NC is the number of channels and F is the fold. 5.1.12 Source Power: There is a decision to be made in some cases on the source power. For dynamite, the charge size in kilograms if the unit. For vibratory sources, the available power (in pounds per square inch) is specified by equipment model. For instance, a large vibrator can generate 50,000 psi. Marine sources such as air guns and water guns are defined in terms of their volume and peak-to-peak strength. The power needed is function of target depth and the environmental noise. As the earth has a natural attenuation, target depth is the primary consideration. Noise is also involved since more power has the potential to generate more noise. The amount of energy generated in a shot hole is proportional to the quality of dynamite. It is well known that an explosive source in a cylindrical enclosure generates pressure waves and shear waves of both polarizations. 5.1.13 Line Location and Orientation: The geometry of the survey is not independent of the target. The location, direction, and length of the lines are important
considerations in the survey design. Dip lines for instance, are favored over strike lines. Some of basic concepts generally accepted for lines locations/orientations are: •
The lines should, when possible, be perpendicular to fault planes. Since definition of the fault plane is best on the seismogram when the lines are perpendicular to the plane.
•
Line ties are important to interpretation. When there is existing seismic data nearby, new lines are planned in such a manner that they can be ties with the existing data. One very helpful ties is to a well. The closer the line can approach the well, the more useful the tie of the seismic data to the well log.
•
When there is no conflict with other needs, lines should be planned to minimize elevation and terrain problems. Sometimes a small shift in the line location can avoid a troublesome obstacle.
Figure 7(a) shows the Surface Geometry and Sub surface Nature and Behavior of 2D Layout.
Chapter 6 3D Survey Design Basics 6.1
Why 3D Seismic Survey?
ub-surface geological features of interest in hydrocarbon exploration are 3-dimensional in
S
nature. A 2D seismic section is a cross-section of 3D seismic response. Despite the fact that 2D seismic section contains signal from all directions, including out-of-plane of the profile, 2D migration normally assumes that all the signal comes from the plane of the profile itself. Although out of plane reflections (side-sweeps) are often recognizable by the experienced seismic interpreter, the out of plane signal sometimes causes 2D migrated section to mistie. These misties are due to inadequate imaging of the subsurface resulting from the use of 2D rather than 3D migration. On the other hand, 3D migration of 3D data provides adequate and detailed 3D image of the subsurface, leading to a more reliable interpretation. When integrated with well logs, core and other petrophysical and production data, 3D data permits reservoir characterization. The integrity of any 3 D data set leans heavily upon the suitability of acquisition geometry. 6.2
Basic Concepts in 3D Surveys The 2D surveys are as linear as the terrain allows. Source and receiver are normally
in-line with each other. Arrays may be multi-dimensional, but most often are also in the line of survey. For 3D surveys, this is seldom the case. The source interval of a 2D survey must be extended to include a definition of the source line. For 3D surveys, source line must be defined, since for most common designs, the source line is orthogonal to the receiver lines. The receiver line becomes the receiver lines. As many receiver lines are laid out as the equipment for acquisition allows. Also, the receiver, layout may not be lines but circles, checkerboards and other patterns developed for 3D surveys. Thus the simple parameters that defined the traditional 2D line now must be extended to include more geometry. The analysis of 2D designs centers on the subsurface coverage in the form of common-depth points (CDPs). For 3D surveys, the CDP becomes two-dimensional and is
termed a “bin”. These bins may be square or rectangular and define the spatial resolution of the data sampling. Indeed, deciding the bin size will be the first step in designing a 3D template. Subsurface sampling will be, as with the CDP, half the surface size. The accent of 2D lines is on the fold of coverage and the offset range. For 3D survey the fold may less, but the azimuth range is added to the offset range as a parameter. If structure is complex, then good azimuths range becomes more important. Where structure is complex the velocity analysis must include an azimuthal property. The range of azimuths in the bin is also a consideration. Another new factor is the use of computers to do the design. Moreover, interpretation is usually conducted on workstations. The multiple source and receiver lines, the difficulty of computing, fold coverage, azimuthal distribution, and offset ranges in the bins make the use of a computer program to aid in 3D design almost a necessity. The Fresnel zone assumes some new characteristics in three dimensions. Essentially, the theoretical point source expands as it propagates in depth, “illuminating” a circular area at vertical incidence. In a seismic context, this is the reflecting surface constructively contributing to the reflection. A good approximation to the radius of the zone is which shows that the zone increases in radius with depth but decreases with higher frequency wave fronts. Migration serves to reduce the zone to some minimal size when accurately done and the data fits the assumption. It should be noted that when the reflecting point is offset, the circle becomes elliptical. This angular effect actually reduces the size of the zone along the minor axis of the elliptical response. Dip and structure also are factors in the actual response..
where, V
=
average velocity to the event,
T
=
arrival time and
t
=
peak-to-zero crossing of the wavelet.
An important aspect of 3D data and Fresnel zones is the extra dimension of focusing possible with migration.
6.2.1 Preliminary Parameters: There are some parameters that need to be estimated as input when designing the 3D survey. The physics and concepts are somewhat independent of whether the survey is to have two or three dimensions. 6.2.1.1 Offset: The imaging of shallow target and deep horizons still requires certain offset of source and receiver. An approximation to the required offset for a given horizon is very simple and used often when surveys are designed in the field: Offset = depth of the horizon. New factors include the fact that the offset may now be measured at an angle and the depth is now that of a plane rather than a line. 6.2.1.2 Fold: The fold required for noise suppression is a function of the S/N conditions. This translates in 3D to the number of traces in a bin. Because of the extra focusing by migration and the flexibility of binning, fold can be less than required in 2D surveys. Field tests or existing 2D seismic data can yield an estimate of the needed fold for the 3D survey. 6.2.1.3 Frequency: The temporal frequency required is not much different from that of 2D surveys. The rules for the resolution of layer of given thickness are best determined by modeling. The general rule is that the resolution of a thin bed requires it to be sampled twice within a quarter wavelength of the highest frequency. As a field approximation, the maximum frequency expected:
T
=
Two way time of the horizon
6.2.1.4 Objectives of the Survey: The most important information is defining the objectives of the survey. Although this seems a rather obvious comment, many times the objectives of the survey except for the aerial extent and approximate spatial sampling are not part of the input to design. Requirements of good fold on a shallow reference layer or a deep reflection for survey are clearly stated.
6.2.1.5 Migration Aperture: When the beds are dipping, the extent of the survey must be increased by: D
=
Z tan θ
where, Z = depth, θ = dip 6.2.1.6 Seismic Data Input: The most useful direct input is existing seismic data. The seismic sections give information abut many of the design parameters such as noise, source power, weathering problems, and general structure. Field records and final stack should be checked for environmental and source generated noise conditions. The array design should be studied for possible use in the 3D survey. There are areas where neither source nor environmental noise is a problem, which greatly simplifies the survey design and makes the whole project less expensive. Type of source, the power used in either surveys, quality of reflections at depth, frequency content of shallow data are some of the key factors in deciding the source power to be used. If extensive static corrections made during processing indicate problems in the near surface, this should be noted on the survey design. The design of the survey can reduce processing problems in many cases. 6.3
3-D Survey Design Sequence There are many ways to begin and complete a survey design. The specific sequence
of steps that follow are general guide lines. Some design templates will dictate a different sequence of other parameters. A summary of the proposed sequence for developing a design sequence is: •
Determine the subsurface bin size. Twice the chosen bin size is the source and receiver station spacings.
•
Compute the number of source stations per kilometer required to achieve fold with available equipment. The number of stations per square kilometer allows computation of the source line spacing.
•
Compute the receiver line spacing.
•
Find the number of receiver lines allowed by the field equipment, constrained by the required offset ranges. The result is the template.
•
Decide the in-line and cross-line roll alongs.
•
Allow for obstacles and run analyses of the offset distribution ranges of offsets and azimuthal properties of the bins.
•
Estimate time and costs of the script and iterate until attributes, costs, and time are satisfied.
6.3.1 Bin size: For 3-D data the bin is the basic building block for the rest of the survey. Bin size depends on target size, spatial resolution needed, and economics. The traces when their subsurface reflection point falls with in the bin, are treated as a CDP, and corrected and summed to represent that bin position by a point. A bin can be any size but rectangles and squares are the popular. The basic sampling theorem applies to the bin.
where, b is the bin size, Fm = Maximum frequency expected, θ = maximum dip in degrees and Vmin = minimum velocity. 6.3.2 Source line spacing: The bin size will, however, allow more design calculations if the fold and number of channels on the equipment are known .
where, NS = shots per square kilometer, F = desired fold, R = number of channels B = subsurface bin size. Determining NS allows for the computation of the next important parameter source line spacing.
6.3.3 Receiver line spacing: The new information required is the minimum offset and the offset ranges needed. The controlling parameter will be the largest minimum offset within a bin. The minimum offset has been previously established with preliminary calculations and modeling. The approximation is that the maximum offset needs to be at least as long as the depth of the most reflection to be imaged. Thus, a2 = (c2-b2)1/2 where ‘a’ is the receiver line spacing, c is the largest minimum offset and b is the source line spacing. A smaller near offset would require ‘a’ smaller receiver line spacing and be more expensive. As with the source line spacing, the receiver line spacing from calculation may be reduced. 6.3.4 Number and length of the receiver lines in the template: The problem is to be determine the number of receiver lines possible with the template. The number of lines is constrained by the required maximum offset which sets the length of the lines. The maximum offset found in the preliminary 2-D calculations or 3-D modeling is a function of deepest horizon to be imaged. The field estimate is that the maximum offset should be a little greater than the depth of the deep horizon, but exact formula include dip. The target parameters are the number and length of the receiver lines. The source line shift is an adjustable variable. The second constraint is the number of channels available with the equipment. 6.3.5 Determining the template movement: Usually the field people prefer to roll along the direction of receiver lines. The increment is at the source line spacing. At the end of the coverage in in-line direction the next swath would be done in same manner incremented in the source direction and continued until the coverage was completed. 6.3.6 Estimation of nominal fold: Stacking fold is the number of field traces that contribute one stack trace. Fold controls the signal to noise ratio. Fold should be decided by looking at previous 2-D and 3-D surveys in the area.
6.3.6.1 In-line fold: For an orthogonal straight-line survey, in-line fold is defined similarly to the fold on 2-D data. The formula is as follows: In line fold = ___( no. of receivers x station interval )__ . 2 x Source interval along the receiver line
(or) In line fold = ( number of receivers x receiver interval ) 2 x Shot line interval 6.3.6.2 Cross-line fold: Similar to the calculation of in-line fold, the cross-line fold is: Cross line fold =
source line length _. 2 x receiver line interval
6.3.6.3 Total Fold: The total 3D nominal fold is the produce of in-line fold and cross-line fold: Total nominal fold = ( in-line fold ) x ( cross-line fold). 6.4
Land 3D Layouts: Numerous layout strategies have been developed for land 3D
surveys. One has to establish which features are important in the area of the survey in order to select the best design option. 6.4.1 Full fold 3-D: A full fold 3D survey is one where source points and receiver stations are distributed on an even two-dimensional grid with station spacings equal to the line spacings. The grids are offset by one bin size. A full fold 3D survey has outstanding offset and azimuth distributions as long as one can afford to record with a large number of channels. All other 3D designs are basically subsets of such full-fold surveys, and the designer has to decide which aspects of a 3D design are absolutely necessary and which can be compromised. 6.4.2 Swath: The swath acquisition method was used in the earliest 3D designs. In this geometry Source and receiver lines are parallel and usually coincident. While source points are taken on one line, receivers are recording not only along the source line but also along neighboring parallel receiver lines, creating swath lines halfway between pairs of source and
receiver lines. The offset distribution in all occupied bin lines is excellent. However inadequate sampling in the cross-line direction makes this design a “poor man’s 3-D”, because many bins are empty. The azimuth mix is very narrow and depends on the number of live receiver lines in the recording patch and the line spacing. Most companies prefer to have the source points at the half-integer positions. Parallel swaths are sometimes considered on land when severe surface restrictions exist, or when costs have to be minimized. The operational advantages are attractive, but are achieved at the cost of a poor azimuth mix and poor cross-line sampling. 6.4.3 Orthogonal: Generally, source and receiver lines are laid out orthogonal to each other. Because the receivers cover a large area, this method is sometimes referred to as the patch method. This geometry is particularly easy for the survey crew and recording crew, and keeping track of station numbering is straightforward. In an orthogonal design, the active receiver lines form a rectangular patch surrounding each source point location creating a series of cross spreads that overlap each other. This technique allows more surface area to be acquired prior to receiver stations moves. This method is easy to lay out in the field and can accommodate the extra equipment and roll along operation. Usually all the source points between adjacent receiver lines are recorded. Then the receiver patch is rolled over one and the process is repeated. The azimuth distribution for the orthogonal method is uniform as long as wide recording patch is used. Figure 8(a) shows a 3D layout and the subsurface nature while figure 8(b) shows the 3D cable layout used by GP “Y”.
Chapter 7 Reflection Field Layouts 7.1
plit-Dip and Common Midpoint Recording: Virtually all routine S seismic work consists of continuous coverage (profiling), that is, the cables and source
points are arranged so that there are no gaps in the data other than those due to the fact that the geophone groups are spaced at intervals rather than continuously spaced. Single coverage implies that each reflecting point is sampled only once, in contrast to common-midpoint, or redundant, coverage where each reflecting point is sampled more than once. Areal or cross coverage indicates that the dip components perpendicular to the seismic line have been measured as well as the dip components along the line. Each of these methods can employ various relationships between sources and geophone groups. 7.2
Spread Types: By spread we mean the relative locations of the source point and
the centers of the geophone groups used to record the energy form the source. In split-dip shooting the source point is at the center of a line of regularly spaced geophone group often results in a noisy trace (because of ground roll or truck noise with a surface source, or gases escaping from the shot hole and ejection of tamping material); hence the source may be moved 15 to 50 m. perpendicular to the seismic line. Often the geophone groups nearest the source are not used, which creates a sourcepoint (shotpoint) gap. Often the source is at the end of the spread of active geophone groups to produce an end-on spread, and in areas of exceptionally heavy ground roll the source point is offset by an appreciable distance along the line from the nearest active geophone group to produce an inline offset spread. Alternatively, the sourcepoint may be offset in the direction normal to the cable, either at one end of the active part to produce a broadside-L or opposite the center to give a broadside-T spread. End-on and in-line offset spreads often employ sources off each end to give continuous coverage and two records for each spread. The in-line and broadside offsets permit recording reflection energy before the ground-roll energy arrives at the spread. Cross spreads, which consist of two lines of geophone groups roughly at right angles to each other, are used to record 3D dip information. 7.3
Arrays: The term array refers either to the pattern of geophones that feeds a single
channel or to a distribution of shotholes or surface energy sources that are fired
simultaneously; it also includes the different locations of sources for which the results are combined by vertical stacking. A wave approaching the surface in the vertical direction will affect each geophone or an array simultaneously so that the outputs will affect the various geophones at different times so that there will be a certain degree of destructive interference. Similarly, waves traveling vertically downward from a source array will add constructively whereas waves traveling horizontally away from the source array will arrive at a geophone with different phases and will be partially cancelled. Thus, arrays provide a means of discriminating between waves arriving from different directions. The two popular types of array designs are the linear array and the areal array. Arrays are linear when the elements are spread along the seismic line or areal when the group is distributed over an area. 7.4
Resolution
7.4.1 Vertical Resolution: Resolution refer to the minimum separation between two features such that we can tell that there are two separate features. If seismic wavelets were a spike, the resolution would not have been a problem. Rayleigh criterion of resolution states that two events can be resolved if their separation is half cycle, since events are recorded in terms of two-way time, therefore real separation of the features must be quarter cycle. Thus resolvable limit is wavelength/4. 7.4.2 Horizontal Resolution: Horizontal resolution depends on the radius of the first “Fresnel Zone”. A “Fresnel Zone” is that portion of the reflector, which sends back energy to the receiver within a half cycle delay, so that it will produce constructive interference. The size of the zone depends on frequency, the higher the frequency the smaller the zone. Effective radius of the first Fresnel zone is half of the actual radius. If we consider point source, the effective radius of first Fresnel zone is
where, V
=
average velocity of the reflector,
t
=
two way time and
f
=
frequency.
Chapter 8 Reflection Field Method for Land Survey he Seismic Field Party: The land seismic data acquisition team is T divided into the following groups:
8.1
Survey Crew •
Fixing the control points for the line based on the GPS points given before hand,
•
Ranging/Filling team for putting the pickets of the specified intervals along the line based on the control points on the line,
•
Leveling team for giving the elevations at the shot point location and the receiver point location.
Shot Hole Drilling Crew •
For drilling the holes up to the specified depth for putting the charge for blasting.
Uphole Survey Crew •
For measuring the velocity and thickness of the weathered layer (Low Velocity Layer) and velocity of the sub-weathered layer (in crude terms for depth optimization)
Recording Unit •
Shooting Crew: For filling the drilled holes with the charge of specified quantity and detonating it.
•
Jug hustlers (the Cable laying crew): For laying the cable and planting the geophones at the specified pickets and for observing them all through the recording time for further corrections.
•
Recording Crew: For recording the seismic signals received by the geophones after blasting the charge.
8.2
Seismic Data Acquisition
8.2.1 The Program: Usually the seismic crew receives the program in the form of lines on a map that indicate where data are to be acquired. Before beginning a survey the following
questions should be asked: “Is it possible that the proposed lines will provide the required information?” Data migration may require that lines be located elsewhere than directly on top of features in order to measure critical aspects of a structure. Crustal areas may be so extensively faulted that lines across them are nondefinitive. The structures being sought may be beyond seismic resolving power. Near surface variations may be so large that the data are difficult to interpret whereas moving the seismic line a short distance may improve data quality. Obstructions along a proposed line may increase difficulties unnecessarily, whereas moving the line slightly may achieve the same objectives at reduced cost. Where the dip is considerable, merely running a seismic line to a wellhead may not extend sufficiently beyond faults and other features to establish the existence of such placements. Lines may cross features such as faults so obliquely that their evidences are not readily interpretable. Lack of cross control may result in features located below the seismic line being confused by features to the side of the line. Objective of the Survey: The objective of the survey done by the GP ‘X’, GP ‘Y’ and GP ‘Z’ is to map strati-structural features within the specified formation at an area in Krishna-Godavari Basin of Andhra Pradesh which lie within the lower to upper cretaceous section. The seismic equivalent of these geological objectives are as under: For GP ‘X’ Area
Depth (m)
Two Way Travel Time in (ms)
Dip
Area 1
1500 to 4300
1250 to 3000
10 to 15
Area 2
1700 to 4200
1400 to 2900
10 to 15
For GP ‘Y’ Area
Depth
Two Way Travel Time in
Average Velocity
(m)
(ms)
(m/sec)
Area 1
1800 to 3600
1500 to 2500
Area 2
1800 to 3400
1500 to 2500
Dip
For GP ‘Z’ Area
Area 1
Depth
Two Way Travel Time in
Average Velocity
(m)
(ms)
(m/sec)
1800 to 3400
1500 to 2500
2400 to 2720
Dip 100 to 120
Reasons for the Survey: Out of the wells drilled in the area some have proved the presence of gaseous hydrocarbons from the formation and some have been dry. There by the area assumed important for exploration from these targets Geology of the Area: The Krishna-Godavari basin has been subdivided into three subbasins Krishna Sub-basin West Godavari Sub-basin and East Godavari Sub-baisn. The area under investigation for the GP ‘X’ and GP ‘Y’ lies in West Godavari Sub-basin while that of GP ‘Z’ lies in the East Godavari Sub-basin. Figure8(c) shows the generalized stratigraphy of KG Basin. 8.2.2 Permitting: Once the seismic program has been decided o n, it is usually necessary to secure permission to enter the land to be traversed. Permission to enter may involve a payment, often a fixed sum per source location, as compensation in advance for “damages that may be incurred”. Even where the surface owners do not have the right to prevent entry, it is advantageous to explain the nature of the impending operations. Of course, a seismic crew is responsible for damages resulting from their actions whether or not permission is required to carry out the survey. 8.2.3 Layout of Line The survey crew lays out the lines to be shot, usually by using an Electronic Total Station (refer Appendix), Compass Theodolite, and transit-and-chain survey that determines the positions and elevations of both the source points and the centers of geophone groups. Usually the survey crew is given a few GPS stations beforehand in the area of operation. The survey crew divides themselves into three main groups. The first group fixes the control points (using the Electronic Total Station) which control the direction of the source line or the receiver line. Usually these control points are given at an interval of about 1km. along the line, on either side of the line. The second group does the ranging and the filling (using the compass Theodolite) part on the line along the line at specified interval and placing the pickets (made of flat bamboo sticks with the marking of the picket number on
them) at those stations. The third group does the leveling i.e., gives the elevation values at each picket. Thus the survey crew lays the grid of source lines and receiver lines with specified picket intervals, receiver line intervals and source line intervals on ground. What they do is to project the details on the given onto ground very precisely. 8.2.4 Shothole Drilling: The next team of people to star their activities unit in the scene is the drilling crew (when explosives are used as the energy source). Depending on the number and depth of holes required and the case of drilling, a seismic crew deploys the drilling crews. Whenever conditions permit, the drills are truck-mounted. Water trucks are often required to supply the drills with water for drilling. In areas of rough terrain, the drills may be mounted on tractors or portable drilling equipment may be used. Usually the drilling crew places the explosive in the holes before leaving the site.
Seismic survey is divided into two main classes which are interlinked. These are: Experimental Surveys and Regular/Production Survey 8a.3 2D Survey Parameters (Before the Experimental Survey) (GP ‘X’) Instrument
408 UL
Source Type
Dynamite
Group Interval
20m
Field Season
2004-05
Type of Shooting
Asymmetrical spread (216 + 40)
Channel/Foldage
256/64
Spread Length
4300 + NTO
Shot Interval
40m
No. of Geophones per group
12
Geophone Pattern
Linear
Shot Hole Pattern
Single
Record Length
6S
Sample Rate
2ms.
8.4
Gain Mode
24bit
K – Gain dB
0, 12
Low Cut Filter (Hz/dB)
Out
High Cut Filter (Hz/dB)
200/370
Notch (50 Hz)
NA
3D Survey Parameters (Before the Experimental Survey) (GP ‘Y’
and GP ‘Z’)
Parameters
GP ‘Y’
GP ‘Z’
Instrument
408UL
SN388
Source Type
Dynamite
Group Interval
40 m.
40 m.
Field Season
2004-05
2004-05
Type of Shooting
Asymmetric Split Spread
Asymmetric Split Spread
Channel/Foldage
1008(168 per line)/6 X 6
1008( 168 per line )/6X6
Spread Length (m)
6680 m (each line)
6680 m (each line)
Shot Interval
40 m
40 m
(m)
No. of Geophones per group
12
Geophone Pattern
Areal
Areal
Shot Hole Pattern
Orthogonal – Single
Orthogonal – Single
Record Length (sec.)
6
5
Sample Rate
2
2
(m sec.)
Gain Mode
0
K – Gain (dB)
12
Low Cut Filter (Hz/dB)
Out
Out
High Cut Filter (Hz)
200
125
Notch (50 Hz)
Out
Out
Receiver Line Interval (m)
280
280
20 x 20
20 x 20
Source Line Interval (m) Bin size (m x m)
8.5
Experimental Survey
8.5.1 Uphole Survey (Depth Optimization) Sheriff defines an uphole survey as follows •
Successive sources at varying depths in a borehole in order to determine the velocities of the near-surface formations, the weathering thickness, and (sometimes) the variations of record quality with source depth.
•
Sometimes a string of geophones is placed in a hole of the order of 200 feet deep to measure the vertical travel times form a nearby shallow source.
8.5.1.1 Data Acquisition Method: Once the locations of the uphole survey have been decided based on line intersections, at regular spacing along the lines, or in an anomalous area any necessary paperwork must be completed prior to drilling. The depth of the hole to be drilled depends on the area on the problem to be solved. Unless there are unusual problems in the area, it is likely that a depth of 50-100 m. will be adequate. Although in extreme cases, uphole depths have exceeded 500m. The type of drill used must be appropriate, or at least acceptable, for the proposed depths and the type of drilling in the area. During drilling, it is important that information be obtained about the penetrated geologic formations, specifically their lithologies. Normally, this is done by cuttings from various depths in the borehole, along with comments about hard or easy drilling or that circulation was lost at a specific depth. The objective of an uphole survey is to estimate the thickness and times and hence velocities, of the near surface layers. To obtain accurate time estimates, the source and receiver must be as broadband as possible and the data have a good signal-to-noise ratio; that is, the source should ideally be a short time-duration pulse. No delays should occur in the recording system, which implies that the recording filters must be left open whenever possible, apart form anti-alias filters used for digital recording. Checks must be made on the whole timing system, from the time break through to the display, to ensure that any delays are understood and accounted for in the interpretation. If detonators (caps) are used, for
example, their delay must either be very small or to be estimated for each shot so that the detonation time is known. Picks should be normally be estimated to an accuracy of 0.5ms, meaning that the recording speed must be fast enough to allow the picks to be interpreted with this precision. In a high-resolution survey with a small depth increment between observations, the accuracy should be better than this. Many systems now use a magnetic storage devise which allows several displays to be made at different gains. The recording equipment should have the capability of stacking the data to enhance the signal-to-noise ratio for low-power surface sources and, possibly in the future, for nondestructive sources in the borehole.
The two basic approaches for conducting uphole surveys are: (i)
The source in the borehole and the receivers on the surfaces and
(ii)
The source at the surface and the receivers in the borehole.
8.5.1.2 Source in Borehole and Receivers at the Surface: The basic field set up is as shown in the figure 9. A succession of charges detonated at different depth are recorded by one or more receivers at the surface located a few meters away from the hole. This is generally preferred method and dynamite is used by the production crew. This mode of operation can also be used in transition zone or shallow-water survey areas where it is practical and safe to drill and load charges into the borehole. 8.5.1.3 Source: If dynamite, the size of the charge depends on the near-surface geology and the depth of the shot; hence, tests must be conducted in the new area. As a guide, caps (detonators) are normally sufficient to at least 20m. depth and primers to at least 50m. Charges can be loaded and detonated independently, or a wiring harness can be used to load many shots at one time. Regardless of which method is used, the deepest shot must be detonated first. Woods and Patterson showed that the times are influenced by the charge size, with larger sizes leading to anomalous times. Thus, to obtain seismic velocities form an uphole survey, the charge size should be kept as small as possible yet still allow the signal recorded at the surface to have sufficient signal-to-noise ratio.
The wiring harness is composed of many pairs of wires each of which is used for one of the charges; consecutive charges have a preset distance (Shot interval) between them. The charges are attached to the harness and a weight attached beneath the deepest charge. The whole assembly is then carefully loaded into the borehole to the correct range of depths, normally with the weight at the base of the borehole. 8.5.1.4 Receiver: A number of receivers are positioned close to the top of the borehole; a normal minimum is four located in a cross arrangement to record data from four azimuths. The type of geophone used should have good low and high frequency responses to obtain the desired broadband recording. Thus, a low-frequency geophone is generally required, with a natural frequency of less than 10Hz. Each receiver should be located several meters away from the top of the borehole. If a receiver is too close to the borehole, the recording will be contaminated by arrivals through the drilling fluid and the invaded zone, where the drilling fluid has entered the rock formation close to the borehole. In addition, the drilling process disturbs the ground near the borehole, which can delay the arrival of an upcoming wave-field by as much as several milliseconds. 8.5.1.5 Sample Interval: The near-surface detail required was related to both the objectives of the survey and the complexity of the near surface. These vary from complex near-surface areas where the targets of the main survey have limited area and closure, to those in which the near surface changes slowly along the line and targets have a appreciable time relief or the exact attitude of the target formations is not critical. With respect to uphole survey sampling requirements, three aspects need to be considered:
•
the sampling over the area and along any one line,
•
the depth sampling of any one survey, and
•
the digital sample rate for surveys that are recorded digitally.
The other technical factor that impacts the spacing of uphole surveys is the method that is used to interpolate the near-surface layers between the uphole survey locations to define a near-surface model for the computation of datum static corrections.
The spacing of uphole surveys depends on several factors and on the problems to be solved. Overall, the system approach should be used, in which an analysis is done of which components of the near-surface problems are to be solved by the various techniques available, such as upholes, refraction, residual static corrections and interpretation. However, it is generally desirable to locate uphole surveys at line intersections so that the information can be used on the two or more intersecting lines and to sample different near-surface lithologies. In critical areas, an uphole survey may be needed as often as every spread-length in extreme cases, and even smaller spacing. The depth sampling must be sufficient to allow time-depth picks to define each of the geologic formations adequately. Each formation requires a minimum of three and preferably more picks for a reasonable velocity estimate. If taken to the limit, this implies a very fine sample interval. However, the near-surface formations change both vertically and horizontally away from the borehole, often on an irregular basis, so that having precise measurements at one location will be of little practical value in interpolating a value midway between two uphole locations. A depth sample interval of a few meters (2-3m) is generally adequate for most areas and allows velocity estimates over an intervals of 5-10 m. Where the data is recorded digitally, the sample interval should be small enough to retain as much high frequency signal as possible so that a good uphole break is obtained. When dynamite is used as a source, this should be 0.5 ms. or less; for detailed shallow high frequency surveys, a much smaller value may be appropriate. For non explosive sources, 1ms. should be more than adequate, and in some areas 2ms. or 4ms. sampling may be appropriate. 8.5.1.6 Parameters in the Uphole Survey The parameters used by all the three parties in conducting the uphole surveys are as under: 8.5.1.6.1
Used by GP ‘X’ and GP ‘Y’
Source Used
: Caps (detonators)
Receiver
: Geophone
Spread Length
: 50m.
No. of Geophones
: 5 (one at 5 different offset distances)
Offset Distance
: 1st Geophone is placed at a distance of 1m from the shotpoint 2nd Geophone is placed at a distance of 3m from the shotpoint
3rd Geophone is placed at a distance of 5m from the shotpoint 4th Geophone is placed at a distance of 25m from the shotpoint 5th Geophone is placed at a distance of 50m from the shotpoint Depth of Shot Hole
: 68m.
Shot interval(depth)
: 2m.
Table (I) shows the description of the uphole used by GP ‘X’. 8.5.1.6.2
Uphole parameters Used by GP ‘Z’
Source Used
: Caps (detonators)
Receiver
: Geophone
Spread Length
: 50m
No. of Geophones
:9
Offset Distance
: four Geophones are placed at a distance of 1m with different azimuths from the shotpoint 5th Geophone is placed at a distance of 3m. from the shotpoint 6th Geophone is placed at a distance of 5m. from the shotpoint 7th Geophone is placed at a distance of 10m. from the shotpoint 8th Geophone is placed at a distance of 25m. from the shotpoint 9th Geophone is placed at a distance of 50m. from the shotpoint
Depth of Shot Hole
: 68m.
Shot Interval (depth)
: 2m.
Figure 10 shows the field layout used for doing the uphole survey by GP Z. 8.5.1.7 Interpretation The main components of uphole survey interpretation are: •
Picking the first arrivals from each depth level,
•
Applying any necessary corrections to these times and
•
Plotting the data and estimating the velocities and thicknesses of the various layers identified.
The interpretation of individual uphole surveys along a line should be followed by lateral adjustments to ensure that the layer thickness and velocity profiles along the line are realistic.
8.5.1.7.1
Picking and Timing Data: The picked times should be estimated to the
nearest 0.5 ms or better. These times are used not only to measure times to specific depths but also to estimate interval velocities over fairly small depth ranges. Prerequisites for picking data at this accuracy are a sufficiently broad band signal bandwidth, adequate signalto-noise ratio, a fast paper speed display, and sufficient gain to show a good break on the display. In addition, a time break test must be conducted with the signal displayed on the display to obtain absolute time information. Any observed delay is measured and then removed from each of the times picked form the display. In most acquisition systems (Smartseis, refer Appendix in this case), data are recorded on a digital tape or disk. The gain of the display is important. With respect of the picking of the first arrival, Ricker stated, “There is no sudden takeoff of the trace when the disturbance arrives. The motion begins gradually as if a first kick arrival time is attempted, the time picked will depend upon the over-all magnification of the seismograph” Figure 11 shows a field record as obtained by the uphole survey team of GP ‘X’ for a source (1m of detonating cord) at a depth of 60m into a spread of geophones. The first four geophones are at an offset of 1m, 3m, 5m, 25m, and 50m For a conventional uphole survey analysis, picks should be made for all near-offset displays. When several traces are recorded at the same offset but with different azimuths, variations in the time are often observed. This can be due to near-surface variations close to the receivers, ground coupling of the receivers, variations in the invaded zone between the source and receiver, or disturbance around the borehole form the drilling process. To investigate these effects, traces out to an offset of about 15 – 25 m. should also be picked. Uphole times are picked from a peak, trough or zero crossing; these cannot give absolute times, but the interval times can be used for interval velocity estimates. For this approach to be sufficiently accurate, the waveform must not change form one depth level to the next. However, the pulse width typically broadens with the distance traveled. 8.5.1.7.2
Arrival-Time Corrections: The two major corrections applied to
uphole survey data are conversion to absolute time and vertical time. The correction to absolute time uses information obtained from the time break test, designed to measure minor delays in the total system due to filters and other components of the recording instruments.
The measured times are from a known depth in the borehole to a specific offset from the top of the borehole. In some cases, the surface elevation at the top of the borehole is different to the receiver (or source) elevation located a few meters away. Corrections for this elevation change the offset from the borehole need to be applied to the picked times to simulate a set of arrival times that would be measured at the top of the borehole. A simple geometric correction is applied routinely to correct from the inclined raypath to a vertical one; the parameters are shown in the figure 12 which assumes that the borehole is vertical. When the drill is on a slope, all the depth and times normally refer to a reference system perpendicular to the ground; in other non-vertical situations, additional corrections are required. The relationship between the vertical uphole time and the measured (inclined) uphole time for the general case is given by
where, t is the measured uphole time corrected for any time delays, T is the vertical uphole time, x is the offset of the receiver from the top of the borehole, z1 is the depth of the shot, z2 is the depth of the receiver, and ∆ E is the difference in elevation between the receiver and the top of the shot hole When ∆ E = 0 and z2 = 0, the above equation simplifies to
Table I shows a worked example of the application of the second equation; the receivers are at different offsets from the top of the borehole. The underlying assumption in the geometric correction of the above equations is that no refraction of rays occurs at any velocity interfaces. This is a reasonable approximation when the offset distance of the receiver (or source) form the top of the borehole is only a few meters; however, it also implies that the dips of the interfaces are small. 8.5.1.7.3
Time – Depth Display: The absolute arrival times, corrected to vertical
travel, are plotted at the appropriate depths on a time-depth display or plot. The most commonly used convention is for depths to be plotted vertically and times horizontally. Any information about near-surface geology from the driller or geologist, as well as other relevant information, should be included on the display. This can be used to help define the various interfaces present and to provide an independent check of the depths noted. The time-depth display is then interpreted and interval velocities are estimated for the layers identified. This is often subjective procedure, and several different interpretations can often be made from one data set. The geologic information is often useful in deciding where an interface is located; however, not all changes in geology give rise to a change in velocity and the velocity can change within a geologic unit. A major point to consider is the error associated with each plotted point; one must also remember that the objective is normally to define the simplest model consistent with the data.
Figures 13 (a) and 13 (b) show the t-d plots drawn for the data obtained at uphole A of GP ‘X’. 8.5.1.7.4
Spatial Consistency: Each uphole survey is initially interpreted on its
own, but consideration must also be given to other uphole surveys in the area. It is then often possible to adjust the velocities for a specific uphole survey to be more consistent with other values along the line or in the area for a specific layer or formation. Any adjustment must be within the error of the survey. 8.5.1.8 Conclusion: From figures 13 (a) and 13 (b) we can thus conclude that the optimum depth to place the charge for uphole A is 36m .
8.5.2 Noise Experiment (Determination of Near Trace Offset and Array Length) At the start of the survey, a noise spread shot performed to measure the level of the noise. If the noise is severe enough to hinder the survey objectives, the geophysicist must decide how to handle the noise problem. One approach is to ignore the noise problems in the field and to assume that various data processing steps subsequently remove the problem of high noise levels. If the dynamic range between the amplitude of the noise and that of the underlying seismic signal exceeds the dynamic range of the recording system, the signal will not be recorded and the data processing methods have nothing to recover. In such situations it is best to select survey parameters to attenuate noise prior to recording in filed. The most common methods of reducing noise in the filed are frequency filtering in the recording instruments and wavelength filtering through use of directional source and receiver arrays. The wavelength data needed to optimize array parameters may be measured by performing noise-spread tests. For each kind of spread, the offset between geophones and the source should extend from zero to maximum offset that will be used in production recording. The receiver interval used during a noise test must be short enough to avoid spatial aliasing of the short-wavelength noise. There are four methods of noise analysis: The normal spread, The transposed spread, The double-ended spread and The expanded spread. Of all the above spread types the transposed spread is more suitable for the land surveys. 8.5.2.1 Transposed Spread: The spread remains fixed in one location and the shot moves away from the receiver spread one spread length after each shot is fired. This method is more popular than the normal spread because it is easier to move the source than the receivers. A problem with this method is that a shot static difference misaligns noise and reflection traces when the individual spread is still the most popular type of noise analysis. It is often called a walk away noise test because the shot or vibrator literally walks away from the receiver spread during the recording horizons.
8.5.2.2 Instrument Parameters faced in the noise test: 8.5.2.2.1 (At GP ‘X’, GP ‘Y’) Instrument
: CM 408 UL
No. of Channels
: 108
Profile Length
: 2160m
Group Interval
: 20m
Number of Shots
:6
Record Length
: 6sec
Sampling Interval
: 2ms
Pre Amplification Gain
: 0 dB
Filters
: Out
8.5.2.2.2 (At GP ‘Z’) Instrument
: SN 388
No. of Channels
: 108
Profile Length
: 2160m
Group Interval
: 20m
Number of Shots
:6
Record Length
: 5sec
Sampling Interval
: 2ms
Pre Amplification Gain
: 12 dB
Filters
: Out
8.5.2.3 Noise Analysis: From field record time, distance (t-X) graph is plotted for each noise wave traces observed in the record. Each wave will align along different straight lines, slope of each straight line gives the apparent velocity of the corresponding wave. This can also be done with the help of computer by simply plotting all the noise records in order of their offset distances. Waves of different apparent velocities will align along different straight lines having different slopes. Time period of the wave can be found by measuring the time difference between two consecutive peaks or troughs where the wave shape / stand out is
clear and with least interference. Inverse of the same indicates frequencies and apparent velocities of signal at different offsets and times can also be measured from the record. Amplitudes of signals and noises can also be measured at different offsets and times. Figure 14 shows the geometry of the noise test carried out by the field party I have visited. The spread length for this test is about 535m with a geophone interval of 5m. The geophones are placed as bunch (a bunch contains 12 geophones). The shots are placed at an interval of 400m and 8 shots were taken. Figures 15 (a), (b), (c) and (d) shows the noise sections as obtained using the recording instrument Sercel CM408UL
by GP ‘X’ after
recording the data for four shot points and figure 16 shows the noise section obtained at GP ‘Y’. On seeing the section in figure 15 (a) and (b) we can observe the noise trends marked as A, B, C, ….. Following are the various noise characteristics deduced from the record / plot Trends / Events
Velocity (m/sec)
Frequency (Hz)
Wavelength (m)
A
198
9
22
B
210
10
21
C
220
11
20
D
252
12
21
Based on the maximum wavelength obtained from noise analysis the array length is fixed. Thus the array length is fixed as 22m. Analysis of amplitude spectra for different trace offsets and F-K plots in different transform windows helps in calculating noise wavelength and amplitudes and also in deciding the near offset. 8.5.3 Fold Back Experiment (Element Spacing Determination ) Fold back experiment is conducted to select the suitable element spacing in an array, which can effectively suppress the source-generated noise. Different types of geophone arrays are tested depending upon the noise characteristics, observed in the noise experiment. Four spreads, each with a different array are shot with constant charge size and depth. The field monitors, simulated plots and frequency-amplitude spectra are evaluated with the emphasis on the standout of events in the zone of interest. Actually the entire spread length decided for the regular survey is folded into four arms as shown in the figure 17, each with equal length. Thus the name is “fold back”
experiment. As per the fold back experiment conducted by GP ‘X’ the length of each arm is about 1060 m. with 54 channels. The first arm consists the channels from 1 to 54, the second arm contains channels from 55 to 108, the third from 109 to 162 and the final limb from 163 to 216. Along the first arm the geophones are placed as bunches at an interval of 20 m. The second arm contains the 12 geophones of each string spaced at 1.5m. again with the same group interval of 20m. The geophones in the third line are spaced at 1.75m. The last arm has the 12 geophones of a string spaced at an interval of 2m with a group interval of 20m. The distance between the 1st arm and the second arm is 5m while the distance between the 2nd and 3rd arm is 10m and the distance between the 3rd and 4th limb is again 5m. The shot line is placed exactly at the center of the four arms in the direction of the lines. Four shots with a shot interval of 400 m. are taken with the first shot placed as shown in the figure 17. Figure 18 shows the section obtained by conducting the fold back experiment at GP ‘X’ and figure 19(a) and 19(b) shows the section obtained by conducting the fold back experiment at GP ‘Y’, while 19 (a) shows the section without the application of any kind of filter (b) shows the section after the application of a band pass filter (10 to 80 Hz). As seen from 18, the limb with 1.75m element spacing appears to be better section with less interference and better signal preservation compared to other arms. Thus the element spacing is fixed as 1.75m. From figure 19 (a) and (b) we can fix the element interval as 2m. 8.5.4 Shot Depth and Charge Size Optimization After optimizing the geophone array, shot depth and charge size optimization is conducted using the normal spread with •
Constant charge size and varying shot hole depth and
•
Constant shot hole depth and varying charge size.
The field setup is laid as per the requirement of regular production work. At first shot location three shot holes are drilled with different depths (in the order of the optimum depth suggested by the uphole survey i.e., if the depth suggested by the uphole survey is 36m. then the three hole are dug with the depth variations as 34, 36 and 38m) and separated by a distance of 5m. perpendicular to the receiver line. Equal amount of charge is placed in all the three holes and recorded one after another. The records are observed and the depth with which the best response is obtained is fixed as the depth for the regular survey. Similarly at the second location, shot holes of same depth ( as optimized previoiusly) are drilled and
different charge sizes are placed in them and the shots are recorded. Again the best response as is seen from the recorded sections size is fixed as charge size for conducting the regular survey. The analysis of the processed outputs is done in a similar manner as for the other experiments. The acquisition parameters optimized on the basis of above experiments are adopted for production work. A set of 2D acquisition parameters optimized on the basis of experimental work is given below 8.6
2D Survey Parameters for production work by GP ‘X’ Instrument
CM 408 UL
Group Interval
20m
Field Season
2004-05
Type of Shooting
Asymmetrical spread (216 + 40)
Channel/Foldage
256/64
Spread Length
4500m
Shot Interval
40m
No. of Geophones per group
12
Geophone Pattern
Linear
Shot Hole Pattern
Single
Record Length
6 secs.
Sample Rate
2ms
Gain Mode
24bit
K – Gain dB
0, 12
Low Cut Filter (Hz/dB)
Out
High Cut Filter (Hz/dB)
200/370
Notch (50 Hz)
NA
___________________________________________________ Shot Hole Depths
36 + 2m.
Charge Size
2.5Kg
Near Trace Offset
200m
Element Spacing
1.35 m.
Array Length
18 m.
8.7
3D Survey Parameters for production work by GP ‘Y’ and GP ‘Z’
Parameters
GP ‘Y’
GP ‘Z’
Instrument
CM 408UL
SN388
Source Type
Dynamite
Dynamite
Group Interval
40m
40m
Field Season
2004-05
2004-05
Type of Shooting
Asymmetric Split Spread
Asymmetric Split Spread
Channel/Foldage
1008(168 per line)/6 X 6
1008( 168 per line )/6X6
Spread Length
6680m(each line)
6680m (each line)
Shot Interval
40m
40m
No. of Geophones per group
12
Geophone Pattern
Areal
Areal
Shot Hole Pattern
Orthogonal – Single
Orthogonal – Single
Record Length
6sec
5sec
Sample Rate
2ms
2ms
Gain Mode
0dB
K – Gain dB
12dB
Low Cut Filter (Hz/dB)
Out
Out
High Cut Filter (Hz)
200Hz
125Hz
Notch (50 Hz)
Out
Out
Receiver Line Interval
280m
280m
Source Line Interval
560m
560m
Bin size
20 x 20
20 x 20
Migration Aperture
4300m
4500m
------------------------------------
-------------------------------
--------------------------------
Charge Size
2.5Kg
2.5Kg
Shot Hole Depth
36 + 2m
36 + 2m
Element Spacing
1.5m
1.5m
Array Length
20m
20m
With all the above said parameters the regular survey is carried out. Figures 20 (a) and 20 (b) shows the first two shot gathers obtained during the regular production work by GP ‘X’.
Chapter 9 Seismic Data Processing 9.1
I
ntroduction: The seismic method has been greatly improved in the both in the areas of data acquisition and processing. Digital recording along with
the CMP multifold coverage was introduced during the early 60’s. Data acquired from the field are prepared for processing by the field party itself and then it is send to the processing centre. Processing is required because the data collected from the field is not a true representation of the subsurface and hence nothing of importance can be inferred from it. With the advent of high end computing systems modern day processing has become a lot easier than it really used to be. Turnaround times have therefore come down with lot of processing taking place in-field or onboard. 9.2
Why Processing? Field record which we obtain contains: •
reflections,
•
coherent noise, and
•
random ambient noise.
9.2.1 Reflections: Reflections are recognized by the hyperbolic travel times. If the reflection interface is horizontally flat, the reflection hyperbola is symmetric with respect to zero offset. On the other hand if it is dipping interface, then the reflection hyperbola is skewed in the up dip direction. 9.2.2 Coherent Noise: Under the coherent noise category there are several wave types. •
Ground roll is recognized by its low frequency, strong amplitude and low group velocity. It is the vertical component of dispersive surface waves i.e. Raleigh waves. Typically we try to eliminate ground roll in the field itself by array forming of receivers.
•
Guided waves are persistent, especially in shallow marine records in areas with hard water bottom. Guided waves also are found in the land records. These waves are largely attenuated by CMP stacking. Because of their prominently linear move-out, in principle they also can be suppressed by dip filtering techniques. One such filtering technique is based on 2D Fourier transformation of the shot record.
•
Side Scattered noise commonly occurs at the water bottom, where there is no flat, smooth topography.
•
Cable noise is another form of coherent noise which is linear and low in amplitude and frequency. It appears on shot records as late arrivals.
•
Another form of coherent noise is the air wave which has a velocity of 300 m/s. It can be a serious problem when shooting with surface charges. Notch muting is the only way of removing them. Power lines also give rise to noisy traces in the form of a mono frequency wave (50 or 60 Hz).
•
Multiples are another type of coherent noise. They are secondary reflections having inter- or intra- bed ray paths. They propagate both in sub and supercritical regions.
•
Power lines also cause noisy traces in the form of a mono-frequency wave. A mono-frequency way may be 50 or 60 Hz, depending on where the field survey was conducted. Notch filters of ten are used in the field to suppress such energy.
9.2.3 Random Noise: Random noise has various sources. Poor planting of geophone, wind, transient movements in the vicinity, wave motion in the water (marine) and finally electrical noise of the recording instrument. One important aspect of data processing is to uncover genuine reflections by suppressing all unwanted energies (noise of various types) .The objective of seismic data processing is to convert the information recorded in the field to a form that can be used for geological interpretation. Through processing we are enhancing the signal to noise ratio, removing the seismic impulse from the trace (inverse filtering) and repositioning the reflectors to its true location (NMO, DMO and migration), thereby making it into a more palatable form.
9.3
Seismic Data Processing Seismic data processing is composed of basically five types of corrections and
adjustments: •
Time,
•
Amplitude,
•
Frequency-phase content,
•
Data compressing (stacking), and
•
Data positioning (migration) These adjustments increase the signal-to-noise ratio, correct the data for various
physical processes that obscure the desired (geologic) information of the seismic data, and reduce the volume of data that the geophysicist must analyze. The geologic information desired form seismic data is the shape and relative position of the geologic formations of interest. In areas of good data quality it is possible to produce estimates of the litho logy based upon velocity information. From the amplitudes of reflections, it is even possible to make estimates of the pore constituents, since gas accumulations often generate amplitude anomalies. Knowing the shape of the structures at depth allows oil company explorationists to assign probabilities of finding commercially exploitable hydrocarbons in the area surveyed. The velocities of seismic waves in the earth can be derived from seismic data or measured in wells, and they are used to convert the known reflection times into estimated reflector depth. 9.3.1 Time Adjustments: Time adjustments fall into two categories:
Static and
Dynamic
Static time corrections (normal move-out) are a function of both time and offset and convert the times of the reflections into coincidence with those that would have been recorded at zero offset, that is, to what would have been recorded if source and receiver were located at the same point.
9.3.2 Amplitude Adjustments: Amplitude adjustments correct the amplitude decay with time due to spherical divergence and energy dissipation in the earth. There are two broad types of amplitude gain programs:
Structural amplitude gaining or automatic gain control (ABC), and
Relative true amplitude gain correction
The first scales amplitudes to a nearly alike and is generally chosen for structural mapping purposes. The second attempts to keep the relative amplitude information so that the amplitude anomalies associated with facies changes, porosity variations, and gaseous hydrocarbons are preserved. 9.3.3 Frequency-Phase Content: The frequency-phase content of the data is manipulated to enhance signal and attenuate noise. Appropriate band-pass filters (onechannel filtering) can be selected by reference to frequency scans of the data which aid in determining the frequency content of the signals. De-convolution is the inverse filtering technique used to compress an oscillatory (long) source waveform, often seen in marine data, into as near a spike (unit-impulse function) as possible. Ghosts, seafloor multiples, and nearsurface reverberations can often be attenuated through de-convolution approaches. Many deconvolution techniques use the autocorrelation of the trace to design an inverse operator that removes undesirable, predictable energy. 9.3.4 Data Compressing (Staking): The data compression technique generally used is the common midpoint (CMP) stack. It sums all offsets of a CMP gather into one trace. Forty-eight to 96-fold stacks are common. Conventional 2D seismic data initially exist in a 3D space: the three axes are time, offset and a coordinate x along the line of survey. Threedimensional data consist initially of a 4D data set; the coordinates being time, offset and two horizontal spatial coordinates, x and y, which lies on the midpoint axis.
9.3.5 Data Positioning (Migration): The data positioning adjustment is migration. Migration moves energy form its CMP position to its proper spatial location. In the presence
of dip, the CMP location is not the true subsurface location of the reflection. Migration collapses diffractions to foci, increases the visual spatial resolution, and corrects amplitudes for geometric focusing effects and spatial smearing. Migration techniques have been developed for application pre-stack, post-stack, or a combination of both. 9.4
Objectives of Data Processing
The objectives of data processing may be summarized as follows: •
To enhance the signal to noise ratio (S/N).
•
To produce seismic cross section representative of geology.
•
To meet the exploration objectives of the client.
9.5
Basic Data Processing Sequence
Since the introduction of digital recording, a routine sequence in seismic data processing has evolved. There are three primary steps in processing seismic data 1. De-convolution, 2. Stacking, and 3. Migration, in their usual order of application. Figure 21(a) represents the seismic data volume in processing coordinates – midpoint, offset and time. All other processing techniques may be considered secondary in that they help improve the effectiveness of the primary processes. The secondary processing steps include corrections (statics, geometric, NMO, DMO, velocity analysis, filtering etc.). Many of the secondary processes are designed to make data compatible with the assumptions of the three primary processes. De-convolution assumes a stationary, vertically incident, minimum-phase, source wavelet and white reflectivity series that is free of noise. Stacking assumes hyperbolic moveout, while migration is based on a zero-offset (primaries only) wave field assumption. Conventional processing of reflection seismic data yields an earth image represented by a seismic section usually is displayed in time. A conventional processing flowchart is shown in the figure 21(b) on the next page.
1. PRE-PROCESSING a. Demulitplexing b. Reformatting c. Resampling c. Editing d. Geometry Merging ( Labeling ) e. Static Corrections f. True Amplitude Recovery i. Spherical Divergence Correction ii. Absorption/Attenuation Correction g. Muting 2.
TIME INVARIANT FILTERING
3. CMP SORTING 4. DECONVOLUTION 5. VELOCITY ANALYSIS 6. RESIDUAL STATIC CORRECTIONS 7. VELOCITY ANALYSIS 8. NMO CORRECTIONS 9. DMO CORRECTION 10. INVERSE NMO CORRECTION 11. VELOCITY ANALYSIS 12. NMO CORRECTION, MUTING AND STACKING 13. DECONVOLUTION 14. TIME VARIANT SPECTRAL WHITENING 15. TIME VARIANT FILTERING 16. MIGRATION 17. GAIN APPLICATION
Chapter 10 Seismic Data Processing Stage I (Pre-Processing) 10.1
Preprocessing is the first and foremost step in the processing Preprocessing: sequence and it commences with the reception of field tapes and
observers log. Field tape contains seismic data and observers log contains geographical data (shot/receiver numbers, elevations, latitude, longitude etc). 10.1.1 De-Multiplexing: Field data are recorded in multiplexed mode (trace sequential) using a certain type of format. So first de-multiplexing (time sequential) of the data has to be done. Mathematically, de-multiplexing can be envisioned as transposing a big matrix so that the rows of the resulting matrix can be read as seismic traces recorded at different offsets i.e. changing time sequential form into a trace sequential form. 10.1.2 Reformatting: In this stage the data are converted to a convenient format which is used through out processing. There are many standards available for data storage. Format differs with the manufacturer, type of recording instrument and also with the version of operating system. Since the processing software can not operate directly on the above mentioned formats, the system internally converts its input data into a format which is compatible to it. Data formatting defines –How data is arranged and what information is stored as on magnetic media (tapes or drives) which will usually follow an industry standard connection. Data from the field will not usually be in the format required by the processing centre. The formats generally used for data recording are SEG-D (multiplexed/demultiplexed data), and SEG-B (multiplexed format). Hence they are called field formats. Demultiplexing is not done on data recorded in SEG-D format. The out put of processing is in SEG-Y format.
10.1.3 Re-sampling: Processing can be done at a sample rate different to that of recording (e.g., 1, 2, or 4ms). Usually processing is performed at 4ms, if the accuracy is sufficient, as the processing time and cost are less. If we are looking for an improvement in resolution, or if we want more accuracy in measurements (velocity analysis, static corrections), a sample rate of 4ms or even 1ms can be taken, provided that recording was at this rate. Frequency aliasing effects can be avoided by high frequency (HF) filter, adopted to the new sample rate: Sample rate 4ms ------ cutoff 125Hz Sample rate 2ms ------ cutoff 250Hz Sample rate 1ms ------ cutoff 500Hz For sample to go from a sample rate of 1ms to 4ms it is necessary to filter all the information of frequency greater than 125Hz. Figure 22 (a) and 22(b) shows two different field records one in SEG-D format, obtained in field and the other in SEG Y format readied for processing. 10.1.4 Editing: Editing involves leaving out the auxiliary channels & NTBC traces and detecting and changing dead or exceptionally noisy traces. Bad data may be replaced with interpolated values. Noisy traces, those with static glitches or mono-frequency high amplitude signal levels are deleted. Polarity reversals are corrected. Out put after editing usually include a plot of each file so that one can see what data need further editing and what type of noise attenuation are required. Figure 23 (a) and (b) clearly shows the effect of editing, wherein the removal of the occasional noisy traces gives the signal unmasked. Figure 23 (a) shows the raw record and 23(b) shows the record after editing. 10.1.5 Geometry Merging (Labeling): No matter how meticulously processing parameters are chosen, such as in de-convolution and velocity analysis, bad quality stack section often is due to incorrect field geometry set up. So an important step in the preprocessing is to apply the field geometry to the seismic data. The field geometry is obtained from the observer’s log. The field geometry has to be incorporated with the seismic traces. This was previously done manually. Nowadays this work is done by a module of the processing software. This procedure is called Labeling or Merging. Figure 24 shows the process of merging with the record being the cmp gather and the window with numbers being the index which gives the details of the field parameters, using which the data on the record was collected
10.1.6 Static Corrections: Sheriff’s definition of static corrections, often shortened to statics, is as follows. “Corrections applied to seismic data to compensate for the effects of variations in elevation, weathering thickness, weathering velocity, or reference to a datum” Statics are time shifts applied to seismic data to compensate for: •
Variations in elevations in land,
•
Variations in source and receiver depths (marine gun/cable, land source),
•
Tidal effects (marine),
•
Variations in velocity/thickness of near surface layers,
•
Change in data reference times.
The objective is to determine the reflection arrival times which would have been observed if all measurements had been made on a (usually) flat plane with no weathering or low-velocity material present. These corrections are based on uphole data, refraction first-breaks, and/or event shooting. •
Uphole-based statics involve the direct measurement of vertical travel-times form a buried source. This is usually the best static correction method where feasible.
•
First-break based statics are the most common method of making field (or first estimate) static corrections.
•
Data-smoothing statics methods assume that patterns of irregularity that most events have in common result from near-surface variations and hence static corrections trace shifts should be such as to minimize such irregularities. Most automatic staticsdetermination programs employ statistical methods to achieve the minimization.
The term ‘static’ is used to denote constant time shift of whole data traces, as opposed to variable time shifts as applied by NMO corrections which are dynamic. The elevation needed for shot/receiver time correction is obtained from labeling records. The velocity needed for calculating the time shift is obtained from shot uphole times. The elevation corrections (also called datum correction) may be used to bring all times in a seismic record to a fixed level in subsurface which is the final processing datum. FPD could be any arbitrary level(depending on the client requirement) or msl (mean sea level).
10.1.7 Amplitude Recovery (Geometric Spreading Correction): A field record represents a wave field that is generated by a single shot. Conceptually a single shot is thought of as a point source that generates a spherical wave field: •
In a homogeneous medium, energy density decays proportionately to 1/r2, where r is the radius of the wave front. Wave amplitude is proportional to the square root of energy density; it decays as 1/r. In practice, velocity usually increases with depth, which causes further divergence of the wave front and a more rapid decay in amplitudes with distance.
•
The frequency content of the initial source signal changes in a time variant manner as it propagates. In particular, high frequencies are absorbed more rapidly than low frequencies. This is because of the intrinsic attenuation of the rocks.
Figure 25 shows a graph relating the Amplitude Decay with time/depth. Newman’s Formula: The factor 1/r that describes the decay of wave amplitudes as a function of the radius of the spherical wave front is valid for a homogeneous earth without attenuation. For a layered earth, amplitude decay can be described approximately by 1/ [ v2 (t) · t ]. Here t is the two way travel time and v(t) is the rms velocity of the primary reflections averaged over a survey area. Therefore the gain function for geometric spreading compensation is defined by
where, v0 is the reflection velocity at a specified time t0 . 10.1.7.1
Spherical Divergence: For a spherically spreading wave in a ‘lossless’
material, the seismic pressure amplitude decreases as reciprocal of the distance traveled.
For a constant velocity medium,
But in the ‘layer cake’ model used in CMP stacking, the velocity increases between the layers, and in practice it increases with depth within layers, this results in a TV2 relationship, yielding
This property is used when compensating for amplitude decay. Figure 26(b) gives a representation of the spherical divergence correction doing which we can see the clear recovery of the amplitudes at the later times of the section that were not comparable with those in figure 26(a) , which represents raw data. 10.1.7.2
Exponential Gain: Absorption is a process where by the energy of a seismic
wave is converted to heat while passing through a medium. The loss is a result of the elastic movement. Absorption is very much a function of geology. Absorption can be expressed as a function of the distance traveled by the seismic wave, implying it is also time variant.
where,
Ax = amplitude at distance x A0 = amplitude at reference point α
= attenuation factor (absorption coefficient)
The key point here is that amplitude decay due to absorption is exponential with distance. Loss due to absorption seems to be nearly constant per cycle. Hence attenuation is lesser for low frequencies and higher for higher frequencies. Again applying this gain correction we can see the amplitudes recovering in figure 26(c) which were not available on figure 26(b). figure 26(d) shows the record which is obtained by applying the filter the record 26(c).
10.1.8 Muting: The field data does not always necessarily contain the reflected data. It may also contain first arrival, super critical reflections, ground coupled air waves, surface waves (ground rolls) etc. So these effects have to be removed to improve the data quality. For this purpose muting is done which involves arbitrarily assigning zero values to traces during a desired interval selected by the processor. 10.2 Sorting: Seismic data acquisition with multifold coverage is done in shot-receiver (s, g) coordinates. Seismic data processing, on the other hand, conventionally is done in midpoint-offset (y, h) coordinates. The required coordinate transformation is achieved by sorting the data into CMP gathers. Based on the field geometry information, each individual trace is assigned to the midpoint between the shot and receiver locations associated with that trace. Those traces with the same midpoint location are grouped together, making up a CMP gather. Albeit incorrectly, the term Common Depth Point (CDP) and common midpoint (CMP) often are used interchangeably. Figures 39(a) and 39(b)shows the superposition of shot receiver (s, g) and midpoint-offset (y, h) coordinates, and raypath geometries for various gather types. For most recording geometries, the fold of coverage nf for CMP stacking is given by
where, ∆g and ∆s are the receiver-group and shot intervals, respectively, and ng is the number of recording channels, by using this relationship, the following rules can be established:
a. The fold does not change when alternating traces in each shot record are dropped. b. The fold is halved when every other shot record is skipped, whether or not alternating traces in each record are dropped. 10.3 Filtering: Filtering is done to remove unwanted frequencies from the seismic data. Seismic frequencies have a range of 12 – 72 Hz and the frequencies other than this are attenuated using various filtering techniques.
The following tables give an idea on various types of noises & methods to attenuate them. Noise Attenuation Techniques Random
Coherent
Band-pass filtering
Band-pass filtering
Notch filtering
Velocity filtering i.e.F-K filtering
K-filtering e.g. Trace/shot summation
Muting
F-K filtering
Coherency filtering
Stacking De-spike F-X filtering Coherency filtering Editing (e.g. kill) Land Data – Additional Type of Noises Noise/problem
Nature
Solution
Hi-line
Random
Kill, notch filter
Ground roll
Coherent
F-K filter
Air wave
Coherent
Hi-cut filter, surgical mute
Correlation noise
Random
Mute
Traffic(vehicles, people, animals)
Random
Filter, stack
Falling debris
Random
Filter, stack
Wind noise
Random
Filter , stack
Chapter 11 Seismic Data Processing Stage II (De-convolution) 11.1
compresses the basic wavelet in the recorded I ntroduction: De-convolution seismogram, attenuates reverberations and short-period multiples,
thus increases temporal resolution and yields a representation of subsurface reflectivity. The processed normally is applied before stack; however, it also is common to apply deconvolution to stacked data. De-convolution sometimes does more than just wavelet compression; it can remove a significant part of the multiple energy from the section. Wavelet compression can be done using an inverse filter as a de-convolution operator. An inverse filter, when convolved with the seismic wavelet, converts it to a spike. When applied to a seismogram, the inverse filter should yield the earth’s impulse response. An accurate inverse filter design is achieved using the least-squares method. The fundamental assumption underlying the de-convolution process (with the usual case of unknown source wavelet) is that of minimum phase.
The Wiener filter converts the
seismic wavelet into any desired shape. For example, much like the inverse filter, a Weiner filter can be designed to convert the seismic wavelet into a spike. However, the Weiner filter differs from the inverse filter in that it is optimal in the least squares sense. Also, the resolution (spikiness) of the output can be controlled by designing a Wiener production error filter – the basis for predictive de-convolution. Converting the seismic wavelet into a spike is like asking for a perfect resolution. In practice, because of noise in the seismogram and assumptions made about the seismic wavelet and the recorded seismogram, spiking deconvolution is not always desirable. Finally, the prediction error filter can be used to remove periodic components – multiples, from the seismogram. 11.2
Convolutional Model: The recorded seismic trace may be modeled as a series of
interactions between the source signature (a finite, band limited wavelet) and the earth. The convolutional model postulates that the above wavelet is the superposition of several
responses (the source wavelet, earth filter, ghosting, multiples, instruments etc.) to form a complex pulse which then convolves with the reflectivity function to give the actual seismogram. A seismic trace x(t) is given by the convolution of the basic seismic wavelet w(t) with the reflectivity series r(t) plus random noise n(t).
------------11.3
(1)
De-convolution: The objective of de-convolution is to remove the effect of the
convolution of the basic wavelet with the reflectivity, output seismic trace to be the reflectivity series. In practice it is to arrive at a better estimate of the reflectivity function. In theory, we resolve the reflectivity r(t) from the equation given below. ---------- (2) where, s(t) is the waveform component associated with source location e(t) represents the earth’s impulse response Under the assumption the source waveform is known we have the following equation: ---------- (3) The basic seismic wavelet w (t) is actually made up of the convolution of source signature with the propagation effects in the earth and the recording system sources. In the frequency domain ------------
(4)
Where, X (f), S (f), E (f) and R (f) represent the amplitude spectra of the corresponding time functions (ignoring the phase for now). We can remove the effect of the (S(f) ×E(f)) term in this equation by making it equal to one (or any constant value). The function which has a constant amplitude spectrum over all frequencies is a SPIKE. The de-convolution operator is an inverse filter. In the time domain, de-convolution involves finding an inverse of the wavelet which, when convoluted with the seismic trace, output the reflectivity series. The seismic wavelet is converted to a spike. 11.4
De-convolution Methods: Generally de-convolution fall into one of the
following two categories
11.4.1 Deterministic De-convolution: De-convolution where part of the seismic system is known. No random elements are involved. For e.g. where the source wavelet is accurately known we can do source signature de-convolution. This is done when vibroseis is used as the source. 11.4.2 Statistical De-convolution: Statistical De-convolution is a process where we:
•
Have no pre knowledge of the wavelet.
•
Derive information about the wavelet (either ‘source’, ‘system’, or combined wavelets) from the data itself, specifically from the auto correlation of the data.
•
Make certain assumptions about the data which justify the statistical approach.
•
Does not need to be used in conjunction with deterministic de-convolution.
Assumptions: To perform statistical de-convolution, the algorithm(s) used rely on the following assumptions. 1. The earth is made up of horizontal layers of constant velocity. 2. The source generates a compress ional plane wave that impinges on layer boundaries at normal incidence. Under such circumstances, no shear waves are generated 3. The source waveform does not change as it travels in the subsurface – it is stationary (i.e. within the operator design window the shape of the wavelet is consistent. Multi-window design/application may be required to get optimum results for particular data sets where frequency content etc varies greatly with time). 4. The noise component is low enough to be ignored. 5. The source waveform is known. 6. Reflectivity is a random process. This implies that the seismic wavelet in that their autocorrelations and amplitude spectra are similar. 7. The input wavelet is minimum phase (i.e., before de-convolution a minimum phase conversion (source de-signature) step may be required), therefore, it has a minimumphase inverse. Assumptions 1, 2 and 3 allow formulating the convolutional model of the 1D seismogram by equation 1. Assumption 4 eliminates the unknown noise term in equation 1 and reduces it to equation 3. Assumption 5 is the basis for deterministic de-convolution – it allows estimation
of the earth’s reflectivity series directly from the 1D seismogram defined by equation 3. Assumption 6 is the basis for statistical de-convolution – it allows estimates for the autocorrelogram and amplitude spectrum of the normally unknown wavelet in equation 3 from the known recorded 1D seismogram. Finally assumption 7 provides a minimum-phase estimate of the phase spectrum, which is re-estimated from the recorded seismogram by way of assumption 6. Statistical de-convolution attempts to ‘spike’ the data and/or remove repetitive energy (e.g. multipliers). ‘Spiking’ compresses the wavelet (by enhancing frequency content) but will never result in ‘reflectivity’ series being output; mainly because
•
Limited bandwidth
•
Assumption not valid. E.g. not minimum phase, noise not zero etc.
Statistical de-convolution can be •
Spiking De-convolution
•
Predictive De-convolution(Also ‘gap’ de-convolution)
11.4.2.1
Spiking De-convolution: The process by which the seismic wavelet is
compressed to a zero-lag spike is called spiking de-convolution. The filters that achieve this goal are the inverse and the least-squares inverse filters. Their performance depends not only on filter length, but also on whether the input wavelet is minimum phase. The spiking deconvolution operator is strictly the inverse of the wavelet. Once the amplitude and phase spectra of the seismic wavelet are statistically estimated from the recorded seismogram, its least-squares inverse – spiking de-convolution operator, is computed using optimum Wiener filters. When applied to the seismogram, the filter yields the earth’s impulse response. The Wiener filter applies to a large class of problems in which any desired output can be considered, not just the zero-lag spike. Five choices for the desired output are Type 1: Zero-Lag Spike Type 2: Spike at arbitrary lag Type 3: Time-Advanced form of Input Series Type 4: Zero-Phase Wavelet Type 5: Any Desired Arbitrary Shape
The general form of the matrix equation for a filter of length ‘n’ is :
here, ri, ai and gi, I = 0,1,2,3
,n-1 are the autocorrelation lags of the input wavelet, the
Wiener filter coefficients, and the cross-correlation lags of the desired output with the input wavelet, respectively.
The process with type 1 desired output is called spiking de-convolution. Cross correlation of the desired spike, say (1, 0, 0, …..,0), with input wavelet, say (x0, x1, x2, ……, xn-1) yields the series (x0, 0, 0, ….., 0). The generalized form of the normal equation1 takes the special form:
This equation is scaled by (1/x0). The least-squares inverse filter has the same form as the matrix equation (6). Therefore, spiking de-convolution is mathematically identical least-squares inverse filtering. The autocorrelation matrix on the left side of equation 6 is computed from the input seismogram (assumption 6) in the case of spiking de-convolution (statistical deconvolution), whereas it is computed directly from the known source wavelet in the case of least-squares inverse filtering (deterministic de-convolution). 11.4.2.2
Predictive De-convolution: The type 3 desired output (Time-Advanced
Form of Input Series) suggests a prediction process. Predictive de-convolution ‘predicts’ repetitive elements within the seismic trace (multiplier, ringing etc) and generates an operator which will remove it leaving only the random element i.e. the reflection series. Given the
input series x(t), w want to predict its value at some future time (t + α), where α is prediction lag. Wiener showed that the filter used to estimate x(t + α) can be computed by using a special form of the matrix equation (5). Since the desired output x(t + α) is the time advanced version of the input x(t), we need to specialize the right side of equation (6) for the prediction problem. Following is the matrix showing an n-long prediction filter and an α-long prediction lag:
Design of the predictive filters requires only autocorrelation of the input series. There are two approaches to predictive de-convolution:
•
The prediction filter may be designed using equation (7) and applied on input series.
•
Alternately, the prediction error filter can be designed and convolved with the input series.
Predictive de-convolution is a general process that encompasses spiking de-convolution. In general, the following statement can be made: “Given an input wavelet of length (n + α), the prediction error filter contracts it to an α-long wavelet, where α is the prediction lag. When α = 1, the procedure is called spiking de-convolution. 11.4.2.3 11.4.2.3.1
Predictive De-convolution in Practice Operator Design: We start with a single, isolated minimum-phase wavelet.
Assumptions 1 through 5 are satisfied for this wavelet. The ideal result of spiking deconvolution is a zero-lag spike. The action of spiking de-convolution on the seismogram derived by convolving the minimum-phase wavelet with a sparse-spike series is similar to the case of the single isolated wavelet. An increasingly better result should be obtained with more and more coefficients are included in the inverse filter. Now consider the real situation of an unknown source wavelet. Based on assumption 6, autocorrelation of the input
seismogram rather than that of the seismic wavelet is used to design the de-convolution operator. Auto Correlation: The result is a zero phase wave form with a maximum at zero lag. If two wave forms are perfectly random then the auto correlation is a spike. Statistical deconvolution filters(or operators) are most commonly derived from the auto correlation of the input data using Wiener-Levinson algorithm. Autocorrelation analysis: We can decay the point on our wavelet where our de-convolution operator begins to operate - via the production ‘lag’ or ‘gap’. If the predictive gap or delay is only one sample, we have spiking de-convolution. Or in other words, spiking de-convolution may be considered as a special case of predictive de-convolution where the ‘gap’ is one sample. Following are some of the implications in designing the De-convolution Operator: •
The operator may be long enough to predict the multiples targeted.
•
Design window usually at least five times operator length.
•
Derivation windows slide behind the first break noise.
•
Window over data representative of design criteria.
•
Not too long an operator (less than 500 ms) – dependent on objective.
•
Separate operators derived from multiple windows?
•
One or two derivation windows at the most (multi window de-con).
11.4.2.3.2 Prediction Gap Length: Gap length will have an effect on: •
Pulse stabilization – to equalize the basic wavelet through out the data.
•
Wavelet compression – degree of spiking.
•
Occasionally, which multiple system is targeted – long gap length with short active operator to straddle long period multiples.
(Too long a gap may result in short period reverberations remaining) 11.4.2.3.3 Pre-Whitening: Addition of white noise to data (auto-correlogram) during operator design is to prevent: •
Operator instability (divisions by zero when calculating wavelet inverse).
•
Equalizing the amplitude of noise in addition to the signal.
The amount of white noise to add will generally be in the range of 0.1 % to 1%.
Too little white noise may: •
Cause the de-convolution operator to become unstable.
•
Decrease the S/N ratio of the data.
Too much white noise may: •
Decrease the effectiveness of the de-convolution process.
•
Narrow the band width of data.
All these predictive de-convolution parameters are fixed from running de-convolution panels by trial and error method. 11.4.2.3.4
De-convolution Panel: Operator length and amount is pre-whitening is
decided by trial and error method by applying different operator lengths and pre-whitening to a CDP gather. The values of operator length and pre-whitening which yields the sharpest output is taken as the optimum and de-convolution is done using these values.
Figure 28 (a) shows the effect of application of the Spiking Deconvolution on the raw data and we can see the events clearly marking their differences from the neighbouring random reflections. The tempporal resolution is incresed and events show the continuity in their behaviour. Figure 28 (b) shows the spectrum of the raw data and the decon data. We can clearly see the removal of the incoherent noise caused by the electric power lines in the decon spectrum.
Chapter 12 Seismic Data Processing Stage III (Velocity Analysis, NMO, DMO and Residual Static Corrections) 12.1
analysis is an interactive tool used to interpret V elocity Analysis: Velocity stacking or normal move out velocities on 2D & 3D pre-
stack seismic data. Several techniques utilize the variation of normal move out with record time to find velocity. Velocity analysis is usually done on common midpoint gathers where the hyperbolic alignment is often reasonable. Where dips are large, a common reflecting is not achieved. Typically the analysis procedure involves comparing a series of stacked traces in which a range of velocities were applied in NMO. There are many methods for determining correct velocities for the NMO equation. The methods that are being used by RCC are given below. Velocity Spectrum Analysis: Velocity spectrum analysis provides a means to interactively pick the velocity which is correct for applying NMO corrections. Multi Velocity Function Stacks: The multi velocity function stacks (mvfs) panel displays a series of side by side stacked traces for a set of CDP’s. These traces are corrected for NMO with a series of different velocities. The velocities can be a series of time variant velocity functions as a function of time. Typically the test range is small at shallow times and larger at deep times due to the nature of the NMO effect. This panel is used to pick velocities by visually locating the maximum-stacked response. In practice velocity analysis is done as follows: A reference velocity function is taken from the well data of the nearest well. A number of velocity functions are then generated (in practice usually six). One half of them will contain lesser velocity values and the other half will contain greater velocity values (as compared to the reference velocity function) with a constant increment or decrement from one velocity function to the other. Figure 29 shows a record displaying a section to be
analysed for velocity. A group of GDP’s (usually 21) which fall under full foldage area is then taken and each of these CDP’s are stacked applying each one of the seven velocity functions. The output is seven strips with 21 traces each, each strip corresponding to each velocity function and each trace corresponding to each CDP. This is called a multi velocity function stacks (mvfs) panel. From this we can interactively pick the correct velocity function. Alternately a velocity spectrum is also generated. Mvfs are used generally to fine tune the velocity picked using velocity spectrum. Figure 30 shows the velocity function selection and thus how the velocity analysis is done. 12.2
Normal Moveout Correctons (NMO): NMO is the difference between
reflection arrival time at a geophone situated at a certain distance from the shot point and arrival time at a geophone situated at the shot point. As offset increases, the seismic wavelet arrives late at the geophone. This is not due to any anomalies in the subsurface, but due to the additional distance traveled by the seismic wavelet. So a time correlation has to be applied according to offset. NMO correction is the time correction which will ideally linearise the alignment of primarily reflected signals in the CDP gather. NMO is applied according to the formula
Where, Tx is the actual reflection time of the seismic event due to Normal Move Out effects. T0 is the zero offset reflection time of the seismic event; x is the actual source receiver distance; v is the normal Move Out velocity or stacking velocity of reflection event. While applying NMO the trace undergoes a slight non linear stretch which is called NMO stretch. As a result of NMO correction a frequency distortion occurs particularly for shallow events and at large offsets. The maximum permissible for the stretch is 10% and signals where more stretch is observed is muted. It is quantified by
where, f is the dominant frequency ∆f is change in frequency ∆TNMO = Tx – T0 Figure 31 shows the NMO stack obtained after stacking the NMO corrected traces.
12.3
Dip Moveout Correctons (DMO): In the case of a dipping reflector, in
addition to NMO, another correction which takes into account is the dip of the reflector must be applied. This following from the fact that, the move out will be greater when the reflector is dipping. DMO correction is applied according to the formula
where, Tx = Two way travel time T0 = Zero offset travel time V = velocity above the reflector φ = dip angle After applying the DMO correction the data is in CMP gather from a dipping interface model do have a common reflector points. The terms CRP and CRP gather are accurate descriptions of the data post DMO. Because DMO is a geometric correction that repositions seismic data in a sense of migration scheme. The alternate name for DMO is pre-stack partial migration.
12.4
Residual Statics Corrections: ‘Field’ statics do not generally solve all delays within the data for a variety of reasons for example:
•
Velocities vary both laterally and vertically within the layers.
•
Weathering thickness varies rapidly.
•
Undetectable thin, low velocity layers.
•
Local anomalies (e .g ‘lenses’ of low velocity material near the surface)
•
Vertical ray approximation is incorrect.
Residual statics correction attempts to fine-tune the field statics. Typical procedure is to measure time-shifts between traces within a CMP and a ‘pilot’ trace (usually the stacked CMP itself) and solve for the source and receiver static in a surface consistent manner .This results in non surface consistent static values for every trace. Residual statics may be applied to data as they are and known as ‘Trim’ statics. Residual statics can be, at times destructive.
Residual statics corrections involve three phases: 1. Picking travel time deviations tij based on cross-correlation of traces in a CMP gather with a reference or pilot trace that needs to be defined in some fashion, 2. Modelling tij by way of following equation and decomposing it into its components: source and receiver statics, structural and residual moveout terms, and
where, the various terms are defined in the figure 32(a) while figure 32(b) shows how to pick travel time deviations from NMO corrected gathers. 3. Applying the derived source and receiver terms sj and rj, respectively, to travel times on the pro – NMO – corrected CMP gathers. The most common methods of deriving the time-shifts and the resultant static values are•
Cross-correlation method
•
Stack-power optimization
•
Combination of above
The time-shifts produced using the cross-correlation technique may be decomposed into shot and receiver statics by solving a set of simultaneous equations. Stack-power optimization, in simple terms, may be the result of applying multiple sets of surface consistent values to the data and the set giving the maximum stack-power chosen. Alternatively, the stack-power optimization may be used to determine the best correlation coefficient prior to solving the final time-shifts using the simultaneous equation or similar techniques. Figure 33 shows a field record on which represents the De-convoluted Stack and Residual Stack.
Chapter 13 Seismic Data Processing Stage IV (Stacking, Time Variant Filtering and Migration) 13.1
S
tacking: Stacking is basically summing of all the traces which has a common reflection point. By summing the S/N ratio is increased as signal gets
enhanced but random noise remains the same. Considering all the noises to be random, the S/N ratio improvement by stacking will be √n times, where n is the foldage. The main point in recording multifold data is to stack all the traces together. Stacking is ineffective in suppressing multiples and diffractions. Before final stacking all the corrections viz.NMO, DMO, Statics etc has to be made. Generally before decon and velocity analysis a gather is stacked to have a rough idea about the different horizons, prevailing noises etc. This stack is called BRUTE STACK. The velocity that has to be applied for NMO correction to prepare brute stack is a reference velocity obtained from VSP data. Figure 34 shows real field record with brute stacking. While the other figure 31 and 35 show the NMO Corrected Stack and the Final Stack. 13.2 Time Variant Filtering: Owing to the attenuation of seismic energy by the earth, the shallow reflections will have high frequencies and the deeper reflections will have lower frequencies. Any departure from this trend (ie high frequencies in lower part of the trace or low frequencies in the upper part of the trace) indicates a noise which has to be removed so as to improve the S/N ratio. This is done using time variant filtering. Time variant filtering is usually applied on stacked data.
Figure 27 (b) represents the filtered record which is obtained by applying a high pass filter (8 to 16 Hz) on the raw field record shown in figure 27 (a). This record clearly shows the elimination of various noise components from the raw field record. The air waves which are clearly visible on the raw record, at the mid portion of the record, are eliminated in the filtered record.
13.3
Migration Migration is a process which attempts to correct the directions of the geological
structures inherent in the seismic section. Migration redistributes energy in the seismic section to better image the true geological structures. Migration is done to rearrange seismic data so that reflection events may be displayed at their true subsurface positions. It collapses diffraction back to their point of origin. It improves resolution and collapses Fresnal zone. It provides more accurate depth section. Zero offset stack section gives a false picture of dipping reflectors as events A`` and B`` are plotted at true trace positions A` and B` respectively in figure 36. The apparent dip of an event on a zero offset stack section is less than the true dip of the event. 13.3.1 Restrictions of 2D Migration: Migration must normally be carried out in the plane of incidence relative to each horizon. It is only valid if this plane of incidence is fixed for each horizon considered. The final section assembles all these planes of incidence to carry out the migration. Migration requires that the velocity function at each of these planes of incidence be known. Migration is based on a 2D scheme with the following assumptions: 1. All depth points of seismic horizons are in a single plane passing through the seismic line. 2. This plane of incidence is vertical 3. Structures can be represented by cylinders whose principal axes are perpendicular to the plane of section. The ideas behind the above constraining assumptions also underlie the production of multifold coverage stack sections, which give an inexact, deformed and displaced image of the subsurface, as soon as there is any dip or velocity variation: 1. Reflections originating anywhere are brought into the vertical plane of section (X,T). Geophones record the vertical component of the moment of the ground and the hydrophones record a pressure wave whatever the incidence of the wavefront is. 2. After NMO and stack , the seismic section now represents
the theoretical
acquisition configurations of coincident source and receiver, which only allows for only travel paths perpendicularly to the reflectors.
3. Times are measured vertically along the CDP traces. 4. The CDP is situated perpendicularly below the midpoint on the surface, which assumes horizontal beds. Geophysicists know well the simple examples of images in time deformed and / or displaced in relation to the depth model: Depth model
Time representation
Diffracting point Dipping reflector
Diffraction hyperbola Dipping reflector, shifted down dip and dip decreased
Tight syncline
“bow tie” shape
13.3.2 Migration in Fourier Domain: Migration in Fourier domain works with dispersion relation which provides the relationship between the horizontal wavenumber and the vertical wavenumber for any temporal frequency. Kx2+ Kz2 = (ω//v)2 If we consider the seismic as a sum of monochromatic plane waves, then all the same frequency and the plane wave of the same frequency and dip are mapped on to a single point in the F-K domain irrespective of their location in the original time section. So any operation in F-K domain is localized to account for any lateral or vertical velocity variations. 13.3.3 Kirchoff Summation: The diffraction summation that incorporates the obliquity, spherical spreading and wavelet shaping factors is called the Kirchhoff summation, and the migration method based on this summation is called the Kirchhoff migration. To perform this method, multiply the input data by the obliquity and spherical spreading factors. Then apply the filter with the above specifications and sum along the hyperbolic path. Place the result on the migrated section at time corresponding to the apex of the hyperbola. In practice, the order of the filter application specified by the wavelet shaping factor (This wavelet shaping factor is designed with a 45-degree constant phase spectrum and an amplitude spectrum proportional to the square root of the frequency for 2-D migration . For 3-D migration the phase shift is 90 degrees and the amplitude is proportional to frequency.) and the summation can be interchanged without sacrificing accuracy because the summation is a linear process and the filter is independent of time space. The velocity is taken as the rms velocity, which can be allowed to vary laterally. However, lateral variation
in velocity distorts the hyperbolic nature of the diffraction pattern and somehow must be considered. The value for the rms velocity typically is that of the output time sample. 13.3.4
Phase Shift Migration: Phaseshift migration is due to Gazdag and works in
F-K domain. For downward continuation, the phaseshift operator is computed at every depth step allowing variation in velocity with depth. At every depth step, inverse Fourier transform is taken to convert F-K domain for imaging at t=0, which is equivalent to summing over all frequencies. This techniques can handles vertical velocity variation for dips while preserving amplitude and phase, but cannot account for lateral velocity variations. Phase Shift Plus Correction: This is an extension of phase shift migration to account for lateral velocity variations. Here, the downward continuation is performed with a constant average velocity function. After converting F-K to F-X, an additional phase shift is applied to account for the difference between the average velocity function and the actual velocity function at each X before applying the imaging principle. Here we cannot downward continue the previous F-K domain data, because at each step an additional phase shift is applied before imaging. Therefore the phase shifted data in F-K for the next depth steps and hence is much move expensive. Still the method can account for only mild lateral velocity variations. 13.3.5
Omega – X Migration (F – X Migration or Hybrid Migration): This
is similar to the finite difference migration in T-X domain and is developed by Kjartannson. It is based on the 45 degree approximation to the one way scalar wave equation and is formulated in the F-X domain.There are two terms in the computation: the diffraction term that collapses the energy along the hyperbolic path to its apex and the thin lens shift term that places the collapsed energy at its actual spatial position in the subsurface. This term is velocity dependent for depth migration and velocity independent for time migration. Figure 37 shows a Migration stack.
Bibliography Name of the Book
Author/Publisher
Introduction to Geophysical Prospecting
Dobrin M.B.
Designing Seismic Surveys in two and three Dimensions
Dale G. Stone
A Handbook for Seismic Data Acquisition
Evans B. J.
Static Corrections for Seismic Reflection Surveys
Mike Cox
ONGC Project Reports on KG Basin
ONGC
Seismic Data Processing Quality Manual
ONGC
Seismic Data Analysis
Oz Yilmaz
Acquiring Better Seismic Data
Peter Carr Perchett
Encyclopedic Dictionary of Applied Geophysics
Robert E. Sheriff
Applied Geophysics
Telford W. M.
